Vol. 80 Friday, 

No. 205 October 23, 2015 

Part II 

Environmental Protection Agency 

40 CFR Parts 60, 70, 71, et al. 

Standards of Performance for Greenhouse Gas Emissions From New, 

Modified, and Reconstructed Stationary Sources: Electric Utility Generating 

Units; Final Rule 

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64510 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60, 70, 71, and 98 

[EPA–HQ–OAR–2013–0495; EPA–HQ–OAR– 

2013–0603; FRL–9930–66–OAR] 

RIN 2060–AQ91 

Standards of Performance for 

Greenhouse Gas Emissions From New, 

Modified, and Reconstructed 

Stationary Sources: Electric Utility 

Generating Units 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is finalizing new source 

performance standards (NSPS) under 

Clean Air Act (CAA) section 111(b) that, 

for the first time, will establish 

standards for emissions of carbon 

dioxide (CO2) for newly constructed, 

modified, and reconstructed affected 

fossil fuel-fired electric utility 

generating units (EGUs). 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. 

DATES: This final rule is effective on 

October 23, 2015. The incorporation by 

reference of certain publications listed 

in the rule is approved by the Director 

of the Federal Register as of October 23, 

2015. 

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 

(D243–01), 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 

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 

DOE Department of Energy 

DOT Department of Transportation 

ECMPS Emissions Collection and 

Monitoring Plan System 

EERS Energy Efficiency Resource Standards 

EGU Electric Generating Unit 

EIA Energy Information Administration 

EO Executive Order 

EOR Enhanced Oil Recovery 

EPA Environmental Protection Agency 

FB Fluidized Bed 

FGD Flue Gas Desulfurization 

FOAK First-of-a-kind 

FR Federal Register 

GHG Greenhouse Gas 

GHGRP Greenhouse Gas Reporting Program 

GPM Gallons per Minute 

GS Geologic Sequestration 

GW Gigawatts 

H2 Hydrogen Gas 

HAP Hazardous Air Pollutant 

HFC Hydrofluorocarbon 

HRSG Heat Recovery Steam Generator 

IGCC Integrated Gasification Combined 

Cycle 

IPCC Intergovernmental Panel on Climate 

Change 

IPM Integrated Planning Model 

IRPs Integrated Resource Plans 

kg/MWh Kilogram per Megawatt-hour 

kJ/kg Kilojoules per Kilogram 

kWh Kilowatt-hour 

lb CO2/MMBtu Pounds of CO2 per Million 

British Thermal Unit 

lb CO2/MWh Pounds of CO2 per Megawatthour 

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 

MWh-g Megawatt-hour gross 

MWh-n Megawatt-hour net 

N2O Nitrous Oxide 

NAAQS National Ambient Air Quality 

Standards 

NAICS North American Industry 

Classification System 

NAS National Academy of Sciences 

NETL National Energy Technology 

Laboratory 

NGCC Natural Gas Combined Cycle 

NOAK nth-of-a-kind 

NRC National Research Council 

NSPS New Source Performance Standards 

NSR New Source Review 

NTTAA National Technology Transfer and 

Advancement Act 

O2 Oxygen Gas 

OMB Office of Management and Budget 

PC Pulverized Coal 

PFC Perfluorocarbon 

PM Particulate Matter 

PM2.5 Fine Particulate Matter 

PRA Paperwork Reduction Act 

PSD Prevention of Significant Deterioration 

PUC Public Utilities Commission 

RCRA Resource Conservation and Recovery 

Act 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

RIA Regulatory Impact Analysis 

RPS Renewable Portfolio Standard 

RTC Response to Comments 

RTP Response to Petitions 

SBA Small Business Administration 

SCC Social Cost of Carbon 

SCR Selective Catalytic Reduction 

SCPC Supercritical Pulverized Coal 

SDWA Safe Drinking Water Act 

SF6 Sulfur Hexafluoride 

SIP State Implementation Plan 

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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 

B. Does this action apply to me? 

C. Where can I get a copy of this 

document? 

D. Judicial Review 

E. How is this preamble organized? 

II. Background 

A. Climate Change Impacts From GHG 

Emissions 

B. GHG Emissions From Fossil Fuel-Fired 

EGUs 

C. The Utility Power Sector 

D. Statutory Background 

E. Regulatory Background 

F. Development of Carbon Pollution 

Standards for Fossil Fuel-Fired Electric 

Utility Generating Units 

G. Stakeholder Engagement and Public 

Comments on the Proposals 

III. Regulatory Authority, Affected EGUs and 

Their Standards, and Legal Requirements 

A. Authority To Regulate Carbon Dioxide 

From Fossil Fuel-Fired EGUs 

B. Treatment of Categories and 

Codification in the Code of Federal 

Regulations 

C. Affected Units 

D. Units Not Covered by This Final Rule 

E. Coal Refuse 

F. Format of the Output-Based Standard 

G. CO2 Emissions Only 

H. Legal Requirements for Establishing 

Emission Standards 

I. Severability 

J. Certain Projects Under Development 

IV. Summary of Final Standards for Newly 

Constructed, Modified, and Reconstructed 

Fossil Fuel-Fired Electric Utility Steam 

Generating Units 

A. Applicability Requirements and 

Rationale 

B. Best System of Emission Reduction 

C. Final Standards of Performance 

V. Rationale for Final Standards for Newly 

Constructed Fossil Fuel-Fired Electric 

Utility Steam Generating Units 

A. Factors Considered in Determining the 

BSER 

B. Highly Efficient SCPC EGU 

Implementing Partial CCS as the BSER 

for Newly Constructed Steam Generating 

Units 

C. Rationale for the Final Emission 

Standards 

D. Post-Combustion Carbon Capture 

E. Pre-Combustion Carbon Capture 

F. Vendor Guarantees, Industry Statements, 

Academic Literature, and Commercial 

Availability 

G. Response to Key Comments on the 

Adequacy of the Technical Feasibility 

Demonstration 

H. Consideration of Costs 

I. Key Comments Regarding the EPA’s 

Consideration of Costs 

J. Achievability of the Final Standards 

K. Emission Reductions Utilizing Partial 

CCS 

L. Further Development and Deployment 

of CCS Technology 

M. Technical and Geographic Aspects of 

Disposition of Captured CO2

N. Final Requirements for Disposition of 

Captured CO2

O. Non-Air Quality Impacts and Energy 

Requirements 

P. Options That Were Considered by the 

EPA But Were Ultimately Not 

Determined to Be the BSER 

Q. Summary 

VI. Rationale for Final Standards for 

Modified Fossil Fuel-Fired Electric 

Utility Steam Generating Units 

A. Rationale for Final Applicability Criteria 

for Modified Steam Generating Units 

B. Identification of the Best System of 

Emission Reduction 

C. BSER Criteria 

VII. Rationale for Final Standards for 

Reconstructed Fossil Fuel-Fired Electric 

Utility Steam Generating Units 

A. Rationale for Final Applicability Criteria 

for Reconstructed Sources 

B. Identification of the Best System of 

Emission Reduction 

VIII. Summary of Final Standards for Newly 

Constructed and Reconstructed 

Stationary Combustion Turbines 

A. Applicability Requirements 

B. Best System of Emission Reduction 

C. Final Emission Standards 

D. Significant Differences Between 

Proposed and Final Combustion Turbine 

Provisions 

IX. Rationale for Final Standards for Newly 

Constructed and Reconstructed 

Stationary Combustion Turbines 

A. Applicability 

B. Subcategories 

C. Identification of the Best System of 

Emission Reduction 

D. Achievability of the Final Standards 

X. Summary of Other Final Requirements for 

Newly Constructed, Modified, and 

Reconstructed Fossil Fuel-Fired Electric 

Utility Steam Generating Units and 

Stationary Combustion Turbines 

A. Startup, Shutdown, and Malfunction 

Requirements 

B. Continuous Monitoring Requirements 

C. Emissions Performance Testing 

Requirements 

D. Continuous Compliance Requirements 

E. Notification, Recordkeeping, and 

Reporting Requirements 

XI. Consistency Between BSER 

Determinations for This Rule and the 

Rule for Existing EGUs 

A. Newly Constructed Steam Generating 

Units 

B. New Combustion Turbines 

C. Modified and Reconstructed Steam and 

NGCC Units 

XII. Interactions With Other EPA Programs 

and Rules 

A. Overview 

B. Applicability of Tailoring Rule 

Thresholds Under the PSD Program 

C. Implications for BACT Determinations 

Under PSD 

D. Implications for Title V Program 

E. Implications for Title V Fee 

Requirements for GHGs 

F. Interactions With Other EPA Rules 

XIII. Impacts of This Action 

A. What are the air impacts? 

B. Endangered Species Act 

C. What are the energy impacts? 

D. What are the water and solid waste 

impacts? 

E. What are the compliance costs? 

F. What are the economic and employment 

impacts? 

G. What are the benefits of the final 

standards? 

XIV. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act (PRA) 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

(UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act (NTTAA) and 1 CFR 

Part 51 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act (CRA) 

XV. Withdrawal of Proposed Standards for 

Certain Modified Sources 

XVI. Statutory Authority 

I. General Information 

A. Executive Summary 

1. Purpose of the Regulatory Action 

In this final action the EPA is 

establishing standards that limit 

greenhouse gas (GHG) emissions from 

newly constructed, modified, and 

reconstructed fossil fuel-fired electric 

utility steam generating units and 

stationary combustion turbines, 

following the issuance of proposals for 

such standards and an accompanying 

Notice of Data Availability. 

On June 25, 2013, in conjunction with 

the announcement of his Climate Action 

Plan (CAP), President Obama issued a 

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64512 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

1The 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). 

2See CAA section 111(a)(2). 

Presidential Memorandum directing the 

EPA to issue a proposal to address 

carbon pollution from new power plants 

by September 30, 2013, and to issue 

‘‘standards, regulations, or guidelines, 

as appropriate, which address carbon 

pollution from modified, reconstructed, 

and existing power plants.’’ Pursuant to 

authority in section 111(b) of the CAA, 

on September 20, 2013, the EPA issued 

proposed carbon pollution standards for 

newly constructed fossil fuel-fired 

power plants. The proposal was 

published in the Federal Register on 

January 8, 2014 (79 FR 1430; ‘‘January 

2014 proposal’’).1 In that proposal, the 

EPA proposed to limit emissions of CO2

from newly constructed fossil fuel-fired 

electric utility steam generating units 

and newly constructed natural gas-fired 

stationary combustion turbines. 

The EPA subsequently issued a Notice 

of Data Availability (NODA) in which 

the EPA solicited comment on its initial 

interpretation of provisions in the 

Energy Policy Act of 2005 (EPAct05) 

and associated provisions in the Internal 

Revenue Code (IRC) and also solicited 

comment on a companion Technical 

Support Document (TSD) that addressed 

these provisions’ relationship to the 

factual record supporting the proposed 

rule. 79 FR 10750 (February 26, 2014). 

On June 2, 2014, the EPA proposed 

standards of performance, also pursuant 

to CAA section 111(b), to limit 

emissions of CO2 from modified and 

reconstructed fossil fuel-fired electric 

utility steam generating units and 

natural gas-fired stationary combustion 

turbines. 79 FR 34960 (June 18, 2014) 

(‘‘June 2014 proposal’’). Specifically, the 

EPA proposed standards of performance 

for: (1) Modified fossil fuel-fired steam 

generating units, (2) modified natural 

gas-fired stationary combustion 

turbines, (3) reconstructed fossil fuelfired steam generating units, and (4) 

reconstructed natural gas-fired 

stationary combustion turbines. 

In this action, the EPA is issuing final 

standards of performance to limit 

emissions of GHG pollution manifested 

as CO2 from newly constructed, 

modified, and reconstructed fossil fuelfired electric utility steam generating 

units (i.e., utility boilers and integrated 

gasification combined cycle (IGCC) 

units) and from newly constructed and 

reconstructed stationary combustion 

turbines. Consistent with the 

requirements of CAA section 111(b), 

these standards reflect the degree of 

emission limitation achievable through 

the application of the best system of 

emission reduction (BSER) that the EPA 

has determined has been adequately 

demonstrated for each type of unit. 

These final standards are codified in 40 

CFR part 60, subpart TTTT, a new 

subpart specifically created for CAA 

111(b) standards of performance for 

GHG emissions from fossil fuel-fired 

EGUs. 

In a separate action that affects the 

same source category, the EPA is issuing 

final emission guidelines under CAA 

section 111(d) for states to use in 

developing plans to limit CO2 emissions 

from existing fossil fuel-fired EGUs. 

Pursuant to those guidelines, states 

must submit plans to the EPA following 

a schedule set by the guidelines. 

The EPA received numerous 

comments and conducted extensive 

outreach to stakeholders for this 

rulemaking. After careful consideration 

of public comments and input from a 

variety of stakeholders, the final 

standards of performance in this action 

reflect certain changes from the 

proposals. Comments considered 

include written comments that were 

submitted during the public comment 

period and oral testimony provided 

during the public hearing for the 

proposed standards. 

2. Summary of Major Provisions and 

Changes to the Proposed Standards 

The BSER determinations and final 

standards of performance for affected 

newly constructed, modified, and 

reconstructed EGUs are summarized in 

Table 1 and discussed in more detail 

below. The final standards for new, 

modified, and reconstructed EGUs 

apply to sources that commenced 

construction—or modification or 

reconstruction, as appropriate—on or 

after the date of publication of 

corresponding proposed standards.2 The 

final standards for newly constructed 

fossil fuel-fired EGUs apply to those 

sources that commenced construction 

on or after the date of publication of the 

proposed standards, January 8, 2014. 

The final standards for modified and 

reconstructed fossil fuel-fired EGUs 

apply to those sources that modify or 

reconstruct on or after the date of 

publication of the proposed standards, 

June 18, 2014. 

TABLE 1—SUMMARY OF BSER AND FINAL STANDARDS FOR AFFECTED EGUS

Affected EGUs BSER Final standards of performance 

Newly Constructed Fossil Fuel-Fired 

Steam Generating Units.

Efficient new supercritical pulverized 

coal (SCPC) utility boiler implementing partial carbon capture and 

storage (CCS).

1,400 lb CO2/MWh-g. 

Modified Fossil Fuel-Fired Steam Generating Units.Most efficient generation at the affected 

EGU achievable through a combination of best operating practices and 

equipment upgrades.

Sources making modifications resulting in an increase in 

CO2 hourly emissions of more than 10 percent are required to meet a unit-specific emission limit determined 

by the unit’s best historical annual CO2 emission rate 

(from 2002 to the date of the modification); the emission 

limit will be no more stringent than: 

1. 1,800 lb CO2/MWh-g for sources with heat input >2,000 

MMBtu/h. 

2. 2,000 lb CO2/MWh-g for sources with heat input ≤2,000 

MMBtu/h. 

Reconstructed Fossil Fuel-Fired Steam 

Generating Units.

Most efficient generating technology at 

the affected source (supercritical 

steam conditions for the larger; and 

subcritical conditions for the smaller).

1. Sources with heat input >2,000 MMBtu/h are required to 

meet an emission limit of 1,800 lb CO2/MWh-g. 

2. Sources with heat input ≤2,000 MMBtu/h are required to 

meet an emission limit of 2,000 lb CO2/MWh-g. 

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3The term ‘‘multi-fuel-fired’’ refers to a stationary 

combustion turbine that is physically connected to 

a natural gas pipeline, but that burns a fuel other 

than natural gas for 10 percent or more of the unit’s 

heat input capacity during the 12-operating-month 

compliance period. 

4The emission standard for combustion turbines 

co-firing natural gas with other fuels shall be 

determined at the end of each operating month 

based on the amount of co-fired natural gas. Units 

only burning natural gas with other fuels with a 

relatively consistent chemical composition and an 

emission factor of 160 lb CO2/MMBtu or less (e.g., 

natural gas, distillate oil, etc.) only need to maintain 

records of the fuels burned at the unit to 

demonstrate compliance. Units burning fuels with 

variable chemical composition or with an emission 

factor greater than 160 lb CO2/MMBtu (e.g., residual 

oil) must conduct periodic fuel sampling and 

testing to determine the overall CO2 emission rate. 

5Also 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. 

6Using the most recent data on partial capture 

rates to meet an emission standard of 1,100 lb CO2/ 

MWh-gross, about 35 percent capture would be 

required at an SCPC unit and about 22 percent 

capture would be required at an IGCC unit. 

7For a summary of lignite drying technologies, 

see ‘‘Techno-economics of modern pre-drying 

technologies for lignite-fired power plants’’ 

available at www.iea-coal.org.uk/documents/83436/ 

9095/Techno-economics-of-modern-pre-dryingtechnologies-for-lignite-fired-power-plants,-CCC/ 

241; ‘‘Drying the lignite prior to combustion in the 

boiler is thus an effective way to increase the 

thermal efficiencies and reduce the CO2 emissions 

from lignite-fired power plants.’’ 

TABLE 1—SUMMARY OF BSER AND FINAL STANDARDS FOR AFFECTED EGUS—Continued 

Affected EGUs BSER Final standards of performance 

Newly Constructed and Reconstructed 

Fossil Fuel-Fired Stationary Combustion Turbines.

Efficient NGCC technology for base 

load natural gas-fired units and clean 

fuels for non-base load and multifuel-fired units.3

1. 1,000 lb CO2/MWh-g or 1,030 lb CO2/MWh-n for base 

load natural gas-fired units. 

2. 120 lb CO2/MMBtu for non-base load natural gas-fired 

units. 

3. 120 to 160 lb CO2/MMBtu for multi-fuel-fired units.4

a. Fossil Fuel-Fired Electric Utility 

Steam Generating Units 

This action establishes standards of 

performance for newly constructed 

fossil fuel-fired steam generating units 5

based on the performance of a new 

highly efficient SCPC EGU 

implementing post-combustion partial 

carbon capture and storage (CCS) 

technology, which the EPA determines 

to be the BSER for these sources. After 

consideration of a wide range of 

comments, technical input received on 

the availability, technical feasibility, 

and cost of CCS implementation, and 

publicly available information about 

projects that are implementing or 

planning to implement CCS, the EPA 

confirms its proposed determination 

that CCS technology is available and 

technically feasible to implement at 

fossil fuel-fired steam generating units. 

However, the EPA’s final standard 

reflects the consideration of legitimate 

concerns regarding the cost to 

implement available CCS technology on 

a new steam generating unit. 

Accordingly, the EPA is finalizing an 

emission standard for newly 

constructed fossil fuel-fired steam 

generating units at 1,400 lb CO2/MWhg, a level that is less stringent than the 

proposed limitation of 1,100 lb CO2/ 

MWh-g. This final standard reflects our 

identification of the BSER for such units 

to be a lower level of partial CCS than 

we identified as the basis of the 

proposed standards—one that we 

conclude better represents the 

requirement that the BSER be 

implementable at reasonable cost. 

The EPA proposed that the BSER for 

newly constructed steam generating 

EGUs was highly efficient new 

generating technology (i.e., a 

supercritical utility boiler or IGCC unit) 

implementing partial CCS technology to 

achieve CO2 emission reductions 

resulting in an emission limit of 1,100 

lb CO2/MWh-g.6

The BSER for newly constructed 

steam generating EGUs in the final rule 

is very similar to that in the January 

2014 proposal. In this final action, the 

EPA finds that a highly efficient new 

supercritical pulverized coal (SCPC) 

utility boiler EGU implementing partial 

CCS to the degree necessary to achieve 

an emission of 1,400 lb CO2/MWh-g is 

the BSER. Contrary to the January 2014 

proposal, the EPA finds that IGCC 

technology—either with natural gas cofiring or implementing partial CCS—is 

not part of the BSER, but recognizes that 

IGCC technology can serve as an 

alternative method of compliance. 

The EPA finds that a highly efficient 

SCPC implementing partial CCS is the 

BSER because CCS technology has been 

demonstrated to be technically feasible 

and is in use or under construction in 

various industrial sectors, including the 

power generation sector. For example, 

the Boundary Dam Unit #3 CCS project 

in Saskatchewan, Canada is a full-scale, 

fully integrated CCS project that is 

currently operating and is designed to 

capture more than 90 percent of the CO2

from the lignite-fired boiler. A newly 

constructed, highly efficient SCPC 

utility boiler burning bituminous coal 

will be able to meet this final standard 

of performance by capturing and storing 

approximately 16 percent of the CO2

produced from the facility. A newly 

constructed, highly efficient SCPC 

utility boiler burning subbituminous 

coal or dried lignite 7 will be able to 

meet this final standard of performance 

by capturing and storing approximately 

23 percent of the CO2 produced from the 

facility. As an alternative compliance 

option, utilities and project developers 

will also be able to construct new steam 

generating units (both utility boilers and 

IGCC units) that meet the final standard 

of performance by co-firing with natural 

gas. This final standard of performance 

for newly constructed fossil fuel-fired 

steam generating units provides a clear 

and achievable path forward for the 

construction of such sources while 

addressing GHG emissions and 

supporting technological innovation. 

The standard of 1,400 lb CO2/MWh-g is 

achievable by fossil fuel-fired steam 

generating units for all fuel types, under 

a wide range of conditions, and 

throughout the United States. 

We note that identifying a highly 

efficient new SCPC EGU implementing 

partial CCS as the BSER provides a path 

forward for new fossil fuel-fired steam 

generation in the current market 

context. Numerous studies have 

predicted that few new fossil fuel-fired 

steam generating units will be 

constructed in the future. These 

analyses identify a range of factors 

unrelated to this rulemaking, including 

low electricity demand growth, highly 

competitive natural gas prices, and 

increases in the supply of renewable 

energy. The EPA recognizes that, in 

certain circumstances, there may be 

interest in building fossil fuel-fired 

steam generating units despite these 

market conditions. In particular, 

utilities and project developers may 

build new fossil fuel-fired steam 

generating EGUs in order to achieve or 

maintain fuel diversity within 

generating fleets, as a hedge against the 

possibility of natural gas prices far 

exceeding projections, or to co-produce 

both power and chemicals, including 

capturing CO2 for use in enhanced oil 

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8As the EIA has stated: Policy-related factors, 

such as environmental regulations and investment 

or production tax credits for specified generation 

sources, can also impact investment decisions. 

Finally, although levelized cost calculations are 

generally made using an assumed set of capital and 

operating costs, the inherent uncertainty about 

future fuel prices and future policies may cause 

plant owners or investors who finance plants to 

place a value on portfolio diversification. While EIA 

considers many of these factors in its analysis of 

technology choice in the electricity sector, these 

concepts are not included in LCOE or LACE 

calculations. http://www.eia.gov/forecasts/aeo/

electricity_generation.cfm. 

9 40 CFR 60.14(h) provides that no physical 

change, or change in the method of operation, at an 

existing electric utility steam generating unit will be 

treated as a modification provided that such change 

does not increase the maximum hourly emissions 

above the maximum hourly emissions achievable at 

that unit during the 5 years prior to the change. 

10For the 2002 reporting year the EPA introduced 

new automated checks in the software that 

integrated automated quality assurance (QA) checks 

on the hourly data. Thus, the EPA believes that the 

data from 2002 and forward are of higher quality. 

11Steam with higher temperature and pressure 

has more thermal energy that can be more 

efficiently converted to electrical energy. 

12We refer to thresholds related to an EGU’s 

actual annual electrical sales (as a fraction of 

potential annual output) as ‘‘percentage electric 

sales criteria.’’ 

13We refer to thresholds related to an EGU’s 

actual annual electrical sales in megawatt-hours as 

‘‘total electric sales criteria.’’ 

recovery (EOR) projects.8 As regulatory 

history has shown, identifying a new 

highly efficient SCPC EGU 

implementing partial CCS as the BSER 

in this rule is likely to further boost 

research and development in CCS 

technologies, making the 

implementation even more efficacious 

and cost-effective, while providing a 

competitive, low emission future for 

fossil fuel-fired steam generation. 

The EPA is also issuing final 

standards for steam generating units that 

implement ‘‘large modifications,’’ (i.e., 

modifications resulting in an increase in 

hourly CO2 emissions of more than 10 

percent when compared to the source’s 

highest hourly emissions in the 

previous 5 years).9 The EPA is not 

issuing final standards, at this time, for 

steam generating units that implement 

‘‘small modifications’’ (i.e., 

modifications resulting in an increase in 

hourly CO2 emissions of less than or 

equal to 10 percent when compared to 

the source’s highest hourly emissions in 

the previous 5 years). 

The standards of performance for 

modified steam generating units that 

make large modifications are based on 

each affected unit’s own best potential 

performance as the BSER. Specifically, 

such a modified steam generating unit 

will be required to meet a unit-specific 

CO2 emission limit determined by that 

unit’s best demonstrated historical 

performance (in the years from 2002 to 

the time of the modification).10 The EPA 

has determined that this standard based 

on each unit’s own best potential 

performance can be met through a 

combination of best operating practices 

and equipment upgrades and that these 

steps can be implemented costeffectively at the time when a source is 

undertaking a large modification. To 

account for facilities that have already 

implemented best practices and 

equipment upgrades, the final rule also 

specifies that modified facilities will not 

have to meet an emission standard more 

stringent than the corresponding 

standard for reconstructed steam 

generating units (i.e., 1,800 lb CO2/ 

MWh-g for units with heat input greater 

than 2,000 MMBtu/h and 2,000 lb CO2/ 

MWh-g for units with heat input less 

than or equal to 2,000 MMBtu/h). 

The final standards for steam 

generating units implementing large 

modifications are similar to the 

proposed standards for such units. In 

the proposal, we suggested that the 

standard should be based on when the 

modification is undertaken (i.e., before 

being subject to requirements under a 

CAA section 111(d) state plan or after 

being subject to such a plan). We also 

suggested that for units that undertake 

modifications prior to becoming subject 

to an approved CAA section 111(d) state 

plan, the standard should be its best 

historical performance plus an 

additional two percent reduction. In 

response to comments on the proposal, 

we are not finalizing separate standards 

that are dependent upon when the 

modification takes place, nor are we 

finalizing the proposed additional two 

percentage reduction. 

The EPA is not promulgating final 

standards of performance for, and is 

withdrawing the proposed standards for 

steam generating sources that make 

modifications resulting in an increase of 

hourly CO2 emissions of less than or 

equal to 10 percent (see Section XV of 

this preamble). As we indicated in the 

proposal, the EPA has been notified of 

very few modifications for criteria 

pollutant emissions from the power 

sector to which NSPS requirements 

have applied. As such, we expect that 

there will be few NSPS modifications 

for GHG emissions as well. Even so, we 

also recognize (and we discuss in this 

preamble) that the power sector is 

undergoing significant change and 

realignment in response to a variety of 

influences and incentives in the 

industry. We do not have sufficient 

information at this time, however, to 

anticipate the types of modifications, if 

any, that may result from these changes. 

In particular, we do not have sufficient 

information about the types of 

modifications, if any, that would result 

in increases in CO2 emissions of 10 

percent or less, and what the 

appropriate standard for such sources 

would be. Therefore, we conclude that 

it is prudent to delay issuing standards 

for sources that undertake small 

modifications (i.e., those resulting in an 

increase in CO2 emissions of less than 

or equal to 10 percent). 

For reconstructed steam generating 

units, the EPA is finalizing standards 

based on the performance of the most 

efficient generating technology for these 

types of units as the BSER (i.e., 

reconstructing the boiler if necessary to 

use steam with higher temperature and 

pressure, even if the boiler was not 

originally designed to do so).11 The 

emission standard for these sources is 

1,800 lb CO2/MWh-g for large sources, 

(i.e. those with a heat input rating of 

greater than 2,000 MMBtu/h) or 2,000 lb 

CO2/MWh-g for small sources (i.e., those 

with a heat input rating of 2,000 

MMBtu/h or less). The difference in the 

standards for larger and smaller units is 

based on greater availability of higher 

pressure/temperature steam turbines 

(e.g., supercritical steam turbines) for 

larger units. The standards can also be 

met through other non-BSER options, 

such as natural gas co-firing. 

b. Stationary Combustion Turbines 

This action also finalizes standards of 

performance for newly constructed and 

reconstructed stationary combustion 

turbines. In the January 2014 proposal 

for newly constructed EGUs, the EPA 

proposed that natural gas-fired 

stationary combustion turbines (i.e., 

turbines combusting over 90 percent 

natural gas) would be subject to a 

standard of performance for CO2

emissions if they are constructed for the 

purpose of supplying and actually 

annually supply to the grid (1) one-third 

or more of their potential electric 

output 12 and (2) more than 219,000 

MWh,13 based on a three-year rolling 

average. We refer to units that operate 

above the electric sales thresholds as 

‘‘base load units,’’ and we refer to units 

that operate below these thresholds as 

‘‘non-base load units.’’ 

In the January 2014 proposal for 

newly constructed combustion turbines, 

the EPA proposed standards for two 

subcategories of base load natural gasfired stationary combustion turbines. 

The proposed standard for small 

combustion turbines (units with base 

load ratings less than or equal to 850 

MMBtu/h) was 1,100 lb CO2/MWh-g. 

The proposed standard for large 

combustion turbines (units with base 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64515 

14The sliding-scale approach determines a unitspecific percentage electric sales threshold 

equivalent to a unit’s net design efficiency (the 

maximum value is capped at 50 percent). 

15Combustion turbines co-firing natural gas with 

other fuels shall determine fuel-based site-specific 

standards at the end of each operating month. The 

site-specific standards depend on the amount of cofired natural gas. 

16The EPA’s Integrated Planning Model (IPM) 

projects no new non-compliant coal (i.e., newly 

constructed coal-fired plants that do not meet the 

final standard of performance) throughout the 

model horizon of 2030 (there is a small amount of 

new coal with CCS that is hardwired into the 

modelling, consistent with EIA assumptions to 

represent units already under construction or under 

development). 

17Conditions in the analysis year of 2022 are 

represented by a model year of 2020. 

load ratings greater than 850 MMBtu/h) 

was 1,000 lb CO2/MWh-g. The EPA did 

not propose standards for non-base load 

units. 

In the June 2014 proposal for 

modified and reconstructed combustion 

turbines, the EPA solicited comment on 

alternative approaches for establishing 

applicability and subcategorization 

criteria, including (1) eliminating the 

‘‘constructed for the purpose of 

supplying’’ qualifier for the total electric 

sales and percentage electric sales 

criteria, (2) eliminating the 219,000 

MWh total electric sales criterion 

altogether, (3) replacing the fixed 

percentage electric sales criterion with a 

variable percentage electric sales 

criterion (i.e., the sliding-scale 

approach 14), and (4) eliminating the 

proposed small and large subcategories 

for base load natural gas-fired 

combustion turbines. These proposed 

applicability requirements were 

intended to exclude combustion 

turbines that are used for the purpose of 

meeting peak power demand, as 

opposed to those that are used to meet 

base load power demand. 

In both proposals, the EPA also 

solicited comment on a broad 

applicability approach that would 

include non-base load natural gas-fired 

units (primarily simple cycle 

combustion turbines) and multi-fuelfired units (primarily distillate oil-fired 

combustion turbines) in the general 

applicability of subpart TTTT. As part 

of the broad applicability approach, the 

EPA solicited comment on imposing 

‘‘no emission standard’’ or establishing 

separate numerical limits for these two 

subcategories. 

In this action, the EPA is finalizing a 

variation of the approaches put forward 

in the January 2014 proposal for new 

sources and the June 2014 proposal for 

modified and reconstructed sources. 

Based on our review of public 

comments related to the proposed 

subcategories for small and large 

combustion turbines and our additional 

data analyses, we have determined that 

there is no need to set two separate 

standards for different sizes of 

combustion turbines for base load 

natural gas-fired combustion turbines. 

The EPA has determined that all sizes 

of affected newly constructed and 

reconstructed stationary combustion 

turbines can achieve the final standards. 

For newly constructed and 

reconstructed base load natural gas-fired 

stationary combustion turbines, the EPA 

is finalizing a standard of 1,000 lb CO2/ 

MWh-g based on efficient natural gas 

combined cycled (NGCC) technology as 

the BSER. Alternatively, owners and 

operators of base load natural gas-fired 

combustion turbines may elect to 

comply with a standard based on net 

output of 1,030 lb CO2/MWh-n. 

The EPA is eliminating the 219,000 

MWh total annual electric sales 

criterion for non-CHP units. In addition, 

the EPA is finalizing the sliding-scale 

approach for deriving the unit-specific, 

percentage electric sales threshold 

above which a combustion turbine 

transitions from the subcategory for 

non-base load units to the subcategory 

for base load units. For newly 

constructed and reconstructed non-base 

load natural gas-fired stationary 

combustion turbines, the EPA is 

finalizing the combustion of clean fuels 

(natural gas with a small allowance for 

distillate oil) as the BSER with a 

corresponding heat input-based 

standard of 120 lb CO2/MMBtu. This 

standard of performance will apply to 

the vast majority of simple cycle 

combustion turbines. The EPA is 

finalizing a heat input-based clean fuels 

standard because we have insufficient 

information at this time to set a uniform 

output-based standard that can be 

achieved by all new and reconstructed 

non-base load units. 

In addition, for newly constructed 

and reconstructed multi-fuel-fired 

stationary combustion turbines, the EPA 

is finalizing an input-based standard of 

120 to 160 lb CO2/MMBtu based on the 

combustion of clean fuels as the BSER.15

The EPA has similarly determined that 

it has insufficient information at this 

time to set a uniform output-based 

standard for stationary combustion 

turbines that operate with significant 

quantities of a fuel other than natural 

gas. 

We are not promulgating final 

standards of performance for stationary 

combustion turbines that make 

modifications at this time. We are 

simultaneously withdrawing the 

proposed standards for modifications 

(see Section XV of this preamble). As we 

indicated in the proposal, sources from 

the power sector have notified the EPA 

of very few NSPS modifications, and we 

expect that there will be few NSPS 

modifications for CO2 emissions as well. 

Moreover, our decision to eliminate the 

subcategories for small and large EGUs 

and set a single standard of 1,000 lb 

CO2/MWh-g has raised questions as to 

whether smaller existing combustion 

turbines that undertake a modification 

can meet this standard. As a result, we 

have concluded that it is prudent to 

delay issuing standards for sources that 

undertake modifications until we can 

gather more information. 

A more detailed discussion of the 

final standards of performance for 

stationary combustion turbines, the 

applicability criteria, and the comments 

that influenced the final standards is 

provided in Sections VIII and IX of this 

preamble. 

3. Costs and Benefits 

As explained in the regulatory impact 

analysis (RIA) for this final rule, 

available data—including utility 

announcements and Energy Information 

Administration (EIA) modeling— 

indicate that, even in the absence of this 

rule, (i) existing and anticipated 

economic conditions are such that few, 

if any, fossil fuel-fired steam-generating 

EGUs will be built in the foreseeable 

future, and (ii) utilities and project 

developers are expected to choose new 

generation technologies (primarily 

NGCC) that would meet the final 

standards and renewable generating 

sources that are not affected by these 

final standards. These projections are 

consistent with utility announcements 

and EIA modeling that indicate that new 

units are likely to be NGCC and that any 

coal-fired steam generating units built 

between now and 2030 would have 

CCS, even in the absence of this rule.16

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.17 However, as noted earlier, for a 

variety of reasons, some companies may 

consider coal-fired steam generating 

units that the modeling does not 

anticipate. Thus, in Chapter 5 of the 

RIA, we also present an analysis of the 

project-level costs of a newly 

constructed coal-fired steam generating 

unit with partial CCS that meets the 

requirements of this final rule alongside 

the project-level costs of a newly 

constructed coal-fired unit without CCS. 

This analysis indicates that the 

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64516 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

quantified benefits of the standards of 

performance would exceed their costs 

under a range of assumptions. 

As explained in the RIA and further 

below, the EPA has been notified of few 

power sector NSPS modifications or 

reconstructions. Based on that 

experience, the EPA expects that few 

EGUs will trigger either the 

modification or the reconstruction 

provisions that we are finalizing in this 

action. In Chapter 6 of the RIA, we 

discuss factors that limit our ability to 

quantify the costs and benefits of the 

standards for modified and 

reconstructed sources. 

B. Does this action apply to me? 

The entities potentially affected by 

the standards are shown in Table 2 

below. 

TABLE 2—POTENTIALLY AFFECTED ENTITIES a

Category NAICS code Examples of potentially affected entities 

Industry .......................... 221112 Fossil fuel electric power generating units. 

Federal Government ...... b221112 Fossil fuel electric power generating units owned by the federal government. 

State/Local Government b221112 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). bFederal, 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, 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 

§ 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-pollutionstandards. 

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 

December 22, 2015. 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 the EPA to enforce these 

requirements. Section 307(d)(7)(B) of 

the CAA further provides that ‘‘[o]nly an 

objection to a rule or procedure which 

was raised with reasonable specificity 

during the period for public comment 

(including any public hearing) may be 

raised during judicial review.’’ This 

section also provides a mechanism 

mandating the EPA to convene a 

proceeding for reconsideration if the 

person raising an objection can 

demonstrate that it was impracticable to 

raise such objection within the period 

for public comment or if the grounds for 

such objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of the rule. Any person seeking 

to make such a demonstration should 

submit a Petition for Reconsideration to 

the Office of the Administrator, U.S. 

EPA, Room 3000, Ariel Rios Building, 

1200 Pennsylvania Ave. NW., 

Washington, DC 20460, with a copy to 

both the person(s) listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section, and the Associate 

General Counsel for the Air and 

Radiation Law Office, Office of General 

Counsel (Mail Code 2344A), U.S. EPA, 

1200 Pennsylvania Ave. NW., 

Washington, DC 20460. 

E. How is this preamble organized? 

This action presents the EPA’s final 

standards of performance for newly 

constructed, modified, and 

reconstructed fossil fuel-fired electric 

utility steam generating units and newly 

constructed and reconstructed 

stationary combustion turbines. Section 

II provides background information on 

climate change impacts from GHG 

emissions, GHG emissions from fossil 

fuel-fired EGUs, the utility power sector, 

the statutory and regulatory background 

relating to CAA section 111(b), EPA 

actions prior to this final action, and 

public comments regarding the 

proposed actions. Section III explains 

the EPA’s authority to regulate CO2 and 

EGUs, identifies affected EGUs, and 

describes the source categories. Section 

IV provides a summary of the final 

standards for newly constructed, 

modified, and reconstructed fossil 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 and reconstructed 

combustion turbines, respectively. 

Section X provides a summary of other 

final requirements for newly 

constructed, modified, and 

reconstructed fossil fuel-fired steam 

generating units and stationary 

combustion turbines. Section XI 

addresses the consistency of the 

respective BSER determinations in these 

rules and under the emission guidelines 

issued separately under CAA section 

111(d). Interactions with other EPA 

programs and rules are described in 

Section XII. Projected impacts of the 

final action are then described in 

Section XIII, followed by a discussion of 

statutory and executive order reviews in 

Section XIV. Section XV addresses the 

withdrawal of the proposed standards 

for steam generating EGUs that make 

modifications resulting in an increase of 

hourly CO2 emissions of less than or 

equal to 10 percent and the proposed 

standards for modified stationary 

combustion turbines. The statutory 

authority for this action is provided in 

Section XVI. We address major 

comments throughout this preamble and 

in greater detail in an accompanying 

response-to-comments document 

located in the docket. 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64517 

18National Research Council, Climate 

Stabilization Targets, p. 3. 

19 ‘‘Endangerment and Cause or Contribute 

Findings for Greenhouse Gases Under Section 

202(a) of the Clean Air Act,’’ 74 FR 66496 (Dec. 15, 

2009) (‘‘Endangerment Finding’’). 

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 fuelfired EGUs and describe the utility 

power sector and its changing structure. 

We then summarize the statutory and 

regulatory background relevant to this 

final rulemaking. In addition, we 

provide background information on the 

EPA’s January 8, 2014 proposed carbon 

pollution standards for newly 

constructed fossil fuel-fired EGUs, the 

June 18, 2014 proposed carbon 

pollution standards for modified and 

reconstructed EGUs, and other actions 

associated with this final rulemaking. 

We close this section with a general 

discussion of comments and stakeholder 

input that the EPA received prior to 

issuing this final rulemaking. 

A. Climate Change Impacts From GHG 

Emissions 

According to the National Research 

Council, ‘‘Emissions of CO2 from the 

burning of fossil fuels have ushered in 

a new epoch where human activities 

will largely determine the evolution of 

Earth’s climate. Because CO2 in the 

atmosphere is long lived, it can 

effectively lock Earth and future 

generations into a range of impacts, 

some of which could become very 

severe. Therefore, emission reduction 

choices made today matter in 

determining impacts experienced not 

just over the next few decades, but in 

the coming centuries and millennia.’’ 18

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).19 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 

Climate change caused by human 

emissions of GHGs threatens the health 

of Americans in multiple ways. By 

raising average temperatures, climate 

change increases the likelihood of heat 

waves, which are associated with 

increased deaths and illnesses. While 

climate change also increases the 

likelihood of reductions in cold-related 

mortality, evidence indicates that the 

increases in heat mortality will be larger 

than the decreases in cold mortality in 

the United States. Compared to a future 

without climate change, climate change 

is expected to increase ozone pollution 

over broad areas of the U.S., especially 

on the highest ozone days and in the 

largest metropolitan areas with the 

worst ozone problems, and thereby 

increase the risk of morbidity and 

mortality. Climate change is also 

expected to cause more intense 

hurricanes and more frequent and 

intense storms and heavy precipitation, 

with impacts on other areas of public 

health, such as the potential for 

increased deaths, injuries, infectious 

and waterborne diseases, and stressrelated disorders. Children, the elderly, 

and the poor are among the most 

vulnerable to these climate-related 

health effects. 

2. Public Welfare Impacts Detailed in 

the 2009 Endangerment Finding 

Climate change impacts touch nearly 

every aspect of public welfare. Among 

the multiple threats caused by human 

emissions of GHGs, climate changes are 

expected to place large areas of the 

country at serious risk of reduced water 

supplies, increased water pollution, and 

increased occurrence of extreme events 

such as floods and droughts. Coastal 

areas are expected to face a multitude of 

increased risks, particularly from rising 

sea level and increases in the severity of 

storms. These communities face storm 

and flood damage to property, or even 

loss of land due to inundation, erosion, 

wetland submergence and habitat loss. 

Impacts of climate change on public 

welfare also include threats to social 

and ecosystem services. Climate change 

is expected to result in an increase in 

peak electricity demand. Extreme 

weather from climate change threatens 

energy, transportation, and water 

resource infrastructure. Climate change 

may also exacerbate ongoing 

environmental pressures in certain 

settlements, particularly in Alaskan 

indigenous communities, and is very 

likely to fundamentally rearrange U.S. 

ecosystems over the 21st century. 

Though some benefits may balance 

adverse effects on agriculture and 

forestry in the next few decades, the 

body of evidence points towards 

increasing risks of net adverse impacts 

on U.S. food production, agriculture and 

forest productivity as temperature 

continues to rise. These impacts are 

global and may exacerbate problems 

outside the U.S. that raise humanitarian, 

trade, and national security issues for 

the U.S. 

3. New Scientific Assessments and 

Observations 

Since the administrative record 

concerning the Endangerment Finding 

closed following the EPA’s 2010 

Reconsideration Denial, the climate has 

continued to change, with new records 

being set for a number of climate 

indicators such as global average surface 

temperatures, Arctic sea ice retreat, CO2

concentrations, and sea level rise. 

Additionally, a number of major 

scientific assessments have been 

released that improve understanding of 

the climate system and strengthen the 

case that GHGs endanger public health 

and welfare both for current and future 

generations. These assessments, from 

the Intergovernmental Panel on Climate 

Change (IPCC), the U.S. Global Change 

Research Program (USGCRP), and the 

National Research Council (NRC), 

include: IPCC’s 2012 Special Report on 

Managing the Risks of Extreme Events 

and Disasters to Advance Climate 

Change Adaptation (SREX) and the 

2013–2014 Fifth Assessment Report 

(AR5), the USGCRP’s 2014 National 

Climate Assessment, Climate Change 

Impacts in the United States (NCA3), 

and the NRC’s 2010 Ocean 

Acidification: A National Strategy to 

Meet the Challenges of a Changing 

Ocean (Ocean Acidification), 2011 

Report on Climate Stabilization Targets: 

Emissions, Concentrations, and Impacts 

over Decades to Millennia (Climate 

Stabilization Targets), 2011 National 

Security Implications for U.S. Naval 

Forces (National Security Implications), 

2011 Understanding Earth’s Deep Past: 

Lessons for Our Climate Future 

(Understanding Earth’s Deep Past), 2012 

Sea Level Rise for the Coasts of 

California, Oregon, and Washington: 

Past, Present, and Future, 2012 Climate 

and Social Stress: Implications for 

Security Analysis (Climate and Social 

Stress), and 2013 Abrupt Impacts of 

Climate Change (Abrupt Impacts) 

assessments. 

The EPA has carefully reviewed these 

recent assessments in keeping with the 

same approach outlined in Section III.A 

of the 2009 Endangerment Finding, 

which was to rely primarily upon the 

major assessments by the USGCRP, the 

IPCC, and the NRC of the National 

Academies to provide the technical and 

scientific information to inform the 

Administrator’s judgment regarding the 

question of whether GHGs endanger 

public health and welfare. These 

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64518 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

20 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. 

21National Research Council, Understanding 

Earth’s Deep Past, p. 1. 

22 Id., p. 138. 

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-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 plantbased 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 to exposed locations 

along ocean, lake, or river 

shorelines.’’ 20 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 lowincome 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. 

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.21 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.’’ 22 Because of these 

unprecedented changes, several 

assessments state that we may be 

approaching critical, poorly understood 

thresholds. As stated in the assessment, 

‘‘As Earth continues to warm, it may be 

approaching a critical climate threshold 

beyond which rapid and potentially 

permanent—at least on a human 

timescale—changes not anticipated by 

climate models tuned to modern 

conditions may occur.’’ The NRC 

Abrupt Impacts report analyzed abrupt 

climate change in the physical climate 

system and abrupt impacts of ongoing 

changes that, when thresholds are 

crossed, can cause abrupt impacts for 

society and ecosystems. The report 

considered destabilization of the West 

Antarctic Ice Sheet (which could cause 

3–4 m of potential sea level rise) as an 

abrupt climate impact with unknown 

but probably low probability of 

occurring this century. The report 

categorized a decrease in ocean oxygen 

content (with attendant threats to 

aerobic marine life); increase in 

intensity, frequency, and duration of 

heat waves; and increase in frequency 

and intensity of extreme precipitation 

events (droughts, floods, hurricanes, 

and major storms) as climate impacts 

with moderate risk of an abrupt change 

within this century. The NRC Abrupt 

Impacts report also analyzed the threat 

of rapid state changes in ecosystems and 

species extinctions as examples of 

irreversible impacts that are expected to 

be exacerbated by climate change. 

Species at most risk include those 

whose migration potential is limited, 

whether because they live on 

mountaintops or fragmented habitats 

with barriers to movement, or because 

climatic conditions are changing more 

rapidly than the species can move or 

adapt. While the NRC determined that 

it is not presently possible to place exact 

probabilities on the added contribution 

of climate change to extinction, they did 

find that there was substantial risk that 

impacts from climate change could, 

within a few decades, drop the 

populations in many species below 

sustainable levels, thereby committing 

the species to extinction. Species within 

tropical and subtropical rainforests such 

as the Amazon and species living in 

coral reef ecosystems were identified by 

the NRC as being particularly vulnerable 

to extinction over the next 30 to 80 

years, as were species in high latitude 

and high elevation regions. Moreover, 

due to the time lags inherent in the 

Earth’s climate, the NRC Climate 

Stabilization Targets assessment notes 

that the full warming from any given 

concentration of CO2 reached will not 

be fully realized for several centuries, 

underscoring that emission activities 

today carry with them climate 

commitments far into the future. 

Future temperature changes will 

depend on what emission path the 

world follows. In its high emission 

scenario, the IPCC AR5 projects that 

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23NRC, 2011: National Security Implications of 

Climate Change for U.S. Naval Forces. The National 

Academies Press, p. 28. 

24Melillo, 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. 

25Melillo, 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. 

26 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. 

average global temperatures by the end 

of the century will likely be 2.6 degrees 

Celsius (°C) to 4.8 °C (4.7 to 8.6 degrees 

Fahrenheit (°F)) warmer than today. 

Temperatures on land and in northern 

latitudes will likely warm even faster 

than the global average. However, 

according to the NCA3, significant 

reductions in emissions would lead to 

noticeably less future warming beyond 

mid-century, and therefore less impact 

to public health and welfare. 

While rainfall may only see small 

globally and annually averaged changes, 

there are expected to be substantial 

shifts in where and when that 

precipitation falls. According to the 

NCA3, regions closer to the poles will 

see more precipitation, while the dry 

subtropics are expected to expand 

(colloquially, this has been summarized 

as wet areas getting wetter and dry 

regions getting drier). In particular, the 

NCA3 notes that the western U.S., and 

especially the Southwest, is expected to 

become drier. This projection is 

consistent with the recent observed 

drought trend in the West. At the time 

of publication of the NCA, even before 

the last 2 years of extreme drought in 

California, tree ring data was already 

indicating that the region might be 

experiencing its driest period in 800 

years. Similarly, the NCA3 projects that 

heavy downpours are expected to 

increase in many regions, with 

precipitation events in general 

becoming less frequent but more 

intense. This trend has already been 

observed in regions such as the 

Midwest, Northeast, and upper Great 

Plains. Meanwhile, the NRC Climate 

Stabilization Targets assessment found 

that the area burned by wildfire is 

expected to grow by 2 to 4 times for 1 

°C (1.8 °F) of warming. For 3 °C of 

warming, the assessment found that 9 

out of 10 summers would be warmer 

than all but the 5 percent of warmest 

summers today, leading to increased 

frequency, duration, and intensity of 

heat waves. Extrapolations by the NCA 

also indicate that Arctic sea ice in 

summer may essentially disappear by 

mid-century. Retreating snow and ice, 

and emissions of CO2 and methane 

released from thawing permafrost, will 

also amplify future warming. 

Since the 2009 Endangerment 

Finding, the USGCRP NCA3, and 

multiple NRC assessments have 

projected future rates of sea level rise 

that are 40 percent larger to more than 

twice as large as the previous estimates 

from the 2007 IPCC 4th Assessment 

Report due in part to improved 

understanding of the future rate of melt 

of the Antarctic and Greenland Ice 

sheets. The NRC Sea Level Rise 

assessment projects a global sea level 

rise of 0.5 to 1.4 meters (1.6 to 4.6 feet) 

by 2100, the NRC National Security 

Implications assessment suggests that 

‘‘the Department of the Navy should 

expect roughly 0.4 to 2 meters (1.3 to 6.6 

feet) global average sea-level rise by 

2100,’’ 23 and the NRC Climate 

Stabilization Targets assessment states 

that an increase of 3 °C will lead to a 

sea level rise of 0.5 to 1 meter (1.6 to 

3.3 feet) by 2100. These assessments 

continue to recognize that there is 

uncertainty inherent in accounting for 

ice sheet processes. Additionally, local 

sea level rise can differ from the global 

total depending on various factors. The 

east coast of the U.S. in particular is 

expected to see higher rates of sea level 

rise than the global average. For 

comparison, the NCA3 states that ‘‘five 

million Americans and hundreds of 

billions of dollars of property are 

located in areas that are less than four 

feet above the local high-tide level,’’ and 

the NCA3 finds that ‘‘[c]oastal 

infrastructure, including roads, rail 

lines, energy infrastructure, airports, 

port facilities, and military bases, are 

increasingly at risk from sea level rise 

and damaging storm surges.’’ 24 Also, 

because of the inertia of the oceans, sea 

level rise will continue for centuries 

after GHG concentrations have 

stabilized (though more slowly than it 

would have otherwise). Additionally, 

there is a threshold temperature above 

which the Greenland ice sheet will be 

committed to inevitable melting. 

According to the NCA, some recent 

research has suggested that even present 

day CO2 levels could be sufficient to 

exceed that threshold. 

In general, climate change impacts are 

expected to be unevenly distributed 

across different regions of the United 

States and have a greater impact on 

certain populations, such as indigenous 

peoples and the poor. The NCA3 finds 

that climate change impacts such as the 

rapid pace of temperature rise, coastal 

erosion and inundation related to sea 

level rise and storms, ice and snow 

melt, and permafrost thaw are affecting 

indigenous people in the U.S. 

Particularly in Alaska, critical 

infrastructure and traditional 

livelihoods are threatened by climate 

change and, ‘‘[i]n parts of Alaska, 

Louisiana, the Pacific Islands, and other 

coastal locations, climate change 

impacts (through erosion and 

inundation) are so severe that some 

communities are already relocating from 

historical homelands to which their 

traditions and cultural identities are 

tied.’’ 25 The IPCC AR5 notes, ‘‘Climaterelated 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.’’ 26

CO2 in particular has unique impacts 

on ocean ecosystems. The NRC Climate 

Stabilization Targets assessment found 

that coral bleaching will increase due 

both to warming and ocean 

acidification. Ocean surface waters have 

already become 30 percent more acidic 

over the past 250 years due to 

absorption of CO2 from the atmosphere. 

According to the NCA3, this 

acidification will reduce the ability of 

organisms such as corals, krill, oysters, 

clams, and crabs to survive, grow, and 

reproduce. The NRC Understanding 

Earth’s Deep Past assessment notes that 

four of the five major coral reef crises of 

the past 500 million years were caused 

by acidification and warming that 

followed GHG increases of similar 

magnitude to the emissions increases 

expected over the next hundred years. 

The NRC Abrupt Impacts assessment 

specifically highlighted similarities 

between the projections for future 

acidification and warming and the 

extinction at the end of the Permian 

which resulted in the loss of an 

estimated 90 percent of known species. 

Similarly, the NRC Ocean Acidification 

assessment finds that ‘‘[t]he chemistry 

of the ocean is changing at an 

unprecedented rate and magnitude due 

to anthropogenic CO2 emissions; the 

rate of change exceeds any known to 

have occurred for at least the past 

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27NRC, 2010: Ocean Acidification: A National 

Strategy to Meet the Challenges of a Changing 

Ocean. The National Academies Press, p. 5. 

28 Id. 

29 ftp://aftp.cmdl.noaa.gov/products/trends/co2/ 

co2_annmean_mlo.txt. 

30http://www.esrl.noaa.gov/gmd/ccgg/trends/. 

31Blunden, J., and D. S. Arndt, Eds., 2014: State 

of the Climate in 2013. Bull. Amer. Meteor. Soc., 

95 (7), S1–S238. 

32http://www.ncdc.noaa.gov/sotc/global/2014/13. 

33NRC, 2011: America’s Climate Choices, The 

National Academies Press. 

hundreds of thousands of years.’’ 27 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.’’ 28

Events outside the United States, as 

also pointed out in the 2009 

Endangerment Finding, will also have 

relevant consequences. The NRC 

Climate and Social Stress assessment 

concluded that it is prudent to expect 

that some climate events ‘‘will produce 

consequences that exceed the capacity 

of the affected societies or global 

systems to manage and that have global 

security implications serious enough to 

compel international response.’’ The 

NRC National Security Implications 

assessment recommends preparing for 

increased needs for humanitarian aid; 

responding to the effects of climate 

change in geopolitical hotspots, 

including possible mass migrations; and 

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 climaterelated changes that have been observed 

recently, and these changes are 

projected to accelerate in the future. The 

planet warmed about 0.85 °C (1.5 °F) 

from 1880 to 2012. It is extremely likely 

(>95 percent probability) that human 

influence was the dominant cause of the 

observed warming since the mid-20th 

century, and likely (>66 percent 

probability) that human influence has 

more than doubled the probability of 

occurrence of heat waves in some 

locations. In the Northern Hemisphere, 

the last 30 years were likely the warmest 

30-year period of the last 1400 years. 

U.S. average temperatures have 

similarly increased by 1.3 to 1.9 °F since 

1895, with most of that increase 

occurring since 1970. Global sea levels 

rose 0.19 m (7.5 inches) from 1901 to 

2010. Contributing to this rise was the 

warming of the oceans and melting of 

land ice. It is likely that 275 gigatons per 

year of ice have melted from land 

glaciers (not including ice sheets) since 

1993, and that the rate of loss of ice 

from the Greenland and Antarctic ice 

sheets has increased substantially in 

recent years, to 215 gigatons per year 

and 147 gigatons per year respectively, 

since 2002. For context, 360 gigatons of 

ice melt is sufficient to cause global sea 

levels to rise 1 mm. Annual mean Arctic 

sea ice has been declining at 3.5 to 4.1 

percent per decade, and Northern 

Hemisphere snow cover extent has 

decreased at about 1.6 percent per 

decade for March and 11.7 percent per 

decade for June. Permafrost 

temperatures have increased in most 

regions since the 1980s, by up to 3 °C 

(5.4 °F) in parts of Northern Alaska. 

Winter storm frequency and intensity 

have both increased in the Northern 

Hemisphere. The NCA3 states that the 

increases in the severity or frequency of 

some types of extreme weather and 

climate events in recent decades can 

affect energy production and delivery, 

causing supply disruptions, and 

compromise other essential 

infrastructure such as water and 

transportation systems. 

In addition to the changes 

documented in the assessment 

literature, there have been other climate 

milestones of note. In 2009, the year of 

the Endangerment Finding, the average 

concentration of CO2 as measured on 

top of Mauna Loa was 387 parts per 

million, far above preindustrial 

concentrations of about 280 parts per 

million.29 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 based on ice 

core records.30 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 1993.31 And 

2014 was the warmest year globally in 

the modern global surface temperature 

record, going back to 1880; this now 

means 19 of the 20 warmest years have 

occurred in the past 20 years, and 

except for 1998, the ten warmest years 

on record have occurred since 2002.32

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.’’ 33 For example: 

• The faster emissions are reduced, 

the lower the risks posed by climate 

change. Delays in reducing emissions 

could commit the planet to a wide range 

of adverse impacts, especially if the 

sensitivity of the climate to greenhouse 

gases is on the higher end of the 

estimated range. 

• Waiting for unacceptable impacts to 

occur before taking action is imprudent 

because the effects of greenhouse gas 

emissions do not fully manifest 

themselves for decades and, once 

manifest, many of these changes will 

persist for hundreds or even thousands 

of years. 

• In the committee’s judgment, the 

risks associated with doing business as 

usual are a much greater concern than 

the risks associated with engaging in 

strong response efforts. 

4. Observed and Projected U.S. Regional 

Changes 

The NCA3 assessed the climate 

impacts in eight regions of the United 

States, noting that changes in physical 

climate parameters such as 

temperatures, precipitation, and sea ice 

retreat were already having impacts on 

forests, water supplies, ecosystems, 

flooding, heat waves, and air quality. 

Moreover, the NCA3 found that future 

warming is projected to be much larger 

than recent observed variations in 

temperature, with precipitation likely to 

increase in the northern states, decrease 

in the southern states, and with the 

heaviest precipitation events projected 

to increase everywhere. 

In the Northeast, temperatures 

increased almost 2 °F from 1895 to 

2011, precipitation increased by about 5 

inches (10 percent), and sea level rise of 

about a foot has led to an increase in 

coastal flooding. The 70 percent 

increase in the amount of rainfall falling 

in the 1 percent of the most intense 

events is a larger increase in extreme 

precipitation than experienced in any 

other U.S. region. 

In the future, if emissions continue 

increasing, the Northeast is expected to 

experience 4.5 to 10 °F of warming by 

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the 2080s. This will lead to more heat 

waves, coastal and river flooding, and 

intense precipitation events. The 

southern portion of the region is 

projected to see 60 additional days per 

year above 90 °F by mid-century. Sea 

levels in the Northeast are expected to 

increase faster than the global average 

because of subsidence, and changing 

ocean currents may further increase the 

rate of sea level rise. Specific 

vulnerabilities highlighted by the NCA 

include large urban populations 

particularly vulnerable to climaterelated 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 tropicalstorm induced storm-surge. The NCA 

also highlighted infrastructure 

vulnerable to inundation in coastal 

metropolitan areas, potential 

agricultural impacts from increased rain 

in the spring delaying planting or 

damaging crops or increased heat in the 

summer leading to decreased yields and 

increased water demand, and shifts in 

ecosystems leading to declines in iconic 

species in some regions, such as cod 

and lobster south of Cape Cod. 

In the Southeast, average annual 

temperature during the last century 

cycled between warm and cool periods. 

A warm peak occurred during the 1930s 

and 1940s, followed by a cool period, 

and temperatures then increased again 

from 1970 to the present by an average 

of 2 °F. There have been increasing 

numbers of days above 95 °F and nights 

above 75 °F, and decreasing numbers of 

extremely cold days since 1970. Daily 

and five-day rainfall intensities have 

also increased, and summers have been 

either increasingly dry or extremely wet. 

Louisiana has already lost 1,880 square 

miles of land in the last 80 years due to 

sea level rise and other contributing 

factors. 

The Southeast is exceptionally 

vulnerable to sea level rise, extreme heat 

events, hurricanes, and decreased water 

availability. Major consequences of 

further warming include significant 

increases in the number of hot days (95 

°F or above) and decreases in freezing 

events, as well as exacerbated groundlevel ozone in urban areas. Although 

projected warming for some parts of the 

region by the year 2100 is generally 

smaller than for other regions of the 

United States, projected warming for 

interior states of the region is larger than 

coastal regions by 1 °F to 2 °F. 

Projections further suggest that there 

will be fewer tropical storms globally, 

but that they will be more intense, with 

more Category 4 and 5 storms. The NCA 

identified New Orleans, Miami, Tampa, 

Charleston, and Virginia Beach as being 

specific cities that are at risk due to sea 

level rise, with homes and infrastructure 

increasingly prone to flooding. 

Additional impacts of sea level rise are 

expected for coastal highways, 

wetlands, fresh water supplies, and 

energy infrastructure. 

In the Northwest, temperatures 

increased by about 1.3 °F between 1895 

and 2011. A small average increase in 

precipitation was observed over this 

time period. However, warming 

temperatures have caused increased 

rainfall relative to snowfall, which has 

altered water availability from 

snowpack across parts of the region. 

Snowpack in the Northwest is an 

important freshwater source for the 

region. More precipitation falling as rain 

instead of snow has reduced the 

snowpack, and warmer springs have 

corresponded to earlier snowpack 

melting and reduced streamflows during 

summer months. Drier conditions have 

increased the extent of wildfires in the 

region. 

Average annual temperatures are 

projected to increase by 3.3 °F to 9.7 °F 

by the end of the century (depending on 

future global GHG emissions), with the 

greatest warming expected during the 

summer. Continued increases in global 

GHG emissions are projected to result in 

up to a 30 percent decrease in summer 

precipitation. Earlier snowpack melt 

and lower summer stream flows are 

expected by the end of the century and 

will affect drinking water supplies, 

agriculture, ecosystems, and 

hydropower production. Warmer waters 

are expected to increase disease and 

mortality in important fish species, 

including Chinook and sockeye salmon. 

Ocean acidification also threatens 

species such as oysters, with the 

Northwest coastal waters already being 

some of the most acidified worldwide 

due to coastal upwelling and other local 

factors. Forest pests are expected to 

spread and wildfires to burn larger 

areas. Other high-elevation ecosystems 

are projected to be lost because they can 

no longer survive the climatic 

conditions. Low lying coastal areas, 

including the cities of Seattle and 

Olympia, will experience heightened 

risks of sea level rise, erosion, seawater 

inundation and damage to infrastructure 

and coastal ecosystems. 

In Alaska, temperatures have changed 

faster than anywhere else in the United 

States. Annual temperatures increased 

by about 3 °F in the past 60 years. 

Warming in the winter has been even 

greater, rising by an average of 6 °F. 

Arctic sea ice is thinning and shrinking 

in area, with the summer minimum ice 

extent now covering only half the area 

it did when satellite records began in 

1979. Glaciers in Alaska are melting at 

some of the fastest rates on Earth. 

Permafrost soils are also warming and 

beginning to thaw. Drier conditions 

have contributed to more large wildfires 

in the last 10 years than in any previous 

decade since the 1940s, when 

recordkeeping began. Climate change 

impacts are harming the health, safety, 

and livelihoods of Native Alaskan 

communities. 

By the end of this century, continued 

increases in GHG emissions are 

expected to increase temperatures by 10 

to 12 °F in the northernmost parts of 

Alaska, by 8 to 10 °F in the interior, and 

by 6 to 8 °F across the rest of the state. 

These increases will exacerbate ongoing 

arctic sea ice loss, glacial melt, 

permafrost thaw and increased wildfire, 

and threaten humans, ecosystems, and 

infrastructure. Precipitation is expected 

to increase to varying degrees across the 

state. However, warmer air temperatures 

and a longer growing season are 

expected to result in drier conditions. 

Native Alaskans are expected to 

experience declines in economically, 

nutritionally, and culturally important 

wildlife and plant species. Health 

threats will also increase, including loss 

of clean water, 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 

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64522 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

34 ‘‘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. 

35U.S. EPA Greenhouse Gas Reporting Program 

Dataset, see http://www.epa.gov/ghgreporting/

ghgdata/reportingdatasets.html. 

or 8 inches in this region, contributing 

to inundation of Highway 101 and back 

up 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. Sea level rise 

along the California coast will worsen 

coastal erosion, increase flooding risk 

for coastal highways, bridges, and lowlying airports, pose a threat to 

groundwater supplies in coastal cities 

such as Los Angeles, and increase 

vulnerability to floods for hundreds of 

thousands of residents in coastal areas. 

Climate change will also have impacts 

on the high-value specialty crops grown 

in the region as a drier climate will 

increase demands for irrigation, more 

frequent heat waves will reduce yields, 

and decreased winter chills may impair 

fruit and nut production for trees in 

California. Increased drought, higher 

temperatures, and bark beetle outbreaks 

are likely to contribute to continued 

increases in wildfires. The highly 

urbanized population of the Southwest 

is vulnerable to heat waves and water 

supply disruptions, which can be 

exacerbated in cases where high use of 

air conditioning triggers energy system 

failures. 

The rate of warming in the Midwest 

has markedly accelerated over the past 

few decades. Temperatures rose by more 

than 1.5 °F from 1900 to 2010, but 

between 1980 and 2010, the rate of 

warming was three times faster than 

from 1900 through 2010. Precipitation 

generally increased over the last 

century, with much of the increase 

driven by intensification of the heaviest 

rainfalls. Several types of extreme 

weather events in the Midwest (e.g., 

heat waves and flooding) have already 

increased in frequency and/or intensity 

due to climate change. 

In the future, if emissions continue 

increasing, the Midwest is expected to 

experience 5.6 to 8.5 °F of warming by 

the 2080s, leading to more heat waves. 

Though projections of changes in total 

precipitation vary across the regions, 

more precipitation is expected to fall in 

the form of heavy downpours across the 

entire region, leading to an increase in 

flooding. Specific vulnerabilities 

highlighted by the NCA include longterm decreases in agricultural 

productivity, changes in the 

composition of the region’s forests, 

increased public health threats from 

heat waves and degraded air and water 

quality, negative impacts on 

transportation and other infrastructure 

associated with extreme rainfall events 

and flooding, and risks to the Great 

Lakes including shifts in invasive 

species, increases in harmful algal 

blooms, and declining beach health. 

High temperatures (more than 100 °F 

in the Southern Plains and more than 

95 °F in the Northern Plains) are 

projected to occur much more 

frequently by mid-century. Increases in 

extreme heat will increase heat stress for 

residents, energy demand for air 

conditioning, and water losses. North 

Dakota’s increase in annual 

temperatures over the past 130 years is 

the fastest in the contiguous U.S., 

mainly driven by warming winters. 

Specific vulnerabilities highlighted by 

the NCA include increased demand for 

water and energy, changes to cropgrowth 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 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 Rinco ́n 

is being eroded at a rate of 3.3 feet per 

year. Freshwater supplies are already 

constrained and will become more 

limited on many islands. Saltwater 

intrusion associated with sea level rise 

will reduce the quantity and quality of 

freshwater in coastal aquifers, especially 

on low islands. In areas where 

precipitation does not increase, 

freshwater supplies will be adversely 

affected as air temperature rises. 

Warmer oceans are leading to 

increased coral bleaching events and 

disease outbreaks in coral reefs, as well 

as changed distribution patterns of tuna 

fisheries. Ocean acidification will 

reduce coral growth and health. 

Warming and acidification, combined 

with existing stresses, will strongly 

affect coral-reef fish communities. For 

Hawaii and the Pacific islands, future 

sea surface temperatures are projected to 

increase 2.3 °F by 2055 and 4.7 °F by 

2090 under a scenario that assumes 

continued increases in emissions. Ocean 

acidification is also taking place in the 

region, which adds to ecosystem stress 

from increasing temperatures. Ocean 

acidity has increased by about 30 

percent since the pre-industrial era and 

is projected to further increase by 37 

percent to 50 percent from present 

levels by 2100. 

The NCA also discussed impacts that 

occur along the coasts and in the oceans 

adjacent to many regions, and noted that 

other impacts occur across regions and 

landscapes in ways that do not follow 

political boundaries. 

B. GHG Emissions From Fossil FuelFired EGUs 

Fossil fuel-fired EGUs are by far the 

largest emitters of GHGs among 

stationary sources in the U.S., primarily 

in the form of CO2. Among fossil 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 Sinks 34

(the U.S. GHG Inventory). 

The EPA implements a separate 

program under 40 CFR part 98 called 

the Greenhouse Gas Reporting 

Program 35 (GHGRP) that requires 

emitting facilities that emit over certain 

threshold amounts of GHGs to report 

their emissions to the EPA annually. 

Using data from the GHGRP, this section 

also places emissions from fossil fuelfired 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 on Climate 

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36Sinks are physical units or processes that store 

GHGs, such as forests or underground or deep sea 

reservoirs of CO2. 

37From 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/us

inventoryreport.html. 

38 1 metric ton (tonne) is equivalent to 1,000 

kilograms (kg) and is equivalent to 1.1023 short tons 

or 2,204.62 pounds (lb). 

39The energy sector includes all greenhouse gases 

resulting from stationary and mobile energy 

activities including fuel combustion and fugitive 

fuel emissions. 40From 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. 

41From 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/usinventory

report.html. 

42From 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/usinventory

report.html. 

43U.S. EPA Greenhouse Gas Reporting Program 

Dataset as of August 18, 2014. http://ghgdata.epa.

gov/ghgp/main.do. 

Change (UNFCCC). This inventory, 

which includes recent trends, is 

organized by industrial sector. It 

provides the information in Table 3 

below, which presents total U.S. 

anthropogenic emissions and sinks 36 of 

GHGs, including CO2 emissions, for the 

years 1990, 2005 and 2013. 

TABLE 3—U.S. GHG EMISSIONS AND SINKS BY SECTOR (MILLION METRIC TONS CARBON DIOXIDE EQUIVALENT (MMT 

CO2e))37 38

Sector 1990 2005 2013 

Energy39 .................................................................................................................... 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 

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.40 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.41 Table 4 below presents 

total CO2 emissions from fossil fuelfired EGUs, for years 1990, 2005, and 

2013. 

TABLE 4—U.S. GHG EMISSIONS FROM GENERATION OF ELECTRICITY FROM COMBUSTION OF FOSSIL FUELS (MMT 

CO2)42

GHG emissions 1990 2005 2013 

Total CO2 from fossil fuel-fired EGUs ....................................................................... 1,820.8 2,400.9 2,039.8 

—from coal ......................................................................................................... 1,547.6 1,983.8 1,575.0 

—from natural gas .............................................................................................. 175.3 318.8 441.9 

—from petroleum ................................................................................................ 97.5 97.9 22.4 

In addition to preparing the official 

U.S. GHG Inventory to present 

comprehensive total U.S. GHG 

emissions and comply with 

commitments under the UNFCCC, the 

EPA collects detailed GHG emissions 

data from the largest emitting facilities 

in the U.S. through its GHGRP. Data 

collected by the GHGRP from large 

stationary sources in the industrial 

sector show that the utility power sector 

emits far greater CO2 emissions than any 

other industrial sector. Table 5 below 

presents total GHG emissions in 2013 

for the largest emitting industrial sectors 

as reported to the GHGRP. As shown in 

Table 4 and Table 5, respectively, CO2

emissions from fossil fuel-fired EGUs 

are nearly three times as large as the 

total reported GHG emissions from the 

next ten largest emitting industrial 

sectors in the GHGRP database 

combined. 

TABLE 5—DIRECT GHG EMISSIONS REPORTED TO GHGRP BY LARGEST EMITTING INDUSTRIAL SECTORS (MMT CO2e)43

Industrial sector 2013 

Fossil Fuel-Fired EGUs ................................................................................................................................................................. 2,039.8 

Petroleum Refineries ..................................................................................................................................................................... 176.7 

Onshore Oil & Gas Production ...................................................................................................................................................... 94.8 

Municipal Solid Waste Landfills ..................................................................................................................................................... 93.0 

Iron & Steel Production ................................................................................................................................................................. 84.2 

Cement Production ........................................................................................................................................................................ 62.8 

Natural Gas Processing Plants ..................................................................................................................................................... 59.0 

Petrochemical Production .............................................................................................................................................................. 52.7 

Hydrogen Production ..................................................................................................................................................................... 41.9 

Underground Coal Mines ............................................................................................................................................................... 39.8 

Food Processing Facilities ............................................................................................................................................................. 30.8 

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44These 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. 

45U.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. 

46U.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. 

47Based 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_03. 

48Bloomberg New Energy Finance and the 

Business Council for Sustainable Energy, 2015 

Factbook: Sustainable Energy in America, at 16 

(2015), available at http://www.bcse.org/images/

2015%20Sustainable%20Energy%20in%20

America%20Factbook.pdf. 

49Energy Information Administration, Electricity: 

Form EIA–860 detailed data (Feb. 17, 2015), 

available at http://www.eia.gov/electricity/data/

eia860/. 

50EIA, Annual Energy Outlook for 2015 with 

Projections to 2040, Final Release, available at 

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

The AEO numbers include projects that are under 

development and model-projected nuclear, coal, 

and NGCC projects. 

51Quadrennial Energy Review, http://energy.gov/ 

epsa/quadrennial-energy-review-qer. 

52We calculated the average age of coal steam 

units based on the NEEDS inventory, and included 

units with planned retirements in 2015–2016. See 

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

needs_v514.xlsx. 

53American Society for Civil Engineers, 2013 

Report Card for America’s Infrastructure (2013), 

available at http://www.infrastructurereportcard.

org/energy/. 

54American Society for Civil Engineers, 2013 

Report Card for America’s Infrastructure (2013), 

available at http://www.infrastructurereportcard.

org/energy/. 

55Business Council for Sustainable Energy 

Comments in Docket Id. No. EPA–HQ–OAR–2013– 

0602 at 2 (Nov. 19, 2014). 

56U.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=

epmt_1_1. 

57 Id. 

58The AEO 2015 Reference case projection is a 

business-as-usual trend estimate, given known 

technology and technological and demographic 

trends. EIA explores the impacts of alternative 

assumptions in other cases with different 

macroeconomic growth rates, world oil prices, and 

resource assumptions. U.S. Energy Information 

Administration (EIA), Annual Energy Outlook 2015 

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

at http://www.eia.gov/forecasts/aeo/pdf/

0383(2015).pdf. 

59Casazza, J. and Delea, F., Understanding 

Electric Power Systems, IEEE Press, at 220–221 (2d 

ed. 2010). 

60Cogeneration 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). 

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 2013.44

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 being provided by other types 

of generation, including nuclear and 

renewables such as wind, solar, and 

hydroelectric power. Coal has 

historically provided the largest 

percentage of fossil-fuel generation.45 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.46

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).47

From 2007 to 2014, use of lower- and 

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.48

Between 2000 and 2013, approximately 

90 percent of new power generation 

capacity built in the U.S. has come in 

the form of natural gas or renewable 

energy facilities.49 In 2015, the U.S. 

Energy Information Administration 

(EIA) projected the need for 28.4 GW of 

additional base load or intermediate 

load generation capacity through 2020, 

with approximately 0.7 GW of new coalfired capacity, 5.5 GW of new nuclear 

capacity, and 14.2 GW of new NGCC 

capacity already in development.50

The change in the resource mix has 

accelerated in recent years, but wind, 

solar, other renewables, and energyefficiency resources have been reliably 

participating in the electric sector for a 

number of years. This rapid 

development of non-fossil fuel resources 

is occurring as much of the existing 

power generation fleet in the U.S. is 

aging and in need of modernization and 

replacement.51 For example, the average 

age of U.S. coal steam units in 2015 is 

45 years.52 In its 2013 Report Card for 

America’s Infrastructure, the American 

Society for Civil Engineers noted that 

‘‘America relies on an aging electrical 

grid and pipeline distribution systems, 

some of which originated in the 

1880s.’’ 53 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.’’54 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-effectively55 with the lowest 

possible emissions and the greatest 

efficiency. 

Natural gas has a long history of 

meeting electricity demand in the U.S. 

with a rapidly growing role as domestic 

supplies of natural gas have 

dramatically increased. Natural gas net 

generation increased by approximately 

36 percent between 2004 and 2014.56 In 

2014, natural gas accounted for 

approximately 27 percent of net 

generation.57 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 2040.58

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).59 QFs were either 

cogeneration facilities 60 or small 

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61Casazza, J. and Delea, F., Understanding 

Electric Power Systems, IEEE Press, at 220–221 (2d 

ed. 2010). 

62U.S. Energy Information Administration (EIA), 

Annual Energy Outlook 2014 with Projections to 

2040, at LR–5 (2014). 

63U.S. Energy Information Administration (EIA), 

Annual Energy Outlook 2015 with Projections to 

2040, at E–12 (2015). 

64U.S. Energy Information Administration (EIA), 

Annual Energy Outlook 2015 with Projections to 

2040, at 24–25(2015). 

65Edison 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%20browser/ee_

commission_history_report_2–1–13.pdf. 

66Edison Electric Institute, Making a Business of 

Energy Efficiency: Sustainable Business Models for 

Utilities, at 1 (2007), available at http://www.eei.

org/whatwedo/PublicPolicyAdvocacy/State

Regulation/Documents/Making_Business_Energy_

Efficiency.pdf. 

67American 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. 

68American 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. 

69American 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/research

reports/e13k.pdf. 

70Levelized Cost and Levelized Avoided Cost of 

New Generation Resources in the Annual Energy 

Outlook 2015 http://www.eia.gov/forecasts/aeo/

electricity_generation.html. 

71http://www.eia.gov/forecasts/aeo/pdf/

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

pdf/0383(2012).pdf; http://prod-http-80-80049

8448.us-east-1.elb.amazonaws.com/w/images/6/6d/

0383%282011%29.pdf. 

generation resources that use 

renewables such as wind, solar, 

biomass, geothermal, or hydroelectric 

power as their primary fuels.61 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.62 In its AEO 2015 

Reference case, the EIA found that 

renewable energy will account for 38 

percent of the overall growth in 

electricity generation from 2013 to 

2040.63 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 2040.64

Price pressures caused by oil 

embargoes in the 1970s also brought the 

issues of conservation and energy 

efficiency to the forefront of U.S. energy 

policy.65 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.’’ 66

Energy efficiency has been utilized to 

meet energy demand to varying levels 

since that time. As of April 2014, 25 

states 67 have ‘‘enacted long-term (3+ 

years), binding energy savings targets, or 

energy efficiency resource standards 

(EERS).’’ 68 Funding for energy 

efficiency programs has grown rapidly 

in recent years, with budgets for electric 

efficiency programs totaling $5.9 billion 

in 2012.69

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 then used 

to produce power using a steam turbine 

(the steam cycle). Combining these 

generation cycles increases the overall 

efficiency of the system. Simple cycle 

combustion turbines use a single 

combustion turbine to produce 

electricity (i.e., there is no heat recovery 

or steam cycle). The power output from 

these simple cycle combustion turbines 

can be easily ramped up and down 

making them ideal for ‘‘peaking’’ 

operations. 

Coal-fired utility boilers are primarily 

either pulverized coal (PC) boilers or 

fluidized bed (FB) boilers. At a PC 

boiler, the coal is crushed (pulverized) 

into a powder in order to increase its 

surface area. The coal powder is then 

blown into a boiler and burned. In a 

coal-fired boiler using FB combustion, 

the coal is burned in a layer of heated 

particles suspended in flowing air. 

Power can also be generated using 

gasification technology. An IGCC unit 

gasifies coal or petroleum coke to form 

a synthetic gas (or syngas) composed of 

carbon monoxide (CO) and hydrogen 

(H2), which can be combusted in a 

combined cycle system to generate 

power. 

3. Technological Developments and 

Costs 

Natural gas prices have decreased 

dramatically and generally stabilized in 

recent years as new drilling techniques 

have brought additional supply to the 

marketplace and greatly increased the 

domestic resource base. As a result, 

natural gas prices are expected to be 

competitive for the foreseeable future, 

and EIA modeling and utility 

announcements confirm that utilities 

are likely to rely heavily on natural gas 

to meet new demand for electricity 

generation. On average, as discussed 

below, the cost of generation from a new 

natural-gas fired power plant (a NGCC 

unit) is expected to be significantly 

lower than the cost of generation from 

a new coal-fired power plant.70

Other drivers that may influence 

decisions to build new power plants are 

increases in renewable energy supplies, 

often due to state and federal energy 

policies. As previously discussed, many 

states have adopted RPS, which require 

a certain portion of electricity to come 

from renewable energy sources such as 

solar or wind. The federal government 

has also offered incentives to encourage 

further deployment of other forms of 

electric generation including renewable 

energy sources and new nuclear power 

plants. 

Reflecting these factors, the EIA 

projections from the last several years 

show that natural gas is likely to be the 

most widely-used fossil fuel for new 

construction of electric generating 

capacity through 2020, along with 

renewable energy, nuclear power, and a 

limited amount of coal with CCS.71

While EIA data shows that natural gas 

is likely to be the most widely-used 

fossil fuel for new construction of 

electric generating capacity through 

2030, a few coal-fired units still remain 

as viable projects at various advanced 

stages of construction and development. 

One new coal facility that has 

essentially completed construction, 

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72 ‘‘Odessa coal-to-gas power plant to break 

ground this year’’, Houston Chronicle (April 1, 

2015). 

73This projection is for business as usual and 

does not account for the proposed or final CO2

emission standard. Even in its sensitivity analysis 

that assumes higher natural gas prices and 

electricity demand, EIA does not project any 

additional coal-fired power plants beyond its 

reference case until 2023, in a case where power 

companies assume no GHGs emission limitations, 

and until 2024 in a case where power companies 

do assume GHGs emission limitations. 

74These sources received federal assistance under 

EPAct 2005. See Section III.H.3.g below. However, 

none of the constraints in that Act affect the 

discussion in the text above, since that discussion 

does not relate to technology use or emissions 

reduction by these sources. 

75http://www.eia.gov/forecasts/aeo/chapter_legs_

regs.cfm. 

76Energy Information Administration’s Annual 

Energy Outlook for 2015, Final Release available at 

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

77EIA’s reference case projections are the result 

of its baseline assumptions for economic growth, 

fuel supply, technology, and other key inputs. 

78Annual Energy Outlook 2010, 2011, 2012, 

2013, 2014 and 2015. 

79http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation. 

80Technical Support Document—‘‘Review of 

Electric Utility Integrated Resource Plans’’ (May 

2015), available in the rulemaking docket EPA–HQ– 

OAR–2013–0495. 

Southern Company’s Kemper County 

Energy Facility, deploys IGCC with 

partial CCS. Additionally, another 

project, Summit Power’s Texas Clean 

Energy Project (TCEP), which will 

deploy IGCC with CCS, continues as a 

viable project.72 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 will be built 

in this decade and that those that are 

built will have CCS.73 Continued 

progress on these projects is consistent 

with the EIA modeling that suggests that 

a small number of coal-fired power 

plants may be constructed. The primary 

reasons for this rate of current and 

projected future development of new 

coal projects include highly competitive 

natural gas prices, lower electricity 

demand growth, and increases in the 

supply of renewable energy. We 

recognize, however, that a variety of 

factors may come into play in a decision 

to build new power generation, and we 

want to ensure that there are standards 

in place to make sure that whatever fuel 

is utilized is done so in a way that 

minimizes CO2 emissions, as Congress 

intended with CAA section 111.74

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 of and 

developments in the power sector. 

These reports are based on economic 

modeling that reflects existing policy 

and regulations, such as state RPS 

programs and federal tax credits for 

renewables.75 The current report, AEO 

2015: 76 (i) Shows that a modest amount 

of coal-fired power plants that are 

currently under construction are 

expected to begin operation in the next 

several years (referred to as ‘‘planned’’); 

and (ii) projects in the reference case 77

that a very small amount of new 

(‘‘unplanned’’) conventional coal-fired 

capacity, with CCS, will come online 

after 2012 and through 2037 in response 

to federal and state incentives. 

According to the AEO 2015, the vast 

majority of new generating capacity 

during this period will be either natural 

gas-fired or renewable sources. 

Similarly, the EIA projections from the 

last several years show that natural gas 

is likely to be the most widely-used 

fossil fuel for new construction of 

electric generating capacity through 

2030.78

Specifically, the AEO 2015 projects 

30.3 GW of additional base load or 

intermediate load generation capacity 

through 2020 (this includes projects that 

are under development—i.e., being 

constructed or in advance planning— 

and model-projected nuclear, coal, and 

NGCC projects). The vast majority of 

this new electric capacity (20.4 GW) is 

already under development (under 

construction or in advanced planning); 

it includes about 0.7 GW of new coalfired capacity, 5.5 GW of new nuclear 

capacity, and 14.2 GW of new NGCC 

capacity. The EPA believes that most 

current fossil fuel-fired projects are 

already designed to meet limits 

consistent with this rule (or they have 

already commenced construction and 

are thus not subject to these final 

standards). The AEO 2015 also projects 

an additional 9.9 GW of new base load 

capacity additions, which are modelprojected (unplanned). This consists of 

7.7 GW of new NGCC capacity, 1.2 GW 

of new geothermal capacity, 0.7 GW of 

new hydroelectric capacity, and 0.3 GW 

of new coal equipped with CCS 

(incentivized with some government 

funding). Therefore, the AEO 2015 

projection suggests that the new power 

generation capacity added through 2020 

is expected to already meet the final 

emissions standards without incurring 

further control costs. This is also true 

during the period from 2020 through 

2030, where new model-projected 

(unplanned) intermediate and base load 

capacity is expected to be compliant 

with the standards without incurring 

further control costs (i.e., an additional 

31.3 GW of NGCC and no additional 

coal, for a total, from 2015 through 

2030, of 39 GW of NGCC and 0.3 GW 

of coal with CCS). 

Under the EIA projections, existing 

coal-fired generation will remain an 

important part of the mix for power 

generation. Modeling from both the EIA 

and the EPA project that coal-fired 

generation will remain the largest single 

source of electricity in the U.S. through 

2040. Specifically, in the EIA’s AEO 

2015, coal will supply approximately 40 

percent of all electricity in the electric 

power sector in both 2020 and 2025. 

The EPA modeling using the 

Integrated Planning Model (IPM), a 

detailed power sector model that the 

EPA uses to support power sector 

regulations, also shows limited future 

construction of new coal-fired power 

plants under the base case.79 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.80

These IRPs indicate that companies are 

focused on demand-side management 

programs to lower future electricity 

demand and are mostly reliant on a mix 

of new natural gas-fired generation and 

renewable energy to meet increased load 

demand and to replace retired 

generation capacity. 

Notwithstanding this clear trend 

towards natural gas-fired generation and 

renewables, many of the IRPs highlight 

the value of fuel diversity and include 

options to diversify new generation 

capacity beyond natural gas and 

renewable energy. Several IRPs indicate 

that companies are considering new 

nuclear generation, including either 

traditional nuclear power plants or 

small modular reactors, and a smaller 

number are considering new coal-fired 

generation capacity with and without 

CCS technology. Based on public 

comments and on the information 

contained in these IRPs, the EPA 

acknowledges that a small number of 

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81The 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). 

82 549 U.S. 497, 520 (2007). 

83 131 S.Ct. 2527, 2537–38 (2011). 

84CAA section 111(b)(1)(A). 

85See generally 40 CFR part 60, subparts D– 

MMMM. 

86 36 FR 5931 (March 31, 1971). 

87 42 FR 53657 (October 3, 1977). 

88CAA section 111(b)(1)(B). 

89CAA section 111(a)(2). 

90CAA section 111(a)(4); See also 40 CFR 60.14 

concerning what constitutes a modification, how to 

determine the emission rate, how to determine an 

emission increase, and specific actions that are not, 

by themselves, considered modifications. 

91 40 CFR 60.2, 60.14(e). 

92 40 CFR 60.15. 

93CAA section 111(b)(5) and (h). 

94CAA section 111(b)(5). 

95CAA section 111(b)(2); see also Lignite Energy 

Council v. EPA, 198 F. 3d 930, 933 (D.C. Cir. 1999). 

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 coalfired 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 GHGs 81 meet 

the definition of ‘‘air pollutant’’ in the 

CAA,82 and premised its decision in 

AEP v. Connecticut,83 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).84

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 

111.85 The EPA listed the two source 

categories at issue here in the 1970s— 

listing fossil fuel-fired electric steam 

generating units in 1971 86 and listing 

combustion turbines in 1977.87

Once the EPA has listed a source 

category, the EPA proposes and then 

promulgates ‘‘standards of 

performance’’ for ‘‘new sources’’ in the 

category.88 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.89 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.’’ 90 The EPA, 

through regulations, has determined 

that certain types of changes are exempt 

from consideration as a modification.91

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.92

CAA section 111(a)(1) defines a 

‘‘standard of performance’’ as ‘‘a 

standard for emissions . . . achievable 

through the application of the best 

system of emission reduction which 

[considering cost, non-air quality health 

and environmental impact, and energy 

requirements] the Administrator 

determines has been adequately 

demonstrated.’’ This definition makes 

clear that the standard of performance 

must be based on ‘‘the best system of 

emission reduction . . . adequately 

demonstrated’’ (BSER). 

The standard that the EPA develops, 

reflecting the performance of the BSER, 

is commonly a numeric emission limit, 

expressed as a numeric performance 

level that can either be normalized to a 

rate of output or input (e.g., tons of 

pollution per amount of product 

produced—a so-called rate-based 

standard), or expressed as a numeric 

limit on mass of pollutant that may be 

emitted (e.g., 100 ug/m3—parts per 

billion). Generally, the EPA does not 

prescribe a particular technological 

system that must be used to comply 

with a standard of performance.93

Rather, sources generally may select any 

measure or combination of measures 

that will achieve the emissions level of 

the standard.94 In establishing standards 

of performance, the EPA has significant 

discretion to create subcategories based 

on source type, class, or size.95

The text and legislative history of 

CAA section 111, as well as relevant 

court decisions, identify the factors that 

the EPA is to consider in making a BSER 

determination. The system of emission 

reduction must be technically feasible, 

the costs of the system must be 

reasonable, and the emission standard 

that the EPA promulgates based on the 

system of emission reduction must be 

achievable. In addition, in identifying a 

BSER, the EPA must consider the 

amount of emissions reductions 

attributable to the system, and must also 

consider non-air quality health and 

environmental impacts and energy 

requirements. The case law addressing 

CAA section 111 makes it clear that the 

EPA has discretion in weighing costs, 

amount of emission reductions, energy 

requirements, and impacts of non-air 

quality pollutants, and may weigh them 

differently for different types of sources 

or air pollutants. We note that under the 

case law of the D.C. Circuit, another 

factor is relevant for the BSER 

determination: Whether the standard 

would effectively promote further 

deployment or development of 

advanced technologies. Within the 

constraints just described, the EPA has 

discretion in identifying the BSER and 

the resulting emission standard. See 

generally Section III.H below. 

For more than four decades, the EPA 

has used its authority under CAA 

section 111 to set cost-effective emission 

standards which ensure that newly 

constructed, reconstructed, and 

modified stationary sources use the best 

performing technologies to limit 

emissions of harmful air pollutants. In 

this final action, the EPA is following 

the same well-established interpretation 

and application of the law under CAA 

section 111 to address GHG emissions 

from newly constructed, reconstructed, 

and modified fossil fuel-fired power 

plants. For each of the standards in this 

final action, the EPA considered a 

number of alternatives and evaluated 

them against the statutory factors. The 

BSER for each category of affected EGUs 

and the standards of performance based 

on these BSER are based on that 

evaluation. 

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96 36 FR 5931 (March 31, 1971). 

97 ‘‘Standards of Performance for Fossil-FuelFired Steam Generators for Which Construction Is 

Commenced After August 17, 1971,’’ 36 FR 24875 

(December 23, 1971) codified at 40 CFR 60.40–46. 

98 42 FR 53657 (October 3, 1977). 

99 ‘‘Standards of Performance for Electric Utility 

Steam Generating Units for Which Construction is 

Commenced After September 18, 1978,’’ 44 FR 

33580 (June 11, 1979). 

100 44 FR 33580 (June 11, 1979). 

101 71 FR 38497 (July 6, 2006), as amended at 74 

FR 11861 (March 20, 2009). 

102 ‘‘Standards of Performance for Electric Utility 

Steam Generating Units, Industrial-CommercialInstitutional Steam Generating Units, and Small 

Industrial-Commercial-Institutional Steam 

Generating Units, Final Rule.’’ 71 FR 9866 

(February 27, 2006). 

103State of New York, et al. v. EPA, No. 06–1322. 

104 79 FR 1430, 1444. 

105See Section III.H.3.g below. The Energy Policy 

Act of 2005 (EPAct05) was signed into law by 

President George W. Bush on August 8, 2005. 

EPAct05 was intended to address energy 

production in the United States, including: (1) 

Energy efficiency; (2) renewable energy; (3) oil and 

gas; (4) coal; (5) Tribal energy; (6) nuclear matters 

and security; (7) vehicles and motor fuels, including 

ethanol; (8) hydrogen; (9) electricity; (10) energy tax 

incentives; (11) hydropower and geothermal energy; 

and (12) climate change technology. www2.epa.gov/ 

laws-regulations/summary-energy-policy-act. 

E. Regulatory Background 

In 1971, the EPA initially included 

fossil fuel-fired EGUs (which includes 

natural gas, petroleum and coal) that use 

steam-generating boilers in a category 

that it listed under CAA section 

111(b)(1)(A),96 and promulgated the first 

set of standards of performance for 

sources in that category, which it 

codified in subpart D.97 In 1977, the 

EPA initially included fossil fuel-fired 

combustion turbines in a category that 

the EPA listed under CAA section 

111(b)(1)(A),98 and the EPA 

promulgated standards of performance 

for that source category in 1979, which 

the EPA codified in subpart GG.99

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-Commercial-Institutional 

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.100 In 

2006, the EPA created subpart KKKK, 

’’Standards of Performance for 

Stationary Combustion Turbines,’’ 

which applied to certain sources 

previously regulated in subparts Da and 

GG.101 None of these subsequent 

rulemakings, including the revised 

codifications, however, constituted a 

new listing under CAA section 

111(b)(1)(A). 

The EPA promulgated amendments to 

subpart Da in 2006, which included 

new standards of performance for 

criteria pollutants for EGUs, but did not 

include specific standards of 

performance for CO2 emissions.102

Petitioners sought judicial review of the 

rule, contending, among other issues, 

that the rule was required to include 

standards of performance for GHG 

emissions from EGUs.103 The January 8, 

2014 preamble to the proposed CO2

standards for new EGUs 104 includes a 

discussion of the GHG-related litigation 

of the 2006 Final Rule as well as other 

GHG-associated litigation. 

F. Development of 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 fuelfired electric utility steam generating 

units. 77 FR 22392 (‘‘April 2012 

proposal’’). The EPA withdrew that 

proposal (79 FR 1352 (January 8, 2014)), 

and, on the same day, proposed the 

standards addressed in this final rule. 

79 FR 1430 (‘‘January 2014 proposal’’). 

Specifically, the EPA proposed 

standards under CAA section 111 to 

limit emissions of CO2 from newly 

constructed fossil fuel-fired electric 

utility steam generating units and newly 

constructed natural gas-fired stationary 

combustion turbines. 

In support of the January 2014 

proposal, on February 26, 2014, the EPA 

published a notice of data availability 

(NODA) (79 FR 10750). Through the 

NODA and an associated technical 

support document, Effect of EPAct05 on 

Best System of Emission Reduction for 

New Power Plants, the EPA solicited 

comment on its interpretation of the 

provisions in the Energy Policy Act of 

2005 (EPAct05),105 including how the 

provisions may affect the rationale for 

the EPA’s proposed determination that 

partial CCS is the best system of 

emission reduction adequately 

demonstrated for fossil fuel-fired 

electric utility steam generating units. 

On June 18, 2014, the EPA proposed 

standards of performance to limit 

emissions of CO2 from modified and 

reconstructed fossil fuel-fired electric 

utility steam generating units and 

natural gas-fired stationary combustion 

turbines (79 FR 34960; June 2014 

proposal). Specifically, the EPA 

proposed standards of performance for: 

(1) Modified fossil fuel-fired electric 

utility steam generating units, (2) 

modified natural gas-fired stationary 

combustion turbines, (3) reconstructed 

fossil fuel-fired 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, nongovernmental organizations and many 

others. 

In February and March 2011, early in 

the process of developing carbon 

pollution standards for new power 

plants, the EPA held five listening 

sessions to obtain information and input 

from key stakeholders and the public. 

Each of the five sessions had a 

particular target audience: The electric 

power industry, environmental and 

environmental justice organizations, 

states and tribes, coalition groups, and 

the petroleum refinery industry. 

The EPA conducted subsequent 

outreach prior to the June 2014 

proposals of standards for modified and 

reconstructed EGUs and emission 

guidelines for existing EGUs, as well as 

during the public comment periods for 

the proposals. Although this stakeholder 

outreach was primarily framed around 

the GHG emission guidelines for 

existing EGUs, the outreach 

encompassed issues relevant to this 

rulemaking and provided an 

opportunity for the EPA to better 

understand previous state and 

stakeholder experience with reducing 

CO2 emissions in the power sector. In 

addition to 11 public listening sessions, 

the EPA held hundreds of meetings with 

individual stakeholder groups, and 

meetings that brought together a variety 

of stakeholders to discuss a wide range 

of issues related to the electricity sector 

and regulation of GHGs under the CAA. 

The agency met with electric utility 

associations and electricity grid 

operators. Agency officials engaged with 

labor unions and with leaders 

representing large and small industries. 

The agency also met with energy 

industries, such as coal and natural gas 

interests, as well as with representatives 

of energy-intensive industries, such as 

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the iron and steel, and aluminum 

industries, to better understand the 

potential concerns of large industrial 

purchasers of electricity. In addition, 

the agency met with companies that 

offer new technology to prevent or 

reduce carbon pollution. The agency 

provided and encouraged multiple 

opportunities for engagement with state, 

local, tribal, and regional environmental 

and energy agencies. The EPA also met 

with representatives of environmental 

justice organizations, environmental 

groups, public health professionals, 

public health organizations, religious 

organizations, and other community 

stakeholders. 

The EPA received more than 2.5 

million comments submitted in 

response to the original April 2012 

proposal for newly constructed fossil 

fuel-fired EGUs. Because the original 

proposal was withdrawn, the EPA 

instructed commenters that wanted 

their comments on the April 2012 

proposal to be considered in connection 

with the January 2014 proposal to 

submit new comments to the EPA or to 

re-submit their previous comments. We 

received more comments in response to 

the January 2014 proposal, as discussed 

in the section below. 

The EPA has given stakeholder input 

provided prior to the proposals, as well 

as during the public comment periods 

for each proposal, careful consideration 

during the development of this 

rulemaking and, as a result, it includes 

elements that are responsive to many 

stakeholder concerns and that enhance 

the rule. This preamble and the 

Response-to-Comments (RTC) document 

summarize and provide the agency’s 

responses to the comments received. 

2. Comments on the January 2014 

Proposal For Newly Constructed Fossil 

Fuel-Fired EGUs 

Upon publication of the January 8, 

2014 proposal for newly constructed 

fossil fuel-fired EGUs, the EPA provided 

a 60-day public comment period. On 

March 6, 2014, in order to provide the 

public additional time to submit 

comments and supporting information, 

the EPA extended the comment period 

by 60 days, to May 9, 2014, giving 

stakeholders over 120 days to review, 

and comment upon, the January 2014 

proposal, as well as the NODA. A public 

hearing was held on February 6, 2014, 

with 159 speakers presenting testimony. 

The EPA received more than 2 million 

comments on the proposed standards 

for newly constructed fossil fuel-fired 

EGUs from a range of stakeholders that 

included industry and electric utility 

representatives, trade groups, 

equipment manufacturers, state and 

local government officials, academia, 

environmental organizations, and 

various interest groups. The agency 

received comments on a range of topics, 

including the determination that a new 

highly-efficient steam generating EGU 

implementing partial CCS was the BSER 

for such sources, the level of the CO2

standard based on implementation of 

partial CCS, the criteria that define 

which newly constructed natural gasfired 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 the EPA’s June 

18, 2014 proposed emission guidelines 

for existing fossil fuel-fired EGUs 

(reflecting the connections between the 

proposed standards for modified and 

reconstructed sources and the proposed 

emission guidelines). A total of 1,322 

speakers testified, and a further 1,450 

attended but did not speak. The 

speakers were provided the opportunity 

to present data, views, or arguments 

concerning one or both proposed 

actions. 

The EPA received over 200 comments 

on the proposed standards for modified 

and reconstructed fossil fuel-fired EGUs 

from a range of stakeholders similar to 

those that submitted comments on the 

January 2014 proposal for newly 

constructed fossil fuel-fired EGUs (i.e., 

industry and electric utility 

representatives, trade groups, 

equipment manufacturers, state and 

local government officials, academia, 

environmental organizations, and 

various interest groups). The agency 

received comments on a range of topics, 

including the methodology for 

determining unit-specific CO2 standards 

for modified steam generating units and 

the use of supercritical boiler conditions 

as the basis for the CO2 standards for 

certain reconstructed steam generating 

units. Many of the comments regarding 

modified and reconstructed natural gasfired 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 

EGUs and Their Standards, and Legal 

Requirements 

In this section, we describe our 

authority to regulate CO2 from fossil 

fuel-fired EGUs. We also describe our 

decision to combine the two existing 

categories of affected EGUs—steam 

generators and combustion turbines— 

into a single category of fossil fuel-fired 

EGUs for purposes of promulgating 

standards of performance for CO2

emissions. We also explain that we are 

codifying all of the requirements in this 

rule for new, modified, and 

reconstructed affected EGUs in new 

subpart TTTT of part 60 of Title 40 of 

the Code of Federal Regulations. In 

addition, we explain which sources are 

and are not affected by this rule, and the 

format of these standards. Finally, we 

describe the legal requirements for 

establishing these emission standards. 

A. Authority To Regulate Carbon 

Dioxide From Fossil Fuel-Fired EGUs 

The EPA’s authority for this rule is 

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

111(b)(1)(A) requires the Administrator 

to establish a list of source categories to 

be regulated under section 111. A 

category of sources is to be included on 

the list ‘‘if in [the Administrator’s] 

judgment it causes, or contributes 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health and welfare.’’ This 

determination is commonly referred to 

as an ‘‘endangerment finding’’ and that 

phrase encompasses both the ‘‘causes or 

contributes significantly’’ component 

and the ‘‘endanger public health and 

welfare’’ component of the 

determination. Then, for the source 

categories listed under section 

111(b)(1)(A), the Administrator 

promulgates, under section 111(b)(1)(B), 

‘‘standards of performance for new 

sources within such category.’’ 

In this rule, the EPA is establishing 

standards under section 111(b)(1)(B) for 

source categories that it has previously 

listed and regulated for other pollutants 

and which now are being regulated for 

an additional pollutant. Because of this, 

there are two aspects of section 

111(b)(1) that warrant particular 

discussion. 

First, because the EPA is not listing a 

new source category in this rule, the 

EPA is not required to make a new 

endangerment finding with regard to 

affected EGUs in order to establish 

standards of performance for the CO2

emissions from those sources. Under the 

plain language of CAA section 

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64530 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

106 In Chevron, the U.S. Supreme Court held that 

an agency must, at Step 1, determine whether 

Congress’s intent as to the specific matter at issue 

is clear, and, if so, the agency must give effect to 

that intent. If Congressional intent is not clear, then, 

at Step 2, the agency has discretion to fashion an 

interpretation that is a reasonable construction of 

the statute. 

107Coalition for Responsible Regulation v. EPA, 

684 F.3d 102, 119–126 (D.C. Circuit 2012). 108 79 FR 1430, 1455–56 (January 8, 2014). 

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), 

and 231(a)(2)(A); see also American 

Electric Power Co. Inc., v. Connecticut, 

131 S. Ct. 2527, 2539 (2011) (‘‘[T]he 

Clean Air Act directs the EPA to 

establish emissions standards for 

categories of stationary sources that, ‘in 

[the Administrator’s] judgment,’ 

‘caus[e], or contribut[e] significantly to, 

air pollution which may reasonably be 

anticipated to endanger public health or 

welfare.’ § 7411(b)(1)(A).’’) (emphasis 

added). 

Second, once a source category is 

listed, the CAA does not specify what 

pollutants should be the subject of 

standards from that source category. The 

statute, in section 111(b)(1)(B), simply 

directs the EPA to propose and then 

promulgate regulations ‘‘establishing 

federal standards of performance for 

new sources within such category.’’ In 

the absence of specific direction or 

enumerated criteria in the statute 

concerning what pollutants from a given 

source category should be the subject of 

standards, it is appropriate for the EPA 

to exercise its authority to adopt a 

reasonable interpretation of this 

provision. Chevron U.S.A. Inc. v. NRDC, 

467 U.S. 837, 843–44 (1984).106

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 FR 35838 (June 24, 2008) 

(concluding that the statute provides 

‘‘the Administrator with significant 

flexibility in determining which 

pollutants are appropriate for regulation 

under section 111(b)(1)(B)’’ and citing 

cases). Further, in directing the 

Administrator to propose and 

promulgate regulations under section 

111(b)(1)(B), Congress provided that the 

Administrator should take comment and 

then finalize the standards with such 

modifications ‘‘as he deems 

appropriate.’’ The D.C. Circuit has 

considered similar statutory phrasing 

from CAA section 231(a)(3) and 

concluded that ‘‘[t]his delegation of 

authority is both explicit and 

extraordinarily broad.’’ National Assoc. 

of Clean Air Agencies v. EPA, 489 F.3d 

1221, 1229 (D.C. Cir. 2007). 

In exercising its discretion with 

respect to which pollutants are 

appropriate for regulation under section 

111(b)(1)(B), the EPA has in the past 

provided a rational basis for its 

decisions. See National Lime Assoc. v. 

EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 

1980) (court discussed, but did not 

review, the EPA’s reasons for not 

promulgating standards for oxides of 

nitrogen (NOX), sulfur dioxide (SO2) and 

CO from lime plants); Standards of 

Performance for Petroleum Refineries, 

73 FR at 35859–60 (June 24, 2008) 

(providing reasons why the EPA was not 

promulgating GHG standards for 

petroleum refineries as part of that rule). 

Though these previous examples 

involved the EPA providing a rational 

basis for not setting standards for a 

given pollutant, a similar approach is 

appropriate where the EPA determines 

that it should set a standard for an 

additional pollutant for a source 

category that was previously listed and 

regulated for other pollutants. 

In this rulemaking, the EPA has a 

rational basis for concluding that 

emissions of CO2 from fossil fuel-fired 

power plants, which are the major U.S. 

source of GHG air pollution, merit 

regulation under CAA section 111. As 

noted, in 2009, the EPA made a finding 

that GHG air pollution may reasonably 

be anticipated to endanger public health 

or welfare, and in 2010, the EPA denied 

petitions to reconsider that finding. The 

EPA extensively reviewed the available 

science concerning GHG pollution and 

its impacts in taking those actions. In 

2012, the U.S. Court of Appeals for the 

D.C. Circuit upheld the finding and the 

denial of petitions to reconsider.107 In 

addition, assessments from the NRC, the 

IPCC, and other organizations published 

after 2010 lend further credence to the 

validity of the Endangerment Finding. 

No information that commenters have 

presented or that the EPA has reviewed 

provides a basis for reaching a different 

conclusion. Indeed, current and 

evolving science discussed in detail in 

Section II.A of this preamble is 

confirming and enhancing our 

understanding of the near- and longerterm impacts emissions of CO2 are 

having on Earth’s climate and the 

adverse public health, welfare, and 

economic consequences that are 

occurring and are projected to occur as 

a result. 

Moreover, the high level of GHG 

emissions from fossil fuel-fired EGUs 

makes clear that it is rational for the 

EPA to regulate GHG emissions from 

this sector. EGUs emit almost one-third 

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 coalfired power plant may amount to 

millions of tons each year. See, e.g., 

Section V.K below (noting that even the 

difference in CO2 emissions between a 

highly efficient SCPC and the same unit 

meeting today’s standard of 

performance can amount to hundreds of 

thousands of tons each year). These 

facts provide a rational basis for 

regulating CO2 emissions from affected 

EGUs. 

Some commenters have argued that 

the EPA is required to make a new 

endangerment finding before it may 

regulate CO2 from EGUs. We disagree, 

for the reasons discussed above. 

Moreover, as discussed in the January 

2014 proposal,108 even if CAA section 

111 required the EPA to make 

endangerment and cause-or-contribute 

significantly findings as prerequisites 

for this rulemaking, then, so far as the 

‘‘CO2 endangers public health and 

welfare’’ component of an 

endangerment finding is concerned, the 

information and conclusions described 

above should be considered to 

constitute the requisite endangerment 

finding. Similarly, so far as a cause-orcontribute significantly finding is 

concerned, the information and 

conclusions described above should be 

considered to constitute the requisite 

finding. The EPA’s rational basis for 

regulating CO2 under CAA section 111 

is based primarily on the analysis and 

conclusions in the EPA’s 2009 

Endangerment Finding and 2010 denial 

of petitions to reconsider 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 

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109Nor does the EPA consider the cost of 

potential standards of performance in making this 

Finding. Like the Endangerment Finding under 

section 202(a) at issue in State of Massachusetts v. 

EPA, 549 U.S. 497 (2007) the pertinent issue is a 

scientific inquiry as to whether an endangerment to 

public health or welfare from the relevant air 

pollution may reasonably be anticipated. Where, as 

here, the scientific inquiry conducted by the EPA 

indicates that these statutory criteria are met, the 

Administrator does not have discretion to decline 

to make a positive endangerment finding to serve 

other policy grounds. Id. at 532–35. In this regard, 

an endangerment finding is analogous to setting 

national ambient air quality standards under 

section 109(b), which similarly call on the 

Administrator to set standards that in her 

‘‘judgment’’ are ‘‘requisite to protect the public 

health’’. The EPA is not permitted to consider 

potential costs of implementation in setting these 

standards. Whitman v. American Trucking Assn’s, 

531 U.S. 457, 466 (2001); see also Michigan v. EPA, 

U.S. (no. 14–46, June 29, 2015) slip op. pp. 10–11 

(reiterating Whitman holding). The EPA notes 

further that section 111(b)(1) contains no terms 

such as ‘‘necessary and appropriate’’ which could 

suggest (or, in some contexts, require) that costs 

may be considered as part of the finding. Compare 

CAA section 111(n)(1)(A); see State of Michigan, 

slip op. pp. 7–8. The EPA, of course, must consider 

costs in determining whether a best system of 

emission reduction is adequately demonstrated and 

so can form the basis for a section 111(b) standard 

of performance, and the EPA has carefully 

considered costs here and found them to be 

reasonable. See section V. H. and I. below. The EPA 

also has found that the rule’s quantifiable benefits 

exceed regulatory costs under a range of 

assumptions were new capacity to be built. RIA 

chapter 5 and section XIII.G below. Accordingly, 

this endangerment finding would be justified if 

(against our view) it is both required, and (again, 

against our view) costs are to be considered as part 

of the finding. 

110The ‘‘air pollution’’ defined in the 

Endangerment Finding is the atmospheric mix of 

six long-lived and directly emitted greenhouse 

gases: Carbon dioxide (CO2), methane (CH4), nitrous 

oxide (N2O), hydrofluorocarbons (HFCs), 

perfluorocarbons (PFCs), and sulfur hexafluoride 

(SF6). See 74 FR 66496 at 66497. The standards of 

performance adopted in the present rulemaking 

address only one component of this air pollution: 

CO2. This is reasonable, given that CO2 is the air 

pollutant emitted in the largest volume by the 

source category, and which is (necessarily) emitted 

by every affected EGU. There is, of course, no 

requirement that standards of performance address 

each component of the air pollution which 

endangers. Section 111(b)(1)(A) requires the EPA to 

establish ‘‘standards of performance’’ for listed 

source categories, and the definition of ‘‘standard of 

performance’’ in section 111(a)(1) does not specify 

which air pollutants must be controlled. See also 

Section III.G below explaining that CH4 and N2O 

emissions represent less than 1 percent of total 

estimated GHG emissions (as CO2e) from fossil fuelfired electric power generating units. 

determine whether that information has 

any meaningful impact on our analysis 

and conclusions. For both the 

endangerment finding and the rational 

basis, the EPA focused on public health 

and welfare impacts within the United 

States, as it did in the 2009 Finding. The 

impacts in other world regions 

strengthen the case because impacts in 

other world regions can in turn 

adversely affect the United States or its 

citizens. 

More specifically, our approach 

here—reflected in the information and 

conclusions described above—is 

substantially similar to that reflected in 

the 2009 Endangerment Finding and the 

2010 denial of petitions to reconsider. 

The D.C. Circuit upheld that approach 

in Coalition for Responsible Regulation 

v. EPA, 684 F.3d 102, 117–123 (D.C. Cir. 

2012) (noting, among other things, the 

‘‘substantial . . . body of scientific 

evidence marshaled by EPA in support 

of the Endangerment Finding’’ (id. at 

120); the ‘‘substantial record evidence 

that anthropogenic emissions of 

greenhouse gases ‘very likely’ caused 

warming of the climate over the last 

several decades’’ (id. at 121); 

‘‘substantial scientific evidence . . . 

that anthropogenically induced climate 

change threatens both public health and 

public welfare . . . [through] extreme 

weather events, changes in air quality, 

increases in food- and water-borne 

pathogens, and increases in 

temperatures’’ (id.); and ‘‘substantial 

evidence . . . that the warming 

resulting from the greenhouse gas 

emissions could be expected to create 

risks to water resources and in general 

to coastal areas. . . .’’ (id.)). The facts, 

unfortunately, have only grown stronger 

and the potential adverse consequences 

to public health and the environment 

more dire in the interim. Accordingly, 

that approach would support an 

endangerment finding for this 

rulemaking.109

Likewise, if the EPA were required to 

make a cause-or-contribute-significantly 

finding for CO2 emissions from the 

fossil fuel-fired EGUs as a prerequisite 

to regulating such emissions under CAA 

section 111, the same facts that support 

our rational basis determination would 

support such a finding. As shown in 

Tables 3 and 4 in this preamble, fossil 

fuel-fired EGUs are very large emitters 

of CO2. All told, these fossil fuel-fired 

EGUs emit almost one-third of all U.S. 

GHG emissions, and are responsible for 

almost three times as much as the 

emissions from the next ten stationary 

source categories combined. The CO2

emissions from even a single new coalfired power plant may amount to 

millions of tons each year, and the CO2

emissions from even a single NGCC unit 

may amount to one million or more tons 

per year. It is not necessary in this 

rulemaking for the EPA to decide 

whether it must identify a specific 

threshold for the amount of emissions 

from a source category that constitutes 

a significant contribution; under any 

reasonable threshold or definition, the 

emissions from combustion turbines 

and steam generators are a significant 

contribution. Indeed, these emissions 

far exceed in magnitude the emissions 

from motor vehicles, which have 

already been held to contribute to the 

endangerment. See Coalition for 

Responsible Regulation, 684 F. 3d at 121 

(‘‘substantial evidence’’ supports the 

EPA’s determination ‘‘that motorvehicle emissions of greenhouse gases 

contribute to climate change and thus to 

the endangerment of public health and 

welfare’’).110

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 sources in the two 

categories. The EPA took comment on 

combining the two categories into a 

single category solely for purposes of 

the CO2 emissions from new, modified, 

and reconstructed affected EGUs. In 

addition, the EPA proposed codifying 

the standards of performance in the 

same Da and KKKK subparts that 

currently contain the standards of 

performance for other pollutants from 

those sources addressed in the NSPS 

program, but co-proposed codifying all 

the standards of performance for CO2

emissions in a new 40 CFR part 60, 

subpart TTTT. 

In this rule, the EPA is combining the 

steam generator and combustion turbine 

categories into a single category of fossil 

fuel-fired electricity generating units for 

purposes of promulgating standards of 

performance for GHG emissions. 

Combining the two categories is 

reasonable because they both provide 

the same product: Electricity services. 

Moreover, combining them in this rule 

is consistent with our decision to 

combine them in the CAA section 

111(d) rule for existing sources that 

accompanies this rule. In addition, 

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111See, e.g., American Trucking Assn’s v. EPA, 

175 F.3d 1027, 1055, rev’d on other grounds sub. 

nom. Whitman v. Am. Trucking Assn’s, 531.U.S. 

457 (because fine particulate matter (PM2.5) was 

already included as a sub-set of the listed pollutant 

particulate matter, it was not a new pollutant 

necessitating a new listing). 

112We refer to the capability to combust 250 

MMBtu/h of fossil fuel as the ‘‘base load rating 

criterion.’’ Note that 250 MMBtu/h is equivalent to 

73 MW or 260 GJ/h heat input. 

113We refer to the capability to supply 25 MW 

net to the grid as the ‘‘total electric sales criterion.’’ 

114We refer to the fraction of heat input derived 

from fossil fuels as the ‘‘fossil fuel-use criterion.’’ 

many of the monitoring, reporting, and 

verification requirements are the same 

for both source categories, and, as 

discussed next, we are codifying all 

requirements in a single new subpart of 

the regulations; as a result, combining 

the two categories into a single category 

will reduce confusion. It should be 

noted that in this rule, we are not 

combining the two categories for 

purposes of standards of performance 

for other air pollutants. 

Because these two source categories 

are pre-existing listed source categories 

and the EPA will not be subjecting any 

additional sources in the categories to 

CAA regulation for the first time, the 

combination of these two categories is 

not considered a new source category 

subject to the listing requirements of 

CAA section 111(b)(1)(A). As a result, 

this final rule does not list a new 

category under CAA section 

111(a)(1)(A), nor does this final rule 

revise either of the two source 

categories. Thus, the EPA is not 

required to make a new endangerment 

and contribution finding for the 

combination of the two categories,111

although as discussed in the previous 

section, the evidence strongly supports 

such findings. Thus, the EPA has found, 

in the alternative, that this category of 

sources contributes significantly to air 

pollution which may be reasonably 

anticipated to endanger public health 

and welfare. 

C. Affected Units 

We generally refer to fossil fuel-fired 

electric generating units that would be 

subject to a CAA section 111 emission 

standard as ‘‘affected’’ or ‘‘covered’’ 

sources, units, facilities or simply as 

EGUs. An EGU is any boiler, IGCC unit, 

or combustion turbine (in either simple 

cycle or combined cycle configuration) 

that meets the applicability criteria. 

Affected EGUs include those that 

commenced construction after January 

8, 2014, and meet the specified 

applicability criteria and, for 

modifications and reconstructions, 

EGUs that commenced those activities 

after June 18, 2014, and meet the 

specified applicability criteria. 

To be considered an EGU, the unit 

must: (1) Be capable of combusting more 

than 250 MMBtu/h (260 GJ/h) heat 

input of fossil fuel; 112 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).113

However, we are not finalizing CO2

standards for certain EGUs. The EGUs 

that are not covered by the standards we 

are finalizing in this rule include: (1) 

Non-fossil fuel units subject to a 

federally enforceable permit that limits 

the use of fossil fuels to 10 percent or 

less of their heat input capacity on an 

annual basis; (2) combined heat and 

power (CHP) units that are subject to a 

federally enforceable permit limiting 

annual net-electric sales to no more than 

the unit’s design efficiency multiplied 

by its potential electric output, or 

219,000 MWh or less, whichever is 

greater; (3) stationary combustion 

turbines that are not physically capable 

of combusting natural gas (e.g., not 

connected to a natural gas pipeline); (4) 

utility boilers and IGCC units that have 

always been subject to a federally 

enforceable permit limiting annual netelectric 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 nonfossil fuel-fired (e.g., biomass) units and 

industrial CHP units, as well as certain 

projects under development. This 

section discusses these sources and our 

rationale for not issuing standards for 

them. Because the rationale applies to 

both steam generating units and 

combustion turbines, we are describing 

it here rather than in the separate steam 

generating unit and combustion turbine 

discussions. We discuss the proposed 

applicability criteria, the topics where 

the agency solicited comment, a brief 

summary of the relevant comments, and 

the rationale for the final applicability 

approach for these sources. 

1. Dedicated Non-fossil Fuel Units 

The proposed applicability for newly 

constructed EGUs included those that 

primarily combust fossil fuels (e.g., coal, 

oil, and natural gas). The proposed 

applicability criteria were that affected 

units must burn fossil fuels for more 

than 10 percent of the unit’s total heat 

input, on average, over a 3-year 

period.114 Under the proposed 

approach, applicability under the final 

NSPS for CO2 emissions could have 

changed on an annual basis depending 

on the composition of fuel burned. We 

solicited comment on several aspects of 

the proposed applicability criteria for 

non-fossil fuel units. Specifically, we 

solicited comment on a broad 

applicability approach that would 

include non-fossil fuel-fired units as 

affected units, but that would impose an 

alternate standard when the unit fires 

fossil fuels for 10 percent or less of the 

heat input during the 3-year 

applicability-determination period. We 

solicited comment on whether, if such 

a subcategory is warranted, the 

applicability-determination period for 

the subcategory should be 1-year or a 3- 

year rolling period. We also solicited 

comment on whether the standard for 

such a subcategory should be an 

alternate numerical limit or ‘‘no 

emission standard.’’ 

While the proposed exemption 

applied to all non-fossil fuels, most 

commenters focused on biomassspecific issues. Many commenters 

supported an exclusion for biomassfired units that fire no more than 10 

percent fossil fuels. Some commenters 

suggested that the exclusion for 

biomass-fired units should be raised to 

a 25 percent fossil fuel-use threshold. 

Many commenters supported the 

proposed 3-year averaging period for the 

fossil fuel-use criterion because it 

provides greater flexibility for operators 

to use fossil fuels when supply chains 

for the primary non-fossil fuels are 

disrupted, during unexpected 

malfunctions of the primary non-fossil 

fuel handling systems, or when the 

unit’s maximum generating capacity is 

required by system operators for 

reliability reasons. Many commenters 

supported the 3-year averaging period 

because it is consistent with the final 

requirements under the EPA’s Mercury 

and Air Toxics Standards (MATS) and 

would allow non-fossil fuel-fired units 

to use some fossil fuels for flame 

stabilization without triggering 

applicability. Some commenters 

requested that the EPA clarify the 

method an operator should use during 

the first 3 years of operations to 

determine if a particular unit will meet 

the 10 percent fossil fuel-use threshold. 

Others asked whether or not an affected 

facility has a compliance obligation 

during the first 3-year period and, if an 

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affected facility does not meet the 10 

percent fossil fuel-use threshold during 

several 12-month periods during the 

first 3 years, whether compliance 

calculations would be required for such 

12-month periods. Other commenters 

had concerns with the 3-year averaging 

period, stating that a source would no 

longer be subject to the NSPS if it fell 

below the threshold for any of the 

applicability metrics that the EPA 

proposed to calculate on a 3-year (or, in 

some cases, annual) basis. They argued 

that this would create a situation in 

which no one would know whether a 

particular plant will be subject to the 

standards until years after the emissions 

had already occurred. Some 

commenters were concerned that plants 

operating near the threshold could move 

in and out of the regulatory system, 

which would provide complications for 

compliance, enforcement, and 

permitting. 

After considering these comments, the 

EPA has concluded that the proposed 

fossil fuel-use criterion based on the 

actual amount of fossil fuel burned is 

not an ideal approach to determine 

applicability. As commenters pointed 

out, facilities, permitting authorities, 

and the public would not know when 

construction is commenced whether a 

facility will be subject to the final NSPS, 

and after operation has commenced, a 

unit could move in and out of 

applicability each year. The intent of 

this rulemaking is to establish CO2

standards for fossil fuel-fired EGUs, not 

for non-fossil fuel-fired EGUs. 

Therefore, to simplify compliance and 

establish CO2 standards for only those 

sources which we set out to regulate, we 

are finalizing a fossil fuel-use criterion 

that will exempt dedicated non-fossil 

units. Specifically, units that are 

capable of burning 50 percent or more 

non-fossil fuel are exempt from the final 

standards so long as they are subject to 

a federally enforceable permit that 

limits their use of fossil fuels to 10 

percent or less of their heat input 

capacity on an annual basis. This 

approach establishes clear applicability 

criteria and avoids the prospect of units 

moving in and out of applicability based 

on their actual fuel use in a given year. 

Consistent with the applicability 

approach in the steam generating unit 

criteria pollutant NSPS, subpart Da, the 

final fossil fuel-use criterion does not 

include ‘‘constructed for the purpose 

of’’ language. Therefore, an owner or 

operator could change a unit’s 

applicability in the future by seeking a 

modification of the unit’s permit 

conditions. A unit with the appropriate 

permit limitation will not be subject to 

the requirements in this rulemaking. 

Similarly, an existing unit that takes a 

permit limitation restricting fossil-fuel 

use would no longer be an affected unit 

for the purposes of 111(d) state plans. 

This is consistent with our intent to 

reduce GHG emissions from fossil fuelfired EGUs. 

We considered using either an annual 

or 3-year average for calculating 

compliance with the final fossil fuel-use 

criterion. Ultimately, we concluded that 

an annual average would provide 

sufficient flexibility for dedicated nonfossil units to combust fossil fuels for 

flame stabilization and other ancillary 

purposes, while maintaining 

consistency with the 12-month 

compliance periods used for most 

permit limitations. A 3-year average 

potentially would allow units to 

combust a significant quantity of fuels 

in a given year, leading to higher CO2

emissions, so long as they curtailed 

fossil-fuel use in a later year. This 

would defeat the purpose of the 

criterion, which is to exempt dedicated 

non-fossil units only. Finally, we are 

finalizing the 10 percent fossil-fuel use 

threshold in relation to a unit’s heat 

input capacity rather than its actual heat 

input, which is consistent with past 

approaches we have taken under the 

industrial boiler criteria pollutant NSPS. 

2. Industrial CHP Units 

Another approach to generating 

electricity is the use of CHP units. A 

CHP unit can use a boiler, combustion 

turbine, reciprocating engine, or various 

other generating technologies to 

generate electricity and useful thermal 

energy in a single, integrated system. 

CHP units are generally more efficient 

than conventional power plants because 

the heat that is normally wasted in a 

conventional power generation cooling 

system (e.g., cooling towers) is instead 

recovered as useful thermal output. 

While the EPA did propose some 

applicability provisions specific to CHP 

units (e.g., subtract purchased power of 

adjacent facilities when determining 

total electric sales), in general, the 

proposed applicability criteria for 

electric-only units and CHP units were 

similar. The intent of the proposed total 

and percentage electric sales criteria 

was to cover only utility CHP units, not 

industrial CHP units. To the extent that 

the proposal’s applicability provisions 

would have the effect of covering 

industrial CHP units, we solicited 

comment on an appropriate 

applicability exemption, and the criteria 

for that exemption, for highly efficient 

CHP facilities. 

Many commenters supported the 

exclusion of CHP units as a means of 

encouraging capital investments in 

highly efficient and reliable distributed 

generation technologies. These 

commenters recommended that the EPA 

adopt an explicit exemption for CHP 

units at facilities that are classified as 

industrial (e.g., gas-fired CHPs within 

SIC codes 2911—petroleum refining, 

13—oil and gas extraction, and other 

industrial SIC codes as appropriate). 

They also stated that the EPA should 

exclude CHP units that have an energy 

savings of 10 percent or more compared 

to separate heat and power. One 

commenter suggested that the final rule 

should cover only industrialcommercial-institutional CHP units that 

supply, on a net basis, more than twothirds of their potential combined 

thermal and electric energy output and 

more than 450,000 MWh net-electric 

output to a utility power distribution 

system on an annual basis for five 

consecutive calendar years. The 

commenter also suggested that CHP 

units which have total thermal energy 

production that approaches or exceeds 

their total electricity production should 

be exempted. 

Other commenters suggested 

exempting CHP units by fuel type or 

based on the definition of potential 

electric output. For example, some 

commenters suggested modifying the 

percentage electric sales threshold to be 

based on net system efficiency 

(including useful thermal output) rather 

than the rated net-electric-output 

efficiency. They also suggested that the 

applicability criteria should use a 

default efficiency of 50 percent for CHP 

units. Some commenters suggested that 

a CHP unit should not be considered an 

affected EGU if 20 percent or more of its 

total gross or net energy output 

consisted of useful thermal output on a 

3-year rolling average basis. Other 

commenters said that highly efficient 

CHP units that achieve an overall 

efficiency level of 60 to 70 percent or 

higher should be excluded from 

applicability. 

The intent of this rulemaking is to 

cover only utility CHP units, because 

they serve essentially the same purpose 

as electric-only EGUs (i.e., the sale of 

electricity to the grid). Industrial CHP 

units, on the other hand, serve a 

different primary purpose (i.e., 

providing useful thermal output with 

electric sales as a by-product). With 

these facts in mind and after 

considering the comments, the EPA has 

concluded that it is appropriate to 

consider two factors for the final CHP 

exemption: (1) Whether the primary 

purpose of the CHP unit is to provide 

useful thermal output rather than 

electricity and (2) whether the CHP unit 

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64534 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

115The EPA has concluded that it is appropriate 

to maintain the 219,000 MWh total electric sales 

criterion for combustion turbine based CHP units to 

avoid potentially covering smaller industrial CHP 

units. 

is highly efficient and thus achieves 

environmental benefits. 

We rejected many of the approaches 

suggested by the commenters because 

they did not achieve one or both of the 

factors we identified. Specifically, the 

EPA has concluded that SIC code 

classification is not a sufficient 

indicator of the purpose (i.e., it does not 

correlate to useful thermal output) or 

environmental benefits (i.e., efficiency) 

of a unit. Further, an exemption based 

on SIC code could result in 

circumvention of the intended 

applicability. For example, this 

approach would allow a new EGU to 

locate near an industrial site, provide a 

trivial amount of useful thermal output 

to that site, sell electricity to the grid, 

and nonetheless avoid applicability. 

Similarly, increasing the electric sales 

criteria to two-thirds of potential 

electric output and 450,000 MWh would 

essentially amount to a blanket 

exemption that tells us nothing about 

the primary purpose or efficiency of the 

unit. 

On the other hand, exemptions based 

on useful thermal output being greater 

than 20 percent of total output, thermal 

output being greater than electric 

output, or overall design efficiency 

value would identify whether the 

primary purpose of a unit is to generate 

thermal output, but they would not 

recognize the environmental benefits of 

highly efficient CHP units. While 

overall efficiency may appear to be a 

good indicator of environmental 

benefits, this is not always the case with 

CHP units. Overall efficiency is a 

function of both efficient design and the 

power to heat ratio (the amount of 

electricity relative to the amount of 

useful thermal output). For example, 

boiler-based CHP units tend to produce 

large amounts of useful thermal output 

relative to electric output and tend to 

have high overall efficiencies. For units 

producing primarily useful thermal 

output, the equivalent separate heat and 

power efficiency (i.e., the theoretical 

overall efficiency if the electricity and 

useful thermal output were produced by 

a stand-alone EGU and stand-alone 

boiler) would approach that of a standalone boiler (e.g., 80 percent). However, 

combustion turbine-based CHP units 

tend to produce relatively equal 

amounts of electricity and useful 

thermal output. In this case, the 

equivalent separate heat and power 

efficiency would be closer to 65 percent. 

Therefore, an exemption based on 

overall efficiency is not an indication of 

the fuel savings a CHP unit will achieve 

relative to separate heat and power. 

Further, this approach would encourage 

the development of CHP units that just 

meet the efficiency exemption criterion 

and would still cover many combustion 

turbine-based industrial CHP units. 

Conversely, while an exemption based 

on fuel savings relative to separate heat 

and power would recognize the 

environmental benefit of highly efficient 

CHP units, it would not consider the 

primary purpose of the CHP unit. 

In the end, the EPA has concluded 

that maintaining the proposed 

percentage electric sales criterion with 

two adjustments addresses both factors 

with which we are concerned. First, we 

are changing the definition of ‘‘potential 

electric output’’ to be based on overall 

net efficiency at the maximum electric 

production rate, instead of just electriconly efficiency. Second, we are 

changing the percentage electric sales 

criterion to reflect the sliding scale, 

which is the overall design efficiency, 

calculated at the maximum useful 

thermal rating of the CHP unit (e.g., a 

CHP unit with a extraction condensing 

steam turbine would determine the 

efficiency at the maximum extraction/

bypass rate), of the unit multiplied by 

the unit’s potential electric output 

instead of one-third of potential electric 

output as proposed. This approach 

recognizes the primary purpose of 

industrial CHP units by providing a 

more generous percentage electric sales 

exemption to CHP units with high 

thermal output. As described 

previously, CHP units with high thermal 

loads tend to be more efficient and will 

therefore have a higher allowable 

percentage electric sales. By amending 

both the definition of ‘‘potential electric 

output’’ and the electric sales threshold, 

we assure that CHP units that primarily 

produce useful thermal output are 

exempted as industrial CHP units even 

if they are selling all of their electric 

output to the grid. As the relative 

amount of electricity generated by the 

CHP unit increases, efficiency will 

generally decrease, thus limiting 

allowable electric sales before 

applicability is triggered. This approach 

also recognizes the environmental 

benefits of increased efficiency by 

encouraging industrial CHP units to be 

designed as efficiently as possible to 

take advantage of the higher electric 

sales permitted by the sliding scale. 

In conclusion, a CHP unit will be an 

affected source unless it is subject to a 

federally enforceable permit that limits 

annual total electric sales to less than or 

equal to the unit’s design efficiency 

multiplied by its potential electric 

output or 219,000 MWh,115 whichever 

is greater. This final applicability 

criterion will only cover CHP units that 

condense a significant portion of steam 

generated by the unit and use the 

electric power generated as a result of 

condensing that steam to supply electric 

power to the grid. CHP facilities that do 

not have a condensing steam turbine 

(e.g., combustion turbine-based CHP 

units without a steam turbine and 

boiler-based systems with a 

backpressure steam turbine) would 

generally not be physically capable of 

selling enough electricity to meet the 

applicability criterion, even if they sold 

100 percent of the electricity generated 

and did not subtract out the electricity 

used by the thermal host(s). The EPA 

has concluded that this is appropriate 

because these sources are industrial by 

design and provide mostly useful 

thermal output. 

CHP facilities with a steam extraction 

condensing steam turbine will 

determine their potential electric output 

based on their efficiency on a net basis 

at the maximum electric production rate 

at the base load heat input rating (e.g., 

the CHP is condensing as much steam 

as possible to create electricity instead 

of using it for useful thermal output). 

We have concluded that it is necessary 

for CHP units with extraction 

condensing steam turbines to calculate 

their potential electric output at the 

maximum condensing level to avoid 

circumvention of the applicability 

criteria. For example, to avoid 

applicability a CHP unit could locate 

next to an industrial host and have the 

capability of selling significant 

quantities of useful thermal output 

without ever actually intending to 

supply much, if any, useful thermal 

output to the industrial host. If we 

calculated the potential electric output 

at the maximum level of thermal output, 

this type of CHP unit could operate at 

full condensing mode at base load 

conditions for the entire year and still 

not exceed the electric sales threshold. 

During the permitting process, the 

owner or operator will be able to 

determine if the unit is subject to the 

final standards in this rule. 

New EGUs with only limited useful 

thermal output will be subject to the 

final standards, but the vast majority of 

new CHP units will be classified as 

industrial CHP and will not be subject 

to the final standards. The EPA has 

concluded that this approach is similar 

to exempting CHP facilities that sell less 

than half of their total output (electricity 

plus thermal), but has the benefit of 

accounting for overall design efficiency. 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64535 

116 79 FR 1447–48. 

This approach both limits applicability 

to the industrial CHP units and 

encourages the installation of the most 

efficient CHP systems because more 

efficient designs will be able to have 

higher permitted electric sales while not 

being subject to the CO2 standards 

included in this rulemaking. 

3. Municipal Waste Combustors and 

Commercial and Industrial Solid Waste 

Incinerators 

The purpose of this rulemaking is to 

establish CO2 standards for fossil fuelfired EGUs. Municipal waste 

combustors and commercial and 

industrial solid waste incinerators 

typically have not been included in this 

source category. Therefore, even if one 

of these types of units meets the general 

heat input and electric sales criteria, we 

are not finalizing CO2 emission 

standards for municipal waste 

combustors subject to subpart Eb of this 

part and commercial and industrial 

solid waste incinerators subject to 

subpart CCCC of this part. 

4. Certain Projects Under Development 

The EPA proposed that a limited class 

of projects under development should 

not be subject to the proposed 

standards. These were planned sources 

that may be capable of commencing 

construction (within the meaning of 

section 111(a)) shortly after the 

standard’s proposal date, and so would 

be classified as new sources, but which 

have a design which would be incapable 

of meeting the proposed standard of 

performance. See 79 FR 1461 and CAA 

section 111(a)(2). The EPA proposed 

that these sources would not be subject 

to the generally-applicable standard of 

performance, but rather would be 

subject to a unit-specific permitting 

determination if and when construction 

actually commences. The EPA indicated 

that there could be three sources to 

which this approach could apply, and 

further indicated that the EPA could 

ultimately adopt the generallyapplicable standard of performance for 

these sources (if actually constructed). 

79 FR 1461. 

As explained at Section III.J below, 

the EPA is finalizing this approach in 

this final rule. We again note that these 

sources, if and when constructed, could 

be ultimately subject to the 1,400 lb 

CO2/MWh-g standard, especially if there 

is no engineering basis, or demonstrated 

action in reliance, showing that the new 

source could not meet that standard. 

E. Coal Refuse 

In the April 2012 proposal, we 

solicited comment on subcategorizing 

and exempting EGUs that burn over 75 

percent coal refuse on an annual basis. 

Multiple commenters supported the 

exemption, citing numerous 

environmental benefits of remediating 

coal refuse piles. Observing that coal 

refuse-fired EGUs typically use 

fluidized bed technologies, other 

commenters disagreed with any 

exemption, specifically citing the N2O 

emissions from fluidized bed boilers. In 

light of the environmental benefits of 

remediating coal refuse piles cited by 

commenters, the limited amount of coal 

refuse, and the fact that a new coal 

refuse-fired EGU would be located in 

close proximity to the coal refuse pile, 

we sought additional comments 

regarding a subcategory for coal refusefired EGUs in the January 2014 

proposal. Specifically, we requested 

additional information on the net 

environmental benefits of coal refusefired EGUs and information to support 

an appropriate emissions standard for 

coal refuse-fired EGUs. One commenter 

on the April 2012 proposal stated that 

existing coal refuse piles are naturally 

combusting at a rate of 0.3 percent 

annually, and we requested comment on 

this rate and the proper approach to 

account for naturally occurring 

emissions from coal refuse piles in the 

January 2014 proposal. 

Commenters said that a performance 

standard is not feasible for coal refuse 

CFBs since there is no economically 

feasible way to capture CO2 through a 

conveyance designed and constructed to 

capture CO2. Commenters suggested that 

the EPA establish BSER for GHGs at 

modified coal refuse CFBs as a boiler 

tune-up that must be performed at least 

every 24 months. Commenters stated 

that the EPA should exempt coal refuse 

CFB units relative to their CO2

emissions to the extent that these units 

offset the uncontrolled ground level 

emissions from spontaneous 

combustion of legacy coal refuse 

stockpiles and noted that the mining of 

coal waste not only produces less 

emissions in the long term, but also 

helps to reclaim land that is currently 

used to store coal waste. In contrast, one 

commenter saw no legitimate basis for 

coal refuse to be subcategorized and 

stated that it should be treated in the 

same manner as all other coal-fired 

EGUs. 

The EPA has concluded that an 

explicit exemption or subcategory 

specifically for coal refuse-fired EGUs is 

not appropriate. The costs faced by coal 

refuse facilities to install CCS are 

similar to coal-fired EGUs burning any 

of the primary coals, and the final 

applicable requirements and standards 

in the rule do not preclude the 

development of new coal refuse-fired 

units without CCS. Specifically, we are 

not finalizing CO2 standards for 

industrial CHP units. Many existing coal 

refuse-fired units are relatively small 

and designed as CHP units. Due to the 

expense of transporting coal refuse long 

distances, we anticipate that any new 

coal refuse-fired EGU would be 

relatively small in size. Moreover, sites 

with sufficient thermal demand exist 

such that the unit could be designed as 

an industrial CHP facility and the 

requirements of this rule would not 

apply. 

F. Format of the Output-Based Standard 

1. Net and Gross Output-Based 

Standards 

For all newly constructed units, the 

EPA proposed standards as gross output 

emission rates consistent with current 

monitoring and reporting requirements 

under 40 CFR part 75.116 For a non-CHP 

EGU, gross output is the electricity 

generation measured at the generator 

terminals. 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. 

Net output is the gross electrical output 

less the unit’s total parasitic (i.e., 

auxiliary) power requirements. A 

parasitic load for an EGU is a load or 

device powered by electricity, steam, 

hot water, or directly by the gross 

output of the EGU that does not 

contribute electrical, mechanical, or 

useful thermal output. In general, 

parasitic energy demands include less 

than 7.5 percent of non-IGCC and nonCCS coal-fired station power output, 

approximately 15 percent of non-CCS 

IGCC-based coal-fired station power 

output, and about 2.5 percent of nonCCS NGCC power output. The use of 

CCS increases both the electric and 

steam parasitic loads used internal to 

the unit, and these outputs are not 

considered when determining the 

emission rate. Net output is used to 

recognize the environmental benefits of: 

(1) EGU designs and control equipment 

that use less auxiliary power; (2) fuels 

that require less emissions control 

equipment; and (3) higher efficiency 

motors, pumps, and fans. For modified 

and reconstructed combustion turbines, 

the EPA also proposed standards as 

gross output emission rates, but 

solicited comment on finalizing net 

output standards. The rationale was that 

due to the low auxiliary loads in nonCCS NGCC designs, the difference 

between a gross-output standard and a 

net-output standard has a limited 

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64536 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

117Additionally, 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. 

118Assuming a 3 percent auxiliary load for the 

NGCC system. 

impact on environmental performance. 

Auxiliary loads are more significant for 

modified and reconstructed boilers and 

IGCC units, and the EPA proposed 

standards on a net output basis for these 

units. The rationale included that this 

would enable owners/operators of these 

types of units to pursue projects that 

reduce auxiliary loads for compliance 

purposes. However, the EPA solicited 

comment on finalizing the standards on 

a gross-output basis. We also proposed 

to use either gross-output or net-output 

bases for each respective subcategory of 

EGUs (i.e., utility boilers, IGCC units, 

and combustion turbines) consistently 

across all CAA section 111(b) standards 

for new, modified, and reconstructed 

EGUs. 

Many commenters supported grossoutput-based standards, maintaining 

that a net-output standard penalizes the 

operation of air pollution control 

equipment. Several commenters 

disagreed with the agency’s proposed 

rationale that a net-output standard 

would provide incentive to minimize 

auxiliary loads. The commenters believe 

utility commissions and existing 

economic forces already provide 

utilities with appropriate incentives to 

properly manage all of these factors. 

Some commenters supported a grossoutput-based standard because 

variations in site conditions (e.g., 

available natural gas pressure, available 

cooling water sources, and elevation) 

will likely penalize some owners and 

benefit others simply through variations 

in their particular plant-site conditions 

if a net basis is used. Several 

commenters stated that if the final rule 

includes a net-output-based standard, it 

should be included as an option in 

conjunction with a gross-output-based 

option. 

Several commenters opposed netoutput-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 wellestablished technology that should be 

required, particularly for newly 

constructed units. 

Other commenters, however, 

maintained that the final rule should 

strictly require compliance on a net 

output-basis. They believe that this is 

the only way for the standards to 

minimize the carbon footprint of the 

electricity delivered to consumers. 

These commenters believe that, at a 

minimum, net-output-based standards 

should be included as an option in the 

final rule. 

We are only finalizing gross-outputbased standards for utility boilers and 

IGCC units. Providing an alternate netoutput-based standard that is based on 

gross-output-based emissions data and 

an assumed auxiliary load is most 

appropriate when the auxiliary load can 

be reasonably estimated and the choice 

between the net- and gross-output-based 

standard will not impact the identified 

BSER. For example, the auxiliary load 

for combustion turbines is relatively 

fixed and small, approximately 2.5 

percent, so the choice between a gross 

and net-output-based standard will not 

substantially impact technology choices. 

However, in the case of utility boilers, 

we have concluded that we do not have 

sufficient information to establish an 

appropriate net-output-based standard 

that would not impact the identified 

BSER for these types of units. The BSER 

for newly constructed steam generating 

units is based on the use of partial CCS. 

However, unlike the case for 

combustion turbines, owners/operators 

of utility boilers have multiple 

technology pathways available to 

comply with the actual emission 

standard. The choice of both control 

technologies and fuel impact the overall 

auxiliary load. For example, a coal-fired 

hybrid EGU (e.g., one that includes 

integrated solar thermal equipment for 

feedwater heating or steam 

augmentation) or a coal-fired EGU cofiring natural gas would have lower 

non-CCS related auxiliary loads and, 

because the amount of CCS needed to 

comply with the standard would also be 

smaller, the CCS auxiliary loads would 

also be reduced. Therefore, we cannot 

identify an appropriate assumed 

auxiliary load to establish an equivalent 

net-output-based standard. In addition, 

many IGCC facilities (which could be 

used as an alternative technology for 

complying with the standard of 

performance; see Sections IV.B and V.P 

below) have been proposed or are 

envisioned as co-production facilities 

(i.e., to produce useful by-products and 

chemicals along with electricity). As 

noted in the proposal, we have 

concluded that predicting the net 

electricity at these co-production 

facilities would be more challenging to 

implement under these circumstances. 

In contrast, based on further 

evaluation and review of issues raised 

by commenters, the EPA is finalizing 

the CO2 standard for combustion turbine 

EGUs in a format that is similar to the 

current NSPS format for criteria 

pollutants. The default final standards 

establish a gross-output-based standard. 

This allows owners/operators of new 

combustion turbines to comply with the 

CO2 emissions standard under part 60 

using the same data currently collected 

under part 75.117 However, many 

permitting authorities commented 

persuasively that the environmental 

benefits of using net-output-based 

standards can outweigh any additional 

complexities for particular units, and 

have indeed adopted net-output 

standards in recent GHG operating 

permits for combustion turbines. We 

expect this trend to continue and have 

concluded that it is appropriate to 

support the expanded use of net-outputbased standards, and therefore are 

allowing certain sources to elect 

between gross output-based and netoutput-based standards. Only 

combustion turbines are eligible to make 

this election. 

The rule specifies an alternative netoutput-based standard of 1,030 lb CO2/ 

MWh-n for combustion turbines. This 

standard is equivalent to the otherwiseapplicable gross-output-based standard 

of 1,000 lb CO2/MWh-g.118

The procedures for requesting this 

alternative net-output-based standard 

require the owner or operator to petition 

the Administrator in writing to comply 

with the alternate applicable net-outputbased standard. If the Administrator 

grants the petition, this election would 

be binding and would be the unit’s sole 

means of demonstrating compliance. 

Owners or operators complying with the 

net-output-based standard must 

similarly petition the Administrator to 

switch back to complying with the 

gross-output-based standard. 

2. Useful Thermal Output 

For CHP units, useful thermal output 

is also used when determining the 

emission rate. Previous rulemakings 

issued by the EPA have prescribed 

various ‘‘discount factors’’ of the 

measured useful thermal output to be 

used when determining the emission 

rate. We proposed that 75 percent credit 

is the appropriate discount factor for 

useful thermal output, and we solicited 

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119As noted above, in the Endangerment Finding, 

the EPA defined the relevant ‘‘air pollution’’ as the 

atmospheric mix of six long-lived and directlyemitted greenhouse gases: carbon dioxide (CO2), 

methane (CH4), nitrous oxide (N2O), 

hydrofluorocarbons (HFCs), perfluorocarbons 

(PFCs), and sulfur hexafluoride (SF6). 74 FR 66497. 

120EPA Greenhouse Gas Reporting Program; 

www.epa.gov/ghgreporting/. 

121See 77 FR 31257–30 (June 3, 2010). 

122 79 FR 1430, 1462 (January 8, 2014). 

123We also discuss our interpretation of the 

requirements for standards of performance and the 

BSER under section 111(d), for existing sources, in 

the section 111(d) rulemaking that the EPA is 

finalizing with this rule. Our interpretations and 

applications of these requirements in the two 

rulemakings are generally consistent with each 

other except to the extent that they reflect 

distinctions between new and existing sources. For 

example, the BSER for new industrial facilities, 

which are expected to have lengthy useful lives, 

should include, at a minimum, the most advanced 

pollution controls available, but for existing 

sources, the additional costs of retrofit may render 

those controls too expensive. 

124 In the 1970 CAAA, Congress defined 

‘‘standard of performance,’’ under section 111(a)(1), 

as—a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable 

through the application of the best system of 

emission reduction which (taking into account the 

cost of achieving such reduction) the Administrator 

determines has been adequately demonstrated. 

In the 1977 CAAA, Congress revised the 

definition to distinguish among different types of 

sources, and to require that for fossil fuel-fired 

sources, the standard: (i) Be based 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 section 111(a)(1) that the standard of 

performance be based on the ‘‘best system of 

emission reduction . . . adequately demonstrated.’’ 

This 1990 CAAA version is the current definition. 

Even so, because parts of the definition as it read 

under the 1977 CAAA were retained in the 1990 

CAAA, the explanation in the 1977 CAAA 

legislative history, and the interpretation in the case 

law, of those parts of the definition in the case law 

remain relevant to the definition as it reads today. 

125Portland 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); 

Continued 

comment on a range from two-thirds to 

three-fourths credit for useful thermal 

output in the proposal for newly 

constructed units and two-thirds to one 

hundred percent credit in the proposal 

for modified and reconstructed units. 

The 75 percent credit was based on 

matching the emission rate, but not the 

overall emissions, of a hypothetical CHP 

unit to the proposed emission rate. 

Many commenters said that in order 

to fully account for the environmental 

benefits of CHP and to reflect the 

environmental benefits of CHP, the EPA 

should allow 100 percent of the useful 

thermal output from CHP units. 

Commenters noted that providing 100 

percent credit for useful thermal output 

is consistent with the past practice of 

the EPA in the stationary combustion 

turbine criteria pollutant NSPS and state 

approaches for determining emission 

rates for CHP units. 

Based on further consideration and 

review of the comments submitted, we 

are finalizing 100 percent credit for 

useful thermal output for all newly 

constructed, modified, and 

reconstructed CHP sources. We have 

concluded that this is appropriate 

because, at the same reported emission 

rate, a hypothetical CHP unit would 

have the same overall GHG emissions as 

the combined emission rate of separate 

heat and power facilities. Any 

discounting of useful thermal output 

could distort the market and discourage 

the development of new CHP units. Full 

credit for useful thermal output 

appropriately recognizes the 

environmental benefit of CHP. 

G. CO2 Emissions Only 

The air pollutant regulated in this 

final action is greenhouse gases. 

However, the standards in this rule are 

expressed in the form of limits on only 

emissions of CO2, and not the other 

constituent gases of the air pollutant 

GHGs.119 We are not establishing a limit 

on aggregate GHGs or separate emission 

limits for other GHGs (such as methane 

(CH4) or nitrous oxide (N2O)) as other 

GHGs represent less than 1 percent of 

total estimated GHG emissions (as CO2e) 

from fossil fuel-fired electric power 

generating units.120 Notwithstanding 

this form of the standard, consistent 

with other EPA regulations addressing 

GHGs, the air pollutant regulated in this 

rule is GHGs.121

H. Legal Requirements for Establishing 

Emission Standards 

1. Introduction 

In the January 2014 proposal, we 

described the principal legal 

requirement for standards of 

performance under CAA section 111(b), 

which is that the standards of 

performance must consist of standards 

for emissions that reflect the degree of 

emission limitation achievable though 

the application of the ‘‘best system of 

emission reduction . . . adequately 

demonstrated,’’ taking into account cost 

and any non-air quality health and 

environment impact and energy 

requirements. We noted that the D.C. 

Circuit has handed down numerous 

decisions that interpret this CAA 

provision, including its component 

elements, and we reviewed that case 

law in detail.122

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.123

2. CAA Requirements and Court 

Interpretation 

As noted above, the CAA section 111 

requirements that govern this rule are as 

follows: As the first step towards 

establishing standards of performance, 

the EPA ‘‘shall publish . . . a list of 

categories of stationary sources . . . 

[that] cause[ ], or contribute[ ] 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health or welfare.’’ CAA section 

111(b)(1)(A). Following that listing, the 

EPA ‘‘shall publish proposed 

regulations, establishing federal 

standards of performance for new 

sources within such category’’ and then 

‘‘promulgate . . . such standards’’ 

within a year after proposal. CAA 

section 111(b)(1)(B). The EPA ‘‘may 

distinguish among classes, types, and 

sizes within categories of new sources 

for the purpose of establishing such 

standards.’’ CAA section 111(b)(2). The 

term ‘‘standard of performance’’ is 

defined to ‘‘mean[ ] a standard for 

emissions . . . achievable through the 

application of the best system of 

emission reduction which [considering 

cost, non-air quality health and 

environmental impact, and energy 

requirements] the Administrator 

determines has been adequately 

demonstrated.’’ CAA section 111(a)(1). 

As noted in the January 2014 

proposal, Congress first included the 

definition of ‘‘standard of performance’’ 

when enacting CAA section 111 in the 

1970 Clean Air Act Amendments 

(CAAA), amended it in the 1977 CAAA, 

and then amended it again in the 1990 

CAAA to largely restore the definition 

as it read in the 1970 CAAA. It is in the 

legislative history for the 1970 and 1977 

CAAAs that Congress primarily 

addressed the definition as it read at 

those times, and that legislative history 

provides guidance in interpreting this 

provision.124 In addition, the D.C. 

Circuit has reviewed rulemakings under 

CAA section 111 on numerous 

occasions during the past 40 years, 

handing down decisions dated from 

1973 to 2011,125 through which the 

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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). 

126See Sierra Club v. Costle, 657 F.2d 298, 326 

(D.C. Cir. 1981). 

127See Sierra Club v. Costle, 657 F.2d at 347. 

128See Lignite Energy Council v. EPA, 198 F.3d 

930, 933 (D.C. Cir. 1999). 

129Although section 111(a)(1) may be read to 

state that the factors enumerated in the 

parenthetical are part of the ‘‘adequately 

demonstrated’’ determination, the D.C. Circuit’s 

case law appears to treat them as part of the ‘‘best’’ 

determination. See Sierra Club v. Costle, 657 F.2d 

at 325–26. It does not appear that those two 

approaches would lead to different outcomes. In 

this rule, the EPA is following the D.C. Circuit case 

law and treating the factors as part of the ‘‘best’’ 

determination. 

130Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 

427, 433 (D.C. Cir. 1973), cert. denied, 416 U.S. 969 

(1974). 

131Portland Cement Ass’n v. Ruckelshaus, 486 

F.2d 375, 391 (D.C. Cir. 1973) (citations omitted) 

(discussing the Senate and House bills and reports 

from which the language in CAA section 111 grew). 

132Portland Cement Ass’n v. Ruckelshaus, 486 

F.2d 375, 391 (D.C. Cir. 1973) (citations omitted). 

133Sierra Club v. Costle, 657 F.2d 298, 364 (1981). 

134Portland Cement Ass’n v. Ruckelshaus, 486 

F.2d 375, 391 (D.C. Cir. 1973) (citations omitted). 

135 79 FR 1464 (January 8, 2014). 

136 Lignite Energy Council v. EPA, 198 F.3d 930, 

933 (D.C. Cir. 1999). 

137Portland Cement Ass’n v. EPA, 513 F.2d 506, 

508 (D.C. Cir. 1975). 

138Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. 

Cir. 1981). 

139Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. 

Cir. 1981). 

140These cost formulations are consistent with 

the legislative history of section 111. The 1977 

House Committee Report noted: 

In the [1970] Congress [sic: Congress’s] view, it 

was only right that the costs of applying best 

practicable control technology be considered by the 

owner of a large new source of pollution as a 

normal and proper expense of doing business. 

1977 House Committee Report at 184. Similarly, 

the 1970 Senate Committee Report stated: 

The implicit consideration of economic factors in 

determining whether technology is ‘‘available’’ 

should not affect the usefulness of this section. The 

overriding purpose of this section would be to 

prevent new air pollution problems, and toward 

that end, maximum feasible control of new sources 

at the time of their construction is seen by the 

committee as the most effective and, in the long 

run, the least expensive approach. 

S. Comm. Rep. No. 91–1196 at 16. Some 

commenters asserted that we do not have authority 

to revise the cost standard as established in the case 

law, e.g., ‘‘exorbitant,’’ ‘‘excessive,’’ etc., to a 

‘‘reasonableness’’ standard that may be considered 

less protective of the environment. We agree that 

we do not have authority to revise the cost standard 

as established in the case law, and we are not 

attempting to do so here. Rather, our description of 

the cost standard as ‘‘reasonableness’’ is intended 

to be a convenient term for referring to the cost 

standard as established in the case law. 

141 1977 House Committee Report at 184. 

142The costs for these standards were described 

in the rulemakings. See 36 FR 24876 (December 23, 

1971), 37 FR 5767, 5769 (March 21, 1972). 

Court has developed a body of case law 

that interprets the term ‘‘standard of 

performance.’’ 

3. Key Elements of Interpretation 

By its terms, the definition of 

‘‘standard of performance’’ under CAA 

section 111(a)(1) provides that the 

emission limits that the EPA 

promulgates must be ‘‘achievable’’ by 

application of a ‘‘system of emission 

reduction’’ that the EPA determines to 

be the ‘‘best’’ that is ‘‘adequately 

demonstrated,’’ ‘‘taking into account 

. . . cost . . . nonair quality health and 

environmental impact and energy 

requirements.’’ The D.C. Circuit has 

stated that, in determining the ‘‘best’’ 

system, the EPA must also take into 

account ‘‘the amount of air 

pollution’’ 126 reduced and the role of 

‘‘technological innovation.’’ 127 The 

Court has emphasized that the EPA has 

discretion in weighing those various 

factors.128 129

Our overall approach to determining 

the BSER, which incorporates the 

various elements, is as follows: First, the 

EPA identifies the ‘‘system[s] of 

emission reduction’’ that have been 

‘‘adequately demonstrated’’ for a 

particular source category. Second, the 

EPA determines the ‘‘best’’ of these 

systems after evaluating extent of 

emission reductions, costs, any non-air 

health and environmental impacts, and 

energy requirements. And third, the 

EPA selects an achievable standard for 

emissions—here, the emission rate— 

based on the performance of the BSER. 

The remainder of this subsection 

discusses the various elements in that 

analytical approach. 

a. ‘‘System[s] of Emission Reduction 

. . . Adequately Demonstrated’’ 

The EPA’s first step is to identify 

‘‘system[s] of emission reduction . . . 

adequately demonstrated.’’ For the 

reasons discussed below, for the various 

types of newly constructed, modified, 

and reconstructed sources in this 

rulemaking, the EPA focused on 

efficient generation, add-on controls, 

efficiency improvements, and clean 

fuels as the systems of emission 

reduction. 

An ‘‘adequately demonstrated’’ 

system, according to the D.C. Circuit, is 

‘‘one which has been shown to be 

reasonably reliable, reasonably efficient, 

and which can reasonably be expected 

to serve the interests of pollution 

control without becoming exorbitantly 

costly in an economic or environmental 

way.’’ 130 It does not mean that the 

system ‘‘must be in actual routine use 

somewhere.’’ 131 Rather, the Court has 

said, ‘‘[t]he Administrator may make a 

projection based on existing technology, 

though that projection is subject to the 

restraints of reasonableness and cannot 

be based on ‘crystal ball’ inquiry.’’ 132

Similarly, the EPA may ‘‘hold the 

industry to a standard of improved 

design and operational advances, so 

long as there is substantial evidence that 

such improvements are feasible.’’ 133

Ultimately, the analysis ‘‘is partially 

dependent on ‘lead time,’ ’’ that is, ‘‘the 

time in which the technology will have 

to be available.’’ 134 Per CAA section 

111(e), standards of performance under 

CAA section 111(b) are applicable 

immediately after the effective date of 

their promulgation. 

(1) Technical Feasibility of the Best 

System of Emission Reduction 

As the January 2014 proposal 

indicates, the requirement that the 

standard for emissions be ‘‘achievable’’ 

based on the ‘‘best system of emission 

reduction . . . adequately 

demonstrated’’ indicates that one of the 

requirements for the technology or other 

measures that the EPA identifies as the 

BSER is that the measure must be 

technically feasible. See 79 FR 1430, 

1463 (January 8, 2014). 

b. ‘‘Best’’ 

In determining which adequately 

demonstrated system of emission 

reduction is the ‘‘best,’’ the EPA 

considers the following factors: 

(1) Costs 

Under CAA section 111(a)(1), the EPA 

is required to take into account ‘‘the cost 

of achieving’’ the required emission 

reductions. As described in the January 

2014 proposal,135 in several cases the 

D.C. Circuit has elaborated on this cost 

factor and formulated the cost standard 

in various ways, stating that the EPA 

may not adopt a standard the cost of 

which would be ‘‘exorbitant,’’ 136

‘‘greater than the industry could bear 

and survive,’’ 137 ‘‘excessive,’’ 138 or 

‘‘unreasonable.’’ 139 For convenience, in 

this rulemaking, we use ‘reasonableness’ 

to describe costs well within the bounds 

established by this jurisprudence.140

The D.C. Circuit has indicated that the 

EPA has substantial discretion in its 

consideration of cost under section 

111(a). In several cases, the Court 

upheld standards that entailed 

significant costs, consistent with 

Congress’s view that ‘‘the costs of 

applying best practicable control 

technology be considered by the owner 

of a large new source of pollution as a 

normal and proper expense of doing 

business.’’ 141 See Essex Chemical Corp. 

v. Ruckelshaus, 486 F.2d 427, 440 (D.C. 

Cir. 1973); 142 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. 

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143 Indeed, in upholding the EPA’s consideration 

of costs under the provisions of the Clean Water Act 

authorizing technology-based standards based on 

performance of a best technology taking costs into 

account, courts have also noted the substantial 

discretion delegated to the EPA to weigh cost 

considerations with other factors. Chemical Mfr’s 

Ass’n v. EPA, 870 F.2d 177, 251 (5th Cir. 1989); 

Association of Iron and Steel Inst. v. EPA, 526 F.2d 

1027, 1054 (3d Cir. 1975); Ass’n of Pacific Fisheries 

v. EPA, 615 F.2d 794, 808 (9th Cir. 1980). 

144See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 

200 (D.C. Cir. 2001) (where CAA section 213 does 

not mandate a specific method of cost analysis, the 

EPA may make a reasoned choice as to how to 

analyze costs). 

145Portland 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). 

146Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 

1981) was governed by the 1977 CAAA version of 

the definition of ‘‘standard of performance,’’ which 

revised the phrase ‘‘best system’’ to read, ‘‘best 

technological system.’’ As noted above, the 1990 

CAAA deleted ‘‘technological,’’ and thereby 

returned the phrase to how it read under the 1970 

CAAA. The court’s interpretation of this phrase in 

Sierra Club v. Costle to require consideration of the 

amount of air emissions reductions remains valid 

for the phrase ‘‘best system.’’ 

147See also NRDC v. EPA, 479 F.3d 875, 880 (D.C. 

Cir. 2006) (‘‘best performing’’ source for purposes 

of CAA section 112 (d)(3) is source with the lowest 

emission levels). 

148 79 FR 1430, 1465 January 8, 2014) (citing 

Sierra Club v. Costle, 657 F.2d at 351). 

149Sierra Club v. Costle, 657 F.2d at 331 (citations 

omitted) (citing legislative history). 

150Sierra Club v. Costle, 657 F.2d at 327–28 

(quoting 44 FR 33583/3–33584/1). In the January 

2014 proposal, we explained that although the D.C. 

Circuit decided Sierra Club v. Costle before the 

Chevron case was decided in 1984, the D.C. 

Circuit’s decision could be justified under either 

Chevron step 1 or 2. 79 FR 1430, 1466 (January 8, 

2014). 

1981) (upholding standard imposing 

controls on SO2 emissions from coalfired power plants when the ‘‘cost of the 

new controls . . . is substantial’’).143

Moreover, section 111(a) does not 

provide specific direction regarding 

what metric or metrics to use in 

considering costs, again affording the 

EPA considerable discretion in choosing 

a means of cost consideration.144

As discussed below, the EPA may 

consider costs on both a source-specific 

basis and a sector-wide, regional, or 

nationwide basis. The EPA is finding 

here that whether costs are considered 

on a source-specific basis, an industry/ 

national basis, or both, they are 

reasonable. See Sections V.H and I 

below. 

(2) Non-Air Quality Health and 

Environmental Impacts 

Under CAA section 111(a)(1), the EPA 

is required to take into account ‘‘any 

nonair quality health and environmental 

impact’’ in determining the BSER. As 

the D.C. Circuit has explained, this 

requirement makes explicit that a 

system cannot be ‘‘best’’ if it does more 

harm than good due to cross-media 

environmental impacts.145 The EPA has 

carefully considered such cross-media 

impacts here, in particular potential 

impacts to underground sources of 

drinking water posed by CO2

sequestration, and water use necessary 

to operate carbon capture systems. See 

Sections V.N and O below. 

(3) Energy Considerations 

Under CAA section 111(a)(1), the EPA 

is required to take into account ‘‘energy 

requirements.’’ As discussed below, the 

EPA may consider energy requirements 

on both a source-specific basis and a 

sector-wide, region-wide, or nationwide 

basis. Considered on a source-specific 

basis, ‘‘energy requirements’’ entail, for 

example, the impact, if any, of the 

system of emission reduction on the 

source’s own energy needs. In this 

rulemaking, as discussed below in 

Section V.O.3, the EPA considered the 

parasitic load requirements of partial 

CCS. The EPA is finding here that 

whether energy requirements are 

considered on a source-specific basis, an 

industry/national basis, or both, they are 

reasonable. See Sections V.O.3 and 

XIII.C. 

(4) Amount of Emissions Reductions 

At proposal, we noted that although 

the definition of ‘‘standard of 

performance’’ does not by its terms 

identify the amount of emissions from 

the category of sources or the amount of 

emission reductions achieved as factors 

the EPA must consider in determining 

the ‘‘best system of emission reduction,’’ 

the D.C. Circuit has stated that the EPA 

must in fact do so. See Sierra Club v. 

Costle, 657 F.2d 298, 326 (D.C. Cir. 

1981) (‘‘we can think of no sensible 

interpretation of the statutory words 

‘‘best . . . system’’ which would not 

incorporate the amount of air pollution 

as a relevant factor to be weighed when 

determining the optimal standard for 

controlling . . . emissions’’).146 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,’’ the EPA must 

consider the amount of emission 

reductions that the system would 

yield.147 Even if the EPA were not 

required to consider the amount of 

emission reductions, the EPA has the 

discretion to do so, on grounds that 

either the term ‘‘system of emission 

reduction’’ or the term ‘‘best’’ may 

reasonably be read to allow that 

discretion. 

(5) Sector or Nationwide Component of 

the BSER Factors 

As discussed in the January 2014 

proposal, another component of the D.C. 

Circuit’s interpretations of CAA section 

111 is that the EPA may consider the 

various factors it is required to consider 

on a national or regional level and over 

time, and not only on a plant-specific 

level at the time of the rulemaking.148

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 

when it discussed section 111.149

The Court has upheld rules that the 

EPA ‘‘justified . . . in terms of the 

policies of the Act,’’ including balancing 

long-term national and regional impacts: 

The standard reflects a balance in 

environmental, economic, and energy 

consideration by being sufficiently stringent 

to bring about substantial reductions in SO2

emissions (3 million tons in 1995) yet does 

so at reasonable costs without significant 

energy penalties. . . . By achieving a 

balanced coal demand within the utility 

sector and by promoting the development of 

less expensive SO2 control technology, the 

final standard will expand environmentally 

acceptable energy supplies to existing power 

plants and industrial sources. 

By substantially reducing SO2 emissions, 

the standard will enhance the potential for 

long term economic growth at both the 

national and regional levels.150

Some commenters objected that this 

case law did not allow the EPA to ignore 

source-specific impacts (particularly 

cost impacts) by basing determinations 

solely on impacts at a regional or 

national level. In fact, the EPA’s 

consideration of cost, non-air quality 

impacts, and energy requirements 

reflect source-specific impacts, as well 

as (for some considerations) impacts 

that are sector-wide, regional, or 

national. See Section V.H.6 below. 

c. Achievability of the Standard for 

Emissions 

In the January 2014 proposal, the EPA 

recognized that the first element of the 

definition of ‘‘standard of performance’’ 

is that ‘‘the emission limit [i.e., the 

‘standard for emissions’] that the EPA 

promulgates must be ‘achievable’ ’’ 

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151Portland Cement, 486 F.2d at 391–92. Some 

commenters stated that the EPA’s analysis of the 

requirements for ‘‘standard of performance,’’ 

including the BSER, attempted to eliminate the 

requirement that the standard for emissions must be 

‘‘achievable.’’ We disagree with this comment. As 

just quoted, the EPA’s analysis recognizes that the 

standard for emissions must be achievable through 

the application of the BSER. 

152Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 

427, 433–34 (D.C. Cir. 1973), cert. denied, 416 U.S. 

969 (1974). 

153Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433, 

n.46 (D.C. Cir. 1980). 

154Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. 

Cir. 1981) (citing Nat’l Lime Ass’n v. EPA, 627 F.2d 

416 (D.C. Cir. 1980). In considering the 

representativeness of the source tested, the EPA 

may consider such variables as the ‘‘‘feedstock, 

operation, size and age’ of the source.’’ Nat’l Lime 

Ass’n v. EPA, 627 F.2d 416, 433 (D.C. Cir. 1980). 

Moreover, it may be sufficient to ‘‘generalize from 

a sample of one when one is the only available 

sample, or when that one is shown to be 

representative of the regulated industry along 

relevant parameters.’’ Nat’l Lime Ass’n v. EPA, 627 

F.2d 416, 434, n.52 (D.C. Cir. 1980). 

155See 79 FR 1430, 1465 (January 8, 2014), Sierra 

Club v. Costle, 657 F.2d at 346–47. 

156Sierra Club v. Costle, 657 F.2d at 346 (‘‘Our 

interpretation of section 111(a) is that the mandated 

balancing of cost, energy, and nonair quality health 

and environmental factors embraces consideration 

of technological innovation as part of that balance. 

The statutory factors which the EPA must weigh are 

broadly defined and include within their ambit 

subfactors such as technological innovation.’’). 

157See 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’’). 

158 79 FR 1465 (citing case law and legislative 

history). 

159Sierra Club v. Costle, 657 F.2d at 319. 160Sierra 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). 

161 Lignite Energy Council v. EPA, 198 F.3d 930, 

933 (D.C. Cir. 1999) (paragraphing revised for 

convenience). See also NRDC v. EPA, 25 F.3d 1063, 

1071 (D.C. Cir. 1994) (The EPA did not err in its 

final balancing because ‘‘neither RCRA nor EPA’s 

regulations purports to assign any particular weight 

to the factors listed in subsection (a)(3). That being 

the case, the Administrator was free to emphasize 

or deemphasize particular factors, constrained only 

by the requirements of reasoned agency decision 

making.’’). 

162 79 FR 1430, 1466 (January 8, 2014). 

based on performance of the BSER. 79 

FR 1430, 1463 (January 8, 2014). 

According to the D.C. Circuit, a standard 

for emissions is ‘‘achievable’’ if a 

technology can reasonably be projected 

to be available to new sources at the 

time they are constructed that will allow 

them to meet the standard.151 Moreover, 

according to the Court, ‘‘[a]n achievable 

standard is one which is within the 

realm of the adequately demonstrated 

system’s efficiency and which, while 

not at a level that is purely theoretical 

or experimental, need not necessarily be 

routinely achieved within the industry 

prior to its adoption.’’ 152 To be 

achievable, a standard ‘‘must be capable 

of being met under most adverse 

conditions which can reasonably be 

expected to recur and which are not or 

cannot be taken into account in 

determining the ‘cost of 

compliance.’ ’’ 153 To show that a 

standard is achievable, the EPA must 

‘‘(1) identify variable conditions that 

might contribute to the amount of 

expected emissions, and (2) establish 

that the test data relied on by the agency 

are representative of potential industrywide performance, given the range of 

variables that affect the achievability of 

the standard.’’ 154

In Sections V.J and IX.D below, we 

show both that the BSER for new steam 

generating units and combustion 

turbines is technically feasible and 

adequately demonstrated, and that the 

standards of 1,400 lb CO2/MWh-g and 

1,000 lb CO2/MWh-g are achievable 

considering the range of operating 

variables that affect achievability. 

d. Expanded Use and Development of 

Technology 

In the January 2014 proposal, we 

noted that the D.C. Circuit has made 

clear that Congress intended for CAA 

section 111 to create incentives for new 

technology and therefore that the EPA is 

required to consider technological 

innovation as one of the factors in 

determining the ‘‘best system of 

emission reduction.’’ 155

The Court grounded its reading in the 

statutory text.156 In addition, in the 

January 2014 proposal, we noted that 

the Court’s interpretation finds 

additional support in the legislative 

history.157 We also explained that the 

legislative history identifies three 

different ways that Congress designed 

CAA section 111 to authorize standards 

of performance that promote 

technological improvement: (i) The 

development of technology that may be 

treated as the ‘‘best system of emission 

reduction . . . adequately 

demonstrated’’ under section 111(a)(1); 

(ii) the expanded use of the best 

demonstrated technology; and (iii) the 

development of emerging technology.158

Even if the EPA were not required to 

consider technological innovation as 

part of its determination of the BSER, it 

would be reasonable for the EPA to 

consider it, either because technological 

innovation may be considered an 

element of the term ‘‘best,’’ or because 

the term ‘‘best system of emission 

reduction’’ is ambiguous as to whether 

technological innovation may be 

considered. The interpretation is 

likewise consistent with the evident 

purpose of section 111(b) to require new 

sources to maximize emission 

reductions using state-of-the-art means 

of control. 

Commenters stated that the 

requirement to consider technological 

innovation does not authorize the EPA 

to identify as the BSER a technology 

that is not adequately demonstrated. 

The proposal did not, and we do not in 

this final rule, claim to the contrary. In 

any event, as discussed below, the EPA 

may justify the control technologies 

identified in this rule as the BSER even 

without considering the factor of 

incentivizing technological innovation 

or development. 

e. Agency Discretion 

As discussed in the January 2014 

proposal, the D.C. Circuit has made 

clear that the EPA has broad discretion 

in determining 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,’’ 159 and emphasized that ‘‘[t]he 

text gives the EPA broad discretion to 

weigh different factors in setting the 

standard.’’ 160 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 111.161

f. Lack of Requirement That Standard 

Must Be Met by All Sources 

In the January 2014 proposal, the EPA 

proposed that, under CAA section 111, 

an emissions standard may meet the 

requirements of a ‘‘standard of 

performance’’ even if it cannot be met 

by every new source in the source 

category that would have constructed in 

the absence of that standard. As 

described in the January 2014 proposal, 

the EPA based this view on (i) the 

legislative history of CAA section 111, 

read in conjunction with the legislative 

history of the CAA as a whole; (ii) case 

law under analogous CAA provisions; 

and (iii) long-standing precedent in the 

EPA rulemakings under CAA section 

111.162

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163Codified at 42 U.S.C. 15962(a). EPAct05 

section 421(a) similarly states: ‘‘No technology, or 

level of emission reduction, shall be treated as 

adequately demonstrated for purpose [sic] of 

section 7411 of this title, . . . solely by reason of 

the use of such technology, or the achievement of 

such emission reduction, by one or more facilities 

receiving assistance under section 13572(a)(1) of 

this title’’. 

164Technical Support Document, Effect of 

EPAct05 on Best System of Emission Reduction for 

New Power Plants, p. 6 (Docket entry: EPA–HQ–

OAR–2013–0495–1873). 

165 Id. 

166 Id. p. 13. 

167 Id. p. 14. 

168Comments of AFPM/API p. 46 (Docket entry: 

EPA–HQ–OAR–2013–0495–10098). 

169State 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-federally-funded 

facilities’’) (emphasis original). 

170For example, any vote of a Justice on the 

Supreme Court may be a necessary but not 

sufficient cause. In a 5–4 decision, the decision of 

the Court would have been different ‘‘but for’’ the 

assent of Justice A or Justice B, who were in the 

majority. But it would be incorrect to say that the 

assent of Justice A was the ‘‘sole’’ reason for the 

outcome, when the decision also required the 

assent of Justice B. 

Commenters contested this assertion, 

arguing that a 111(b) standard must be 

achievable by all new sources. We 

continue to take the same position as at 

proposal for the reasons described there. 

We note that as a practical matter, in 

this rulemaking, the issue of whether all 

new steam-generating sources can 

implement partial-capture CCS is 

largely dependent on the geographic 

scope of geologic sequestration sites. As 

discussed below in Section V.M, 

geologic sequestration sites are widely 

available, and a steam-generating plant 

with partial CCS that is sited near an 

area that is suitable for geologic 

sequestration can serve demand in a 

large area that may not have 

sequestration sites available. In any 

event, the standard of 1,400 lb CO2/MWg that we promulgate in this final rule 

can be achieved by new steam 

generating EGUs—including new utility 

boilers and IGCC units—through cofiring with natural gas in lieu of 

installing partial CCS, which moots the 

issue of the geographic availability of 

geologic sequestration. 

g. EPAct05 

The Energy Policy Act of 2005 

(‘‘EPAct05’’) authorizes assistance in the 

form of grants, loan guarantees, as well 

as federal tax credits for investment in 

‘‘clean coal technology.’’ Sections 

402(i), 421(a), and 1307(b) (adding 

section 48A(g) to the Internal Revenue 

Code (‘‘IRC’’)) address the extent to 

which information from clean coal 

projects receiving assistance under the 

EPAct05 may be considered by the EPA 

in determining what is the best system 

of emission reduction adequately 

demonstrated. Section 402(i) of the 

EPAct05 limits the use of information 

from facilities that receive assistance 

under EPAct05 in CAA section 111 

rulemakings: 

‘‘No technology, or level of emission 

reduction, solely by reason of the use of 

the technology, or the achievement of 

the emission reduction, by 1 or more 

facilities receiving assistance under this 

Act, shall be considered to be 

adequately demonstrated [ ] for 

purposes of section 111 of the Clean Air 

Act. . . .’’ 163

IRC section 48A(g) contains a similar 

constraint concerning the use of 

technology or level of emission 

reduction from EGU facilities for which 

a tax credit is allowed: 

‘‘No use of technology (or level of emission 

reduction solely by reason of the use of the 

technology), and no achievement of any 

emission reduction by the demonstration of 

any technology or performance level, by or at 

one or more facilities with respect to which 

a credit is allowed under this section, shall 

be considered to indicate that the technology 

or performance level is adequately 

demonstrated [ ] for purposes of section 111 

of the Clean Air Act. . . .’’ 

The EPA specifically solicited 

comment on its interpretation of these 

provisions. 79 FR 10750 (Feb. 26, 2014) 

(Notice of Data Availability). With 

respect to EPAct05 sections 402(i) and 

421(a), the EPA proposed that these 

provisions barred consideration where 

EPAct05-assisted facilities were the sole 

support for the BSER determination, but 

that these sources could support a BSER 

determination so long as there is 

additional evidence supporting the 

determination.164 In addition, the EPA 

viewed the two prohibitions as relating 

only to the technology or emissions 

reduction for which assistance was 

given.165 The EPA likewise interpreted 

IRC section 48A(g)—based on the plain 

language and the context provided by 

sections 402(i) and 421(a)—to mean that 

use of technology, or emission 

performance, from a facility for which 

the credit is allowed cannot, by itself, 

support a finding that the technology or 

performance level is adequately 

demonstrated, but the information can 

corroborate an otherwise supported 

determination or otherwise provide part 

of the basis for such a determination.166

The EPA also proposed to interpret the 

phrase ‘‘with respect to which a credit 

is allowed under this section’’ as 

referring to the entire phrase ‘‘use of 

technology (or level of emission 

reduction . . .) and [] achievement of 

any emission reduction . . . , by or at 

one or more facilities.’’ Thus, if 

technology A received a tax credit, but 

technology B at the same facility did 

not, the constraint would not apply to 

technology B.167

Some commenters supported the 

EPA’s proposed interpretation. Others 

contended that the EPA’s interpretation 

would allow it to support a BSER 

determination even where EPAct05 

facility information comprised 99 

percent of the supporting information 

for a BSER determination because that 

determination would not be based 

‘‘solely’’ on EPAct05 sources. These 

commenters urged the EPA to conclude 

that a determination ‘‘solely’’ on the 

basis of information from EPAct05- 

assisted facilities is any determination 

where ‘‘but for’’ that information, the 

EPA could not justify its chosen 

standard as the BSER.168 Other 

commenters argued that the provisions 

bar the EPA from all consideration of 

EPAct05 facilities when determining 

that a technology or level of 

performance is adequately 

demonstrated. 

In this final rule, the EPA is adopting 

the interpretations of all three 

provisions that it proposed, largely for 

the reasons previously advanced. The 

EPA thus interprets these provisions to 

preclude the EPA from relying solely on 

the experience of facilities that received 

DOE assistance, but not to preclude the 

EPA from relying on the experience of 

such facilities in conjunction with other 

information. This reading of sections 

402(i) and 421(a) is consistent with the 

views of the only court to date to 

consider the matter.169

The EPA notes that the extreme 

hypothetical posed in the comments 

(where the EPA might avoid a limitation 

on its consideration of EPAct05-assisted 

facilities by including a mere scintilla of 

evidence from non-EPAct05 facilities) is 

not presented here, where the principal 

evidence that partial post-combustion 

CCS is a demonstrated and feasible 

technology comes from sources which 

received no assistance of any type under 

EPAct05. The EPA also concludes that 

the ‘‘but for’’ test urged by these 

commenters is an inappropriate reading 

of the term ‘‘solely’’ in sections 402(i) 

and 421(a), as any piece of evidence 

may be a necessary, or ‘‘but for,’’ cause 

without being a sufficient, or ‘‘sole,’’ 

cause.170 Nonetheless, if the ‘‘but for’’ 

test were applicable here, the available 

evidence would satisfy it. 

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64542 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

171Supplemental Comments of Murray Energy p. 

11 (Docket entry: EPA–HQ–OAR–2013–0495–9498). 

172With respect to sections 402(i) and 421(a), 

commenters fail to reconcile their reading of the 

statute with the Act’s grammatical structure, as 

explained in detail in chapter 2 of the Response-toComment document. One commenter supported its 

reading by adding suggested text to the statutory 

language, a highly disfavored form of statutory 

construction. Comments of UARG, p.124 n.38 

(Docket entry: EPA–HQ–OAR–2013–0495–9666). 

With respect to section 48A(g), commenters misread 

the phrase ‘‘considered to indicate,’’ and do not 

explain how their reading of all three provisions 

together is tenable. 

173 ‘‘Wolverine ends plant speculation in Rogers 

City’’, The Alpena News, December 17, 2013. http:// 

www.thealpenanews.com/page/content.detail/id/

527862/Wolverine-ends-plant-speculation-inRogers-City.html?nav=5004. 

Other commenters took the extreme 

position that the EPAct05 provisions bar 

all consideration of a facility’s existence 

if the facility received EPAct05 

assistance.171 The EPA does not accept 

this argument because it is contrary to 

both the plain statutory language 172 (see 

Chapter 2 of the Response-to-Comment 

document) and to Congress’s intent that 

the EPAct05 programs advance the 

commercialization of clean coal 

technology. For the same reason, the 

EPA does not accept some commenters’ 

suggestion that sections 402(i), 421(a), 

and 48A(g) preclude the EPA from 

considering NETL’s cost projections for 

CCS, which base cost estimates on upto-date vendor quotes reflecting costs for 

the CCS technology being utilized at the 

Boundary Dam Unit #3 facility (a 

facility receiving no assistance under 

EPAct05), but also considers that to-bebuilt plants will no longer be first-of-a 

kind. See generally Section V.I.2 below. 

Commenters suggest that the EPAct05 

requires that the EPA treat future plants 

as ‘‘first of a kind’’ when projecting 

costs, as if EPAct05 facilities simply did 

not exist. This reading is contrary to the 

text of the provisions, which as noted, 

relates specifically to a source’s 

performance and operation (whether a 

technology is demonstrated, and the 

level of performance achieved by use of 

technology), not to sources’ existence. 

NETL’s cost projections, on the other 

hand, merely acknowledge the evident 

fact that CCS technologies exist, and 

reasonably project that they will 

continue to develop. See Section V.I.2. 

The NETL cost estimates, moreover, are 

based on vendor quotes for the CCS 

technology in use at the Boundary Dam 

facility, a Canadian plant which 

obviously is not a recipient of EPAct05 

assistance. See sections V.D.2.a and V. 

I.2 below. 

In any case, as shown in Section V 

below, the EPA finds that a new highlyefficient SCPC EGU implementing 

partial post-combustion CCS is the best 

system of emission reduction 

adequately demonstrated and is doing 

so based in greater part on performance 

of facilities receiving no assistance 

under EPAct05, and on other 

information likewise not having any 

connection to EPAct05 assistance. The 

corroborative information from EPAct05 

facilities, though supportive, is not 

necessary to the EPA’s findings. 

I. Severability 

This rule has numerous components, 

and the EPA intends that they be 

severable from each other to the extent 

that they function separately. For 

example, the EPA intends that each set 

of BSER determinations and standards 

of performance in this rulemaking be 

severable from each other set. That is, 

the BSER determination and standard of 

performance for newly constructed 

fossil fuel-fired electric utility steam 

generating units are severable from all 

the other BSER determinations and 

standards of performance, and the same 

is true for the BSER determination and 

standard of performance for modified 

fossil fuel-fired electric utility steam 

generating units, and so on. It is 

reasonable to consider each set of BSER 

determination and standard of 

performance to be severable from each 

other set of BSER determination and 

standard of performance because each 

set is independently justifiable and does 

not depend on any other set. Thus, in 

the event that a court should strike 

down any set of BSER determination 

and standard of performance, the 

remaining BSER determinations and 

standards of performance should not be 

affected. 

J. Certain Projects Under Development 

In the January 2014 proposal, the EPA 

indicated that the proposed Wolverine 

EGU project (Rogers City, Michigan) 

appeared to be the only fossil fuel-fired 

steam generating unit that was currently 

under development that may be capable 

of ‘‘commencing construction’’ for NSPS 

purposes at the time of the proposal. See 

79 FR 1461. The EPA also 

acknowledged that the Wolverine EGU, 

as designed, would not meet the 

proposed standard of 1,100 lb CO2/

MWh for new utility steam generating 

EGUs. The EPA proposed that, at the 

time of finalization of the proposed 

standards, if the Wolverine project 

remains under development and has not 

either commenced construction or been 

canceled, we anticipated proposing a 

standard of performance specifically for 

that facility. Additional discussion of 

the approach can be found in the 

proposal or in the technical support 

document in the docket entitled ‘‘Fossil 

Fuel-Fired Boiler and IGCC EGU 

Projects under Development: Status and 

Approach.’’ 

In December 2013—after the proposed 

action was signed, but before it was 

published—Wolverine Power 

Cooperative announced that it was 

cancelling construction of the proposed 

coal-fired power plant in Rogers City, 

MI.173 Therefore, we are not finalizing 

the proposed exclusion for that project. 

In the January 2014 proposal, the EPA 

also identified two other fossil fuel-fired 

steam generating EGU projects that, as 

currently designed, would not meet the 

proposed 1,100 lb CO2/MWh emissions 

standard—the Plant Washington project 

in Georgia and the Holcomb 2 project in 

Kansas. We indicated that, at the time 

of the proposal, those projects appeared 

to remain under development but that 

the project developers had represented 

that the projects have commenced 

construction for NSPS purposes and, 

thus, would not be new sources subject 

to the proposed or final NSPS. Based 

solely on the developers’ 

representations, the EPA indicated that 

those projects, if ultimately fully 

constructed, would be existing sources, 

and would thus not be subject to the 

standards of performance in this final 

action. 

To date, neither developer has sought 

a formal EPA determination of NSPS 

applicability. As we specified in the 

January 2014 proposal—and we reiterate 

here—if such an applicability 

determination concludes that either the 

Plant Washington (GA) project or the 

Holcomb 2 (KS) project did not 

commence construction prior to January 

8, 2014 (the publication of the January 

2014 proposal), then the project should 

be situated similarly to the disposition 

the EPA proposed for the Wolverine 

project. Accordingly, the EPA is 

finalizing in this action that if it is 

determined that either of these projects 

has not commenced construction as 

January 8, 2014, then that project will be 

addressed in the same manner as was 

proposed for the Wolverine project. 

In public comments submitted in 

response to the January 2014, 

Power4Georgians (P4G), the Plant 

Washington developer, reiterated that 

they had executed binding contracts for 

the purchase and erection of the facility 

boiler prior to publication of the January 

2014 proposal and believe that the 

binding contracts are sufficient to 

constitute commencement of 

construction for purposes of the NSPS 

program, so that they are existing rather 

than new sources for purposes of this 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64543 

174 Docket entry: EPA–HQ–OAR–2013–0495– 

9403. 

175 Docket entry: EPA–HQ–OAR–2013–0495– 

9599. 

176 ‘‘Kansas High Court Invalidates 895–MW Coal 

Project Air Permit’’, Power Magazine, 10/10/2013, 

available at: www.powermag.com/kansas-highcourt-invalidates-2010-895-mw-coal-project-airpermit/. 

177http://www.macon.com/2015/06/23/3811798/

audit-sandersville-coal-plant.html. 

178 In the proposed emission guidelines for 

existing EGUs, the EPA did not include estimates 

of emissions for either Plant Washington or the 

Holcomb 2 unit in baseline data used to calculate 

proposed state goals for Georgia and Kansas. It 

appears that the possibility of these plants actually 

being built and operating is too remote. If either 

unit eventually seeks an applicability determination 

and that unit is determined to be an existing source, 

and there is reliable evidence that the source will 

operate, then the source will be subject to the final 

111(d) rule and the EPA will allow the state to 

adjust its state goal to reflect adjustment of the 

state’s baseline data so as to include the unit. 

Guidance for adjustment of state goals is provided 

in the record for the EPA’s final CAA section 111(d) 

rulemaking. 

179 ‘‘Fossil Fuel-Fired Boiler and IGCC EGU 

Projects Under Development: Status and 

Approach’’, Technical Support Document at pp. 

10–1 (Docket Entry: EPA–HQ–OAR–2013–0495– 

0024). 

rule.174 Public comments submitted by 

Tri-State Generation and Transmission 

Association and Sunflower Electric 

Power Corporation, the developers of 

the Holcomb 2 project, discussed the 

cost incurred in the development of the 

project. They also indicated they had 

awarded contracts for the turbine/

generator purchase and had negotiated a 

rail-supply agreement that provides for 

the delivery of fuel to the proposed 

Holcomb 2 site. The developers did not, 

however, explicitly characterize the 

construction status of the project.175

Other groups submitted comments 

contending that neither project has 

actually commenced construction. 

In October 2013, the Kansas Supreme 

Court invalidated the 2010 air pollution 

permit granted to Sunflower Electric 

Power Corporation by the Kansas 

Department of Health and Environment 

(KDHE).176 In May 2014, the KDHE 

issued an air quality permit addendum 

for the proposed Holcomb 2 coal plant. 

The addendum addressed federal 

regulations that the Kansas Supreme 

Court held had been overlooked in the 

initial permitting determination. In June 

2014, the Sierra Club filed an appeal 

with the Kansas Appellate Court 

challenging the legality of the May 2014 

permit. Since the publication of the 

January 2014 proposal, the EPA is 

unaware of any physical construction 

activity at the proposed Holcomb 2 site. 

In October 2014, the Plant 

Washington project was given an 18- 

month air permit extension by the 

Georgia Environmental Protection 

Division (EPD). However, as with the 

Holcomb expansion project, the EPA is 

unaware of any physical construction 

that has taken place at the proposed 

Plant Washington site and a recent audit 

of the project described it as 

‘‘dormant’’.177

Based on this information, it appears 

that these sources have not commenced 

construction for purposes of section 

111(b) and therefore would likely be 

new sources should they actually be 

constructed. As noted above, the EPA 

proposed that, if these projects are 

determined to not have commenced 

construction for NSPS purposes prior to 

the publication of the proposed rule, 

they will be addressed in the same 

manner proposed for the Wolverine 

project. 79 FR 1461. We are finalizing 

that proposal here. However, because 

these units may never actually be fully 

built and operated, we are not 

promulgating a standard of performance 

at this time because such action may 

prove to be unnecessary.178

There is one possible additional new 

EGU, the Two Elk project in Wyoming. 

In a supporting TSD accompanying the 

January 2014 proposal, we discussed the 

Two Elk project and relied on developer 

statements and state acquiescence that 

the unit had commenced construction 

for NSPS purposes before January 8, 

2014.179 We did not, therefore, propose 

any special section 111(b) standard for 

the project. Some commenters 

maintained that a continuous program 

of construction at the facility has not 

been maintained and that if the plant is 

ultimately constructed, it should be 

classified as a new source under CAA 

section 111(b). These comments were 

not specific enough to change the EPA’s 

view of the project for purposes of this 

rulemaking. We accordingly continue to 

rely on developer statements that this 

facility has commenced construction 

and would not be a new source for 

purposes of this proceeding. 

IV. Summary of Final Standards for 

Newly Constructed, Modified, and 

Reconstructed Fossil Fuel-Fired Electric 

Utility Steam Generating Units 

This section sets forth the standards 

for newly constructed, modified, and 

reconstructed steam generating units 

(i.e., utility boilers and IGCCs). We 

explain the rationale for the final 

standards in Sections V (newly 

constructed steam generating unit), VI 

(modified steam generating units), and 

VII (reconstructed steam generating 

units). 

A. Applicability Requirements and 

Rationale 

We generally refer to fossil fuel-fired 

electric utility generating units that 

would be subject to an emission 

standard in this rulemaking as 

‘‘affected’’ or ‘‘covered’’ sources, units, 

facilities or simply as EGUs. These units 

meet both the definition of ‘‘affected’’ 

and ‘‘covered’’ EGUs subject to an 

emission standard as provided by this 

rule, and the criteria for being 

considered ‘‘new,’’ ‘‘modified’’ or 

‘‘reconstructed’’ sources as defined 

under the provisions of CAA section 

111 and the EPA’s regulations. This 

section discusses applicability for newly 

constructed, modified, and 

reconstructed steam generating units. 

1. General Applicability Criteria 

The EPA is finalizing applicability 

criteria for new, modified, and 

reconstructed electric utility steam 

generating units (i.e., utility boilers and 

IGCC units) in 40 CFR part 60, subpart 

TTTT that are similar to the 

applicability criteria for those units in 

40 CFR part 60, subpart Da (utility 

boiler and IGCC performance standards 

for criteria pollutants), but with some 

differences. The proposed applicability 

criteria, relevant comments, and final 

applicability criteria specific to newly 

constructed, modified, and 

reconstructed steam generating units are 

discussed below. 

The applicability requirements in the 

proposal for newly constructed EGUs 

included that a utility boiler or IGCC 

unit must: (1) Be capable of combusting 

more than 250 MMBtu/h heat input of 

fossil fuel; (2) be constructed for the 

purpose of supplying, and actually 

supply, more than one-third of its 

potential net-electric output capacity to 

any utility power distribution system 

(that is, to the grid) for sale on an annual 

basis; (3) be constructed for the purpose 

of supplying, and actually supply, more 

than 219,000 MWh net-electric output 

to the grid on an annual basis; and (4) 

combust over 10 percent fossil fuel on 

a heat input basis over a 3-year average. 

At proposal, applicability was 

determined based on a combination of 

design and actual operating conditions 

that could change annually depending 

on the proportion and the amount of 

electricity actually sold and on the 

proportion of fossil fuels combusted by 

the unit. 

In the proposal for modified and 

reconstructed EGUs, we proposed a 

broader applicability approach such that 

applicability would be based solely on 

design criteria and would be identical to 

the applicability requirements in 

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64544 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

subpart Da. First, we proposed electric 

sales criteria that the source be 

constructed for the purpose of selling 

more than one-third of their potential 

electric output and more than 219,000 

MWh to the grid on an annual basis, 

regardless of the actual amount of 

electricity sold (i.e., we did not include 

the applicability criterion that the unit 

actually sell the specified amount of 

electricity on an annual basis). In 

addition, we proposed a base load rating 

criterion that the source be capable of 

combusting more than 250 MMBtu/h of 

fossil fuel, regardless of the actual 

amount of fossil fuel burned (i.e., we did 

not include the fossil fuel-use criterion 

that an EGU actually combust more than 

10 percent fossil fuel on a heat input 

basis on a 3-year average). Under this 

approach, applicability would be known 

prior to the unit actually commencing 

operation and would not change on an 

annual basis. We also proposed that the 

final applicability criteria would be 

consistent for newly constructed, 

reconstructed, and modified units. The 

proposed broad applicability criteria 

would still not have included boilers 

and IGCC units that were constructed 

for the purpose of selling one-third or 

less of their potential output or 219,000 

MWh or less to the grid on an annual 

basis. These units are not covered under 

subpart Da (the utility boiler and IGCC 

EGU criteria pollutant NSPS) but are 

instead covered as industrial boilers 

under subpart Db (industrial, 

institutional, and commercial boilers 

NSPS) or subpart KKKK (the 

combustion turbine criteria pollutant 

NSPS). 

We solicited comment on whether, to 

avoid implementation issues related 

with different interpretations of 

‘‘constructed for the purpose,’’ the total 

and percentage electric sales criteria 

should be recast to be based on permit 

conditions. The ‘‘constructed for the 

purpose’’ language was included in the 

original subpart Da rulemaking. At that 

time, the vast majority of new steam 

generating units were clearly base load 

units. The ‘‘constructed for the 

purpose’’ language was intended to 

exempt industrial CHP units. These 

units tend to be relatively small and 

were not the focus of the rulemaking. In 

addition, units not meeting the electric 

sales applicability criteria in subpart Da 

would be covered by other NSPS so 

there is limited regulatory incentive, or 

impact to the environment, for owners/ 

operators to avoid applicability with the 

utility NSPS. However, for new units, 

there is no corresponding industrial unit 

CO2 NSPS and existing units could 

debate their original intent (i.e., the 

purpose for which they were 

constructed) in an attempt to avoid 

applicability under section 111(d) 

requirements. Consequently, there could 

be a regulatory incentive for owners/

operators to circumvent the CO2 NSPS 

applicability. For units that avoid 

coverage, there would also be a 

corresponding environmental impact. 

For example, an owner/operator of a 

new unit could initially request a permit 

restriction to limit electric sales to less 

than one-third of potential annual 

electric output, but amend the operating 

permit shortly after operation has 

commenced to circumvent the intended 

applicability. Many existing units were 

initially built with excess capacity to 

account for projected load growth and 

were intended to sell more than onethird of their potential electric output. 

However, due to various factors (lower 

than expected load growth, availability 

of other lower cost units, etc.), certain 

units might have sold less than onethird of their potential electric output, at 

least during their initial period of 

operation. Therefore, the EPA has 

concluded that determining 

applicability based on whether a unit is 

‘‘constructed for the purpose of 

supplying one-third or more of its 

potential electric output and more than 

219,000 MWh as net-electric sales’’ 

(emphasis added) could create 

applicability uncertainty for both the 

regulated community and regulators. In 

addition, we have concluded that 

applicability based on actual operating 

conditions (i.e., actual electric sales) is 

not ideal because applicability would 

not be known prior to determining 

compliance and could change annually. 

This action finalizes applicability 

criteria based on design characteristics 

and federally enforceable permit 

restrictions included in each individual 

permit. Based on restrictions, if any, on 

annual total electric sales in the 

operating permit, it will be clear from 

the time of construction whether or not 

a new unit is subject to this rule. The 

applicability includes all utility boilers 

and IGCC units unless the electric sales 

restriction was in the original and 

remains in the current operating permit 

without any lapses (this is to be 

consistent with the ‘constructed for the 

purpose of’ criteria in subpart Da). We 

have concluded that this approach is 

equivalent to, but clearer than, the 

existing language used in subpart Da. In 

addition, we have concluded that it is 

important for both the 111(b) and 111(d) 

requirements for electric-only steam 

generating units that the permit 

restriction limiting annual electric sales 

be included in both the original and 

current operating permit. Without this 

restriction, existing units could avoid 

obligations under state plans developed 

as part of the 111(d) program by 

amending their operating permit to limit 

total annual electric sales to one-third of 

potential electric output. These units 

would not be subject to any GHG NSPS 

requirements because they would not 

meet the 111(b) or 111(d) applicability 

criteria and, at this time, there is no 

NSPS that would cover these units. As 

described in Section III, industrial CHP 

and dedicated non-fossil units also are 

not affected EGUs under this final 

action. 

In this rule, we are finalizing the 

definition of a steam generating EGU as 

a utility boiler or IGCC unit that: (1) Has 

a base load rating greater than 260 GJ/ 

h (250 MMBtu/h) of fossil fuel (either 

alone or in combination with any other 

fuel) and (2) serves a generator capable 

of supplying more than 25 MW-net to a 

utility distribution system (i.e., for sale 

to the grid). However, we are not 

establishing final CO2 standards for 

certain EGUs. These include: (1) Steam 

generating units and IGCC units that are 

currently subject to—and have been 

continuously subject to—a federally 

enforceable permit limiting annual 

electric sales to one-third or less of their 

potential electric output (e.g., limiting 

hours of operation to less than 2,920 

hours annually) or limiting annual 

electric sales to 219,000 MWh or less; 

(2) units subject to a federally 

enforceable permit that limits the use of 

fossil fuels to 10 percent or less of the 

unit’s heat input capacity on an annual 

basis; and (3) CHP units that are subject 

to a federally enforceable permit 

condition limiting annual total electric 

sales to no more than their design 

efficiency times their potential electric 

output, or to no more than 219,000 

MWh, whichever is greater. 

2. Applicability Specific to Newly 

Constructed Steam Generating Units 

In CAA section 111(a)(2), a ‘‘new 

source’’ is defined as any stationary 

source, the construction or modification 

of which is commenced after the 

publication of regulations (or if earlier, 

proposed regulations) prescribing a 

standard of performance under this 

section which will be applicable to such 

source. Accordingly, for purposes of this 

rule, a newly constructed steam 

generating EGU is a unit that fits the 

definition and applicability criteria of a 

fossil fuel-fired steam generating EGU 

and commences construction on or after 

January 8, 2014, which is the date that 

the proposed standards were published 

for those sources (see 79 FR 1430). 

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180 40 CFR 60.2, 60.14(e). 

181 40 CFR 60.15. 

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’’ that either ‘‘increases the 

amount of any air pollutant emitted by 

such source or . . . 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.180

For purposes of this rule, a modified 

steam generating EGU is a unit that fits 

the definition and applicability criteria 

of a fossil fuel-fired steam generating 

EGU and that modifies on or after June 

18, 2014, which is the date that the 

proposed standards were published for 

those sources (see 79 FR 34960). 

4. Applicability Specific to 

Reconstructed Steam Generating Units 

The NSPS general provisions (40 CFR 

part 60, subpart A) provide that an 

existing source is considered a new 

source if it undertakes a 

‘‘reconstruction,’’ which is the 

replacement of components of an 

existing facility to an extent that: (1) The 

fixed capital cost of the new 

components exceeds 50 percent of the 

fixed capital cost that would be required 

to construct a comparable entirely new 

facility, and (2) it is technologically and 

economically feasible to meet the 

applicable standards.181

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 

In the January 2014 proposal, the EPA 

proposed that highly efficient new 

generation technology implementing 

partial CCS is the BSER for GHG 

emissions from new steam generating 

EGUs. (See generally 79 FR 1468–1469.) 

In this final action, the EPA has 

determined that the BSER for newly 

constructed steam generating units is a 

new highly efficient supercritical 

pulverized coal (SCPC) boiler 

implementing partial CCS technology to 

the extent of removal efficiency that 

meets a final emission limitation of 

1,400 lb CO2/MWh-g. The final standard 

of performance is less stringent than the 

proposed emission limitation of 1,100 lb 

CO2/MWh-g. This change, as will be 

discussed in greater detail later in this 

preamble, is in response to public 

comments and reflects both a reexamination of the potential BSER 

technologies and the most recent, 

reliable information regarding 

technology costs. A newly constructed 

fossil fuel-fired supercritical utility 

boiler will be able to meet the final 

standard by implementing postcombustion carbon capture treating a 

slip-stream of the combustion flue gas. 

Alternative potential compliance paths 

are to build a new IGCC unit and co-fire 

with natural gas (or use pre-combustion 

carbon capture on a slip-stream), or for 

a supercritical utility boiler to co-fire 

with natural gas. 

The EPA of course realizes that the 

final standard of performance (1,400 lb 

CO2/MWh-g) differs from the proposed 

standard (1,100 lb CO2/MWh-g). The 

EPA notes further, however, that the 

methodology for determining the final 

standard of performance is identical to 

that at proposal—determining that a 

new highly efficient generating 

technology implementing some degree 

of partial CCS is the BSER, with that 

degree of implementation being 

determined based on the reasonableness 

of costs. A key means of assessing the 

reasonableness of cost at proposal was 

comparison of the levelized cost of 

electricity (LCOE) with that of other 

dispatchable, base load non-NGCC 

generating options. We have maintained 

that approach in identifying BSER for 

the final standard. Applying this 

methodology to the most recent cost 

information has led the EPA to adopt 

the final standard of performance of 

1,400 lb CO2/MWh-g. See Section V.H at 

Table 8 below. This final standard 

reflects the level of emission reduction 

achievable by a highly efficient SCPC 

implementing the degree of partial CCS 

that remains cost comparable to the 

other non-NGCC dispatchable base load 

generating options. 

The BSER for newly constructed 

steam generating EGUs in the final rule 

is very similar to that in the proposal. 

In this final action, the EPA finds that 

a highly efficient new SCPC EGU 

implementing partial CCS to the degree 

necessary to achieve an emission of 

1,400 lb CO2/MWh-g is the BSER. 

Contrary to the January 2014 proposal, 

the EPA finds that IGCC technology— 

either alone or implementing partial 

CCS—is not part of the BSER, but rather 

is a viable alternative compliance 

option. As noted at proposal, a BSER 

typically advances performance of a 

technology beyond current levels of 

performance. 79 FR 1465, 1471. 

Similarly, promotion of technology 

innovation can be a relevant factor in 

BSER determinations. Id. and Section 

III.H.3.d above. For these reasons, the 

EPA at proposal voiced concerns about 

adopting standards that would allow an 

IGCC to comply without utilizing CCS 

for slip-stream control. Id. at 1471. The 

final standard of 1,400 lb CO2/MWh-g, 

adopted as a means of assuring 

reasonableness of costs, allows IGCC 

units to comply without using partial 

CCS. Thus, although the standard can be 

met by a highly efficient new IGCC unit 

using approximately 3 percent partial 

CCS (see Sections V.E and V.H.7 below), 

the EPA does not believe that 

implementation of partial CCS at such a 

low level, while technically feasible, is 

the option that utilities and project 

developers will choose. The EPA 

believes that IGCC project developers 

will either choose to meet the final 

standard by co-firing with natural gas— 

which would be a less costly and very 

straightforward process for a new IGCC 

unit—or they will choose to install CCS 

equipment that will allow the facility to 

achieve much deeper CO2 reductions 

than required by this rule—likely to coproduce chemicals and/or to capture 

large volumes of CO2 for use in EOR 

operations. Similarly, project developers 

may also—as an alternative to utilizing 

partial CCS technology—meet the final 

standard by co-firing approximately 40 

percent natural gas in a new highly 

efficient SCPC EGU. 

While the EPA does not find that 

IGCC technology—either alone or with 

implementation of partial CCS—is part 

of the BSER for new steam generating 

EGUs, we remain convinced that it is 

technically feasible (see Section V.E 

below) and believe that it represents a 

viable alternative compliance option 

that some project developers will 

consider to meet the final standard 

issued in this action. The EPA notes 

further that IGCC is available at 

reasonable cost (see Table 9 below), and 

involves use of an advanced technology. 

So, although the final standard reflects 

performance of a BSER which includes 

partial CCS, even in the instances that 

a compliance alternative might be 

utilized, that alternative would both 

result in emission reductions consistent 

with use of the BSER, and would reflect 

many of the underlying principles and 

attributes of the BSER (costs are both 

reasonable, not greatly dissimilar than 

BSER, no collateral adverse impacts on 

health or the environment, and reflects 

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182Although co-firing with natural gas is not part 

of BSER, as noted above, it could be part of a 

compliance pathway for either SCPC or IGCC units. 

In this regard, a number of commenters addressed 

the issue of natural gas co-firing, indicating that 

there were circumstances where it could be part of 

BSER. See e.g. Comments of Exelon Corp. p. 12 

(Docket entry: EPA–HQ–OAR–2013–0495–9406); 

Comments of the Sierra Club p. 108 Docket entry: 

EPA–HQ–OAR–2013–0495–9514). See Northeast 

Md. Waste Disposal Authority v. EPA, 358 F.3d 936, 

952 (D.C. Cir. 2004); Appalachian Power v. EPA, 

135 F.3d 791, 816 (D.C. Cir. 1998) (commenters 

understood a matter was under consideration when 

they addressed it in comments). 

183Certain commenters maintained that the BSER 

determination does not comply with (purportedly) 

binding legal requirements created by regulations 

implementing the Information Quality Act. These 

comments are mistaken as a matter of both law and 

fact. The Information Quality Act does not create 

legal rights in third parties (see, e.g. Mississippi 

Comm’n on Environmental Quality v. EPA, no. 12– 

1309 at 84 (D.C. Cir. June 2, 2015)), and the OMB 

Guidelines are not binding rules but rather, as their 

title indicates, guidance to assist agencies. See State 

of Mississippi, 744 F.3d at 1347 (the Guidelines 

provide ‘‘policy and procedural guidance’’, are 

meant to be ‘‘flexible’’ and are to be implemented 

differently by different agencies accounting for 

circumstances). There are also significant factual 

omissions and mischaracterizations in these 

comments regarding peer review of the proposed 

standard and underlying record information. The 

complete response to these comments is in chapter 

2 of the RTC. See also Section V.I.2.a and N below 

describing findings of the SAB panel that materials 

of the National Energy Technology Laboratory had 

been fully and adequately peer reviewed, and that 

the EPA findings related to sequestration of 

captured CO2 reflected the best available science. 

performance of an advanced 

technology). 

In reaching the final standard of 

performance, the EPA is aware that at 

proposal, the agency stated that it was 

not ‘‘currently considering’’ a standard 

of performance as high as 1,400 lb CO2/ 

MWh-g. 79 FR 1471. However, in that 

same discussion, the EPA noted the 

reasons for its reservations (chiefly 

reservations about the extent of 

emission reductions, promotion of 

advanced CO2 control technologies, and 

whether the standard could be met by 

either utility boilers or IGCC units cofiring with natural gas, or otherwise 

complying without utilizing partial 

CCS), and we specifically solicited 

comment on the issue: ‘‘We request that 

commenters who suggest emission rates 

above 1,200 lb CO2/MWh address 

potential concerns about providing 

adequate reductions and technology 

development to be considered BSER.’’ 

Id. The proposal thus both solicited 

comment on higher emission standards 

(including 1,400 lb CO2/MWh-g based 

on a less aggressive rate of partial CCS), 

and provided ample notice of the 

methodology the EPA would use to 

determine the final BSER and the 

corresponding final standard.182 For 

these reasons, the EPA believes that it 

provided adequate notice of this 

potential outcome at proposal, that the 

final standard of performance was 

reasonably foreseeable, and that the 

final standard is a logical outgrowth of 

the proposed rule. Allina Health 

Services v. Sebelius, 746 F. 3d 1102, 

1107 (D.C. Cir. 2014). 

A more detailed discussion of the 

rationale for the final BSER 

determination and of other systems that 

were also considered is provided in 

Section V.P of this preamble.183

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. However, as 

explained below, the final BSER 

determination and the scope of 

modifications to which the final 

standards apply differ in some 

important respects from what the EPA 

proposed. 

The EPA proposed that the modified 

unit’s best potential performance would 

be determined depending upon when 

the unit implemented the modification 

(i.e., before or after being subject to an 

approved CAA section 111(d) state 

plan). For units that commenced 

modification prior to becoming subject 

to an approved CAA section 111(d) state 

plan, the EPA proposed 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 affected 

steam generating units that implement 

larger modifications that are consistent 

with the proposed BSER determination 

for those units. The final standard for 

those sources that implement larger 

modifications is a unit-specific emission 

limitation consistent with each 

modified unit’s best one-year historical 

performance (during the years from 

2002 to the time of the modification), 

but does not include the additional two 

percent reduction that was proposed in 

the January 2014 proposal. 

In this action, the EPA is not 

finalizing standards for those sources 

that conduct smaller modifications and 

is withdrawing the proposed standards 

for those sources. See Section XV below. 

A more detailed discussion of the 

rationale for the BSER determination 

and final standards is provided in 

Section VI of this preamble. 

3. BSER for Reconstructed Steam 

Generating Units 

Consistent with our proposal, the EPA 

has determined that the BSER for 

reconstructed steam generating units is 

the most efficient demonstrated 

generating technology for these types of 

units (i.e., meeting a standard of 

performance consistent with a 

reconstructed boiler using the most 

efficient steam conditions available, 

even if the boiler was not originally 

designed to do so). A more detailed 

discussion of the rationale for the BSER 

determination and the final standards is 

provided in Section VII of this 

preamble. 

C. Final Standards of Performance 

The EPA is issuing final standards of 

performance for newly constructed, 

modified, and reconstructed affected 

steam generating units based on the 

degree of emission reduction achievable 

by application of the best system of 

emission reduction for those categories, 

as described above. The final standards 

are presented below in Table 6. 

TABLE 6—FINAL STANDARDS OF PERFORMANCE FOR NEW, MODIFIED, AND RECONSTRUCTED STEAM GENERATING UNITS

Source Description Final standard * 

lb CO2/MWh-g 

New Sources ........................ All newly constructed steam generating EGUs .............. 1,400. 

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184Note that the standards for sources that 

conduct larger modifications is a unit-specific 

numerical standard based on the unit’s best oneyear historical performance during the period from 

2002 to the time of the modification. The unitspecific standard will also be in the form of a gross 

energy output-based CO2 emission limit expressed 

in pounds of CO2 per megawatt-hour (lb CO2/MWhg). 

TABLE 6—FINAL STANDARDS OF PERFORMANCE FOR NEW, MODIFIED, AND RECONSTRUCTED STEAM GENERATING

UNITS—Continued 

Source Description Final standard * 

lb CO2/MWh-g 

Modified Sources ................. Sources that implement larger modifications—those resulting in an increase in hourly CO2 emissions (lb 

CO2/hr) of more than 10 percent.

Best annual performance (lb CO2/MWh-g) during the 

time period from 2002 to the time of the modification. 

Reconstructed Sources ........ Large ** ............................................................................ 1,800. 

Reconstructed Sources ........ Small ** ............................................................................ 2,000. 

* Standards are to be met over a 12-operating-month compliance period. 

** Large units are those with heat input capacity of >2,000 mmBtu/hr; small units are those with heat input capacity of ≤2,000 mmBtu/hr. 

For newly constructed and 

reconstructed steam generating units 

and for modified steam generating 

sources that result in larger hourly 

increases of CO2 emissions, the EPA is 

finalizing standards in the form of a 

gross energy output-based CO2 emission 

limit expressed in units of mass per 

useful energy output, specifically, in 

pounds of CO2 per megawatt-hour (lb 

CO2/MWh-g).184 The standard of 

performance will apply to affected EGUs 

upon the effective date of the final 

action. 

Compliance with the final standard 

will be demonstrated by summing the 

emissions (in pounds of CO2) for all 

operating hours in the 12-operatingmonth compliance period and then 

dividing that value by the sum of the 

useful energy output (on a gross basis, 

i.e., gross megawatt-hours) over the 

rolling 12-operating-month compliance 

period. The final rule requires rounding 

of emission rates with numerical values 

greater than or equal to 1,000 to three 

significant figures and rounding of rates 

with numerical values less than 1,000 to 

two significant figures. 

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-operating-month standard or with a 

more stringent standard over an 84- 

operating-month compliance period, 

and we solicited comment on including 

an interim 12-operating-month standard 

(based on use of supercritical boiler 

technology, see 79 FR at 1448). We are 

not finalizing the proposed 84- 

operating-month compliance period 

option because the final standard of 

performance for newly constructed 

sources is less stringent than the 

proposed standard and because, as 

discussed in Section V below, we are 

identifying alternative compliance 

pathways for new steam generating 

EGUs. Specifically, we have concluded 

that there are unlikely to be significant 

issues with short-term variability during 

initial operation, in view of both the 

reduced numerical stringency of the 

standard, and the availability of 

compliance alternatives. The EPA notes 

that co-firing of natural gas can also 

serve as an interim means to reduce 

emissions if a new source operator 

believes additional time is needed to 

phase-in the operation of a CCS system. 

Therefore, the applicable final standards 

of performance for all newly 

constructed, modified, and 

reconstructed steam generating units 

must be met over a rolling 12-operatingmonth compliance period. 

In the Clean Power Plan, which is a 

separate rulemaking under CAA section 

111(d) published at the same time as the 

present rulemaking under CAA section 

111(b), the EPA is promulgating 

emission guidelines for states to develop 

state plans regulating CO2 emissions 

from existing fossil fuel-fired EGUs. 

Existing sources that are subject to state 

plans under CAA section 111(d) may 

undertake modifications or 

reconstructions and thereby become 

subject to the requirements under 

section 111(b) in the present 

rulemaking. In the section 111(d) Clean 

Power Plan rulemaking, the EPA 

discusses how undertaking a 

modification or reconstruction affects an 

existing source’s section 111(d) 

requirements. 

V. Rationale for Final Standards for 

Newly Constructed Fossil Fuel-Fired 

Electric Utility Steam Generating Units 

In the discussion below, the EPA 

describes the rationale and justification 

of the BSER determination and the 

resulting final standards of performance 

for newly constructed steam generating 

units. We also explain why this 

determination is consistent with the 

constraints imposed by the EPAct05. 

A. Factors Considered in Determining 

the BSER 

In evaluating the final determination 

of the BSER for newly constructed 

steam generating units, the EPA 

considered the factors for the BSER 

described above, looked widely at all 

relevant information and considered all 

the data, information, and comments 

that were submitted during the public 

comment period. We re-examined and 

updated the information that was 

available to us and concluded, as 

described below, that the final standard 

of 1,400 lb CO2/MWh-g is consistent 

with the degree of emission reduction 

achievable through the implementation 

of the BSER. This final standard of 

performance for newly constructed 

fossil fuel-fired steam generating units 

provides a clear and achievable path 

forward for the construction of new 

coal-fired generating sources that 

addresses GHG emissions. 

B. Highly Efficient SCPC EGU 

Implementing Partial CCS as the BSER 

for Newly Constructed Steam 

Generating Units 

In the sections that follow, we explain 

the technical configurations that may be 

used to implement BSER to meet the 

final standard, describe the operational 

flexibilities that partial CCS offers, and 

then provide the rationale for the final 

standard of performance. After that, we 

discuss, in greater detail, consideration 

of the criteria for the determination of 

the BSER. We describe why a highly 

efficient new SCPC EGU implementing 

partial CCS in the amount that results in 

an emission limitation of 1,400 lb CO2/ 

MWh-g best meets those criteria, 

including, among others, that such a 

system is technically feasible, provides 

meaningful emission reductions, can be 

implemented at a reasonable cost, does 

not pose non-air quality health and 

environmental concerns or impair 

energy reliability, and consequently is 

adequately demonstrated. We also 

explain why the emission standard of 

1,400 lb CO2/MWh-g is achievable, 

including under all circumstances 

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64548 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

reasonably likely to occur when the 

system is properly designed and 

operated. We also discuss alternative 

compliance options that new source 

project developers can elect to use, 

instead of SCPC with partial CCS, to 

meet the final standard of performance. 

C. Rationale for the Final Emission 

Standards 

1. The Proposed Standards 

In the January 2014 proposal, the EPA 

proposed an emission limitation of 

1,100 lb CO2/MWh-g, which a new 

highly efficient utility boiler burning 

bituminous coal could have met by 

capturing roughly 40 percent of its CO2

emissions and a new highly efficient 

IGCC unit could have met by capturing 

and storing roughly 25 percent of its 

CO2 emissions. The captured CO2 would 

then be securely stored in sequestration 

repositories subject to either Class II or 

Class VI standards under the 

Underground Injection Control program. 

The EPA arrived at the proposed 

standard by examining the available 

CCS implementation configurations and 

concluding that the proposed standard 

at the corresponding levels of partial 

CCS best balanced the BSER criteria and 

resulted in an achievable emission level. 

The EPA also proposed to find that 

highly efficient new generation 

implementing ‘‘full CCS’’ (i.e., more 

than 90 percent capture and storage) 

was not the BSER because the costs of 

that configuration—for both utility 

boilers and IGCC units—are projected to 

substantially exceed the projected costs 

of other non-NGCC dispatchable 

technologies that utilities and project 

developers are considering (e.g., new 

nuclear and biomass). See generally 79 

FR at 1477–78. Conversely, the EPA 

rejected highly efficient SCPC as the 

BSER because it would not result in 

meaningful emission reductions from 

any newly constructed PC unit. Id. at 

1470. The EPA also declined to base the 

BSER on IGCC operating alone due to 

the same concern—lack of emission 

reductions from a new IGCC unit 

otherwise planned. Id. 

2. Basis for the Final Standards 

For this final action, the EPA 

reexamined the BSER options available 

at proposal. Those options are: (1) 

Highly efficient generation without CCS, 

(2) highly efficient generation 

implementing partial CCS, and (3) 

highly efficient generation 

implementing full CCS. Consistent with 

our determination in the January 2014 

proposal, we remain convinced that 

highly efficient generation (i.e., a new 

supercritical utility boiler or a new 

IGCC unit) without CCS does not 

represent the BSER because it does not 

achieve emission reductions beyond the 

sector’s business as usual, when options 

that do achieve more emission 

reductions are available. 79 FR 1470; see 

also Section V.P below. We also do not 

find that a highly efficient new steam 

generating unit implementing full CCS 

is the BSER because, at this time, the 

costs are predicted to be significantly 

more than the costs for implementation 

of partial CCS and significantly more 

than the costs for competing non-NGCC 

base load, dispatchable technologies— 

primarily new nuclear generation—and 

are, therefore, potentially unreasonable. 

See Section V.P. 

As with the proposal, the EPA has 

determined the final BSER and 

corresponding emission limitation by 

appropriately balancing the BSER 

criteria and determining that the 

emission limitation is achievable. The 

final standard of performance of 1,400 

lb CO2/MWh-g is less stringent than at 

proposal and reflects changes that are 

responsive to comments received on, 

and the EPA’s further evaluation of, the 

costs to implement partial CCS. The 

EPA has determined that a newly 

constructed highly efficient 

supercritical utility boiler burning 

bituminous coal can meet this final 

emission limitation by capturing 16 

percent of the CO2 produced from the 

facility (or 23 percent if burning 

subbituminous or dried lignite), which 

would be either stored in on-site or offsite geologic sequestration repositories 

subject to control under either the Class 

VI (for geologic sequestration) or Class 

II (for Enhanced Oil Recovery) standards 

under the UIC program. This BSER is 

technically feasible, as shown by the 

fact that post-combustion CCS 

technology—both the capture and 

storage components—is demonstrated in 

full-scale operation within the 

electricity generating industry. There 

are also numerous operating results 

from smaller-scale projects that are 

reasonably predictive of operation at 

full-scale. It is available at reasonable 

cost, does not have collateral adverse 

non-air quality health or environmental 

impacts, and does not have adverse 

energy implications. 

The proposed BSER was a highly 

efficient newly constructed steam 

generating EGU implementing partial 

CCS to an emission standard of 1,100 lb 

CO2/MWh-g. The final BSER is a highly 

efficient SCPC EGU implementing 

partial CCS to achieve an emission 

standard of 1,400 lb CO2/MWh-g. In 

both cases, the EPA specified that the 

BSER includes a ‘‘highly efficient’’ new 

EGU implementing partial CCS. This 

assumes that a new project developer 

will construct the most efficient 

generating technology available—i.e., a 

supercritical or ultra-supercritical utility 

boiler—that will inherently generate 

lower volumes of uncontrolled CO2 per 

MWh. See Section V.J below. A well 

performing and highly efficient new 

SCPC EGU will need to implement 

lower levels of partial CCS in order to 

meet the final standard of 1,400 lb CO2/ 

MWh-g than a less efficient new steam 

generating EGU. The construction of 

highly efficient steam generating 

EGUs—as opposed to less efficient units 

such as a subcritical utility boiler—will 

result in lower overall costs from 

decreased fuel consumption and the 

need for lower levels of required partial 

CCS to meet the final standard. 

3. Consideration of Projects Receiving 

Funding Under the EPAct05 

As noted in Section III.H.3.g above, 

the EPA’s determination of the BSER 

here includes review of recently 

constructed facilities and those planned 

or under construction to evaluate the 

control technologies being used and 

considered. Some of the projects 

discussed in the January 2014 proposal, 

and discussed here in this preamble, 

received or are receiving financial 

assistance under the EPAct05 (P.L. 109– 

58). This assistance may include 

financial assistance from the 

Department of Energy (DOE), as well as 

receipt of the federal tax credit for 

investment in clean coal technology 

under IRC Section 48A. 

As noted above, the EPA interprets 

these provisions as allowing 

consideration of EPAct05 facilities 

provided that such information is not 

the sole basis for the BSER 

determination, and particularly so in 

circumstances like those here, where the 

information is corroborative but the 

essential information justifying the 

determinations comes from facilities 

and other sources of information with 

no nexus with EPAct05 assistance. In 

the discussion below, the EPA explains 

its reliance on other information in 

making the BSER determination for new 

fossil fuel-fired steam generating units. 

The EPA notes that information from 

facilities that did not receive any DOE 

assistance, and did not receive the 

federal tax credit, is sufficient by itself 

to support its BSER determination. 

D. Post-Combustion Carbon Capture 

In this section, we describe a variety 

of facts that support our conclusion that 

the technical feasibility of postcombustion carbon capture is 

adequately demonstrated. First, we 

describe the technology of postmstockstill on DSK4VPTVN1PROD with RULES2

Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64549 

185The typical concentration of CO2 in the flue 

gas of a coal-fired utility boiler is roughly around 

15 volume percent. 

186A solvent is a substance (usually a liquid) that 

dissolves a solute (a chemically different liquid, 

solid or gas), resulting in a solution. 

187Amines are derivatives of ammonia (NH3) 

where one or more hydrogen atoms have been 

replaced by hydrocarbon groups. 

188Technical Support Document—‘‘Literature 

Survey of Carbon Capture Technology’’, available in 

the rulemaking docket (Docket ID: EPA–HQ–OAR– 

2013–0495). 

189 ‘‘[W]e are achieving better than expected’’ 

operation out of the plant, SaskPower’s Mike Marsh 

said April 8, 2015 in Washington, DC, summarizing 

the status of the first-of-a-kind plant in 

Saskatchewan, Canada, known as Boundary Dam 

Unit 3. Marsh spoke at a meeting of the National 

Coal Council, which advises the Energy Department 

on coal-related topics. From ‘‘Bolstering EPA’s 

NSPS, Canadian CCS Plant Working ‘Better Than 

Expected’ ’’, Climate Daily News, Inside EPA/

climate (April 08, 2015); www.insideepa.com 

(subscription required). 

190 ‘‘CCS performance data exceeding 

expectations at world-first Boundary Dam Power 

Station Unit #3’’, http://www.saskpowerccs.com/

newsandmedia/latest-news/ccs-performance-dataexceeding-expectations/. 

191Correspondence between Mike Monea 

(SaskPower) and Nick Hutson (EPA), February 20, 

2015. 

192 30 percent of the water used for cooling comes 

from the recycled or reclaimed water from the 

process itself; namely, water in the coal is 

reclaimed. 

193About $1.2B USD; roughly $700M (USD) for 

the carbon capture system, which was on budget. 

194 ‘‘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). 

combustion capture. We then describe 

EGUs that have previously utilized or 

are currently utilizing post-combustion 

carbon capture technology. This 

discussion is complemented by later 

sections that explain and justify our 

conclusions that the technical feasibility 

of other aspects of partial CCS are 

adequately demonstrated—namely, the 

transportation and carbon storage (see 

Sections V.M. and N). Further, the 

conclusions of this section are 

reinforced by the discussion in Section 

V.F. below, in which we identify 

commercial vendors that offer carbon 

capture technology and offer 

performance guarantees, and discuss 

industry and technology developers’ 

public pronouncements of their 

confidence in the feasibility and 

availability of CCS technologies. 

1. Post-Combustion Carbon Capture— 

How it Works 

Post-combustion capture processes 

remove CO2 from the exhaust gas of a 

combustion system—such as a utility 

boiler. It is referred to as ‘‘postcombustion 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 most combustion 

processes are at atmospheric pressure 

and are moved through the flue gas 

system by fans. The concentration of 

CO2 in most combustion flue gas 

streams is somewhat dilute.185 Most 

post-combustion capture systems utilize 

liquid solvents 186 that separate the CO2

from the flue gas in CO2 scrubber 

systems. Because the flue gas is at 

atmospheric pressure and is somewhat 

dilute, the solvents used for postcombustion capture are ones that 

separate the CO2 using chemical 

absorption (or chemisorption). Aminebased solvents 187 are the most 

commonly used in post-combustion 

capture systems. In a chemisorptionbased separation process, the flue gas is 

processed through the CO2 scrubber and 

the CO2 is absorbed by the liquid 

solvent and then released by heating to 

form a high purity CO2 stream. This 

heating step is referred to as ‘‘solvent 

regeneration’’ and is responsible for 

much of the ‘‘energy penalty’’ of the 

capture system. Steam from the boiler 

(or potentially from another external 

source) that would otherwise be used to 

generate electricity is instead used in 

the solvent regeneration process. The 

development of advanced solvents— 

those that are chemically stable, have 

high CO2 absorption capacities, and 

have low regeneration energy 

requirements—is an active area of 

research. Many post-combustion 

solvents will also selectively remove 

other acidic gases such as SO2 and 

hydrochloric acid (HCl), which can 

result in degradation of the solvent. For 

that reason, the CO2 scrubber systems 

are normally installed downstream of 

other pollutant control devices (e.g., 

particulate matter and flue gas 

desulfurization controls) and in some 

cases, the acidic gases will need to be 

scrubbed to very low levels prior to the 

flue gas entering the CO2 capture 

system. See also RIA chapter 5 

(quantifying SO2 reductions resulting 

from this scrubbing process). 

Additional information on postcombustion carbon capture—including 

process diagrams—can be found in a 

summary technical support 

document.188

2. Post-Combustion Carbon Capture 

Projects That Have Not Received DOE 

Assistance Through the EPAct05 or Tax 

Credits Under IRC Section 48A 

a. Boundary Dam Unit #3 

SaskPower’s Boundary Dam CCS 

Project in Estevan, a city in 

Saskatchewan, Canada, is the world’s 

first commercial-scale fully integrated 

post-combustion CCS project at a coalfired power plant. The project fully 

integrates the rebuilt 110 MW coal-fired 

Unit #3 with a CO2 capture system using 

Shell Cansolv amine-based solvent to 

capture 90 percent of its CO2 emissions. 

The facility, which utilizes local 

Saskatchewan lignite, began operations 

in October 2014 and accounts of the 

system’s performance describe it as 

working even ‘‘better than 

expected.’’ 189 190 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 facility is 

producing more power than predicted 

and that the energy penalty (parasitic 

load—the energy needed to regenerate 

the CO2 capture solvent) is much lower 

than initially predicted.191 Water use at 

the facility is consistent with levels that 

were predicted.192 The total project 

costs—for the power plant and the 

carbon capture plant—was $1.467B 

(CAD).193 The CO2 from the capture 

system is more than 99.999 percent pure 

with only trace levels of N2 in the 

product stream.194 This purity is foodgrade quality CO2 and is a clear 

indication that the system is working 

well. The captured CO2 is transported 

by pipeline to nearby oil fields in 

southern Saskatchewan where it is 

being used for EOR operations. Any 

captured CO2 that is not used for EOR 

operations will be stored in nearby deep 

brine-filled sandstone formations. Thus, 

the Boundary Dam Unit #3 project is 

demonstrating CO2 post-combustion 

capture, CO2 compression and transport, 

and CO2 injection for both EOR and 

geologic storage. The CCS system is 

fully integrated with the electricity 

production of the plant. 

Some commenters noted that, at 110 

MW, the Boundary Dam Unit #3 is a 

relatively small coal-fired utility boiler 

and thus, in the commenters’ view, does 

not demonstrate that such a system 

could be utilized at a much larger utility 

coal-fired boiler. However, there is 

nothing to indicate that the postcombustion system used at Boundary 

Dam could not be scaled-up for use at 

a larger utility boiler. In fact, the carbon 

capture system at Boundary Dam #3 is 

designed and constructed to implement 

‘‘full CCS’’—that is to capture more than 

90 percent of the CO2 produced from the 

subcritical unit. A similarly-sized 

capture system—with no need for 

further scale-up—could be used to treat 

a slip-stream of a much larger 

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195See Figure 1A from Atmospheric 

Environment, 43, 3974 (2009), for an example of 

this type of configuration. 

196 ‘‘Cost and Performance of PC and IGCC for a 

Range of Carbon Capture’’, Rev 1 (2013), DOE/

NETL–2011/1498 p. 2 (‘‘A literature search was 

conducted to verify that <90 percent CO2 capture 

is most economical using a ‘slip-stream’ (or bypass) 

approach. Indeed, the slip-stream approach is more 

cost-effective for <90 percent CO2 capture than 

removing reduced CO2 fractions from the entire flue 

gas stream, according to multiple peer-reviewed 

studies.’’ See also id. at 19, 21, 77, and 478 

(documenting further that treating a slip-stream is 

the most economical approach). 

197 In fact, in ‘‘Cost and Performance Baseline for 

Fossil Energy Plants Volume 1a: Bituminous Coal 

(PC) and Natural Gas to Electricity Revision 3’’, 

DOE/NETL–2015/1723 (July 2015), Exh.2–3 the 

Shell Cansolv process is used as the capture process 

for a new SCPC unit using bituminous coal rather 

than the subcritical PC unit at Boundary Dam that 

uses Canadian lignite. The study evidently assumes 

that the CanSolv process can be used effectively for 

bituminous coal since this type of coal is assumed 

for cost estimation purposes. 

198 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. 

199 IEA (2009), World Energy Outlook 2009, 

OECD/IEA, Paris. 

supercritical utility boiler (a new unit of 

approximately 500 to 600 MW) in order 

to meet the final standard of 

performance of 1,400 lb CO2/MWh-g, 

which would only require partial CCS 

on the order of approximately 16 to 23 

percent (depending on the coal used). 

A ‘‘slip-stream’’ is a portion of the 

flue gas stream that can be treated 

separately from the bulk exhaust gas. It 

is not an uncommon configuration for 

the flue gas from a coal-fired boiler to 

be separated into two or more streams 

and treated separately in different 

control equipment before being 

recombined to exit from a common 

stack.195 A slip-stream configuration is 

often used to treat a smaller portion of 

the bulk flue gas stream as a way of 

testing or demonstrating a control 

device or measurement technology. For 

implementation of post-combustion 

partial carbon capture, a portion of the 

bulk flue gas stream would be treated 

separately to capture approximately 90 

percent of the CO2 from that smaller 

slip-stream of the flue gas. For example, 

in order to capture 20 percent of the CO2

produced by a coal-fired utility boiler, 

an operator would treat approximately 

25 percent of the bulk flue gas stream 

(rather than treating the entire stream). 

Approximately 90 percent of the CO2

would be captured from the slip-stream 

gas, resulting in an overall capture of 

about 20 percent. 

In its study on the cost and 

performance of a range of carbon 

capture rates, the DOE/NETL 

determined that the slip-stream 

approach was the most economical for 

carbon capture of less than 90 percent 

of the total CO2.196 The advantage of the 

slip-stream approach is that the capture 

system will be sized to treat a lower 

volume of flue gas flow, which reduces 

the size of the CO2 absorption columns, 

induced draft fans, and other 

equipment, leading to lower capital and 

operating costs. 

The carbon capture system at 

Boundary Dam does not utilize the 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 the flue gas from a 550 MW 

facility. Thus, the equipment that is 

currently working very well (in fact, 

‘‘better than expected’’) at the Boundary 

Dam plant can be utilized for partial 

carbon capture at a much larger coalfired unit without the need for further 

scale-up. 

The experience at Boundary Dam is 

directly transferrable to other types of 

post-combustion sources, including 

those using different boiler types and 

those burning different coal types. There 

is nothing to suggest that the Shell 

CanSolv process would not work with 

other coal types and indeed, the latest 

NETL cost estimates assume that the 

capture technology would be used in a 

new unit using bituminous coal.197 The 

EPA is unaware of any reasons why the 

Boundary Dam technology would not be 

transferrable to another utility boiler at 

a different location at a different 

elevation or climate because the control 

technology is not climate or elevationdependent. 

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 full-scale, fully integrated 

implementation of available postcombustion CCS 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. 

Essex Chemical Corp., 486 F. 2d at 436 

(test results from single facility 

demonstrates achievability of standard 

of performance). 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) plants are both circulating 

fluidized bed (CFB) coal-fired power 

plants with carbon capture amine 

scrubbers developed by ABB/Lummus. 

The scrubbers were designed to process 

a slip-stream of each plant’s flue gas. At 

the 180 MW Warrior Run Plant, a plant 

that burns bituminous coal, 

approximately 10 percent of the plant’s 

CO2 emissions (about 110,000 metric 

tons of CO2 per year) has been captured 

since 2000 and sold to the food and 

beverage industry. At the 320 MW 

Shady Point Plant, a plant that burns a 

blend of bituminous and subbituminous 

coals, CO2 from an approximate 5 

percent slip-stream (about 66,000 metric 

tons of CO2 per year) has been captured 

since 2001. The captured CO2 from the 

Shady Point Plant is also sold for use in 

the food processing industry.198 While 

these projects do not demonstrate the 

CO2 storage component of CCS, they 

clearly demonstrate the technical 

viability of partial CO2 capture. The 

capture of CO2 from a slip-stream of the 

bulk flue gas, as described earlier, is the 

most economical method for capturing 

less than 90 percent of the CO2. The 

amounts of partial capture that these 

sources have demonstrated—up to 10 

percent—is reasonably similar to the 

level, at 16 to 23 percent, that the EPA 

predicts would be needed by a new 

highly efficient steam utility boiler to 

meet the final standard of performance. 

These facilities, which have been 

operating for multiple years, clearly 

show the technical feasibility of postcombustion carbon capture. 

c. Searles Valley Minerals 

Since 1978, the Searles Valley 

Minerals soda ash plant in Trona, CA 

has used post-combustion amine 

scrubbing to capture approximately 

270,000 metric tons of CO2 per year 

from the flue gas of a coal-fired power 

plant that generates steam and power for 

on-site use. The captured CO2 is used 

for the carbonation of brine in the 

process of producing soda ash.199 Again, 

while the captured CO2 is not 

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200Moreover, the final rule allows alternative 

means of storage of captured CO2 based on a caseby-case demonstration of efficacy. See Section 

V.M.4 below. 201The heat duty for the amine scrubbing process 

used at Searles Valley in the mid-70’s was about 12 

MJ/mt CO2 removed as compared to a heat duty of 

about 2.5 MJ/mt CO2 removed for the amine 

processes used at Boundary Dam and to be used at 

WA Parish. ‘‘From Lubbock, TX to Thompsons, 

TX—Amine Scrubbing for Commercial CO2 Capture 

from Power Plants’’, plenary address by Prof. Gary 

Rochelle at the 12th International Conference on 

Greenhouse Gas Technology (GHGT–12), Austin, 

TX (October 2014). 

202Thus, even if the project received DOE 

assistance for the initial 60 MW design, the 

expansion of the project from 60 MW to 240 MW 

should not be considered a DOE-assisted project. In 

any case, as described above, even without 

consideration of this facility at all, other 

information adequately demonstrates the technical 

feasibility of post-combustion CCS. 

203WA Parish CO2 Capture Project Fact Sheet; 

available at www.nrg.com/documents/business/pla2014-petranova-waparish-factsheet.pdf (2014). 

204The 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 highperformance solvent for the CO2 absorption and 

desorption. 

205Using emissions data reported to the Acid 

Rain Program, the EPA estimates that the CO2

emissions from the WA Parish Unit #8 will be 

1,250–1,300 lb CO2/MWh-g during operations with 

the post-combustion capture system. 

sequestered, this project clearly 

demonstrates the technical feasibility of 

the amine scrubbing system for CO2

capture from a coal-fired power 

plant.200 The fact that this system is an 

industrial coal-fired power plant rather 

than a utility coal-fired power plant is 

irrelevant as they both serve a similar 

purpose—the production of electricity. 

Each of these processes indicate a 

willingness of industry to utilize 

available post-combustion technology 

for capture of CO2 for commercial 

purposes. Not one of the CO2 capture 

systems at Warrior Run, Shady Point, or 

Searles Valley was installed for 

regulatory purposes or as governmentfunded demonstration projects. They 

were installed to capture CO2 for 

commercial use. The fact that the 

captured CO2 was utilized rather than 

being stored is of no consequence in the 

consideration of the technical feasibility 

of post-combustion CO2 capture 

technology. These commercial 

operations have helped to improve the 

performance of scrubbing systems that 

are available today. For example, the 

heat duty (i.e., the energy needed to 

remove the CO2) has been reduced by 

about 5 times from the amine process 

originally used at the Searles Valley 

facility. The amine scrubbing process 

used at Boundary Dam is equally 

efficient, and the amine scrubbing 

system to be used at the Petra Nova WA 

Parish project (Thompsons, TX) is 

projected to be as well.201

3. Post-Combustion Carbon Capture 

Projects That Received DOE Assistance 

Through the EPAct05, but Did Not 

Receive Tax Credits Under IRC Section 

48A 

The EPA considers the experiences 

from the CCS projects described above, 

coupled with evidence that the design 

of CCS is well accepted (also described 

above) and the strong support that CCS 

has received from vendors and others 

(described below) to adequately 

demonstrate that post-combustion 

partial CCS is technically feasible. The 

EPA finds that additional projects, 

described next, provide more support 

for that conclusion. These projects 

received funding under EPAct05 from 

the Department of Energy, but that does 

not disqualify them from being 

considered. See Section III.H.3 above. 

a. Petra Nova WA Parish Project 

Petra Nova, a joint venture between 

NRG Energy Inc. and JX Nippon Oil & 

Gas Exploration, is constructing a 

commercial-scale post-combustion 

carbon capture project at Unit #8 of 

NRG’s WA Parish generating station 

southwest of Houston, Texas. The 

project is designed to utilize partial CCS 

by capturing approximately 90 percent 

of the CO2 from a 240 MW slip-stream 

of the 610 MW WA Parish facility. The 

project is expected to be operational in 

2016 and thus does not yet directly 

demonstrate the technical feasibility or 

performance of the MHI amine 

scrubbing system. However, this project 

is a clear indication that the developers 

have confidence in the technical 

feasibility of the post-combustion 

carbon capture system. 

The project was originally envisioned 

as a 60 MW slip-stream demonstration 

and received DOE Clean Coal Power 

Initiative (CCPI) funding (as provided in 

EPAct05) on that basis. The developers 

later expanded the project to the larger 

240 MW slip-stream because of the need 

to capture greater volumes of CO2 for 

EOR operations. No additional DOE or 

other federal funding was obtained for 

the expansion from a 60 MW slip-stream 

to a 240 MW slip-stream.202

At 240 MW, the Petra Nova project 

will be the largest post-combustion 

carbon capture system installed on an 

existing coal-fueled power plant. The 

project will use for EOR or will 

sequester 1.6 million tons of captured 

CO2 each year. The project is expected 

to be operational in 2016. 

In 2014 project materials,203 the 

project developer NRG recognized the 

importance of CCS technology by 

noting: 

The technology has the potential to 

enhance the long-term viability and 

sustainability of coal-fueled power plants 

across the U.S. and around the world. . . . 

Post-combustion carbon capture is essential 

so that we can use coal to sustain our energy 

ecosystem while we begin reducing our 

carbon footprint. 

According to NRG, the Petra Nova 

Carbon Capture Project will utilize ‘‘a 

proven carbon capture process,’’ jointly 

developed by Mitsubishi Heavy 

Industries, Ltd. (MHI) and the Kansai 

Electric Power Co., that uses a highperformance solvent for CO2 absorption 

and desorption.204 In using the MHI 

high-performance solvent, the Petra 

Nova project will benefit from pilotscale testing of this solvent at Alabama 

Power’s Plant Barry and at other 

installations. WA Parish Unit #8 came 

on-line in 1982 and is thus an existing 

source that will not be subject to final 

standards of performance issued in this 

action. However, because it will be 

capturing roughly 35 percent of the CO2

generated by the facility, its emissions 

will be below the final new source 

emission limitation of 1,400 lb CO2/

MWh-g.205

The captured CO2 from the WA Parish 

CO2 Capture Project will be used in EOR 

operations at mature oil fields in the 

Gulf Coast region. Using EOR at 

Hilcorp’s West Ranch Oil Field, the 

production is expected to be boosted 

from around 500 barrels per day to 

approximately 15,000 barrels per day. 

Thus the project will utilize all aspects 

of CCS by capturing CO2 at the large 

coal-fired power plant, compressing the 

CO2, transporting it by pipeline to the 

EOR operations, and injecting it for EOR 

and eventual geologic storage. 

The carbon capture system at WA 

Parish will utilize a slip-stream 

configuration. However, as noted, the 

system is designed to capture roughly 

35 percent of the CO2 from WA Parish 

Unit #8 (90 percent of the CO2 from the 

240 MW slip-stream from the 610 MW 

unit). A carbon capture system of the 

same size as that used at WA Parish 

could be used to treat a 240 MW slipstream from a 1,000 MW unit in order 

to meet the final standard of 

performance of 1,400 lb CO2/MWh-g. 

Again, the experience at the WA 

Parish Unit #8 project will be directly 

transferable to post-combustion capture 

at a new utility boiler, even though WA 

Parish Unit #8 is an existing source that 

has been in operation for over 30 years. 

In fact, retrofit of such technology at an 

existing unit can be more challenging 

than incorporating the technology into 

the design of a new facility. The 

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206http://www.alstom.com/press-centre/2011/5/

alstom-announces-sucessful-results-ofmountaineer-carbon-capture-and-sequestration-ccsproject/. 

207 ‘‘CCS front end engineering & design report: 

American Electric Power Mountaineer CCS II 

Project. Phase 1’’, pp 10–11; available at: http://

www.globalccsinstitute.com/publications/aepmountaineer-ii-project-front-end-engineering-anddesign-feed-report. 

208 Id. at 11. The EPA does not view this 

information as being affected by the constraints in 

EPAct05. The information does not relate to use of 

technology, level of emission reduction by reason 

of use of technology, achievement of emission 

reduction by demonstration of technology, or 

demonstration of a level of performance. The FEED 

study rather explains engineering challenges which 

would remain at full scale and how those 

challenges can be addressed. 

209This is the same carbon capture system that 

is being utilized at the Petra Nova project at the 

NRG WA Parish plant. 

210 Ivie, M.A. et al.; ‘‘Project Status and Research 

Plans of 500 TPD CO2 Capture and Sequestration 

Demonstration at Alabama Power’s Plant Barry’’, 

Energy Procedia 37, 6335 (2013). 

211 Id. 

212The amount of CO2 in syngas depends upon 

the specific gasifier technology used, the operating 

conditions, and the fuel used; but is typically less 

experience will be directly transferrable 

to other types of post-combustion 

sources including those using different 

boiler types and those burning different 

coals. The amine scrubbing and 

associated systems are not boiler typeor coal-specific. The EPA is unaware of 

any reasons that the technology utilized 

at the WA Parish plant would not be 

transferrable to another utility boiler at 

a different location at a different 

elevation or climate, given that the 

technology is not dependent on either 

climate or topography. 

b. AEP/Alstom Mountaineer Project 

In September 2009, AEP began a pilotscale CCS demonstration at its 

Mountaineer Plant in New Haven, WV. 

The Mountaineer Plant is a very large 

(1,300 MW) coal-fired unit that was 

retrofitted with Alstom’s patented 

chilled ammonia CO2 capture 

technology on a 20 MWe slip-stream of 

the plant’s exhaust flue gas. In May 

2011, Alstom Power announced the 

successful operation of the chilled 

ammonia CCS validation project. The 

demonstration achieved capture rates 

from 75 percent (design value) to as 

high as 90 percent, and produced CO2

at a purity of greater than 99 percent, 

with energy penalties 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.206

AEP, with assistance from the DOE, 

had planned to expand the slip-stream 

demonstration to a commercial scale, 

fully integrated demonstration at the 

Mountaineer facility. The commercialscale system was designed to capture at 

least 90 percent of the CO2 from 235 

MW of the plant’s 1,300 MW total 

capacity. Plans were for the project to be 

completed in four phases, with the 

system to begin commercial operation in 

2015. However, in July 2011, AEP 

announced that it would terminate its 

cooperative agreement with the DOE 

and place its plans to advance CO2

capture and storage technology to 

commercial scale on hold. AEP cited the 

uncertain status of U.S. climate policy 

as a contributor to its decision, but did 

not express doubts about the feasibility 

of the technology. See Section V.L 

below. 

AEP also prepared a Front End 

Engineering & Design (FEED) Report,207

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.208 See Section V.G.3 below, 

addressing in more detail the record 

support for how CCS technology can be 

scaled up to commercial size in both 

pre- and post-combustion applications. 

c. Southern Company/MHI Plant Barry 

In June 2011, Southern Company and 

Mitsubishi Heavy Industries (MHI) 

launched operations at a 25 MW coalfired carbon capture facility at 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 solvent 209 for CO2

absorption and desorption that was 

jointly developed by MHI and Japanese 

utility Kansai Electric Power Co. The 

captured CO2 has been transported via 

pipeline approximately 12 miles to the 

Citronelle oil field where it is injected 

into the Paluxy formation, a saline 

reservoir, for storage.210

Project participants have reported that 

‘‘[t]he plant performance was stable at 

the full load condition with CO2 capture 

rate of 500 TPD at 90 percent CO2

removal and lower steam consumption 

than conventional capture 

processes.’’ 211

E. Pre-Combustion Carbon Capture 

As described earlier, the EPA does not 

find that IGCC technology—either alone 

or implementing partial CCS—is part of 

the BSER for newly constructed steam 

generating EGUs. However, as noted, 

there may be specific circumstances and 

business plans—such as co-production 

of chemicals or fertilizers, or capture of 

CO2 for use in EOR operations—that 

encourage greater CO2 emission 

reductions than are required by this 

standard. In this section, we describe 

and justify our conclusion that the 

technical feasibility of pre-combustion 

carbon capture is adequately 

demonstrated, indicating that this could 

be a viable alternative compliance 

pathway. First, we explain the 

technology of pre-combustion capture. 

We then describe EGUs that have 

previously utilized or are currently 

utilizing pre-combustion carbon capture 

technology. This discussion is 

complemented by other sections that 

conclude the technical feasibility of 

other aspects of partial CCS are 

adequately demonstrated—namely, 

post-combustion carbon capture 

(Section V.D) and sequestration 

(Sections V.M and V.N). Further, this 

section’s conclusions are reinforced by 

Section V.F, in which we identify 

commercial vendors that offer CCS 

performance guarantees as well as 

developers that have publicly stated 

their confidence in CCS technologies. 

1. Pre-Combustion Carbon Capture— 

How It Works 

Pre-combustion capture systems are 

typically used with IGCC processes. In 

a gasification system, the fuel (usually 

coal or petroleum coke) is heated with 

water and oxygen in an oxygen-lean 

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 turbine 

combined with a HRSG and steam 

turbine). The gasification process also 

typically produces some amount of 

CO2 212 as a by-product along with other 

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than 20 volume percent (http://www.netl.doe.gov/

research/coal/energy-systems/gasification/

gasifipedia/syngas-composition). 

213Technical Support Document—‘‘Literature 

Survey of Carbon Capture Technology’’, available in 

the rulemaking docket (Docket ID: EPA–HQ–OAR– 

2013–0495). 

214http://www.dakotagas.com/Gasification/. 

215 ‘‘Cost and Performance of PC and IGCC for a 

Range of Carbon Capture’’, Rev 1 (2013), DOE/

NETL–2011/1498. 

216www.linde-engineering.com/en/process_

plants/hydrogen_and_synthesis_gas_plants/gas_

processing/rectisol_wash/index.html. 

217http://www.downstreambusiness.com/item/

Summit-Power-Wins-Funding-Studies-ProposedIGCC-CCS-Project_140878. 

218http://www.summitpower.com/projects/

carbon-capture/. 

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 multistage 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 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. Precombustion capture systems have been 

used widely in industrial processes 

such as natural gas processing. 

Additional information on precombustion carbon capture can be 

found in a summary technical support 

document.213

2. Pre-Combustion Carbon Capture 

Projects That Have Not Received DOE 

Assistance Through EPAct05 or Tax 

Credits Under IRC Section 48A 

a. Dakota Gasification Great Plains 

Synfuels Plant 

Each day, the Dakota Gasification 

Great Plains Synfuels Plant uses 

approximately 18,000 tons of North 

Dakota lignite in a coal gasification 

process that produces syngas (a mixture 

of CO, CO2, and H2), which is then 

converted to methane gas (synthetic 

natural gas) using a methanation 

process. Each day, the process produces 

an average of 145 million cubic feet of 

synthetic natural gas that is ultimately 

transported for use in home heating and 

electricity generation.214

Capture of CO2 from the facility began 

in 2000. The Synfuels Plant, using a precombustion 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 the implementation of the 

pre-combustion capture technology 

would be similar enough for 

comparison. See 79 FR at 1435–36 and 

n. 11. We continue to hold this view. 

As explained above, in an IGCC 

gasification system, coal (or petroleum 

coke) is gasified to produce a synthesis 

gas comprised of primarily CO, H2, and 

some amount of CO2 (depending on the 

gasifier and the specific operating 

conditions). A 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.215

The Dakota Gasification process bears 

essential similarities to the justdescribed 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 

present purposes, only the manner in 

which the syngas is used distinguishes 

the IGCC gasification system from the 

Dakota Gasification facility. In the IGCC 

process, the syngas is combusted. In the 

Dakota Gasification facility, the syngas 

is processed through a catalytic 

methanation process where the CO and 

H2 react to produce CH4 (methane, 

synthetic natural gas) and water. 

Importantly, the CO2 capture system 

that is used in the Dakota Gasification 

facility can readily be used in an IGCC 

EGU. There is no indication that the 

RECTISOL® process (or other similar 

physical gas removal systems) is not 

feasible for an IGCC EGU. In 

confirmation, according to product 

literature, RECTISOL®, which was 

independently developed by Linde and 

Lurgi, is frequently used to purify 

shifted, partially shifted or un-shifted 

gas from the gasification of coal, lignite, 

and residual oil.216

b. International Projects 

There are some international projects 

that are in various stages of 

development that indicate confidence 

by developers in the technical feasibility 

of pre-combustion carbon capture. 

Summit Carbon Capture, LLC is 

developing the Caledonia Clean Energy 

Project, a proposed 570-megawatt IGCC 

plant with 90 percent CO2 capture that 

would be built in Scotland, U.K. 

Captured CO2 from the plant will be 

transported via on-shore and sub-sea 

pipeline for sequestration in a saline 

formation in the North Sea. The U.K. 

Department of Energy & Climate Change 

(DECC) recently announced funding to 

allow for feasibility studies for this 

plant.217 Commercial operation is 

expected in 2017.218

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 

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219http://sequestration.mit.edu/tools/projects/

greengen.html. 

220Buggenum Fact Sheet: Carbon Dioxide Capture 

and Storage Project, Carbon Capture & 

Sequestration Technologies @MIT, http://

sequestration.mit.edu/tools/projects/

buggenum.html. 

221Puertollano Fact Sheet: Carbon Dioxide 

Capture and Storage Project, Carbon Capture & 

Sequestration Technologies @MIT, https://

sequestration.mit.edu/tools/projects/

puertollanto.html. 

222ESI CCS Project Fact Sheet: Carbon Dioxide 

and Storage Project, Carbon Capture & 

Sequestration Technologies @MIT, https://

sequestration.mit.edu/tools/projects/esi_ccs.html 

and https://www.globalccsinstitute.com/projects/

large-scale-ccs-projects. 

223Uthmaniyah CO2 EOR Demonstration Project, 

Global CCS Institute, https://www.global

ccsinstitute.com/projects/large-scale-ccs-projects. 

224Mississippi 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. 

225 ‘‘Odessa coal-to-gas power plant to break 

ground this year’’, Houston Chronicle (April 1, 

2015). 

226http://www.texascleanenergyproject.com/

project/. 

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.219

Vattenfall and Nuon’s pilot project in 

Bugennum, The Netherlands involves 

carbon capture from coal- and biomassfired IGCC plants. It has operated since 

2011.220

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 

2010.221

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 

2016.222

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 2015.223

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. Pre-Combustion Carbon Capture 

Projects That Have Received DOE 

Assistance Through EPAct05, but Did 

Not Receive Tax Credits Under IRC 

Section 48A 

a. Coffeyville Fertilizer 

Coffeyville Resources Nitrogen 

Fertilizers, LLC, owns and operates a 

nitrogen fertilizer facility in Coffeyville, 

Kansas. The plant began operation in 

2000 and is the only one in North 

America using a petroleum coke-based 

fertilizer production process. The 

petroleum coke is generated at an oil 

refinery adjacent to the plant. The 

petroleum coke is gasified to produce a 

hydrogen rich synthetic gas, from which 

ammonia and urea ammonium nitrate 

fertilizers are subsequently synthesized. 

As a by-product of manufacturing 

fertilizers, the plant also produces 

significant amounts of CO2. In March 

2011, Chaparral Energy announced a 

long-term agreement for the purchase of 

captured CO2 which is transported 68 

miles via CO2 pipeline for use in EOR 

operations in Osage County, OK. 

Injection at the site started in 2013. 

At least one commenter suggested that 

the cost and complexity of carbon 

capture from these and other industrial 

projects was significantly decreased 

because the sources already separate 

CO2 as part of their normal operations. 

The EPA finds this argument 

unconvincing. The Coffeyville process 

involves gasification of a solid fossil 

fuel (pet coke), shifting the resulting 

syngas stream, and separation of the 

resulting CO2 using a pre-combustion 

carbon capture system. These are the 

same, or very similar, processes that are 

used in an IGCC EGU. The argument is 

even less convincing when considering 

that the Coffeyville Fertilizer process 

uses the SelexolTM pre-combustion 

capture process—the same process that 

Mississippi Power described as having 

been ‘‘in commercial use in the 

chemical industry for decades’’ and is 

expected by Mississippi Power to ‘‘pose 

little technology risk’’ when used at the 

Kemper IGCC EGU. 

4. Pre-Combustion Carbon Capture 

Projects That Have Received DOE 

Assistance Through EPAct05 and Tax 

Credits Under IRC Section 48A 

a. Kemper County Energy Facility 

Southern Company’s subsidiary 

Mississippi Power has constructed the 

Kemper County Energy Facility in 

Kemper County, MS. This is a 582 MW 

IGCC plant that will utilize local 

Mississippi lignite and includes a precombustion carbon capture system to 

reduce CO2 emissions by approximately 

65 percent. The pre-combustion solvent, 

SelexolTM has also been used 

extensively for acid gas removal 

(including for CO2 removal) in various 

processes. In filings with the 

Mississippi Public Service Commission 

for the Kemper project, Mississippi 

described the carbon capture system: 

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) 224

Thus, Mississippi Power believes that, 

because the SelexolTM process has been 

in commercial use in the chemical 

industry for decades, it is well proven, 

and will pose little technical risk when 

used in the Kemper IGCC EGU. 

b. Texas Clean Energy Project and 

Hydrogen Energy California Project 

The Texas Clean Energy Project 

(TCEP), a 400 MW IGCC facility located 

near Odessa, Texas will capture 90 

percent of its CO2, which is 

approximately 3 million metric tons 

annually. The captured CO2 will be 

used for EOR in the West Texas Permian 

Basin. Additionally, the plant will 

produce urea and smaller quantities of 

commercial-grade sulfuric acid, argon, 

and inert slag, all of which will also be 

marketed. Summit has announced that 

they expect to commence construction 

on the project in 2015.225 The facility 

will utilize the Linde Rectisol® gas 

cleanup process to capture carbon 

dioxide 226—the same process that has 

been deployed for decades, including at 

the Dakota Gasification facility, a clear 

indication of the developer’s confidence 

in that technology and further evidence 

that the Dakota Gasification carbon 

capture technology is transferable to 

EGUs. 

F. Vendor Guarantees, Industry 

Statements, Academic Literature, and 

Commercial Availability 

In this section, we describe additional 

information that supports our 

determination that CCS is adequately 

demonstrated to be technically feasible. 

This includes performance guarantees 

from vendors, public statements from 

industry officials, and review of the 

literature. 

1. Performance Guarantees 

The D.C. Circuit made clear in its first 

cases concerning CAA section 111 

standards, and has affirmed since then, 

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227See 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.’’). 

228Sierra 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’’). 

229 www.intermediates.basf.com/chemicals/web/

gas-treatment/en/function/conversions:/publish/

content/products-and-industries/gas-treatment/

images/Linde_and_BASF-Flue_Gas_Carbon_

Capture_Plants.pdf. 

230www.fluor.com/client-markets/energychemicals/Pages/carbon-capture.aspx. 

231http://www.powermag.com/commerciallyavailable-co2-capture-technology/. 

232http://www.shell.com/global/productsservices/solutions-for-businesses/globalsolutions/

shell-cansolv/shell-cansolv-solutions/co2- 

capture.html. 

233Comments of Murray Energy, p. 73, (Docket 

entry: EPA–HQ–OAR–2013–0495–10046). 

234Technical Support Document—‘‘Literature 

Survey of Carbon Capture Technology’’, available in 

the rulemaking docket (Docket ID: EPA–HQ–OAR– 

2013–0495). 

that performance guarantees from 

vendors are an important basis for 

supporting a determination that 

pollution technology is adequately 

demonstrated to be technically feasible. 

In 1973, in Essex Chem. Corp. v. 

Ruckelshaus, 486 F.2d 427, 440 (D.C. 

Cir. 1973), the Court upheld standards 

of performance for coal-fired steam 

generators based on ‘‘prototype testing 

data and full-scale control systems, 

considerations of available fuel 

supplies, literature sources, and 

documentation of manufacturer 

guarantees and expectations’’ (emphasis 

supplied)).227 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.’’ 228

Linde and BASF offer performance 

guarantees for carbon capture 

technology. The two companies are 

jointly marketing new, advanced 

technology for capturing CO2 from low 

pressure gas streams in power or 

chemical plants. In product 

literature,229 they note that Linde will 

provide a turn-key carbon capture plant 

using a scrubbing process and solvents 

developed by BASF, one of the world’s 

leading technical suppliers for gas 

treatment. They further note that: 

The captured carbon dioxide can be used 

commercially for example for EOR (enhanced 

oil recovery) or as a building block for the 

production of urea. Alternatively it can be 

stored underground as a carbon abatement 

measure. [. . .] The PCC (Post-Combustion 

Capture) technology is now commercially 

available for lignite and hard coal fired 

power plant [. . .] applications. 

The alliance between Linde, a worldleading gases and engineering company and 

BASF, the chemical company, offers great 

benefits [. . .] Complete capture plants 

including CO2 compression and drying . . . 

Proven and tested processes including 

guarantee . . . Synergies between process, 

engineering, construction and operation . . . 

Optimized total and operational costs for the 

owner. (emphasis added) 

In addition, other well-established 

companies that either offer technologies 

that are actively marketed for CO2

capture from fossil fuel-fired power 

plants or that develop those power 

plants, have publicly expressed 

confidence in the technical feasibility of 

carbon capture. For example, Fluor has 

developed patented CO2 recovery 

technologies to help its clients reduce 

GHG emissions. The Fluor product 

literature 230 specifically points to the 

Econamine FG PlusSM (EFG+) process, 

which uses an amine solvent to capture 

and produce food grade CO2 from postcombustion sources. The literature 

further notes that EFG+ is also used for 

carbon capture and sequestration 

projects, that the proprietary technology 

provides a proven, cost-effective process 

for the removal of CO2 from power plant 

flue gas streams, and that the process 

can be customized to meet a power 

plant’s unique site requirements, flue 

gas conditions, and operating 

parameters. 

Fluor has also published an article 

titled ‘‘Commercially Available CO2

Capture Technology’’ in which it 

describes the EFG+ technology.231 The 

article notes, ‘‘Technology for the 

removal of carbon dioxide (CO2) from 

flue gas streams has been around for 

quite some time. The technology was 

developed not to address the GHG effect 

but to provide an economic source of 

CO2 for use in enhanced oil recovery 

and industrial purposes, such as in the 

beverage industry.’’ 

Mitshubishi Heavy Industries (MHI) 

offers a CO2 capture system that uses a 

proprietary energy-efficient CO2

absorbent called KS–1TM. Compared 

with the conventional 

monoethanolamine (MEA)-based 

absorbent, KS–1TM solvent requires less 

solvent circulation to capture the CO2

and less energy to recover the captured 

CO2. 

In addition, Shell has developed the 

CANSOLV CO2 Capture System, which 

Shell describes in its product 

literature 232 as a world leading amine 

based CO2 capture technology that is 

ideal for use in fossil fuel-fired power 

plants where enormous amounts of CO2

are generated. The company also notes 

that the technology can help refiners, 

utilities, and other industries lower 

their carbon intensity and meet 

stringent GHG abatement regulations by 

removing CO2 from their exhaust 

streams, with the added benefit of 

simultaneously lowering SO2 and NO2

emissions. 

At least one commenter suggested that 

it is unlikely that any vendor is willing 

or able to provide guarantees of the 

performance of the system as a whole, 

arguing that this shows the system isn’t 

adequately demonstrated.233 However, 

this suggestion is inconsistent with the 

performance guarantees offered for other 

air pollution control equipment. 

Particulate matter (PM) is controlled in 

the flue gas stream of a coal-fired power 

plant using fabric filters or electrostatic 

precipitators (ESP). The captured PM is 

then moved using PM/ash handling 

systems and is then transported for 

storage or re-use. It is unlikely that a 

fabric filter or ESP vendor would 

provide a performance guarantee for 

‘‘the system as a whole.’’ Similarly, a 

wet-FGD scrubber vendor would not be 

expected to provide a performance 

guarantee for handling, transportation, 

and re-use of scrubber solids for gypsum 

wallboard manufacturing. CO2 capture, 

transportation, and storage should, 

similarly, not be viewed as a single 

technology. Rather, these should be 

viewed as components of an overall 

system of emission reduction. Different 

companies will have expertise in each 

of these components, but it is unlikely 

that a single technology vendor would 

provide a guarantee for ‘‘the system as 

a whole.’’ 

2. Academic and Other Literature 

Climate change mitigation options— 

including CCS—are the subject of great 

academic interest, and there is a large 

body of academic literature on these 

options and their technical feasibility. 

In addition, other research organizations 

(e.g., U.S. national laboratories and 

others) have also published studies on 

these subjects that demonstrate the 

availability of these technologies. A 

compendium of relevant literature is 

provided in a Technical Support 

Document available in the rulemaking 

docket.234

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 

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235Testimony of Thomas O. Anderson, Vice 

President, Generation Development for Mississippi 

Power, MS Public Service Commission Docket 

2009–UA–14 at 22 (Dec. 7, 2009). 

236Mississippi 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. 

237American Electric Power Co Inc AEP Q2 2011 

Earnings Call Transcript, Morningstar, http://

www.morningstar.com/earnings/28688913- 

american-electric-power-co-incaep-q2–2011- 

earnings-call-transcript.aspx. 

238Alstom Comments, p. 3 (Docket entry: EPA– 

HQ–OAR–2013–0495–9033). 

239We 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-cost-competiveness/. 

240 ‘‘Cost and Performance Baseline for Fossil 

Energy Plants Volume 1a: Bituminous Coal (PC) and 

Natural Gas to Electricity Revision 3’’, DOE/NETL– 

2015/1723 (July 2015) at p. 36. 

241More recently, the D.C. Circuit stated: 

Our prior decisions relating to technology-forcing 

standards are no bar to this conclusion. We 

recognize here, as we have recognized in the past, 

that an agency may base a standard or mandate on 

future technology when there exists a rational 

connection between the regulatory target and the 

presumed innovation. 

API v. EPA, 706 F. 3d at 480 (D.C. Cir. 2013) 

(citing the section 111 case Sierra Club v. Costle, 

657 F. 2d at 364). The Senate Report to the original 

section 111 likewise makes clear that it was not 

intended that the technology ‘‘must be in actual 

routine use somewhere.’’ Rather, the question was 

whether the technology would be available for 

installation in new plants. S. Rep. No. 91–1196, 

91st Cong., 2d Sess. 16 (1970). 

242See, e.g., Comments of UARG p. 5 (Docket 

entry: EPA–HQ–OAR–2013–0495–9666). 

technically feasible. Industry officials 

have made additional positive 

statements in conjunction with facilities 

that received DOE assistance under 

EPAct05 or the IRC Section 48A tax 

credit. These statements provide further, 

although not necessary, support. 

For example, Southern Company’s 

Mississippi Power has stated that, 

because the SelexolTM process has been 

used in industry for decades, the 

technical risk of its use at the Kemper 

IGCC facility is minimized. For 

example: 

The carbon capture process being utilized 

for the Kemper County IGCC is a commercial 

technology referred to as SelexolTM. The 

SelexolTM process is a commercial 

technology that uses proprietary solvents, but 

is based on a technology and principles that 

have been in commercial use in the chemical 

industry for over 40 years. Thus, the risk 

associated with the design and operation of 

the carbon capture equipment incorporated 

into the Plant’s design is manageable.235

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.236

Similarly, in an AEP Second Quarter 

2011 Earnings Conference Call, 

Chairman and CEO Mike Morris said of 

the Mountaineer CCS project: 

We are encouraged by what we saw, we’re 

clearly impressed with what we learned, and 

we feel that we have demonstrated to a 

certainty that the carbon capture and storage 

is in fact viable technology for the United 

States and quite honestly for the rest of the 

world going forward.237

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).238

As discussed above, vendors do in 

fact offer performance guarantees. We 

further note that, as noted above, 

Boundary Dam Unit #3 is a full-scale 

project that is successfully 

implementing full CCS with postcombustion capture, and Dakota 

Gasification is likewise a full-scale 

commercial operation that is 

successfully implementing precombustion CCS technology. Moreover, 

as we explain above, this technology 

and performance is transferable to the 

steam electric generating sector. In 

addition, as noted above, technology 

providers and technology end users 

have expressed confidence in the 

availability and performance of CCS 

technology.239

G. Response to Key Comments on the 

Adequacy of the Technical Feasibility 

Demonstration 

1. Commercial Availability 

Some commenters asserted that CCS 

cannot be considered the BSER because 

it is not commercially available. There 

is no requirement, as part of the BSER 

determination, that the EPA finds that 

the technology in question is 

‘‘commercially available.’’ As we 

described in the January 2014 proposal, 

the D.C. Circuit has explained that a 

standard of performance is ‘‘achievable’’ 

if a technology or other system of 

emission reduction can reasonably be 

projected to be available to new sources 

at the time they are constructed that will 

allow them to meet the standard, and 

that there is no requirement that the 

technology ‘‘must be in routine use 

somewhere.’’ See Portland Cement v. 

Ruckelshaus, 486 F. 2d at 391; 79 FR 

1463. In any case, as discussed above, 

CCS technology is available through 

vendors who provide performance 

guarantees, which indicates that in fact, 

CCS is commercially available, which 

adds to the evidence that the technology 

is adequately demonstrated to be 

technically feasible. In sum, ‘‘[t]he 

capture and CO2 compression 

technologies have commercial operating 

experience with demonstrated ability 

for high reliability.’’ 240

2. Must a technology or system of 

emission reduction 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 or 

system of emission reduction itself. This 

is mistaken. Since the very inception of 

the CAA section 111 program, courts 

have noted that ‘‘[i]t would have been 

entirely appropriate if the Administrator 

had justified the standard, not on the 

basis of tests on existing sources or old 

test data in 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 401–02.241

In a related argument, other 

commenters stated that a system cannot 

be adequately demonstrated unless all 

of its component parts are operating 

together.242 Courts have, in fact, 

accepted that the EPA can legitimately 

infer that a technology is demonstrated 

as a whole based on operation of 

component parts which have not, as yet, 

been fully integrated. Sur Contra la 

Contaminacion v. EPA, 202 F. 3d 443, 

448 (1st Cir. 2000); Native Village of 

Point Hope v Salazar 680 F. 3d 1123, 

1133 (9th Cir. 2012). Moreover, all 

components of CCS are fully integrated 

at Boundary Dam: Post-combustion full 

CCS is being utilized at a steam electric 

fossil fuel-fired plant, with captured 

carbon being transported via dedicated 

pipeline to both sequestration and EOR 

sites. All components are likewise 

demonstrated for pre-combustion CCS at 

the Dakota Gasification facility, except 

that the facility does not generate 

electricity, a distinction without a 

difference for this purpose (see Section 

V.E.2.a above). 

The short of it is that the ‘‘EPA does 

have authority to hold the industry to a 

standard of improved design and 

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243Sierra Club v. Costle, 657 F. 2d 298, 341 n.157 

and 380–84 (D.C. Cir. 1981). See also Essex 

Chemical Corp. v. EPA, 486 F. 2d at 440 (upholding 

achievability of standard of performance for coalburning steam generating plants which hadn’t been 

achieved in full-scale performance based in part on 

‘‘prototype testing data’’ which, along with vendor 

guarantees, indicated that the promulgated standard 

was achievable); Weyerhaeuser v. Costle, 590 F. 2d 

1054 n. 170 (D.C. Cir. 1978) (use of pilot plant 

information to justify technology-based standard for 

Best Available Technology Economically 

Achievable under section 304 of the Clean Water 

Act); FMC Corp. v. Train, 539 F. 2d 973, 983–84 

(4th Cir. 1976)(same). 

244Cost and Performance Baseline for Fossil 

Energy Plants Volume 1: Bituminous Coal and 

Natural Gas to Electricity; Revision 2a, pp. 57–74. 

245Final front-end engineering design (FEED) 

study report’’, available at: 

www.globalccsinstitute.com/publications/tenaskatrailblazer-front-end-engineering-design-feed-study. 

246Report of the Interagency Task Force on 

Carbon Capture and Storage (August 2010), page 28. 

See also DOE Carbon Capture Web site: ‘‘First 

generation CO2 capture technologies are currently 

being used in various industrial applications. 

However, in their current state of development, 

these technologies are not ready for implementation 

on coal-based power plants because they have not 

been demonstrated at appropriate scale, requisite 

approximately one-third of the plant’s steam power 

to operate, and are cost prohibitive.’’ (Dec 2010); 

and Testimony of Dr. S. Julio Friedmann, Deputy 

Asst. Secretary of Energy for Clean Coal, U.S. Dept. 

of Energy, before the Subcommittee on Oversight 

and Investigations Committee on Energy and 

Commerce (Feb. 11, 2014): CCS technologies at new 

coal-fired plants would result in ‘‘something like a 

70 to 80 percent increase on the wholesale price of 

electricity.’’ 

operational advances, so long as there is 

substantial evidence that such 

improvements are feasible and will 

produce the improved performance 

necessary to meet the standard.’’ Sierra 

Club, 657 F. 2d at 364. The EPA’s task 

is to ‘‘identify the major steps necessary 

for development of the device, and give 

plausible reasons for its belief that the 

industry will be able to solve those 

problems in the time remaining’’. API v. 

EPA, 706 F. 3d at 480 (quoting NRDC v. 

EPA, 655 F. 2d 318, 333 (D.C. Cir. 1981), 

and citing Sierra Club for this 

proposition). 

3. Scalability of Pilot and Demonstration 

Projects 

Commenters maintained that the EPA 

had no basis for maintaining that pilot 

and demonstration plant operations 

showed that CCS was adequately 

demonstrated. This is mistaken. In a 

1981 decision, Sierra Club v. Costle, the 

D.C. Circuit explained that data from 

pilot-scale, or less than full-scale 

operation, 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.243 The EPA 

has done so here. 

Most obviously, the final standard 

reflects experience of full-scale 

operation of post-combustion carbon 

capture. Pre-combustion carbon capture 

is likewise demonstrated at full-scale. 

Second, the record explains in detail 

how CCS can be implemented at fullscale. 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 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.244

It is important to note that, while 

some commenters challenged the EPA’s 

use of costs in the DOE/NETL cost and 

performance reports, commenters did 

not challenge the technical methodology 

in the work. 

In addition, the AEP FEED study 

indicates how the development scale 

post-combustion CCS could be 

successfully scaled up to full-scale 

operation. See Section V.D.3.b above. 

Tenaska Trailblazer Partners, LLC also 

prepared a FEED study 245 for the carbon 

capture portion of the previously 

proposed Trailblazer Energy Center, a 

760 MW SCPC EGU that was proposed 

to include 85 to 90 percent CO2 postcombustion capture. Tenaska selected 

the Fluor Econamine FG PlusSM

technology and contracted Fluor to 

conduct the FEED study. One of the 

goals of the FEED study was to 

‘‘[c]onfirm that scale up to a large 

commercial size is achievable.’’ Tenaska 

ultimately concluded that the study had 

achieved its objectives resulting in 

‘‘[c]onfirmation that the technology can 

be scaled up to constructable design at 

commercial size through (1) process and 

discipline engineering design and CFD 

(computational fluid dynamics) 

analysis, (2) 3D model development, 

and (3) receipt of firm price quotes for 

large equipment.’’ 

Much has been written about the 

complexities of adding CCS systems to 

fossil fuel-fired power plants. Some of 

these statements come from high 

government officials. Some commenters 

argued that the EPA minimized—or 

even ignored—these publically voiced 

concerns in the discussion presented in 

the January 2014 proposal. On the 

contrary, the EPA has not minimized or 

ignored these complexities, but it is 

important to realize that most of these 

statements come in a different context: 

Namely, implementing full CCS, or 

retrofitting CCS onto existing power 

plants. For example, in the Final Report 

of the President’s CCS Task Force, it 

was noted that ‘‘integration of CCS 

technologies with the power cycle at 

generating plants can present significant 

cost and operating issues that will need 

to be addressed to facilitate widespread, 

cost-effective deployment of CO2

capture.’’ 246 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 and many reference 

widespread implementation of such 

technology. The EPA has addressed the 

concerns regarding ‘‘significant cost’’ by 

finalizing a standard that relies on 

partial CCS which we show, in this 

preamble and in the supporting record, 

can be implemented at a reasonable, 

non-exorbitant cost. The Boundary Dam 

facility, in particular, demonstrates that 

the complexities of implementing 

CCS—even full CCS—can be overcome. 

Concerns regarding ‘‘operating issues’’ 

are also often associated with 

implementation of full CCS—and often 

with implementation of full CCS as a 

retrofit to an existing source. 

Implementation of CCS at some existing 

sources may be challenging because of 

space limitations. That should not be an 

issue for a new facility because the 

developer will need to ensure that 

adequate space is available during the 

design of the facility. Constructing CCS 

technology at an existing facility can be 

challenging even if there is adequate 

space because the positioning of the 

equipment may be awkward when it 

must be constructed to fit with the 

existing equipment at the plant. Some 

commenters noted the challenges of 

diverting steam from the plant’s steam 

cycle. Again, that is primarily an issue 

with full CCS implementation as a 

retrofit to an existing source. 

Consideration of steam requirements for 

solvent regeneration can be factored into 

the design of a new facility. We also 

note that issues of integration with the 

plant’s steam cycle are less challenging 

when implementing partial CCS. 

Some commenters noted conclusions 

and statements from the CCS Task Force 

report as contradictory to the EPA’s 

determination of that partial CCS is 

technically feasible and adequately 

demonstrated. However, the EPA 

mentioned in the January 2014 

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247For the cost estimates in the January 2014 

proposal, the EPA used costs for new SCPC and 

IGCC units utilizing bituminous coal from the 

reports ‘‘Cost and Performance Baseline for Fossil 

Energy Plants Volume 1: Bituminous Coal and 

Natural Gas to Electricity’’, Revision 2, Report DOE/ 

NETL–2010/1397 (November 2010) and ‘‘Cost and 

Performance of PC and IGCC Plants for a Range of 

Carbon Dioxide Capture’’, DOE/NETL–2011/1498, 

May 27, 2011. Additional cost and performance 

information can be found in additional volumes 

that are available at http://www.netl.doe.gov/

research/energy-analysis/energy-baseline-studies. 

248Even in its sensitivity analysis that assumes 

higher natural gas prices and electricity demand, 

EIA does not project any additional coal beyond its 

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, if any, new coalfired steam generating EGUs will be 

built in the near term. 

Thus, the EPA has provided an ample 

record supporting its finding that partial 

CCS is feasible at full-scale. As in Sierra 

Club, the EPA has presented evidence 

from full-scale operation, smaller scale 

installations, and reasonable, 

corroborated technical explanations of 

how the BSER can be successfully 

operated at full scale. See 657 F. 2d at 

380, 382. Indeed, the EPA has more 

evidence here, as the baghouse standard 

in Sierra Club was justified based 

largely on less-than-full-scale operation. 

See 657 F.2d at 380 (there was only 

‘‘limited data from one full scale 

commercial sized operation’’), 376 (‘‘the 

baghouses surveyed were installed at 

small plants’’), and 341 n.157; see also 

Section V.L, explaining why CCS is a 

more developed technology than FGD 

scrubbers were at the inception of the 

1971 NSPS for this industry. 

H. Consideration of Costs 

CAA section 111(a) defines ‘‘standard 

of performance’’ as an emission 

standard that reflects the best system of 

emission reduction that is adequately 

demonstrated, ‘‘taking into account 

[among other things] the cost of 

achieving such reduction.’’ Based on 

consideration of relevant cost metrics in 

the context of current market 

conditions, the EPA concludes that the 

costs associated with the final standard 

are reasonable. 

In reaching this determination, the 

EPA considered a host of different cost 

metrics, each of which illuminated a 

particular aspect of cost consideration, 

and each of which demonstrated that 

the costs of the final standard are 

reasonable. The EPA evaluated capital 

costs on a per-plant basis, responding to 

public comment that noted the 

particular significance of capital costs 

for coal-fired EGUs. As in the proposal, 

the EPA also considered how the 

standard would affect the LCOE for 

individual affected EGUs as well as 

national, overall cost impacts of the 

standard. The EPA found that the 

anticipated cost impacts are similar to 

those in other promulgated NSPS— 

including for this industry—that have 

been upheld by the D.C. Circuit. The 

costs are also comparable to those of 

other base load technologies that might 

be selected on comparable energy 

portfolio diversity grounds. Finally, the 

EPA does not anticipate any significant 

overall nationwide costs or cost impacts 

on consumers because projected new 

generating capacity is expected to meet 

the standards even in the baseline. 

Accordingly, after considering costs 

from a range of different perspectives, 

the EPA concludes that the costs of the 

final standard are reasonable. 

1. Rationale at Proposal 

At proposal, the EPA evaluated the 

costs of new coal-fired EGUs 

implementing full (90 percent) and 

partial CCS. The EPA compared the 

predicted LCOE of those units against 

the LCOE of other new dispatchable 

technologies often considered for new 

base load power with fuel diversity, 

primarily including a new nuclear 

plant, as well as a new biomass-fired 

EGU. See 79 FR at 1475–78. The 

levelized cost for a new steam EGU 

implementing full CCS was higher than 

that of the other non-NGCC dispatchable 

technologies, and we did not propose to 

identify a new steam EGU implementing 

full CCS as BSER on that basis. Id. at 

1477. The EPA proposed that a standard 

of performance of 1,100 lb CO2/MWh-g, 

reflecting a new steam EGU 

implementing partial CCS, could be 

achieved at reasonable cost based on a 

comparison of the projected LCOE 

associated with achieving this standard 

with the alternative dispatchable 

technologies just mentioned. In the 

January 2014 proposal, the EPA used 

LCOE projections for new fossil fuelfired EGUs from a series of studies 

conducted by the DOE NETL. These 

studies—the ‘‘cost and performance 

studies’’—detail expected costs and 

performance for a range of technology 

options both with and without CCS.247

The EPA used LCOE projections for 

non-fossil dispatchable generation— 

specifically nuclear and biomass—from 

the EIA AEO 2013. See 79 FR 1435. 

In addition, the EPA proposed that 

the costs to implement partial CCS were 

reasonable because a segment of the 

industry was already accommodating 

them. Id. at 1478. The EPA also 

considered anticipated decreases in the 

cost of CCS technologies, the 

availability of government tax benefits, 

loan guarantees, and direct 

expenditures, and the opportunity to 

generate income from sale of captured 

CO2 for EOR. Id. at 1478–80. The EPA 

noted that the proposed standard was 

not expected to lead to any significant 

overall costs or effects on electricity 

prices. Id. at 1480–81. The EPA also 

acknowledged the overall market 

context, noting that fossil steam EGUs, 

even without any type of CCS, are 

significantly more expensive than new 

natural gas-fired electricity generation, 

but that some electricity suppliers might 

include new coal-fired generating 

sources in their generation portfolio, 

and would pay a premium to do so. Id. 

at 1478. 

2. Brief Summary of Cost Considerations 

Under CAA Section 111 

As explained above, CAA section 

111(a) directs the EPA to ‘‘tak[e] into 

account the cost’’ of achieving 

reductions in determining if a particular 

system of emission reduction is the best 

that is adequately demonstrated. The 

statute does not provide further 

guidance on how costs should be 

considered, thus affording the EPA 

considerable discretion in choosing a 

means of cost consideration. In 

addition, it should be noted that in 

evaluating the reasonableness of costs, 

the D.C. Circuit has upheld application 

of a variety of metrics, such as the 

amount of control costs or product price 

increases. See Section III.H.3.(b).(1) 

above. 

Following the directive of CAA 

section 111(a) and applicable precedent, 

the EPA evaluated relevant metrics and 

context in considering the 

reasonableness of the regulation’s costs. 

The EPA’s findings demonstrate that the 

costs of the selected final standard are 

reasonable. 

3. Current Context 

The EIA projects that few new coalfired EGUs will be constructed over the 

coming decade and that those that are 

built will apply CCS, reflecting the 

broad consensus of government, 

academic, and industry forecasters.248

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reference case until 2023, in a case where power 

companies assume no GHGs emission limitations, 

and until 2024 in a case where power companies 

do assume GHGs emission limitations. EIA, 

‘‘Annual Energy Outlook 2015,’’ DOE/EIA– 

0383(2015), April 2015, ‘‘[v]ery little unplanned 

coal-fired capacity is added across all the AEO 2015 

cases’’, p. 26. 

249EIA, ‘‘Annual Energy Outlook 2015,’’ DOE/

EIA–0383(2015), April 2015, p. 8. 

250 Integrated Planning Model (IPM) run by the 

EPA (v. 5.15) Base Case, available at www.epa.gov/ 

airmarkets/powersectormodeling.html. 

251Technical Support Document—‘‘Review of 

Electric Utility Integrated Resource Plans’’ (May 

2015), available in the rulemaking docket EPA–HQ– 

OAR–2013–0495. 

252The EPA may, of course, consider revenues 

generated as a result of application of pollution 

control measures in assessing the costs of a best 

system of emission reduction. See New York v. 

Reilly, 969 F.2d 1147, 1150–52 (D.C. Cir. 1992). 

253See, e.g., Comments of Murray Energy, pp. 79– 

80 (Docket entry: EPA–HQ–OAR–2013–0495– 

10046). 

254 Indeed, the EPA is not only adopting a 

standard predicated on a lower rate of carbon 

capture than proposed, but also rejecting full CCS 

for reasons of cost. See Section V.P below. Thus, 

although the EPA has reasonably taken into account 

the current economic posture of the industry 

whereby new capacity is not cost-competitive and 

so would be added for non-economic reasons, it is 

not using that fact to negate consideration of cost 

here. See also Section V.I.4 below responding to 

comments that the incremental cost of partial CCS 

could prove the difference between constructing 

and not constructing new coal capacity. 

255 In this rulemaking, our determination that the 

costs are reasonable means that the costs meet the 

cost standard in the case law no matter how that 

standard is articulated, that is, whether the cost 

standard is articulated through the terms that the 

case law uses, e.g., ‘‘exorbitant,’’ ‘‘excessive,’’ etc., 

or through the term we use for convenience, 

‘‘reasonableness.’’ 

256See RIA chapter 4.5.4 and Fig. 4–3; see also 

‘‘Cost and Performance Baseline for Fossil Energy 

Plants Supplement: Sensitivity to CO2 Capture Rate 

in Coal-Fired Power Plants’’, DOE/NETL–2015/1720 

(July 2015) p. 17. 

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, U.S. 

electricity demand growth has followed 

a downward sloping trend for decades 

with future growth expected to remain 

very low.249 Furthermore, the EPA 

projects that, for any new fossil fuelfired electricity generating capacity that 

is constructed through 2030, natural gas 

will be the overwhelming fuel of 

choice.250 See RIA chapter 4. 

The EIA’s projection is confirmed by 

an examination of Integrated Resource 

Plans (IRPs) contained in a TSD in the 

docket for this rulemaking. IRPs are 

used by utilities to plan operations and 

investments in both owned generation 

and power purchase agreements over 

long time horizons. Though IRPs do not 

demonstrate a utility’s intent to pursue 

a particular generation technology, they 

do indicate the types of new generating 

technologies that a utility would 

consider for new generating capacity. 

The EPA’s survey of recent IRPs 

demonstrates that across the nation, 

utilities are not actively considering 

constructing new coal-fired generation 

without CCS in the near term. 

Accordingly, construction of new 

uncontrolled coal-fired generating 

capacity is not anticipated in the near 

term, even in the absence of the 

standards of performance we are 

finalizing in this rule, except perhaps in 

certain limited circumstances. 

In particular, commenters suggested 

that some developers might choose to 

build a new coal-fired EGU, despite its 

not being cost competitive, in order to 

achieve or maintain ‘‘fuel diversity.’’ 

Fuel diversity could provide important 

value by serving as a hedge against the 

possibility that future natural gas prices 

will far exceed projected levels. 

Public announcements, including 

IRPs, confirm that utilities are interested 

in technologies that could provide or 

preserve fuel diversity within generating 

fleets. The Integrated Resource Plan 

TSD 251 notes examples where the goal 

of fuel diversity was considered in IRPs; 

in many cases, these plans considered 

new generation that would not rely on 

natural gas. In particular, several 

utilities that considered fuel diversity in 

developing their IRPs included new 

nuclear generation as a potential future 

generation strategy. 

In addition, the EPA recognizes that 

there may be interest in constructing a 

new combined-purpose coal-fired 

facility that would generate power as 

well as produce chemicals or CO2 for 

use in EOR projects. These facilities 

would similarly provide additional 

value due to the revenue streams from 

saleable chemical products or CO2.252

As demonstrated below, the agency 

carefully considered the reasonableness 

of costs in identifying a standard that 

allows a path forward for such projects 

and rejects more stringent options that 

would impose potentially excessive 

costs. In fact, based on this careful 

consideration of costs, the EPA is 

finalizing a substantially lower cost 

standard than the one we proposed. At 

the same time, we note the unusual 

circumstances presented here, where 

the record, and indeed simple 

consideration of electricity market 

economics, demonstrates that noneconomic factors such as fuel diversity 

are likely to drive any construction of 

new coal-fired generation. See also RIA 

chapter 4 (documenting that electric 

power companies will choose to build 

new EGUs that comply with the 

regulatory requirements of this rule 

even in its absence, primarily NGCC 

units, because of existing and expected 

market conditions). Under these 

circumstances, the EPA’s consideration 

of costs takes into account that higher 

costs can be viewed as reasonable when 

costs are not a paramount factor in new 

coal capacity decisions. At the same 

time, the EPA acknowledges and agrees 

with the public comments that such an 

argument, left unconstrained, could 

justify any standard and obviate all cost 

considerations.253 The EPA has 

reasonably cabined its consideration of 

costs by examining costs for comparable 

non-NGCC base load dispatchable 

technologies, as well as by considering 

capital costs and other cost metrics.254

This cost-reasonable standard will 

preserve the opportunity for such 

projects while driving new technology 

deployment.255

4. Consideration of Capital Costs 

As noted above, CAA section 111 

does not mandate any particular method 

for evaluating costs, leaving the EPA 

with significant discretion as to how to 

do so. One method is to consider the 

incremental capital costs required for a 

unit to achieve the standard of 

performance. 

The EPA included information on 

capital cost at proposal and, as 

discussed further below, the LCOE 

metric relied upon at proposal and in 

this final rulemaking incorporates and 

fully reflects capital costs.256

Nonetheless, extensive comment from 

industry representatives and others 

noted persuasively that fossil-steam 

units are very capital-intensive projects 

and recommended that a separate 

metric, solely of capital costs, be 

considered by the EPA in evaluating the 

final standard’s costs. Accordingly, the 

EPA has considered the final standard’s 

impact on the capital costs of new 

fossil-steam generation. The EPA has 

determined that the incremental capital 

costs of the final standard are reasonable 

because they are comparable to those in 

prior regulations and to industry 

experience, and because the fossil steam 

electric power industry has been shown 

to be able to successfully absorb capital 

costs of this magnitude in the past. 

Prior new source performance 

standards for new fossil steam 

generation units have had significant— 

yet manageable—impacts on the capital 

costs of construction. The EPA 

estimated that the costs for the 1971 

NSPS for coal-fired EGUs were $19M for 

a 600 MW plant, consisting of $3.6M for 

particulate matter controls, $14.4M for 

sulfur dioxide controls, and $1M for 

nitrogen oxides controls, representing a 

15.8 percent increase in capital costs 

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257Congressional Budget Office report, ‘‘The 

Clean Air Act, the Electric Utilities, and the Coal 

Market’’, April 1982, p. 10–11, 23. 

258 Id. at 10–11. 

259 Id. at 22. 

260 Id. at xvi. 

261 Id. 

262We explain at Section V.I.2 and 3 below the 

reasonableness of the EPA’s cost projections here. 

263We estimate that a new SCPC EGU using low 

rank coal (subbituminous coal or dried lignite) 

would incur a capital cost increase of 23 percent to 

meet the final standard. See ‘‘Achievability of the 

Standard for Newly Constructed Steam Generating 

EGUs’’ technical support document available in the 

rulemaking docket. 264Exhibit A–3 (p. 18); ‘‘Cost and Performance 

Baseline for Fossil Energy Plants Supplement: 

Sensitivity to CO2 Capture Rate in Coal-Fired Power 

Plants’’, DOE/NETL–2015/1720 (June 2015). 

265 ‘‘Cost and Performance Baseline for Fossil 

Energy Plants: Volume 1a’’ Bituminous Coal (PC) 

and Natural Gas to Electricity, Revision 3, U.S. DOE 

NETL report (2015) and ‘‘Cost and Performance 

Baseline for Fossil Energy Plants: Volume 1b: 

Bituminous Coal (IGCC) to Electricity, Revision 2— 

Year Dollar Update, U.S. DOE NETL report (2015). 

Both reports are available at www.netl.doe.gov/

research/energy-analysis/energy-baseline-studies. 

above the $120M cost of the plant. See 

1972 Supplemental Statement, 37 FR 

5767, 5769 (March 21, 1972). The D.C. 

Circuit upheld the EPA’s determination 

that the costs associated with the final 

1971 standard were reasonable, 

concluding that the EPA had properly 

taken costs into consideration. Essex 

Cement v. EPA, 486 F. 2d at 440. 

In reviewing the 1978 NSPS for coalfired EGUs, the D.C. Circuit recognized 

that ‘‘EPA estimates that utilities will 

have to spend tens of billions of dollars 

by 1995 on pollution control under the 

new NSPS’’ and that ‘‘[c]onsumers will 

ultimately bear these costs.’’ Sierra 

Club, 657 F.2d at 314. The court 

nonetheless upheld the EPA’s 

determination that the standard was 

reasonable. Id. at 410. 

The cost and investment impacts of 

the 1978 NSPS on electric utilities were 

subsequently evaluated in a 1982 

Congressional Budget Office (CBO) 

retrospective study.257 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.258 The 

study further noted that air pollution 

control requirements in general had led 

to an estimated 37.5 to 45 percent 

increase in capital costs for coal-fired 

power plant installation between 1971 

and 1980.259

The study retrospectively confirmed 

the EPA’s conclusion that imposition of 

these costs was reasonable, finding that 

‘‘utilities with commitments to 

pollution control tend to fare no better 

and no worse than all electric utilities 

in general.’’ 260 In assessing the capital 

cost impacts of the suite of 1970s EPA 

air pollution standards, the report 

concluded that ‘‘though controlling 

emissions is indeed costly, it has not 

played a major role in impairing the 

utilities’ financial position, and is not 

likely to do so in the future.’’ 261

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 

comparable in magnitude on an 

individual unit basis to those projected 

for the present standard. We predict that 

the incremental costs of control for a 

new highly efficient SCPC unit to meet 

the final emission limitation of 1,400 lb 

CO2/MWh-g would be an increase of 

21–22 percent for capital costs. See 

Table 7 below.262 263

TABLE 7—COMPARISON OF ESTIMATED CAPITAL COSTS FOR A NEW SCPC AND A NEW SCPC MEETING THE FINAL

STANDARD OF PERFORMANCE 264

Total overnight 

cost 

(2011$/kW) 

Total as-spent 

capital 

(2011$/kW) 

SCPC—no CCS ....................................................................................................................................................... 2,507 2,842 

SCPC—partial CCS (1,400 lb CO2/MWh-g) ............................................................................................................ 3,042 3,458 

Incremental cost increase ........................................................................................................................................ 21.3% 21.7% 

By comparison, a SCPC that co-fires 

with natural gas to meet the final 

standard of 1,400 lb CO2/MWh-g would 

not result in an increase in capital cost 

over the uncontrolled SCPC. A 

compliant IGCC unit co-firing natural 

gas is predicted to have Total Overnight 

Cost of $3,036/kW—an approximately 

21.1 percent increase in capital over the 

uncontrolled SCPC unit. 

5. Consideration of Costs Based on 

Levelized Cost of Electricity 

As in the proposal, the EPA also 

considered the reasonableness of costs 

by evaluating the LCOE associated with 

the final standard. The LCOE is a 

commonly used economic metric that 

takes into account all costs to construct 

and operate a new power plant over an 

assumed time period and an assumed 

capacity factor. The LCOE is a summary 

metric, which expresses the full cost of 

generating electricity on a per unit basis 

(i.e., megawatt-hours). Levelized costs 

are often used to compare the cost of 

different potential generating sources. 

While capital cost is a useful and 

relevant metric for capital-intensive 

fossil-steam units, the LCOE can serve 

as a useful complement because it takes 

into account all specified costs 

(operation and maintenance, fuel—as 

well as capital costs), over the whole 

lifetime of the project. 

As previously mentioned, at proposal 

the EPA relied on LCOE projections for 

fossil fuel-fired EGUs (with and without 

CCS) from DOE/NETL reports detailing 

the results of studies evaluating the 

costs and performance of such units. For 

non-fossil dispatchable generating 

sources, the EPA relied on LCOE 

projections from EIA AEO 2013. For this 

final action, the EPA is relying on 

updated costs from the same sources. 

The NETL has provided updated cost 

and performance information in 

recently published revisions of reports 

used in the January 2014 proposal.265

The updated SCPC cases in the reports 

include up-to-date cost and performance 

information from recent vendor quotes 

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266Cost and Performance Baseline for Fossil 

Energy Plants Supplement: Sensitivity to CO2

Capture Rate in Coal-Fired Power Plants’’, DOE/

NETL–2015/1720 (June 2015) p. 18. 

267 ‘‘Cost and Performance Baseline for Fossil 

Energy Plants Supplement: Sensitivity to CO2

Capture Rate in Coal-Fired Power Plants’’, DOE/

NETL–2015/1720 (June 2015). Available at http://

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

268http://www.eia.gov/forecasts/aeo/electricity_

generation.cfm. 

269See, e.g. ‘‘Cost and Performance Baseline for 

Fossil Energy Plants Supplement: Sensitivity to CO2

Capture Rate in Coal-Fired Power Plants’’, DOE/

NETL–2015/1720 (June 2015) at p. 17. 

270See also discussion at V.C.3 above. The IRPs 

do not provide an indication of the utility’s 

intention to pursue a particular generation 

technology. However, the IRPs do provide an 

indication of the types of new generating 

technologies that the utility would consider for new 

generating capacity. 

271See, e.g. the 2014 IRP of Dominion Virginia 

Power: 

With those factors in mind, the 2014 Plan 

presents two paths forward for resource expansion: 

a Base Plan, designed using least-cost planning 

methods and consistent with the requirements of 

Rule R8–60 for utility plans to provide ‘‘reliable 

electric utility service at least cost over the planning 

period;’’ and a Fuel Diversity Plan, which includes 

a broader array of low or zero-emissions options. 

While the Fuel 2 Diversity Plan currently represents 

a higher cost option at today’s current and projected 

commodity prices, its resource mix provides the 

important benefits of greater fuel diversity and 

lower carbon intensity. Therefore, the Company 

will continue reasonable development of the more 

diverse and lower carbon intensive options in the 

Fuel Diversity Plan and will be ready to implement 

them as conditions warrant. . . . The Fuel Diversity 

Plan places a greater reliance on generation sources 

with little or no carbon emissions and is less reliant 

on natural gas. While following the resource 

expansion scenario in the least-cost Base Plan, the 

Company will continue evaluation and reasonable 

development efforts for the following projects 

identified in the Fuel Diversity Plan. These include: 

Continued development of a third nuclear reactor 

at North Anna Power Station, using reactor 

technology supplied by GE-Hitachi Nuclear Energy 

Americas LLC. While the Company has made no 

final commitment to building this unit, it 

recognizes the many operational and environmental 

benefits of nuclear power and continues to actively 

develop the project. Our customers have benefitted 

from the existing nuclear fleet for many years now, 

and they will continue to benefit from the existing 

fleet for many years in the future. A final decision 

on construction of North Anna Unit 3 will not be 

made until after the Company receives a Combined 

Operating License or COL from the U.S. Nuclear 

Regulatory Commission, now expected in 2016. The 

Fuel Diversity Plan includes the addition of North 

Anna Unit 3’s 1,453 megawatts of zero-emissions 

generation by 2028. If constructed, the project 

would provide a dramatic boost to the regional 

economy. 

Additional reliance on renewable energy, 

including 247 megawatts of onshore wind capacity 

at sites in western Virginia and a 12 megawatt 

offshore wind demonstration project by 2018. 

An additional 559 megawatts of nameplate solar 

capacity, including several new Company-owned 

photovoltaic CPV) installations. Solar PV costs have 

declined significantly in recent years, making 

utility-scale solar much more cost-effective than 

distributed solar, and continuing technological 

development, in which the Company is 

participating, may allow it to become a more costeffective source of intermittent generation in the 

future.cover letter for 2014 IRP—https://

www.dom.com/library/domcom/pdfs/corporate/

integrated-resource-planning/va-irp-2014.pdf. 

272Another example are the recent statements of 

officials of Tri-State Generation and Transmission, 

available at http://www.wyofile.com/coal-power/, 

including: 

‘‘We are considering nuclear, coal and natural 

gas,’’ said Ken Anderson, general manager of TriState at a conference in October [2010], a position 

that Tri-State representatives say remains. ‘‘We will 

pick our technology once policy certainty comes 

about,’’ he added. . . . Longer-term forecasts are 

based on assumptions that may or may not prove 

well-founded. Because of this uncertainty, Tri-State 

believes it must retain options for all fuels and 

technologies. 

‘‘We will not take anything off the table,’’ [TriState spokesman Lee] Boughey said. That includes 

coal. ‘‘Coal is an affordable and plentiful resource, 

but it does come with challenges—and we are 

Continued 

and implementation of the Shell 

Cansolv post-combustion capture 

process—the process that is currently 

being utilized at the Boundary Dam #3 

facility. The IGCC cost and performance 

results in the updated reports utilize 

vendor quotes from the previous report; 

the costs are adjusted from $2007 to 

$2011. Important also to note is that 

DOE/NETL utilized conventional 

financing for cases without CCS and 

utilized high-risk financial assumptions 

for cases that include CCS.266

Using information from those reports, 

the DOE/NETL prepared a separate 

report summarizing a study that 

evaluated the cost and performance of 

various plants designed to meet a range 

of CO2 emissions by varying the CO2

capture rate (i.e., the level of partial 

capture).267 The EIA also updated LCOE 

projections from AEO 2013 to AEO 2014 

and again in AEO 2015. Those are 

discussed in more detail in Section 

V.I.2.b and d. In evaluating costs for the 

final standards in this action, the EPA 

relied primarily on the updated NETL 

LCOE projections for new fossil fuelfired EGUs provided in the reports 

described above and on the LCOE 

projections for non-fossil, dispatchable 

generating options from the EIA’s AEO 

2015.268 Here, the EPA compared the 

LCOE of the final standard to the LCOE 

of analogous potential sources of 

intermediate and base load power. This 

comparison demonstrated that the LCOE 

for a fossil steam unit with partial CCS 

is within the range of the LCOE of 

comparable alternative non-NGCC 

generation sources. In particular, 

nuclear and biomass generation, which 

similarly provide both base load power 

and fuel diversity, have comparable 

LCOE. The EPA concludes that an 

evaluation of the LCOE also 

demonstrates that the costs of the final 

standard are reasonable. 

a. Calculation of the LCOE 

The LCOE of a power plant source is 

calculated with the expected lifetime 

and average capacity factor, and 

represents the average cost of producing 

a megawatt-hour (MWh) of electricity 

over the expected lifetime of the asset. 

The LCOE incorporates all specified 

costs, and therefore is dependent on the 

project’s capital costs, the fixed and 

variable operating and maintenance 

(O&M) costs, the fuel costs, the costs to 

finance the project, and finally on the 

assumed capacity factor.269 The relative 

contribution of each of these inputs to 

LCOE will vary among the generating 

technologies. For example, the LCOE for 

a new supercritical PC plant or a new 

IGCC plant is influenced more by the 

capital costs (and thus the financing 

assumptions) and less on fuel costs than 

a comparably sized new NGCC facility 

which would require less capital 

investment but would be more 

influenced by assumed fuel costs. 

b. Use of the LCOE 

The utility industry and electricity 

sector regulators often use levelized 

costs as a summary measure for 

comparing the cost of different potential 

generating sources. Use of the LCOE as 

a comparison measure is appropriate 

where the facilities being compared 

would serve load in a similar manner. 

The value of generation, as reflected 

in the wholesale electricity price, can 

vary seasonally and over the course of 

a day. In addition, electricity generation 

technologies differ on dimensions other 

than just cost, such as ramping 

efficiency, intermittency, or uncertainty 

in future fuel costs. These other factors 

are also important in determining the 

value of a particular generation 

technology to a firm, and accordingly 

cost comparisons between two different 

technologies are most appropriate and 

insightful when the technologies align 

along these other dimensions. Isolating 

a comparison of technologies based on 

their LCOE is appropriate when they 

can be assumed to provide similar 

services and similar values of electricity 

generated. 

As we indicated in the proposal, we 

evaluated publicly available IRPs and 

other available information (such as 

public announcements) to determine the 

types of technologies that utilities are 

considering as options for new 

generating capacity.270 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.271 272 The options for 

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looking to different technology that can address 

some of those challenges while continuing to 

provide a reliable and affordable power supply,’’ 

Boughey said. ‘‘Some critics believe we shouldn’t 

be looking at resource options that include coal, 

and even nuclear technology,’’ Boughey added. 

‘‘We believe it would be irresponsible not to 

consider these fuels or technologies as part of an 

affordable, reliable and responsible resource 

portfolio.’’ 

273Lazard’s Levelized Cost of Energy Analysis— 

Version 8.0; September 2014; available at: http://

www.lazard.com/media/1777/levelized_cost_of_

energy_-_version_80.pdf and in the rulemaking 

docket. 

274Lazard is one of the world’s preeminent 

financial advisory and asset management firms. 

Lazard’s Global Power, Energy & Infrastructure 

Group serves private and public sector clients with 

advisory services regarding M&A, financing, and 

other strategic matters. The group is active in all 

areas of the traditional and alternative energy 

industries, including regulated utilities, 

independent power producers, advanced 

transportation technologies, renewable energy 

technologies, meters, smart grid and energy 

efficiency technologies, and infrastructure. http://

www.marketwatch.com/story/lazard-releases-newlevelized-cost-of-energy-analysis-2014-09-18. 

275LCOE cost estimates for SCPC and IGCC cases 

come from ‘‘Cost and Performance Baseline for 

Fossil Energy Plants Supplement: Sensitivity to CO2

Capture Rate in Coal-Fired Power Plants’’ DOE/

NETL–2015/1720 (June 22, 2015). Cost and 

performance for low rank SCPC is adapted from 

‘‘Cost and Performance Baseline for Fossil Energy 

Plants Volume 3 Executive Summary: Low Rank 

Coal and Natural Gas to Electricity’’, DOE/NETL– 

2010/1399 (September 2011). LCOE cost estimates 

for nuclear and biomass are derived from 

‘‘Levelized Cost and Levelized Avoided Cost of 

New Generation Resources in the Annual Energy 

Outlook 2015’’, June 2015, www.eia.gov/forecasts/

aeo/pdf/electricity_generation.pdf. LCOE cost 

estimates for NGCC technology are EPA estimates 

based on a range of potential natural gas prices. 

276Table 8 includes LCOE figures for biomassfired generation, a potential sources of dispatchable 

base load power that is not fueled by natural gas. 

The EPA includes this information for 

completeness, while noting that biomass-fired units 

in operation in the U.S. are smaller scale and thus 

are not as robust analogues as nuclear power. CO2

emissions are not provided for biomass units 

because different biomass feedstocks have different 

net CO2 emissions; therefore a single emission rate 

is not appropriate to show in Table 8. 

277 ‘‘Cost and Performance Baseline for Fossil 

Energy Plants Supplement: Sensitivity to CO2

Capture Rate in Coal-Fired Power Plants’’, DOE/

NETL–2015/1720 (June 2015) at p. 18. 

278LCOE comparisons of reasonably available 

compliance alternatives—IGCC with natural gas cofiring, and SCPC with natural gas co-firing—are 

found below in Table 9. As shown there, these 

alternatives are either lower cost than SCPC with 

partial CCS, or of comparable cost. 

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 coalfired plant with that of a peaking natural 

gas-fired simple cycle turbine. 

Similarly, it may not be appropriate to 

compare LCOE for dispatchable 

technologies (i.e., generating sources 

that can be ramped up or down as 

needed, e.g., coal-fired units, NGCC 

units, nuclear) with that of nondispatchable technologies (i.e., 

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 that 

of other sources, as shown in Table 8 

below. As mentioned earlier and 

discussed in further detail below, these 

estimates rely most heavily on DOE/

NETL cost projections for fossil fuel 

generating technologies and on the 

updated EIA AEO 2015 for non-fossil 

generation technologies. Recent 

estimates from Lazard 273 274 are also 

provided for nuclear and biomass 

generation options. 

TABLE 8—PREDICTED COST AND CO2 EMISSION LEVELS FOR A RANGE OF POTENTIAL NEW GENERATION

TECHNOLOGIES 275

New generation technology Emission 

lb CO2/MWh-g 

LCOE* 

$/MWh 

SCPC—no CCS (bit) ................................................................................................................................... 1,620 76–95 

SCPC—no CCS (low rank) ......................................................................................................................... 1,740 75–94 

SCPC + ∼16% partial CCS (bit) .................................................................................................................. 1,400 92–117 

SCPC + ∼23% partial CCS (low rank) ........................................................................................................ 1,400 95–121 

Nuclear (EIA) ............................................................................................................................................... 0 87–115 

Nuclear (Lazard) .......................................................................................................................................... 0 92–132 

Biomass (EIA) 276 ......................................................................................................................................... — 94–113 

Biomass (Lazard) ......................................................................................................................................... — 87–116 

IGCC ............................................................................................................................................................ 1,430 94–120 

NGCC .......................................................................................................................................................... 1,000 ** 52–86 

* The LCOE ranges presented in Table 8 include an uncertainty of ¥15%/+30% on capital costs for SCPC and IGCC cases and an uncertainty 

of ¥10%/+30% on capital costs for nuclear and biomass cases from EIA. This reflects information provided by EIA. Nuclear staff experts expect 

that nuclear plants currently under construction would not have capital costs under estimates and that one could expect to see a 30% ‘‘upside’’ 

variation in capital cost. There is also insufficient market data to get a good statistical range of potential capital cost variation (i.e. only 2 plants 

under construction, neither complete). The nuclear cost estimates from Lazard likewise reflect the range of expected nuclear costs. LCOE estimates displayed in this table for SCPC units with partial CCS as well as for IGCC units use a higher financing cost rate in comparison to the 

SCPC unit without capture.277

** This range represents a natural gas price from $5/MMBtu to $10/MMBtu. 

As shown in Table 8, we project that 

the LCOE for new fossil steam capacity 

meeting the final 1,400 lb CO2/MWh-g 

standard to be substantially similar to 

that for a new nuclear unit, the 

principal other alternative to natural gas 

to provide new base load power. This is 

the case for new units firing bituminous 

and subbituminous coals and dried 

lignite. This is another demonstration 

that the costs of the final standard are 

reasonable because nuclear and fossil 

steam generation each would serve an 

analogous role in adding dispatchable 

base load generation diversity—or at 

least non-NGCC alternatives—to a 

power provider’s portfolio; hence, they 

are reasonably viewed as comparable 

alternatives.278

As previously mentioned, the DOE/

NETL assumed conventional financing 

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279 ‘‘Cost and Performance Baseline for Fossil 

Energy Plants Supplement: Sensitivity to CO2

Capture Rate in Coal-Fired Power Plants’’, DOE/

NETL–2015/1720 (June 2015) at p. 7. 

280As another example, San Antonio customers 

will benefit from low-carbon power from the Texas 

Clean Energy Project. CPS Energy CEO Doyle 

Deneby said in a news release: ‘‘Adding clean coal 

to our portfolio dovetails with our strategy to 

diversify and reduce the carbon intensity of the 

power we supply to our customers.’’ 

www.bizjournals.com/sanantonio/news/2014/10/

06/cps-energy-strikes-new-deal-to-buy-powerfrom.html. 

281RIA chapter 4. For example, even in the EIA’s 

sensitivity analysis that assumes higher natural gas 

prices and electricity demand, the EIA does not 

project any additional coal beyond its reference 

case until 2023, in a case where power companies 

assume no GHGs emission limitations, and until 

2024 in a case where power companies do assume 

GHGs emission limitations. AEO 2015. 

282Annual Energy Outlook 2010, 2011, 2012, 

2013, 2014 and 2015. 

283Conditions in the analysis year of 2022 are 

represented by a model year of 2020. 

284Sierra Club, 657 F.2d at 314. 

for cases without CCS and assumed 

high-risk financing for cases with some 

level of CCS. Specifically a high-risk 

financial structure resulting in a capital 

charge factor (CCF) of 0.124 is used in 

the study to evaluate the costs of all 

cases with CO2 capture (non-capture 

case uses a conventional financial 

structure with a CCF of 0.116).279 As a 

comparison of how this affects the 

resulting DOE/NETL costs, a new SCPC 

utilizing 16 percent partial CCS is 

projected to have an LCOE of $99/MWh 

(including transportation and storage 

costs; does not include the range for 

uncertainty). That projected LCOE 

includes the ‘‘high risk financial 

assumptions’’. If the LCOE for that unit 

were to be calculated using the 

‘‘conventional financing assumptions’’, 

the resulting LCOE would be $94/MWh. 

This approach is in contrast to that 

taken by the EIA which applies a 3- 

percentage-point cost of capital 

premium (the ‘climate uncertainty 

adder’) to non-capture coal plants to 

reflect the market reaction to potential 

future GHG regulation. 

Under current and anticipated market 

conditions, power providers that are 

considering costs alone in choosing a 

fuel source for new intermediate or base 

load generation will choose natural gas 

because of its competitive current and 

projected price. However, as noted in 

Section V.H.3, public IRPs indicate 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.280 Utilities 

may be willing to pay a premium for 

these generation sources because they 

could serve as a hedge against the 

possibility that future natural gas prices 

will far exceed projected levels. 

Accordingly, the LCOE analysis 

demonstrates that the final standard’s 

costs are in line with power sources that 

provide analogous services— 

dispatchable base load power and fuel 

diversity. 

We further note a number of 

conservative elements of the costs we 

used in making this comparison. In 

particular, these estimates include the 

highest value in the projected range of 

potential costs for partial CCS. They do 

not reflect revenues which can be 

generated by selling captured CO2 for 

enhanced oil recovery, and reflect the 

costs of partial CCS rather than 

potentially less expensive alternative 

compliance paths such as a utility boiler 

co-firing with natural gas. See also 

V.H.7 and 8 below. 

6. Overall Costs and Economic Impacts 

As noted above, an assessment of 

national costs is also an appropriate 

means of evaluating the reasonableness 

of costs under CAA section 111. See 

Sierra Club, 657 F.2d at 330. 

The EPA considered the regulation’s 

overall costs and economic impacts as 

part of its RIA. The RIA demonstrates 

that these costs would be negligible and 

that the effects on electricity rates and 

other market indicators would similarly 

be minimal. 

These results are driven by the 

existing market context for fossil-steam 

generation. Even in the absence of the 

standards of performance for newly 

constructed EGUs, substantial new 

construction of uncontrolled fossil 

steam units is not anticipated under 

existing prevailing and anticipated 

future economic conditions. Modeling 

projections from government, industry, 

and academia anticipate that few new 

fossil steam EGUs will be constructed 

over the coming decade and that those 

that are built would have CCS.281

Instead, EIA data shows that natural gas 

is likely to be the most widely-used 

fossil fuel for new construction of 

electric generating capacity in the near 

future.282 Of the coal-fired units moving 

forward at various advanced stages of 

construction and development— 

Southern Company’s Kemper County 

Energy Facility and Summit Power’s 

Texas Clean Energy Project (TCEP)— 

each will deploy IGCC with some level 

of CCS. The primary reasons for this rate 

of current and projected future 

development of new coal projects 

include highly competitive natural gas 

prices, lower electricity demand, and 

increases in the supply of renewable 

energy. 

In its RIA, the EPA considered the 

overall costs of this regulation in the 

context of these prevailing market 

trends. Because of the expectation of no 

new fossil steam generation, the RIA 

projects that this final rule will result in 

negligible costs overall on owners and 

operators of newly constructed EGUs by 

2022.283 More broadly, this regulation is 

not expected to have significant effects 

on fuel markets, electricity prices, or the 

economy as a whole, as described in 

detail in Chapter 4 of the RIA. 

In comparison, courts have upheld 

past regulations that imposed 

substantial overall costs in order to 

protect against uncontrolled emissions. 

As noted above, in Sierra Club v. Costle, 

the D.C. Circuit upheld a standard of 

performance that imposed costly 

controls on SO2 emissions from new 

coal-fired power plants. 657 F.2d at 410. 

These standards had implications for 

the economy ‘‘at the local and national 

levels,’’ as ‘‘EPA estimates that utilities 

will have to spend tens of billions of 

dollars by 1995 on pollution control 

under the new NSPS.’’ Id. at 314. 

Further, the court acknowledged that 

‘‘[c]onsumers will ultimately bear these 

costs, both directly in the form of 

residential utility bills, and indirectly in 

the form of higher consumer prices due 

to increased energy costs,’’ before 

concluding that the costs were 

reasonable. Id. 

The projected total incremental 

capital costs associated with the 

standard we are finalizing in this rule 

are dramatically lower than was the case 

for this prior standard, as well as other 

prior standards summarized previously. 

For example, when the standard at issue 

in Sierra Club was upheld, the industry 

was expected to build, and did build, 

dozens of plants ultimately meeting the 

standards—at a projected incremental 

cost of tens of billions of dollars.284

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 

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285Portland Cement Ass’n, 513 F.2d at 508. 

286See Memorandum ‘‘Consideration of Costs and 

Benefits under the Clean Air Act’’ available in the 

rulemaking dockets, EPA–HQ–OAR–2013–0495 

(new sources) and EPA–OAR–HQ–2013–0603 

(modified and reconstructed sources). 

287The 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. 

288 Gas Cofiring Assessment for Coal Fired Utility 

Boilers; Final Report, August 2000; EPRI Technical 

Report available at www.epri.com. 

289Many 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. 

290 ‘‘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. 

are considering both sets of costs and, 

in fact, we are not identifying full CCS 

as the BSER primarily for reasons of its 

cost to individual sources. At the same 

time, total projected costs are relevant in 

assessing the overall reasonableness of 

costs associated with a standard. Our 

analysis demonstrates that the impacts 

on the industry as a whole are 

negligible, and are certainly not greater 

than ‘‘what the industry could bear and 

survive.’’ 285 These facts support the 

EPA’s overall conclusion that the costs 

of the standard are reasonable. 

However, as noted earlier, for a 

variety of reasons, some companies may 

consider coal-fired steam generating 

units that the modeling does not 

anticipate. Thus, in Chapter 5 of the 

RIA, we also present an analysis of the 

project-level costs of a newly 

constructed coal-fired steam generating 

unit with partial CCS that meets the 

requirements of this final rule alongside 

the project-level costs of a newly 

constructed coal-fired unit without CCS. 

This analysis in RIA chapter 5 indicates 

that the quantified benefits of the 

standards of performance would exceed 

their costs under a range of 

assumptions. 

As required under Executive Order 

12866, the EPA conducts benefit-cost 

analyses for major Clean Air Act rules, 

and has done so here. While such 

analysis can help to inform policy 

decisions, as permissible and 

appropriate under governing statutory 

provisions, the EPA does not use a 

benefit-cost test (i.e., a determination of 

whether monetized benefits exceed 

costs) as the sole or primary decision 

tool when required to consider costs or 

to determine whether to issue 

regulations under the Clean Air Act, and 

is not doing so here.286 Nonetheless, as 

just noted, the RIA analysis shows that 

the standard of performance has net 

quantified benefits under a range of 

assumptions. 

7. Opportunities to Further Reduce 

Compliance Costs 

While the EPA believes, as detailed 

above, that there is sufficient evidence 

to show that the final standards of 

performance for new steam generating 

units can be met at a reasonable cost, we 

also note that there are potential 

opportunities to further reduce 

compliance costs. We believe that, in 

most cases, the actual costs will be less 

than those presented earlier. 

As explained in more detail in the 

following subsection, a new utility 

boiler can meet the final standard of 

performance by co-firing with natural 

gas. Some project developers may 

choose to utilize natural gas co-firing as 

a means of delaying, rather than 

avoiding, implementation of partial 

CCS. Developers can also choose to 

install IGCC with a small amount of 

natural gas co-firing at costs within the 

range of SCPC with partial CCS, 

although slightly higher. 

The EPA also notes that new units 

that capture CO2 will likely be built in 

areas where there are opportunities to 

sell the captured CO2 for some useful 

purpose prior to (or concomitant with) 

permanent storage. The DOE refers to 

this as ‘‘carbon capture, utilization and 

storage’’ or CCUS. In particular, the 

ability to sell captured CO2 for use in 

enhanced oil recovery operations offers 

the most opportunity to reduce costs. In 

this regard, the newly-operating 

Boundary Dam facility is selling 

captured CO2 for EOR. The Kemper 

facility likewise plans to do so.287

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 fuelfired, 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. 

a. Cost and Feasibility of Natural Gas 

Co-firing as an Alternative Compliance 

Pathway 

Although the EPA has determined 

that implementation of partial CCS at an 

emission limitation of 1,400 lb CO2/

MWh-g is the BSER for newly 

constructed fossil fuel-fired steam 

generating EGUs, we also note that 

operators can consider the use of natural 

gas co-firing to achieve the final 

emission limitation, likely at a lower 

cost. 

At the final emissions limitation of 

1,400 lb CO2/MWh-g a new supercritical 

PC or supercritical CFB can meet the 

standard by co-firing with natural gas at 

levels up to approximately 40 percent 

(heat input basis) and could potentially 

avoid (or delay) installation and use of 

partial CCS altogether. 

Natural gas co-firing has long been 

recognized as an option for coal-fired 

boilers to reduce emissions of criteria 

and hazardous air pollutants. EPRI 

sponsored a study to assess both 

technical and economic issues 

associated with natural gas co-firing in 

coal-fired boilers.288 They determined 

that the largest number of applications 

and the longest experience time is with 

natural gas reburning and with 

supplemental gas firing. Natural gas 

reburning has been used primarily as a 

NOX control technology. It is 

implemented by introducing natural gas 

(up to 20 percent total fuel heat input) 

in a secondary combustion zone (called 

the ‘‘reburn zone’’) downstream of the 

primary combustion zone in the boiler. 

Injecting the natural gas creates a fuelrich zone where NOX formed in the 

main combustion zone is reduced to 

nitrogen and water vapor. 

Higher levels of natural gas co-firing 

can be met by utilizing supplemental 

gas co-firing (either alone or along with 

natural gas reburning). This involves the 

simultaneous firing of natural gas and 

pulverized coal in a boiler’s primary 

combustion zone. Others have also 

evaluated configurations that would 

allow coal-fired units to utilize natural 

gas.289 290

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64565 

291Utility Options for Leveraging Natural Gas, 10/ 

01/2013 article in Power. Available at http://

www.powermag.com/utility-options-for-leveragingnatural-gas/. 

292Costs and emissions for cases that do not 

utilize natural gas co-firing are from ‘‘Cost and 

Performance Baseline for Fossil Energy Plants 

Supplement: Sensitivity to CO2 Capture Rate in 

Coal-Fired Power Plants’’, DOE/NETL–2015/1720 

(June 2015). Costs and emissions for natural gas cofired cases are EPA estimates. 

293Certain 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. 

294 IGCC units already have combined cycle 

capacity, and so can be readily operated in whole 

or in part using natural gas as a fuel. Indeed, both 

the Edwardsport and Kemper IGCC facilities have 

operated at times by firing exclusively natural gas. 

295 ‘‘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). 

296http://www.saskpowerccs.com/consortium/. 

297www.saskpowerccs.com/ccs-projects/shandcarbon-capture-test-facility/. 

298www.nationalcarboncapturecenter.com/

index.html. 

A 2013 article entitled ‘‘Utility 

Options for Leveraging Natural Gas’’ 291

noted that: 

Utility owners of coal-fired power stations 

that wish to balance their exposure to coalfired generation with additional natural gasfired 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. [. . .] Co-firing is the lowest-risk 

option for substituting gas use for coal. 

The EPA examined compliance costs 

for a new steam generating unit to meet 

the final standard of performance using 

natural gas co-firing and compared 

those costs to the estimated costs of 

meeting the final standards using partial 

CCS. Those costs are provided below in 

Table 9. 

TABLE 9—PREDICTED COSTS TO MEET THE FINAL STANDARD USING NATURAL GAS CO-FIRING 292

New generation technology Emission lb 

CO2/MWh-g 

LCOE $/

MWh 

SCPC—no CCS ............................................................................................................................................................... 1,620 82 

SCPC + ∼16% partial CCS .............................................................................................................................................. 1,400 99 

SCPC + ∼34% NG co-fire ................................................................................................................................................ 1,400 92 

IGCC—no CCS ................................................................................................................................................................ 1,434 103 

IGCC + ∼6% NG co-fire ................................................................................................................................................... 1,400 105 

NGCC* ............................................................................................................................................................................. 1,000 60 

* The generation cost using NG co-fire and NGCC assume a natural gas price of $6.19/mmBtu. 

The EPA thus again notes that the cost 

assumptions it is making in its BSER 

determination are conservative. That is, 

by costing partial CCS as BSER, the EPA 

may be overestimating actual 

compliance costs since there exist other 

less expensive means of meeting the 

promulgated standard.293

Notwithstanding that costs for a SCPC 

to meet the standard would be lower if 

it co-fired with natural gas, we have not 

identified that compliance alternative as 

BSER because we believe that new coalfired steam electric generating capacity 

would be built to provide fuel diversity, 

and burning substantial amounts of 

natural gas would be contrary to that 

objective. In addition, this choice would 

not promote use of advanced pollution 

control technology. New IGCC has costs 

which are comparable to SCPC, as does 

IGCC with natural gas co-firing,294 but 

we are choosing not to identify it as 

BSER for reasons stated at Sections 

V.C.2 and V.P: use of IGCC does not 

advance emission control beyond 

current levels of performance for 

sources which may choose to utilize 

IGCC technology. Nonetheless, use of 

IGCC remains a viable, demonstrated 

compliance option to meet the 1,400 lb 

CO2/MWh-g standard of performance, 

and is available at reasonable cost and 

(as shown at Section V.P below) without 

significant adverse non-air quality 

impacts or energy implications. 

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 coal-fired generation facilities that 

are either operating or are nearing 

completion. These would include the 

Boundary Dam Unit #3 facility, the 

Petra Nova WA Parish project, and the 

Kemper County IGCC facility. The 

operators of the Boundary Dam Unit #3 

are considering construction of 

additional CCS units and have projected 

that the next units could be constructed 

at a cost of at least 30 percent less than 

that at Unit #3.295 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.296 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).297 The test facility 

will provide technology developers with 

an opportunity to test new and emerging 

carbon capture systems for controlling 

carbon emissions from coal-fired power 

plants. 

The DOE also sponsors testing at the 

National Carbon Capture Center (NCCC). 

The NCCC—located at Southern 

Company’s Plant Gaston in Wilsonville, 

AL—provides first-class facilities to test 

new capture technologies for extended 

periods under commercially 

representative conditions with coalderived flue gas and syngas.298

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64566 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

299Tracking Clean Energy Progress 2013, 

International Energy Agency (IEA), Input to the 

Clean Energy Ministerial, OECD/IEA 2013. 

300Comments of EEI, pp 94–5 (Docket entry: 

EPA–HQ–OAR–2013–0495–9780). 

301http://www.eia.gov/forecasts/aeo/electricity_

generation.cfm. 

302Technical Support Document—‘‘Review of 

Electric Utility Integrated Resource Plans’’ (May 

2015), available in the rulemaking docket EPA–HQ– 

OAR–2013–0495. 

We expect continued additional cost 

reductions to come from knowledge 

gained from continued operation of nonpower sector industrial projects which, 

as we have discussed, are informative in 

transferring the technology to power 

sector applications. We expect the ongoing research and development 

efforts—such as those sponsored by the 

DOE/NETL. 

Significant reductions in the cost of 

CO2 capture would be consistent with 

overall experience with the cost of 

pollution control technology. 

Reductions in the cost of air pollution 

control technologies as a result of 

learning-by-doing, reductions in 

financial premiums related to risk, 

research and development investments, 

and other factors have been observed 

over the decades. 

c. Opportunities To Reduce Cost 

Through Sales of Captured CO2

Geologic storage options include use 

of CO2 in EOR operations, which is the 

injection of fluids into a reservoir after 

production yields have decreased from 

primary production in order to increase 

oil production efficiency. CO2-EOR has 

been successfully used for decades at 

many production fields throughout the 

U.S. to increase oil recovery. The use of 

CO2 for EOR can significantly lower the 

net cost of implementing CCS. The 

opportunity to sell the captured CO2 for 

EOR, rather than paying directly for its 

long-term storage, improves the overall 

economics of the new generating unit. 

According to the International Energy 

Agency (IEA), of the CCS projects under 

construction or at an advanced stage of 

planning, 70 percent intend to use 

captured CO2 to improve recovery of oil 

in mature fields.299 See also Section 

V.M.3 below. 

I. Key Comments Regarding the EPA’s 

Consideration of Costs 

In its consideration of the costs 

associated with the final standard, the 

EPA considered a range of different cost 

metrics, each with its individual 

strengths and weaknesses. As discussed 

above, each metric supports the EPA’s 

conclusion that the costs of the final 

standard are reasonable. 

In this section, we review the 

comments received on assessing cost 

reasonableness and specific cost 

metrics. We explain how these 

comments informed our consideration 

of different metrics and cost 

reasonableness in general. 

1. Use of LCOE as a Cost Metric 

As noted, CAA section 111(a) directs 

the EPA to consider ‘‘cost’’ in 

determining if the BSER is adequately 

demonstrated. It does not provide 

further guidance as to how costs are to 

be considered, thus affording the EPA 

considerable discretion to choose a 

reasonable means of cost consideration. 

See, e.g. Lignite Energy Council v. EPA, 

198 F. 3d at 933. Certain commenters 

nonetheless argued that LCOE was an 

impermissible metric because it does 

not measure the cost of achieving the 

emission reduction, but rather measures 

the impact on the product produced by 

the entity subject to the standard.300 The 

EPA does not agree that its authority is 

so limited. Indeed, in the first decided 

case under section 111, the D.C. Circuit, 

in holding that the EPA’s consideration 

of costs was reasonable, specifically 

noted the EPA’s examination of the 

impact of the standards on the regulated 

source category’s product in comparison 

to competitive products. Portland 

Cement Ass’n v. EPA, 486 F. 2d at 388 

(‘‘costs of control equipment could be 

passed on without substantially 

affecting competition with construction 

substitutes such as steel, asphalt, and 

aluminum’’). 

Commenters also argued that the 

choice of LCOE as a cost metric masked 

consideration of the considerable capital 

costs associated with CCS. The EPA 

disagrees with this contention. The 

LCOE does not mask consideration of 

capital costs. Rather, as explained at 

V.H.5 above, LCOE is a summary metric 

that expresses the full cost (e.g., capital, 

O&M, fuel) of generating electricity and 

therefore provides a useful summary 

metric of costs per unit of production 

(i.e., megawatt-hours). Provided that 

those megawatt-hours provide similar 

electricity services and align on 

dimensions other than just cost, then 

the LCOE provides a useful comparison 

of which technologies are least cost. 

The EPA certainly does not minimize 

that project developers must take capital 

costs into consideration, and as 

discussed in Section V.H.4 above, the 

EPA accordingly has considered direct 

capital costs here as part of its 

assessment and found those costs to be 

reasonable. In addition, the EPA notes 

that its comparison of the marginal 

impacts from an individual illustrative 

facility’s compliance with the standard, 

discussed in detail above and in the RIA 

Chapter 5, took into account the 

marginal capital costs that would be 

incurred by an individual facility. 

According to EIA,301 capital costs 

represent approximately 63 percent of 

the LCOE for a new coal-fired SCPC 

plant; approximately 66 percent of the 

LCOE for a new IGCC plant; 

approximately 74 percent of the LCOE 

for a new nuclear plant; and only about 

22 percent of the LCOE for a new NGCC 

unit. The LCOE of a new NGCC unit is 

much more strongly affected by fuel 

costs (natural gas). As we have 

discussed in detail in this preamble, in 

the preamble for the January 2014 

proposal, and in associated technical 

support documents, the power sector 

has moved toward increased use of 

natural gas for a variety of reasons. If 

capital was the only cost that utilities 

and project developers considered, then 

they would almost certainly always 

choose to build a new NGCC unit. 

However, a variety of factors can be 

involved in selecting a generation 

source beyond capital costs. 

Accordingly, in considering cost 

reasonableness the EPA considered 

metrics that encompassed other costs as 

well as the value of fuel and fleet 

diversity. 

Some commenters maintained that 

even if LCOE was a proper cost metric, 

the comparison with the costs of a new 

nuclear power plant is improper 

because nuclear itself is a highly 

expensive technology. The EPA 

disagrees. The comparison is 

appropriate and valid because, as 

discussed at V.H.3 above, under current 

and foreseeable economic conditions 

affecting the cost of new fossil steam 

generation and new nuclear generation 

relative to the cost of new natural gas 

generation, neither new nuclear power 

nor fossil steam generation are 

competitive with new natural gas if 

evaluated on the basis of LCOE alone. 

Nonetheless, both are important 

potential alternatives to natural gas 

power for those interested in 

dispatchable base load power that 

maintains or increases fuel diversity. As 

shown in a survey of recent IRP filings 

in the docket 302 and Section II.C.5 

above, several utilities are considering 

new nuclear power as a potential 

generation option. Because both fossil 

steam and nuclear generation serve a 

comparable role of offering a diverse 

source of base load power generation, 

the EPA concludes that the comparison 

of their LCOE is a valid approach to 

evaluating cost reasonableness. 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64567 

303http://www.netl.doe.gov/research/energyanalysis/energy-baseline-studies. 304The NETL costs and studies are often cited in 

academic and other publications. 

305The 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. 

306Letter 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/F43D89070E89893485257C5A00

7AF573/$File/SAB+work+grp+memo+w+attach+

20140107.pdf. The SAB’s statement that these 

guidance documents ‘‘require’’ any specific peer 

review is an overstatement, since guidance 

documents, by definition, do not mandate any 

specific course of action. 

307Recommended 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. 

308 ‘‘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. 

309Cost and Performance Baseline for Fossil 

Energy Plants Volume 1a: Bituminous Coal (PC) and 

Natural Gas to Electricity, Revision 3, July 6, 2015, 

DOE/NETL–2015/1723. 

310EPRI 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). 

311www.globalccsinstitute.com. 

2. Use of Cost Estimates From DOE/

NETL and DOE/EIA 

In the January 2014 proposal, the EPA 

relied mostly on the cost projections for 

new fossil fuel-fired generating sources 

that were informed by cost studies 

conducted by DOE/NETL. The EPA 

relied on the EIA’s AEO 2013 

projections for non-fossil based 

generating sources (i.e., nuclear, 

renewables, etc.). For this final rule, the 

EPA continues to rely most heavily on 

DOE/NETL cost projections for fossil 

fuel generating technologies and on the 

updated DOE/EIA AEO 2014 for nuclear 

and other base load non-fossil 

generation technologies. 

a. DOE/NETL Cost and Performance 

Studies 

The DOE/NETL ‘‘Cost and 

Performance Baselines for Fossil Energy 

Plants’’ are a series of studies conducted 

by NETL to establish estimates for the 

cost and performance of combustion 

and gasification based power plants 

with and without CO2 capture and 

storage.303 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.304 The NETL studies were 

extensively peer reviewed.305 The EPA 

Science Advisory Board Work Group 

considering the adequacy of the peer 

review noted the EPA staff’s statement 

that ‘‘the NETL studies were all peer 

reviewed under DOE peer review 

protocols’’, further noted the EPA staff’s 

statement that ‘‘the different levels of 

review of these DOE documents met the 

requirements to support the analyses as 

defined by the EPA Peer Review 

Handbook,’’ and concluded that ‘‘peer 

review on the DOE documents’’ was 

conducted ‘‘at a level required by 

agency guidance.’’ 306

The cost estimates were indicated by 

DOE/NETL to carry an accuracy of ¥15 

percent to +30 percent on the capital 

costs, consistent with a AACE Class 4 

cost estimate—i.e., a ‘‘feasibility study’’ 

level of design engineering.307 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.’’ 308

For the final standard, the EPA made 

particular use of the most recent NETL 

cost estimates for post-combustion CCS, 

which reflect up-to-date vendor quotes 

and incorporate the post-combustion 

capture technology—the Shell Cansolv 

amine-based process—that is being 

utilized at the Boundary Dam Unit #3 

facility.309 The EPA used this latest 

version of the NETL studies not only to 

assure that it considers the most up-todate information but also to address 

public comments criticizing the 

proposal for relying on out-of-date cost 

information. 

b. Other Studies That Corroborate NETL 

Cost Estimates 

A variety of government, industry and 

academic groups routinely conduct 

studies to estimate costs of new 

generating technologies. These studies 

use techno-economic models to predict 

the cost to build a new generating 

facility at some point in the future. 

These studies often use levelized cost of 

electricity (LCOE) to summarize costs 

and to compare the competiveness of 

the different generating technologies. 

A variety of groups have recently 

published LCOE estimates for new 

dispatchable generating technologies. 

Those are shown below in Table 10. The 

table shows LCOE projections from the 

EPA’s January 2014 proposal, from 

studies conducted by the Electric Power 

Research Institute (EPRI),310 by the 

DOE’s Energy Information 

Administration (EIA) in their 2015 

Annual Energy Outlook (AEO 2015), by 

the DOE’s National Energy Technology 

Laboratory (NETL), and by researchers 

from the Department of Engineering and 

Public Policy at the Carnegie Mellon 

University (CMU) in Pittsburgh, PA. 

The Global CCS Institute 311 has 

recently published a report that 

examines costs of major low and zero 

emissions technologies currently 

available for power generation and 

compares the predicted LCOEs of those 

technologies. Importantly, the analysis 

presented in the report uses cost and 

performance data from several recent 

studies, and applies a common 

methodology and economic parameters 

to derive comparable lifetime costs. 

Analysis and findings in the paper 

reflect costs specific to the U.S. 

The fact that these various groups 

have conducted independent studies 

and that the results of those 

independent studies are reasonably 

consistent with the estimates of DOE/

NETL are further indications that the 

DOE/NETL cost estimates are 

reasonable. 

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64568 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

312Lazard’s Levelized Cost of Energy Analysis— 

Version 8.0 (Sept 2014); available at http://www.

lazard.com/media/1777/levelized_cost_of_energy_- 

_version_80.pdf and in the rulemaking docket. 313 ‘‘Program on Technology Innovation: 

Integrated Generation Technology Options 2012; 

Report 1026656; Available at: www.epri.com. 314 ‘‘Levelized Cost and Levelized Avoided Cost 

of New Generation Resources in the Annual Energy 

Outlook 2015’’, Available at: www.eia.gov/forecasts/ 

aeo/electricity_generation.cfm; the LCOE values 

displayed incorporate ¥10%/+30% for uncertainty 

for biomass and nuclear. 315 ‘‘Cost and Performance Baseline for Fossil 

Energy Plants Supplement: Sensitivity to CO2

Capture Rate in Coal-Fired Power Plants’’ DOE/

NETL–2015/1720 (June 22, 2015). 316CMU 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. 317 ‘‘The Costs of CCS and other Low-Carbon 

Technologies—2015 update’’ July 2015, Global CCS 

Institute, Available at: http://hub.globalccsinstitute.

com/sites/default/files/publications/195008/costsccs-other-low-carbon-technologies-2015-update.pdf. 

318See Section V.F above, explaining that the 

D.C. Circuit has repeatedly stated that vendor 

statements are probative in demonstrating that a 

technology is adequately demonstrated under 

section 111. 

319http://www.summitpower.com/projects/

carbon-capture/. 

320 ‘‘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. 

321No proprietary or business confidential 

information was shared with the EPA. No specific 

vendors were mentioned by name during 

discussions with Summit Power. Summit also used 

available DOE/NETL and EIA cost information. 

TABLE 10—SELECTION OF LEVELIZED COST OF ELECTRICITY (LCOE) PROJECTIONS

New generation technology Lazard 312

$2014/MWh 

EPRI 313

$2011/MWh 

AEO2015 314

$2013/MWh* 

DOE/NETL 315

$2011/MWh* 

CMU 316

$2010/MWh 

GCCSI 317** 

$2014/MWh 

SCPC—no CCS ....................................... 66 62–77 95 76–95 59 78 

SCPC—full CCS ...................................... 151 102–137 — 140–176 — 115–160 

SCPC—16% CCS .................................... — — — 92–117 — — 

Nuclear*** ................................................. 92–132 85–97 87–115 — — 86–102 

Biomass ................................................... 87–116 90–155 94–113 — — 123–137 

IGCC ........................................................ 102 82–96 116 94–120 — — 

IGCC—full CCS ....................................... 171 105–136 144 142–178 — — 

NGCC ....................................................... 61—87 33—65 73 58 63 60 

* EIA, in cost projections for SCPC and IGCC with no CCS, includes a climate uncertainty adder (CUA), which is a 3-percentage point increase in the cost of capital. In contrast, DOE/NETL utilized conventional financing for cases without CCS and utilized high-risk financial assumptions for cases that include CCS. 

** The Global CCS Institute provided range for coal with full CCS (shown as ‘‘CCS(coal)’’ in Figure 5.2 of the referenced report) reflects a 

combination of costs for both PC and IGCC coal plants. 

*** EIA AEO assumes use of Westinghouse AP1000 technology. Other groups assume a wider range of technology options. 

The LCOE values from the Lazard, 

EPRI, and NETL studies are presented as 

a range. The EPRI costs incorporate 

uncertainty reflecting the range of 

inputs (i.e., capital costs, fuel costs, 

fixed and variable O&M, etc.). The 

NETL costs are indicated to carry an 

accuracy of ¥15 percent to + 30 

percent, consistent with a ‘‘feasibility 

study’’ level of design. The range in 

Table 10 is the NETL projected costs 

with the ¥15 percent to +30 percent 

uncertainty on the capital costs. Overall, 

as can be seen from the results in Table 

10, the range of LCOE estimates from 

the different groups are in reasonable 

agreement with the DOE/NETL 

estimates most often representing the 

most conservative of the estimates 

shown. 

The EIA cost estimates include a 

climate uncertainty adder (CUA)— 

represented by a three percent increase 

to the weighted average cost of capital— 

to certain coal-fired capacity types. The 

EIA developed the CUA to address 

inconsistencies between power sector 

modeling absent GHG regulation and 

the widespread use of a cost of CO2

emissions in power sector resource 

planning. The CUA reflects the 

additional planning cost typically 

assigned by project developers and 

utilities to GHG-intensive projects in a 

context of climate uncertainty. The EPA 

believes the CUA is consistent with the 

industry’s planning and evaluation 

framework (demonstrable through IRPs 

and PUC orders) and is therefore 

pertinent when evaluating the cost 

competitiveness of alternative 

generating technologies. The EPA 

believes the CUA is relevant in 

considering the range of costs that 

power companies are willing to pay for 

generation alternatives to natural gas. 

c. Industry Information That 

Corroborates NETL Cost Estimates 

Information from vendors of CCS 

technology also supports the reliability 

of the cost estimates the EPA is using 

here.318 Specifically, the EPA had 

conversations with representatives from 

Summit Carbon Capture, LLC regarding 

available cost information. Cost 

estimates provided by another leading 

provider of CCS technology likewise are 

consistent (indeed, somewhat less than) 

the estimates the EPA is using for 

purposes of cost analysis in the rule. 

Summit Carbon Capture’s primary 

business is large-scale carbon capture 

from power and other industrial projects 

and use of the captured CO2 for EOR.319

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.320 The 

presentation focused on costs to retrofit 

available carbon capture equipment at 

an existing PC power plant that is 

ideally located to take advantage of 

opportunities to sell captured CO2 for 

use in EOR operations. Summit received 

proprietary costing information from 

numerous technology providers and that 

information, along with other publically 

available information, was used to 

develop their cost predictions.321

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 predicted by NETL, EIA, EPRI and 

others. The company ultimately 

concluded that ‘‘in a world of uncertain 

gas prices, falling CO2 capture 

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322Others have come to similar conclusions—that 

retrofit of CCS technology at existing coal-fired 

power plants can be feasible—e.g., ‘‘The results 

indicate that for about 60 gigawatts of the existing 

coal-fired capacity, the implementation of partial 

CO2 capture appears feasible, though its cost is 

highly dependent on the unit characteristics and 

fuel prices.’’ (Zhai, H.; Ou, Y.; Rubin, E.S.; 

‘‘Opportunities for Decarbonizing Existing U.S. 

Coal-fired Plants via CO2 Capture, Utilization, and 

Storage’’, accepted for publication in Env. Sci & 

Tech. (2015). 323Leandri, 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. 

324Note that in other tables in this preamble, the 

EPA has presented LCOE values from the DOE/

NETL work as a range in order to incorporate the 

uncertainty on the capital costs. The range is not 

present here for easy comparison with the industry 

costs which were not provided as a range. The full 

range of DOE/NETL costs for each of the cases 

presented can be found in Exhibit A–3 in ‘‘Cost and 

Performance Baseline for Fossil Energy Plants 

Supplement: Sensitivity to CO2 Capture Rate in 

Coal-Fired Power Plants’’, DOE/NETL–2015/1720 

(June 2015), p. 18. 

325Alstom Comment p. 3 (Docket entry: EPA– 

HQ–OAR–2013–0495–9033). The comment also 

urged the EPA to evaluate costs without considering 

EOR opportunities (which in fact is our 

methodology, albeit a conservative one), and 

without considering possible subsidies. Id. The 

LCOE and capital cost estimates above are direct 

cost comparisons, again consistent with the 

commenter’s position. 

326www.eia.gov/oiaf/beck_plantcosts/pdf/

updatedplantcosts.pdf. 

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.’’ 322

In June 2012, Alstom Power released 

a report entitled ‘‘Cost assessment of 

fossil power plants equipped with CCS 

under typical scenarios’’.323 The study 

examined costs for a new coal-fired 

power plant implementing postcombustion CCS (full CCS) in Europe, in 

North America, and in Asia. The results 

for the North American case—along 

with similar cost estimates from 

Summit—are shown in Table 11 below. 

The DOE/NETL estimated costs are also 

included for comparison. The results 

show predicted costs for a new SCPC 

ranging from $53/MWh to $82/MWh 

and costs to implement full CCS ranging 

from $97/MWh to $143/MWh. Costs to 

implement varying levels of partial CCS 

are also provided for comparison. The 

industry cost estimates are on the lower 

end of the range of costs predicted from 

other techno-economic studies (see 

Table 11 below) and, like those 

economic studies, are affected by the 

specific assumptions. As with the techoeconomic studies presented earlier in 

Table 10, there is relatively good 

agreement among these projected costs 

and the DOE/NETL costs. There is 

relatively good agreement in the 

incremental levelized cost to implement 

full CCS on the new SCPC units 

(ranging from 74 to 85 percent) and to 

implement 50 percent CCS on the new 

SCPC unit (from 41 to 45 percent 

increase). These industry estimates are 

also lower than the DOE/NETL 

estimates for both full and 50 percent 

partial CCS (with the incremental cost 

percentage for full CCS being almost 

identical), providing further support for 

the reasonableness of the EPA using the 

NETL cost estimates here. 

TABLE 11—INDUSTRY LCOE ESTIMATES FOR IMPLEMENTATION OF POST-COMBUSTION CCS 324

Summit 

$/MWh 

Alstom 

$/MWh* 

DOE/NETL 

$/MWh 

SCPC ........................................................................................................................................... 64.5 52.6 82.3 

SCPC + full CCS ......................................................................................................................... 117.6 97.4 152.4 

Full CCS incremental cost, % ..................................................................................................... 82.3% 85.0% 85.2% 

SCPC + 50% CCS ....................................................................................................................... 91.1 — 123.6 

50% CCS incremental cost, % .................................................................................................... 41.2% — 50.1% 

SCPC + 35% CCS ....................................................................................................................... — — 114.7 

SCPC + 16% CCS ....................................................................................................................... — — 100.5 

NGCC** ........................................................................................................................................ 47.7 35.0 **52.0 

* Costs are from Figure 2 in the referenced Alstom report (North American case); costs are presented as Ö/MWh in the report. The costs were 

converted to $/MWh assuming a conversion rate of 1 USD = 0.76 Ö (in 2012). 

** NGCC cost is estimated by the EPA using NETL information. Assumed natural gas prices = Summit ($4/mmBtu); Astom ($3.9/mmBtu); EPA 

($5.00/mmBtu). 

The EPA notes that in its public 

comments, Alstom maintained that ‘‘no 

CCS projects that would [sic] be 

considered cost competitive in today’s 

energy economy.’’ 325 As explained 

above, no steam electric EGU would be 

cost competitive even without CCS— 

and that is substantiated in the 

projected costs presented above in Table 

11 where NGCC is consistently the most 

economic new generation option when 

compared to the other listed 

technologies. Alstom does not explain 

(or address) why the cost premium for 

partial CCS would be a decisive 

deterrent for capacity that would 

otherwise be constructed. More 

important, Alstom does not challenge 

the specific cost estimates used by the 

EPA at proposal, nor disavow its own 

estimates of CCS costs (which are even 

less) which it is publically 

disseminating in the marketplace. See 

also Section V.F.3 above, quoting 

Alstom’s press release stating 

unequivocally that ‘‘CCS works and is 

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 AEO 2013 

cost projections for non-fossil based 

generation. The AEO presents long-term 

annual projections of energy supply, 

demand, and prices focused on U.S. 

energy markets. The predictions are 

based on results from EIA’s National 

Energy Modeling System (NEMS). The 

AEO costs are updated annually, they 

are highly scrutinized, and they are 

widely used by those involved in the 

energy sector. 

In the January 2014 proposal, the EPA 

presented LCOE costs for new non-fossil 

dispatchable generation (see 77 FR 

1477, Table 7) from the AEO 2013. 

Those costs were updated as part of the 

AEO 2015 release. The estimated cost 

for all of these technologies decreased 

from AEO 2013 to AEO 2014 and AEO 

2015. This was due to changes in the 

interest rates that resulted in lower 

financing costs relative to those used the 

AEO 2013.326 The EIA commissioned a 

comprehensive update of its capital cost 

assumptions for all generation 

technologies in 2013. Fuel cost and 

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327EIA does not provided uncertainty estimates 

in the AEO cost projections. However, EIA staff 

have indicated to the EPA that a range of 

uncertainty of ¥10%/+30% on the capital 

component of the LCOE can be expected based on 

market uncertainties. See memorandum ‘‘Range of 

uncertainty for AEO nuclear costs’’ available in the 

rulemaking docket, EPA–HQ–OAR–2013–0495. 

328 ‘‘The Costs of CCS and other Low-Carbon 

Technologies—2015 update’’ July 2015, Global CCS 

Institute, Available at: http://hub.globalccsinstitute.

com/sites/default/files/publications/195008/costsccs-other-low-carbon-technologies-2015-update.pdf. 

329The EPA notes that two of these facilities, 

Kemper and TCEP, received both assistance from 

DOE under EPAct05 and the IRC section 48A tax 

credit; and that the AEP Mountaineer pilot project 

received assistance from DOE under EPAct05. 

Under the most extreme interpretations of those 

provisions offered by commenters, the EPA would 

be precluded from any consideration of any 

information from those sources, including cost 

information, in showing whether a system of 

emission reduction is adequately demonstrated. We 

note, however, that many of these same commenters 

urged consideration of the cost information from 

these sources. In fact, the EPA is not relying on 

information about the costs of these sources to 

determine the BSER or the standards of 

performance in this rulemaking, and the EPA is 

discussing the cost information here to explain why 

not. Accordingly, this discussion of cost 

information from these sources is not precluded by 

the EPAct05 and IRC section 48A provisions and, 

even if it is precluded, that would have no impact 

on the EPA’s determination of the BSER and the 

standards of performance in this rule. 

330http://www.nrg.com/sustainability/strategy/ 

enhance-generation/carbon-capture/wa-parish-ccsproject/. 

331http://www.mississippipower.com/aboutenergy/plants/kemper-county-energy-facility/facts. 

financial assumptions are updated for 

each edition of the Annual Energy 

Outlook. 

e. Accounting for Uncertainty of 

Projected Costs 

As previously mentioned, the 

projected costs are dependent upon a 

range of assumptions including the 

projected capital costs, the cost of 

financing the project, the fixed and 

variable O&M costs, the projected fuel 

costs, and incorporation of any 

incentives such as tax credits or 

favorable financing that may be 

available to the project developer. There 

are also regional or geographic 

differences that affect the final cost of a 

project. The LCOE projections in this 

final action are not intended to provide 

an absolute cost for a new project using 

any of these respective technologies. 

Large construction projects—as these 

would be—would be subjected to 

detailed cost analyses that would take 

into consideration site-specific 

information and specific design details 

in order to determine the project costs. 

The DOE/NETL noted that the cost 

estimates from their studies carry an 

accuracy in the range of ¥15 percent to 

+30 percent, which is consistent with a 

‘‘feasibility study’’ level of design. They 

also noted that the value of the studies 

lies ‘‘not in the absolute accuracy of the 

individual case results but in the fact 

that all cases were evaluated under the 

same set of technical and economic 

assumptions. This consistency of 

approach allows meaningful 

comparisons among the cases 

evaluated.’’ 

The EIA AEO 2015 presented LCOE 

costs as a single point estimate 

representing average nationwide costs 

and separately as a range to represent 

the regional variation in costs. In order 

to compare the fossil fuel generation 

technologies from the NETL studies 

with the cost projections for non-fossil 

dispatchable technologies from EIA 

AEO 2015, we assume that the EIA 

studies would carry a similar level of 

uncertainty (i.e., +30 percent) and we 

present the AEO 2015 projected costs as 

the average nationwide LCOE with a 

range of ¥10 percent to +30 percent to 

account for uncertainty.327 The EIA 

does not provide uncertainty estimates 

in the AEO cost projections. However, 

nuclear experts from EIA staff have 

indicated to the EPA that a range of 

uncertainty of ¥10 percent to +30 

percent on the capital component of the 

LCOE can be expected based on market 

uncertainties. Specifically, these staff 

experts expect that nuclear plants 

currently under construction would not 

have capital costs under estimates and 

that one could expect to see a 30 percent 

‘‘upside’’ variation in capital cost. There 

is also insufficient market data to get a 

good statistical range of potential capital 

cost variation (i.e., only two plants 

under construction, neither complete). 

This is reasonably consistent with 

estimates for nuclear costs estimated by 

Lazard (see Table 8 above) which 

likewise reflect a similar level of cost 

uncertainty. The Lazard nuclear costs 

show a range of projected levelized 

capital cost from $73/MWh to $110/ 

MWh—a range of 50 percent, very 

similar to the 40 percent range (i.e., ¥10 

percent to +30 percent) suggested by 

EIA nuclear experts. The Global CCS 

Institute, in its most recent cost update, 

also provides nuclear costs as a range 

from $86/MWh to $102/MWh.328

3. Use of Costs From Current Projects 

Although we are relying on cost 

estimates drawn from techno-economic 

models, we recognize that there are a 

few steam electric plants that include 

CCS that have been built, or are being 

constructed. Some information about 

the costs (or cost-to-date) for these 

projects is known. We discuss in this 

section the costs at facilities which have 

installed or are installing CCS, why the 

EPA does not consider those costs to be 

reasonably predictive of the costs of the 

next new plants to be built, and why the 

EPA considers that the next new plants 

will have lower costs along the lines 

predicted by NETL.329

The Boundary Dam Unit #3 facility 

utilizing post-combustion capture from 

Shell Cansolv is now operational. Petra 

Nova, a joint venture between NRG 

Energy Inc. and JX Nippon Oil & Gas 

Exploration, is currently constructing a 

post-combustion capture system at 

NRG’s WA Parish generating station 

near Houston, TX. The post-combustion 

capture system will utilize MHI aminebased solvents and is currently being 

constructed with plans to initiate 

operation in 2016.330

Construction on Mississippi Power’s 

Kemper County Energy Center IGCC 

facility is now nearly complete. The 

combined cycle portion of the facility 

has been generating power using natural 

gas. The gasification portion of the 

facility and the carbon capture system 

are undergoing system checks and 

training to enable commercial 

operations using a UOP SelexolTM precombustion capture system in early 

2016.331

Another full-scale project, the Summit 

Power Texas Clean Energy Project has 

not commenced construction but 

remains a viable project. Several other 

full-scale projects have been proposed 

and have progressed through the early 

stages of design, but have been 

cancelled or postponed for a variety of 

reasons. 

Some cost information is also 

available for small demonstration 

projects—including those that have 

been supported by USDOE research 

programs. These projects would include 

Alabama Power’s demonstration project 

at Plant Barry and the AEP/Alstom 

demonstration at Plant Mountaineer. 

Many commenters felt that the EPA 

should rely on those high costs when 

considering whether the costs are 

reasonable. The costs from these largescale projects appear to be consistently 

higher than those projected by technoeconomic models. However, the costs 

from these full-scale projects represent 

first-of-a-kind (FOAK) costs and, it is 

reasonable to expect these costs to come 

down to the level projected in the NETL 

and other techno-economic 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 

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332 ‘‘Cost and Performance Baseline for Fossil 

Energy Plants Volume 1a: Bituminous Coal (PC) and 

Natural Gas to Electricity Revision 3’’, DOE/NETL– 

2015/1723 (July 2015) at p. 38. 

333http://www.saskpowerccs.com/consortium/. 

334http://www.saskpowerccs.com/ccs-projects/

shand-carbon-capture-test-facility/. 

335See Independent Monitor’s Prudency 

Evaluation Report for the Kemper County IGCC 

Project (prepared for Mississippi Public Utilities 

Staff), available at www.psc.state.ms.us/Insite

Connect/InSiteView.aspx?model=INSITE_

CONNECT&queue=CTS_ARCHIVEQ&

docid=328417 (‘‘Report’’). As documented in this 

Report, costs escalated significantly because the 

developers adopted a ‘‘compressed schedule’’ in an 

attempt to obtain the IRC 48A tax credit, resulting 

in ‘‘engineering and design changes which are a 

normal result of detailed engineering and design 

. . . occurring at the same time as, rather than 

ahead of, construction activities’’, which did not 

allow for proper sequencing during construction. 

This ‘‘ ’just-in-time’ approach to engineering and 

procurement (meaning that the engineering was 

often completed shortly before material 

procurement and construction activities) resulted in 

a greater number of construction work-arounds, 

congestion of construction craft labor in the field, 

inefficiencies and additional steps that became 

necessary during construction to cope with this 

just-in-time engineering, procurement and 

construction approach.’’ Report, p. 6. Ironically, 

work was still completed too late to obtain the tax 

credit. Id. p. 15. 

that the per-unit cost of producing or 

using a given technology declines as 

experience with that technology 

increases over time, and this has 

certainly been the case with air 

pollution control technologies. 

Reductions in the cost of air pollution 

control technologies as a result of 

learning-by-doing, research and 

development investments, and other 

factors have been observed over the 

decades. We expect that the costs of 

capture technology will follow this 

pattern. 

The NETL cost estimates reasonably 

account for this documented 

phenomenon. Specifically, ‘‘[I]n all 

cases, the report intends to represent the 

next commercial offering, and relies on 

vendor cost estimates for component 

technologies. It also applies process 

contingencies at the appropriate 

subsystem levels in an attempt to 

account for expected but undefined 

costs (a challenge for emerging 

technologies).’’ 332

Commenters argued that the next 

plants to be built would still reflect firstof-a-kind costs, pointing to the newness 

of the technology and the lack of 

operating experience, i.e. the alleged 

absence of learning by doing. The EPA 

disagrees. In addition to operating 

experience from operating and partially 

constructed CCS projects, substantial 

research efforts are underway providing 

a further knowledge base to reduce CO2

capture costs and to improve 

performance. 

The DOE/NETL sponsors an extensive 

research, development and 

demonstration program that is focused 

on developing advanced technology 

options that will dramatically lower the 

cost of capturing CO2 from fossil fuel 

energy plants compared to currently 

available capture technologies. The 

large-scale CO2 capture demonstrations 

that are currently planned and in some 

cases underway, under DOE’s 

initiatives, as well as other domestic 

and international projects, will generate 

operational knowledge and enable 

continued commercialization and 

deployment of these technologies. Gas 

absorption processes using chemical 

solvents, such as amines, to separate 

CO2 from other gases have been in use 

since the 1930s in the natural gas 

industry and to produce food and 

chemical grade CO2. The advancement 

of 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. 

As noted in Section V.H.7.d above, 

SaskPower has created the CCS Global 

Consortium to facilitate further 

knowledge regarding, and use of, carbon 

capture technology.333 This consortium 

provides SaskPower the opportunity to 

share its knowledge and experience 

with global energy leaders, technology 

developers, and project developers. 

SaskPower, in partnership with 

Mitsubishi and Hitachi, is also helping 

to advance CCS knowledge and 

technology through the creation of the 

Shand Carbon Capture Test Facility 

(CCTF).334 The test facility will provide 

technology developers with an 

opportunity to test new and emerging 

carbon capture systems for controlling 

carbon emissions from coal-fired power 

plants. 

We also note certain features of the 

commercial plants already built that 

suggest that their costs are uniquely 

high, and otherwise not fairly 

comparable to the costs of plants 

meeting the NSPS using the BSER. Most 

obviously, many of these projects 

involve deeper capture than the partial 

CCS that the EPA assumes in this final 

action. In addition, cost overruns at the 

Kemper facility, mentioned repeatedly 

in the public comments, resulted in 

major part from highly idiosyncratic 

circumstances, and are related to the 

cost of the IGCC system, not to the cost 

of CCS.335 The EPA does not believe 

that these unusual circumstances are a 

reasonable basis for assessing costs of 

either CCS or IGCC here. 

4. Cost Competitiveness of New Coal 

Units 

As the EPA noted, all indications 

suggest that very few new coal-fired 

power plants will be constructed in the 

foreseeable future. Although a small 

number of new coal-fired power plants 

have been built recently, the industry 

generally is not building these kinds of 

power plants at present and is not 

expected to do so for the foreseeable 

future. The reasons include the current 

economic environment and improved 

energy efficiency, which has led to 

lower electricity demand, and 

competitive current and projected 

natural gas prices. On average, the cost 

of generation from a new NGCC power 

plant is expected to be lower than the 

cost of generation from a new coal-fired 

power plant, and the EPA has 

concluded that, even in the absence of 

the requirements of this final rule, very 

few new coal-fired power plants will be 

built in the near term. 

Some commenters, however, 

disagreed with this conclusion. They 

contended instead that it is the CCSbased NSPS that would preclude such 

new generation. However, as the EPA 

has discussed, there is considerable 

evidence that utilities and project 

developers are moving away—or have 

already moved away—from a long term 

dependence on coal-fired generating 

sources. A review of publicly available 

integrated resource plans show that 

many utilities are not considering 

construction of new coal-fired sources 

without CCS. See Section V. H.3 above. 

Few new coal-fired generating sources 

have commenced construction in the 

past 5 years and, of the projects that are 

currently in the development phase, the 

EPA is only aware of projects that will 

include CCS in the design. As we have 

noted in this preamble, the bulk of new 

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336www.aep.com/newsroom/newsreleases/ 

?id=1704. 

337 ‘‘CCS LESSONS LEARNED REPORT American 

Electric Power Mountaineer CCS II Project Phase 

1’’, prepared for The Global CCS Institute Project # 

PRO 004, January 23, 2012, page 2. Available at: 

www.globalccsinstitute.com/publications/ccslessons-learned-report-american-electric-powermountaineer-ccs-ii-project-phase-1; See also AEP 

FEED Study at pp. 4, 63, Available at: 

www.globalccsinstitute.com/publications/aepmountaineer-ii-project-front-end-engineering-anddesign-feed-report. 

338Updated 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/NETL–2011/1498); Cost and Performance 

Baseline for Fossil Energy Plants (DOE/NETL–2010/ 

1397); Economic Evaluation of CO2 Storage and 

Sink Enhancement Options, Tennessee Valley 

Authority, NETL and EPRI, December 2002; Carbon 

Dioxide and Transport and Storage Costs in NETL 

Studies (DOE/NETL–2013/1614), March 2013; 

Carbon Dioxide and Transport and Storage Costs in 

NETL Studies (DOE/NETL–2014/1653), May 2014; 

Cost and Performance Baseline for Fossil Energy 

Power Plants, Volume 1a: Bituminous Coal (PC) 

and Natural Gas to Electricity (DOE–NETL–2015/ 

1723), July 2015. 

339Carbon Dioxide and Transport and Storage 

Costs in NETL Studies. DOE/NETL–2013/1614. 

March 2013. P. 13. 

340RIA at section 5.5; proposed rule RIA at 5–30. 

341http://hub.globalccsinstitute.com/sites/ 

default/files/publications/12786/economicassessment-carbon-capture-and-storagetechnologies-2011-update.pdf. 

342See, for example, comments from American 

Electric Power, pp 97–8 (Docket entry: EPA–HQ– 

OAR–2013–0495–10618), Southern Company, pp. 

47–48 (Docket entry: EPA–HQ–OAR–2013–0495– 

10095), and Duke Energy p. 28 (Docket entry: EPA– 

HQ–OAR–2013–0495–9426). 

343See RIA at section 5.5 and proposed RIA at 5– 

30. 344See RIA at section 5.5. 345The pipeline diameter was sized for this to be 

achieved without the need for recompression stages 

along the pipeline length. 346 JJ Dooley, CL Davidson, RT Dahowski, MA 

Wise, N Gupta, SH Kim, EL Malone (2006), Carbon 

Dioxide Capture and Geologic Storage: A Key 

Component of a Global Energy Technology Strategy 

to Address Climate Change. Joint Global Change 

Research Institute, Battelle Pacific Northwest 

Division. PNWD–3602. College Park, MD. 

347A Review of the CO2 Pipeline Infrastructure in 

the U.S., April 21, 2015, DOE/NETL–2014/1681, 

Office of Fossil Energy, National Energy Technology 

Laboratory. 

generation that has been added recently 

has been either natural gas-fired or 

renewable sources. Overall, the EPA 

remains convinced that the energy 

sector modeling is reflecting the realities 

of the market in predicting very few 

new coal-fired power plants in the near 

future—even in the absence of these 

final standards. 

In addition, we note that the 

Administration’s CCS Task Force report 

recognized that CCS would not become 

more widely available without the 

advent of a regulatory framework that 

promoted CCS or provided a strong 

price signal for CO2. In this regard, we 

note American Electric Power’s 

statements regarding the need for 

federal requirement for GHG control to 

aid in cost recovery for CCS projects, to 

attract other investment partners, and 

thereby promote advancement and 

deployment of CCS technology: ‘‘as a 

regulated utility, it is impossible to gain 

regulatory approval to recover our share 

of the costs for validating and deploying 

the technology without federal 

requirements to reduce greenhouse gas 

emissions already in place. The 

uncertainty also makes it difficult to 

attract partners to help fund the 

industry’s share’’.336 Indeed, AEP has 

stated that CCS is important for the very 

future of the industry: ‘‘AEP still 

believes the advancement of CCS is 

critical for the sustainability of coalfired generation.’’ 337 This final rule’s 

action is an important component in 

developing that needed regulatory 

framework. 

5. Accuracy of Cost Estimates for 

Transportation and Geologic 

Sequestration 

The EPA’s estimates of costs take into 

account the transport of CO2 and 

sequestration of captured CO2. Estimates 

of transport and sequestration costs— 

approximately $5–$15 per ton of CO2— 

are based on DOE NETL studies and are 

also consistent with other published 

studies.338 For transport, costs reflect 

pipeline capital costs, related capital 

expenditures, and O&M costs. 

Sequestration cost estimates reflect the 

cost of site screening and evaluation, the 

cost of injection wells, the cost of 

injection equipment, operation and 

maintenance costs, pore volume 

acquisition expense, and long term 

liability protection. These sequestration 

costs reflect the regulatory requirements 

of the Underground Injection Control 

Class VI program and GHGRP subpart 

RR for geologic sequestration of CO2 in 

deep saline formations, which are 

discussed further in Sections V. M. and 

N below.339

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 CO2.340 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.341 Some commenters 

suggested that the EPA underestimated 

the costs associated with transporting 

captured CO2 from an EGU to a 

sequestration site.342 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. 

The EPA believes its estimates of 

transportation and sequestration costs 

are reasonable. First, the EPA in fact 

includes cost estimates for CO2

transport when EOR opportunities are 

not available—consistent with its 

overall conservative cost methodology 

of assuming no revenues from sale of 

captured CO2. Specifically, the EPA 

estimates transport, storage and 

monitoring (TSM) costs of $5–$15 per 

ton of CO2 for non-EOR applications.343

This estimate is reflected in the LCOE 

comparative costs.344

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.345 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.346 As a point of reference, the 

longest CO2 pipeline in the United 

States is 502 miles.347 For new sources, 

pipeline distance and costs can be 

factored into siting and, as discussed in 

Section V.M, there is widespread 

availability of geologic formations for 

geologic sequestration (GS). Moreover, 

data from the Pipeline and Hazardous 

Materials Safety Administration show 

that in 2013 there were 5,195 miles of 

CO2 pipelines operating in the United 

States. This represents a seven percent 

increase in CO2 pipeline miles over the 

previous year and a 38 percent increase 

in CO2 pipeline miles since 2004. For 

the reasons outlined above, the EPA 

believes its estimates have a reasoned 

basis. See also Section V.M below 

further discussing the current 

availability of CO2 pipelines. 

With respect to sequestration, certain 

commenters argued that the EPA’s cost 

analysis failed to account for many 

contingencies and uncertainties (surface 

and sub-surface property rights in 

particular), ignored the costs of GHGRP 

subpart RR, and also was not 

representative of the costs associated 

with specific GS site characterization, 

development, and operation/injection of 

monitoring wells. Commenter American 

Electric Power (AEP) referred to its own 

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348AEP Comments at pp. 93, 96 (Docket entry: 

EPA–HQ–OAR–2013–0495–10618). 

349 ‘‘Cost and Performance of PC and IGCC Plants 

for a Range of Carbon Dioxide Capture.’’ DOE/ 

NETL–2011/1498 (September 2013) p. 49. 

Specifically, the report estimates the costs 

associated with acquiring rights to use the pore 

space in the geologic formation. Costs are estimated 

based on studies of subsurface rights acquisition for 

natural gas storage. The report also estimates costs 

for land acquisition for surface property rights. Id. 

p. 48. 

350Bock, B., R. Rhudy, H. Herzog, M. Klett, J. 

Davidson, D.G. De La Torre Ugarte, and D. Simbeck. 

(2003). Economic Evaluation of CO2 Storage and 

Sink Enhancement Options, Final Technical Report 

Prepared by Tennessee Valley Authority for DOE. 

351As noted above, other sequestration-related 

costs are also estimated, including injection wells 

and equipment, pore volume acquisition, and longterm-liability. ‘‘Cost and Performance Baseline for 

Fossil Energy Plants Volume 1: Bituminous Coal 

and Natural Gas to Electricity Revision 2a, 

September 2013 DOE/NETL–2010/1397, p. 55. 

352 ‘‘Overview of Monitoring Requirements for 

Geologic Storage Projects’’, IEA Greenhouse Gas 

R&D Programme, Report Number PH4/29, 

November 2004. 

353Cost Analysis for the Federal Requirements 

Under the Underground Injection Control Program 

for Carbon Dioxide Geologic Sequestration Wells, 

U.S. Environmental Protection Agency Office of 

Water, EPA 816–R10–013, November 2010, pages 

3–1, 5–42. 

354Economic Evaluation of CO2 Storage and Sink 

Enhancement Options, Tennessee Valley Authority, 

NETL and EPRI, December 2002. 

355See ‘‘CCS front end engineering & design 

report: American Electric Power Mountaineer CCS 

II Project. Phase 1’’ at pp. 36–43. The company 

likewise explained the monitoring regime it would 

utilize to verify containment, and the well 

construction it would utilize to guarantee secure 

sequestration. Id. at pp. 44–54. Available at: http:// 

www.globalccsinstitute.com/publications/aepmountaineer-ii-project-front-end-engineering-anddesign-feed-report. 

356Additional information can be found in a 

Technical Support Document (TSD)— 

‘‘Achievability of the Standard for Newly 

Constructed Steam Generating EGUs’’ available in 

the rulemaking docket. 

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 its estimated cost of 

expanding the existing Mountaineer 

plant to a larger scale project, 

particularly the cost of site 

characterization and well 

construction.348

The EPA’s cost estimates account for 

the requirements of the Underground 

Injection Control Class VI program, and 

GHGRP subpart RR, among them site 

screening and evaluation costs, costs for 

injection wells and equipment, O&M 

costs, and monitoring costs. The 

estimated sequestration costs include 

operational and post-injection site care 

monitoring, which are components of 

the UIC Class VI requirements, and also 

reflect costs for sub-surface pore volume 

property rights acquisition.349 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 CO2.350 351

Monitoring costs were evaluated based 

on the methodology set forth in the 

International Energy Agency 

Greenhouse Gas R&D Programme’s 

Overview of Monitoring Projects for 

Geologic Storage Projects report.352

The EPA’s cost estimates for 

sequestration thus cover all aspects 

commenters claimed the EPA 

disregarded. The EPA believes that the 

use of costs and scenarios presented in 

the studies referenced are representative 

for purposes of the cost analysis. The 

NETL cost estimates upon which the 

EPA’s costs draw directly from the UIC 

Class VI economic impact analysis.353

That analysis is based on estimated 

characteristics for a representative group 

of projects over a 50-year period of 

analysis, as well as industry averages for 

several cost components and subcomponents. The EPA also made 

reasonable assumptions regarding the 

assumed injection site: A deep saline 

formation with typical characteristics 

(e.g., representative depth and 

pressure).354

With respect to AEP’s experience with 

the Mountaineer demonstration project, 

sequestration siting issues are of course 

site-specific, and raise individual issues. 

For this reason, it is inappropriate to 

generalize from a particular individual 

experience. In this regard, as explained 

in Section V.N below, the construction 

permits issued by the EPA to-date under 

the Underground Injection Control Class 

VI regulations required far fewer wells 

for site characterization and monitoring 

than AEP found to be necessary at its 

Mountaineer site. Moreover, 

notwithstanding difficulties, the 

company was able to successfully drill 

and complete wells, and safely inject 

captured CO2. The company also 

indicated it fully expected to be able to 

do so at full scale and explained how.355

For discussion of 40 CFR part 98, 

subpart RR (the GHGRP requirements 

for geologic sequestration), including 

costs associated with compliance with 

those requirements, see Section V.N 

below. 

J. Achievability of the Final Standards 

The EPA finds the final standard of 

1,400 lb CO2/MWh-g to be achievable 

over a wide range of variable conditions 

that are reasonably likely to occur when 

the system is properly designed and 

operated. As discussed elsewhere, the 

final standard reflects the degree of 

emission limitation achievable through 

the application of the BSER which we 

have determined to be a highly efficient 

SCPC implementing partial CCS at a 

level sufficient to achieve the final 

standard—for such a unit utilizing 

bituminous coal that would be 

approximately 16 percent. In 

determining the predicted cost and 

performance of such a system, the EPA 

utilized information contained in 

updated DOE/NETL studies that 

assumed use of bituminous coal and an 

85 percent capacity factor. Here we 

examine the effects of deviating from 

those assumed operational parameters 

on the achievability of the final standard 

of performance.356 This is in keeping 

with the requirement that a standard of 

performance must be achievable 

accounting for all normal operating 

variability when a control system is 

properly designed, maintained, and 

operated. See Section III.H.1.c above. 

1. Operational Fluctuations, Start-Ups, 

Shutdowns, and Malfunctions 

Importantly, compliance with the 

standard must be demonstrated over a 

12-operating-month average. The total 

CO2 emissions (pounds of CO2) over 12 

operational months are summed and 

divided by the total gross output (in 

megawatt-hours) over the same 12 

operational months. Such a compliance 

averaging period is very forgiving of 

short-term excursions that can be 

associated with non-routine events such 

as start-ups, shutdowns, and 

malfunctions. A new fossil fuel-fired 

steam generating EGU—if constructed— 

would, most likely, be built to serve 

base load power demand and would not 

be expected to routinely start-up or 

shutdown or ramp its capacity factor in 

order to follow load demand. Thus, 

planned start-up and shutdown events 

would only be expected to occur a few 

times during the course of a 12- 

operating-month compliance period. 

Malfunctions are unplanned and 

unpredictable events and emission 

excursions can happen at or around the 

time of the equipment malfunction. But 

a malfunctioning EGU that cannot be 

operated properly should be shut down 

until the malfunctioning equipment can 

be addressed and the EGU can be 

restarted to operate properly. 

The post-combustion capture systems 

that have been utilized have proven to 

be reliable. The Boundary Dam facility 

has been operating full CCS successfully 

at commercial scale since October 2014. 

As described earlier, in evaluating 

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357http://www.alstom.com/press-centre/2011/5/ 

alstom-announces-sucessful-results-ofmountaineer-carbon-capture-and-sequestration-ccsproject/. The Boundary Dam facility likewise is 

operating reliably (see Section V.D.3.a above). See 

also ‘‘Cost and Performance Baseline for Fossil 

Energy Plants Volume 1a: Bituminous Coal (PC) and 

Natural Gas to Electricity, Revision 3’’, DOE/NETL– 

2015/1723 (July 2015) at p. 36 (‘‘[t]he capture and 

CO2 compression technologies have commercial 

operating experience with demonstrated ability for 

high reliability’’). 

358For additional detail, see the Technical 

Support Document (TSD)—‘‘Achievability of the 

Standard for Newly Constructed Steam Generating 

EGUs’’—available in the rulemaking docket. 

359The cost of the lignite drying equipment is 

assumed to be low compared to the cost of the 

carbon capture equipment. Further, pre-drying of 

the lignite reduces fuel, auxiliary power 

consumption and other O&M costs. www.ieacoal.org.uk/documents/83436/9095/Technoeconomics-of-modern-pre-drying-technologies-forlignite-fired-power-plants,-CCC/241. 

360Note that the 23 percent increase in expected 

capital costs and the 23 percent CO2 capture needed 

to meet the final standard are coincidental and are 

not correlated. 

361Sierra 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.’’ 

362Using U.S. EPA Office of Transportation and 

Air Quality (OTAQ) estimate of average vehicle 

emissions of 4.7 tonnes/year. 

363 Greenhouse Gas Reporting Program, data 

reported as of August 18, 2014. 

stream demonstration, AEP and Alstom 

reported robust steady-state operation 

during all modes of power plant 

operation including load changes, and 

saw an availability of the CCS system of 

greater than 90 percent.357

2. Variations in Coal Type 

The use of specific coal types can 

affect the amount of CO2 that is emitted 

from a new coal-fired power plant. As 

previously discussed, the EPA utilized 

studies by the DOE/NETL to predict the 

cost and performance of new steam 

generating units. Based on those reports, 

the EPA predicts that a new SCPC 

burning low rank coal (subbituminous 

coal or dried lignite) would have an 

uncontrolled emission rate about 7 

percent higher than a similar unit firing 

typical bituminous coal.358 The EPA 

predicts that such a highly efficient new 

SCPC utilizing subbituminous coal or 

dried lignite would need to capture 

approximately 23 percent of the CO2. 

The EPA also believes that it is 

technically feasible to do so, although 

additional cost would be entailed. The 

EPA has evaluated those costs and finds 

them to remain reasonable.359 As shown 

in Table 8 above, the predicted cost 

remains within the estimated range for 

the other principal base load, 

dispatchable non-NGCC alternative 

technologies. Estimated capital cost 

using these coal types would also be 

somewhat higher, an estimated 23 

percent increase.360 The EPA finds these 

increases to be reasonable because, as 

discussed earlier, the costs are 

reasonably consistent with capital cost 

increases in previous NSPS. See Section 

V.H.4 above. 

K. Emission Reductions Utilizing Partial 

CCS 

Although the definition of ‘‘standard 

of performance’’ does not by its terms 

identify the amount of emissions from 

the category of sources and the amount 

of emission reductions achieved as 

factors the EPA must consider in 

determining the ‘‘best system of 

emission reduction,’’ the D.C. Circuit 

has stated that the EPA must do so. See 

Sierra Club v. Costle, 657 F.2d at 326 

(‘‘we can think of no sensible 

interpretation of the statutory words 

‘‘best . . . system’’ which would not 

incorporate the amount of air pollution 

as a relevant factor to be weighed when 

determining the optimal standard for 

controlling . . . emissions’’).361 This is 

consistent with the Court’s statements 

in Essex Chemical Corp. v. Ruckelshaus, 

486 F.2d at 437 that it is necessary to 

‘‘[k]eep[] in mind Congress’ intent that 

new plants be controlled to the 

‘maximum practicable degree’ ’’. 

The final standard of performance 

will result in meaningful and significant 

emission reductions of GHG emissions 

from a new coal-fired steam generating 

unit. The EPA estimates that a new 

highly efficient 500 MW coal-fired SCPC 

meeting the final standard of 1,400 lb 

CO2/MWh-g will emit about 354,000 

fewer metric tons of CO2 each year than 

that new highly efficient unit would 

have emitted otherwise. That is 

equivalent to taking about 75,000 

vehicles off the road each year 362 and 

will result in over 14,000,000 fewer 

metric tons of CO2 in a 40-year 

operating life. To emphasize the 

importance of constructing a highly 

efficient SCPC unit that includes partial 

CCS—the highly efficient 500 MW coalfired SCPC with partial CCS would emit 

about 675,000 fewer metric tons of CO2

each year than that from a new, less 

efficient coal-fired utility boiler with an 

assumed emission of 1,800 lb CO2/ 

MWh-g. 

For comparison, see Table 12 below 

which provides the amount of CO2

emissions captured each year by other 

CCS projects. These result show that, 

even though the emission reductions are 

significant, they are reasonably within 

the range of emission reductions that are 

currently being achieved now in 

existing facilities. For comparison, 

approximately 60,000,000 metric tons of 

CO2 were supplied to U.S. EOR 

operations in 2013.363

TABLE 12—ANNUAL METRIC TONS OF CO2 CAPTURED (OR PREDICTED TO CAPTURE) FROM CCS PROJECTS AND FROM A

MODEL 500 MW PLANT MEETING THE FINAL STANDARD. 

Project CO2 captured 

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 EGU (1,400 lb CO2/MWh-g) .............................................................................................................................. 354,000 

Coffeyville Fertilizer ............................................................................................................................................................................. 700,000 

Boundary Dam #3 ................................................................................................................................................................................ 1,000,000 

Petra Nova/NRG WA Parish ............................................................................................................................................................... 1,400,000 

Dakota Gasification .............................................................................................................................................................................. 3,000,000 

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364See Technical Support Document/ 

Memorandum ‘‘History Of Flue Gas Desulfurization 

in the United States’’ (July 11, 2015) summarizing 

the doctoral dissertation of Margaret R. Taylor, 

‘‘The Influence of Government Actions on 

Innovative Activities in the Development of 

Environmental Technologies to Control Sulfur 

Dioxide Emissions from Stationary Sources,’’ MA 

dissertation submitted to the Carnegie Institute of 

Technology, Carnegie Mellon University in partial 

fulfillment of the requirements for the degree of 

Doctor of Philosophy in Engineering and Public 

Policy, Pittsburgh, PA, January 2001. 

365See also Carbon Sequestration Council and 

Southern Company Services v. EPA, No. 14–1406 

(D.C. Cir. June 2, 2015) at *10 (‘‘[c]arbon capture 

and storage is an emerging climate change 

mitigation program that involves capturing carbon 

dioxide from industrial sources, compressing it into 

a ‘supercritical fluid,’ and injecting that fluid 

underground for the purposes of geologic 

sequestration, with the goal of preventing the 

carbon from reentering the atmosphere. Because the 

last of these steps—geologic sequestration of the 

supercritical carbon dioxide—involves that 

injection of fluid into underground wells, it is 

subject to regulation under the Safe Drinking Water 

Act’’). 

366See, e.g., USEPA. 2008. Vulnerability 

Evaluation Framework for Geologic Sequestration of 

Carbon Dioxide. 

367Report of the Interagency Task Force on 

Carbon Capture and Storage (August 2010), page 47. 

368See, e.g., Intergovernmental Panel on Climate 

Change. (2005). Special Report on Carbon Dioxide 

Capture and Storage. 

L. Further Development and 

Deployment of CCS Technology 

Researchers at Carnegie Mellon 

University (CMU) have studied the 

history and the technological response 

to environmental regulations.364 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 powerplant emissions resulted in a significant 

upswing in inventive activity to develop 

technologies to reduce those emissions. 

The researchers found that, following 

the 1970 Clean Air Act, there was a 10- 

fold increase in patenting activity 

directed at improving the SO2 scrubbers 

that were needed to comply with 

stringent federal and state-level 

standards. 

Much like carbon capture scrubbers 

today, the technology to capture and 

remove SO2 from power plant flue gases 

was new to the industry and was not yet 

widely deployed at large coal-burning 

plants when the EPA first promulgated 

the 1971 standards. 

Many of the early Flue Gas 

Desulfurization (FGD) units did not 

perform well, as the technology at that 

time was poorly understood and there 

was little or no prior experience on coalfired power plants. In contrast, aminebased capture systems have a much 

longer history of reliable use at coalfired plants and other industrial 

sources. There is also a better 

understanding of the amine process 

chemistry and overall process design— 

and project developers have much 

sophisticated analytical tools available 

today than in the 1970s during the 

development of FGD scrubber 

technologies. 

While R&D efforts were essential to 

achieving improvements in FGD 

scrubber technology—and are also very 

important to improving carbon capture 

technologies, the influence of regulatory 

actions that establish commercial 

markets for advanced technologies 

cannot be minimized. The existence of 

national government regulation for SO2

emissions control stimulated 

innovation, as shown by the patent 

analysis following initial SO2 regulatory 

requirements for EGU emissions. The 

study author further found that 

regulatory stringency appears to be 

particularly important as a driver of 

innovation, both in terms of inventive 

activity and in terms of the 

communication processes involved in 

knowledge transfer and diffusion. 

Further, as electric power generation 

doubled, the operating and maintenance 

costs of FGD systems decline to 83 

percent of their original level. This 

finding, which is very much in line with 

progress ratios determined in other 

industries, shows that quantifiable 

technological improvements can be 

shown to occur solely on the basis of the 

experience of operating an 

environmental control technology 

forced into being by government 

actions. 

M. Technical and Geographic Aspects of 

Disposition of Captured CO2

In the following sections of the 

preamble, we discuss issues associated 

with the disposition of captured CO2: 

the ‘‘S’’—sequestration—in CCS. In this 

section, we review the existing 

processes, technologies, and geologic 

conditions that enable successful 

geologic sequestration (GS). In Section 

V.N., we discuss in detail the 

comprehensive, in-place regulatory 

structure that is currently available to 

oversee GS projects and assure their 

safety and effectiveness. Together, these 

discussions demonstrate that the 

technical feasibility of GS, another key 

component of a partial CCS unit, is 

adequately demonstrated. Sequestration 

is already well proven. CO2 has been 

retained underground for eons in 

geologic (natural) repositories and the 

mechanisms by which CO2 is trapped 

underground are well understood. The 

physical and chemical trapping 

mechanisms, along with the regulatory 

requirements and safeguards of the 

Underground Injection Control Program 

and complementary monitoring and 

reporting requirements of the GHGRP, 

together ensure that sequestered CO2

will remain secure and provide the 

monitoring to identify and address 

potential leakage using Safe Drinking 

Water Act (SDWA) and CAA authorities 

(see Section V.N of this preamble).365

1. Geologic and Geographic 

Considerations for GS 

Geologic sequestration (i.e., long-term 

containment of a CO2 stream in 

subsurface geologic formations) is 

technically feasible and available 

throughout most of the United States. 

GS is based on a demonstrated 

understanding of the processes that 

affect CO2 fate in the subsurface; these 

processes can vary regionally as the 

subsurface geology changes. GS occurs 

through a combination of mechanisms 

including: (1) Structural and 

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).366 These mechanisms are 

functions of the physical and chemical 

properties of CO2 and the geologic 

formations into which the CO2 stream is 

injected. Subsurface formations suitable 

for GS of CO2 captured from affected 

EGUs are geographically widespread 

throughout most parts of the United 

States. 

Storage security is expected to 

increase over time through post-closure, 

resulting in a decrease in potential 

risks.367 This expectation is based in 

part on a technical understanding of the 

variety of trapping mechanisms that 

work to reduce CO2 mobility over 

time.368 In addition, site 

characterization, site operations, and 

monitoring strategies can work in 

combination to promote storage 

security. 

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369Holloway, 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. 370 Intergovernmental Panel on Climate Change. 

(2005). Special Report on Carbon Dioxide Capture 

and Storage. 371 DiPietro, P., Balash, P. & M. Wallace. A Note 

on Sources of CO2 Supply for Enhanced-Oil 

Recovery Operations. SPE Economics & 

Management. April 2012. 

372A color version of the figure, which readers 

may find easier to view, can be found in the 

technical support document on geographic 

availability in the rulemaking docket. 373Alaska is not shown in Figure 1; it has deep 

saline formation storage capacity, geology amenable 

to EOR operations, and potential GS capacity in 

unmineable coal seams. 374The distance of 100 kilometers reflects 

assumptions in DOE–NETL cost estimates which 

the EPA used for cost estimation purposes. See 

‘‘Carbon Dioxide and Transport and Storage Costs 

in NETL Studies’’, DOE/NETL–2014/1653 (May 

2014). 375Other types of opportunities include organic 

shales and basalt. 

376The United States 2012 Carbon Utilization and 

Storage Atlas, Fourth Edition, U.S. Department of 

Energy, Office of Fossil Energy, National Energy 

Technology Laboratory (NETL). 

377Similarly, as discussed below, the U.S. 

territories lack available coal, do not currently have 

coal-fired power plants, and, as a result, are not 

expected to see new coal-fired power plants. Hawaii 

is not expected to constructed new coal plants as 

it intends to utilize 100 percent renewable energy 

sources by 2050. 

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.369 For 

example, CO2 has been trapped for more 

than 65 million years in the Jackson 

Dome, located near Jackson, 

Mississippi.370 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.371

GS is feasible in different types of 

geologic formations including deep 

saline formations (formations with high 

salinity formation fluids) or in oil and 

gas formations, such as where injected 

CO2 increases oil production efficiency 

through a process referred to as 

enhanced oil recovery (EOR). Both deep 

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.372 As shown 

in the figure, there are 39 states for 

which onshore and offshore deep saline 

formation storage capacity has been 

identified.373 EOR operations are 

currently being conducted in 12 states. 

An additional 17 states have geology 

that is amenable to EOR operations. 

Figure 1 also shows areas that are 

within 100 kilometers (62 miles) of 

where storage capacity has been 

identified.374 There are 10 states with 

operating CO2 pipelines and 18 states 

that are within 100 kilometers (62 miles) 

of an active EOR location. 

CO2 may also be used for other types 

of enhanced recovery, such as for 

natural gas production. Reservoirs such 

as unmineable coal seams also offer the 

potential for geologic storage.375

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 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.376 The 

availability of unmineable coal seams is 

shown in Figure 1 below. 

As discussed below in Section M.7, a 

few states do not have geologic 

conditions suitable for GS, or may not 

be located in proximity to these areas. 

However, in some cases, demand in 

those states can be served by coal-fired 

power plants located in areas suitable 

for GS, and in other cases, coal-fired 

power plants are unlikely to be built in 

those areas for other reasons, such as the 

lack of available coal or state law 

prohibitions and restrictions against 

coal-fired power plants.377

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-- Existing C02 pipeline {Department ofTransportation) 

---- Probable, planned, or under study C02 pipeline 

Counties with active C02-EOR operations (EPA GHG Reporting Program) 

Deep Saline Formations (Department of Energy, NATCARB) 

Unmineable Coal Seams (Department of Energy, NATCARB) 

100 km from Geologic Sequestration 

Figure 1: Geologic Sequestration in the Continental United 

States 
64578 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

378 Ventyx Velocity Suite Online. April 2015. 

379The United States 2012 Carbon Utilization and 

Storage Atlas, Fourth Edition, U.S. Department of 

Energy, Office of Fossil Energy, National Energy 

Technology Laboratory (NETL). 

2. Availability of Geologic Sequestration 

in Deep Saline Formations 

The DOE and the United States 

Geological Survey (USGS) have 

independently conducted preliminary 

analyses of the availability and potential 

CO2 sequestration capacity of deep 

saline formations in the United States. 

DOE estimates are compiled by the 

DOE’s National Carbon Sequestration 

Database and Geographic Information 

System (NATCARB) using volumetric 

models and published in a Carbon 

Utilization and Storage Atlas.379 DOE 

estimates that areas of the United States 


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United States 378 
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64579 

380U.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/. 

381http://energy.gov/fe/science-innovation/

carbon-capture-and-storage-research/regionalpartnerships. 

382http://energy.gov/fe/science-innovation/

carbon-capture-and-storage-research/regionalpartnerships. 

383http://energy.gov/articles/milestone-energydepartment-projects-safely-and-permanently-store10-million-metric-tons. 

384U.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. 

385A description of the types of monitoring 

technologies employed at RCSP projects can be 

found here: http://www.netl.doe.gov/research/coal/ 

carbon-storage/carbon-storage-infrastructure/

regional-partnership-development-phase-iii. 

386 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). 

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 

assessment.380 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 largescale 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.381 The seven 

partnerships include more than 400 

organizations spanning 43 states (and 

four Canadian provinces).382 RCSP 

project objectives are to inject at least 

one million metric tons of CO2. In April 

2015, DOE announced that CCS projects 

supported by the department have 

safely and permanently stored 10 

million metric tons of CO2.383

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 2013.384 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.385 No CO2

leakage has been reported from these 

sites, which further supports the 

availability of effective GS. 

3. Availability of CO2 Storage via EOR 

Although the determination that the 

BSER is adequately demonstrated and 

the regulatory impact analysis for this 

rule relies on GS in deep saline 

formations, the EPA also recognizes the 

potential for securely sequestering CO2

via EOR. 

EOR is a technique that is used to 

increase the production of oil. 

Approaches used for EOR include steam 

injection, injection of specific fluids 

such as surfactants and polymers, and 

gas injection including nitrogen and 

CO2. EOR using CO2, sometimes referred 

to as ‘‘CO2 flooding’’ or CO2-EOR, 

involves injecting CO2 into an oil 

reservoir to help mobilize the remaining 

oil to make it more amenable for 

recovery. The crude oil and CO2 mixture 

is then recovered and sent to a separator 

where the crude oil is separated from 

the gaseous hydrocarbons, native 

formation fluids, and CO2. The gaseous 

CO2-rich stream then is typically 

dehydrated, purified to remove 

hydrocarbons, re-compressed, and reinjected 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 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. 

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.386

More than half of the projects evaluated 

in the study have been in operation for 

more than 10 years, and many have 

been in operation for more than 30 

years. This experience provides a strong 

foundation for demonstrating successful 

CO2 injection and monitoring 

technologies, which are needed for safe 

and secure GS (see Section N below) 

that can be used for deployment of CCS 

across geographically diverse areas. 

Currently, 12 states have active EOR 

operations and most have developed an 

extensive CO2 infrastructure, including 

pipelines, to support the continued 

operation and growth of EOR. An 

additional 18 states are within 100 

kilometers (62 miles) of current EOR 

operations. See Figure 1 above. The vast 

majority of EOR is conducted in oil 

reservoirs in the Permian Basin, which 

extends through southwest Texas and 

southeast New Mexico. States where 

EOR is utilized include Alabama, 

Colorado, Louisiana, Michigan, 

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387Han, 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. 

388 Greenhouse Gas Reporting Program, data 

reported as of August 18, 2014. 

389 Greenhouse Gas Reporting Program, data 

reported as of August 18, 2014. 

390 ‘‘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/energy-analysis/

publications/details?pub=df02ffba-6b4b-4721-a7b4- 

04a505a19185. 

391 ‘‘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/energy-analysis/

publications/details?pub=df02ffba-6b4b-4721-a7b4- 

04a505a19185. 

392Han, 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. 

393Romanak, 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. 

394Roston, 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. 

395Hitchon, B. (Editor), 2012, Best Practices for 

Validating CO2 Geological Storage: Geoscience 

Publishing, p. 353. 

396http://www.beg.utexas.edu/gccc/

cranfield.php. 

397http://www.beg.utexas.edu/gccc/

cranfield.php. 

Mississippi, New Mexico, Oklahoma, 

Texas, Utah, and Wyoming. Several 

commenters raised concerns about the 

volume of CO2 used in EOR projects 

relative to the scale of EGU emissions 

and the demand for CO2 for EOR 

projects. At the project level, the volume 

of CO2 already injected for EOR and the 

duration of operations are of similar 

magnitude to the duration and volume 

of CO2 expected to be captured from 

fossil fuel-fired EGUs. The volume of 

CO2 used in EOR operations can be large 

(e.g., 55 million tons of CO2 were stored 

in the SACROC unit in the Permian 

Basin over 35 years), and operations at 

a single oil field may last for decades, 

injecting into multiple parts of the 

field.387 According to data reported to 

the EPA’s GHGRP, approximately 60 

million metric tons of CO2 were 

supplied to EOR in the United States in 

2013.388 Approximately 70 percent of 

this total CO2 supplied was produced 

from natural (geologic) CO2 sources and 

approximately 30 percent was captured 

from anthropogenic sources.389

A DOE-sponsored study has analyzed 

the geographic availability of applying 

EOR in 11 major oil producing regions 

of the United States and found that 

there is an opportunity to significantly 

increase the application of EOR to areas 

outside of current operations.390 DOEsponsored 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.391 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. 

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 longterm 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 CO2.392 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 groundwater 

sampling program to look for evidence 

of CO2 leakage in the shallow freshwater 

aquifers. No evidence of leakage was 

detected.393

The International Energy Agency 

Greenhouse Gas Programme conducted 

an extensive monitoring program at the 

Weyburn oil field in Saskatchewan 

between 2000 and 2010 (the site 

receiving CO2 captured by the Dakota 

Gasification synfuel plant discussed in 

Section V.E.2.a above). During that time 

over 16 million metric tons of CO2 were 

safely sequestered as evidenced by soil 

gas surveys, shallow groundwater 

monitoring, seismic surveys and 

wellbore integrity testing. An extensive 

shallow groundwater monitoring 

program revealed no significant changes 

in water chemistry that could be 

attributed to CO2 storage operations.394

The International Energy Agency 

Greenhouse Gas Programme developed 

a best practices manual for CO2

monitoring at EOR sites based on the 

comprehensive analysis of surface and 

subsurface monitoring methods applied 

over the 10 years.395

The Texas Bureau of Economic 

Geology also has been testing a wide 

range of surface and subsurface 

monitoring tools and approaches to 

document sequestration efficiency and 

sequestration permanence at the 

Cranfield oilfield in Mississippi (see 

Section L.1 above).396 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.397 The project also 

demonstrates the availability and 

effectiveness of many different 

monitoring techniques for tracking CO2

underground and detecting CO2 leakage 

to ensure CO2 remains safely 

sequestered. 

As discussed in Section M.1 above 

and as shown in Figure 1, the United 

States has widespread potential for 

storage, including in deep saline 

formations and oil and gas formations. 

However, some commenters maintained 

that the EPA’s information 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 

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398Comments of Southern Co., p. 38 (Docket 

entry: EPA–HQ–OAR–2013–0495–10095). 

399Comments of AEP pp. 93, 96 (Docket entry: 

EPA–HQ–OAR–2013–0495–10618). 

400Comments of Duke Energy, pp. 24–5 Docket 

entry: EPA–HQ–OAR–2013–0495–9426); UARG, 

pp. 53, 57 (Docket entry: EPA–HQ–OAR–2013– 

0495–9666) citing Cichanowicz (2012). 401http://skyonic.com/technologies/skymine. 

402Report of the Interagency Task Force on 

Carbon Capture and Storage (August 2010), page 36. 

403 ‘‘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. 

that sites are not available as a practical 

matter.398 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.399 Other commenters 

noted significant geographic disparity in 

GS site availability, claiming absence of 

sites in southeastern areas of the 

country.400

Project- and site-specific factors do 

influence where CO2 can be safely 

sequestered. However, as outlined 

above, there is widespread potential for 

GS in the United States. If an area does 

not have a suitable GS site, EGUs can 

either transport CO2 to GS sites via CO2

pipelines (see Section M.5 below), or 

they may choose to locate their units 

closer to GS sites and provide electric 

power to customers through 

transmission lines (see Figure 2 and 

Section M.7). In addition, there are 

alternative means of complying with the 

final standards of performance that do 

not necessitate use of partial CCS, so 

any siting difficulties based on lack of 

a CO2 repository would be obviated. See 

Portland Cement Ass’n v. EPA, 665 F. 

3d 177, 191 (D.C. Cir. 2011), holding 

that the EPA could adopt section 111 

standards of performance based on the 

performance of a kiln type that kilns of 

older design would have great difficulty 

satisfying, since, among other things, 

there were alternative methods of 

compliance available should a new kiln 

of this older design be built. 

4. Alternatives to Geologic 

Sequestration 

Potential alternatives to sequestering 

CO2 in geologic formations are 

emerging. These relatively new 

potential alternatives may offer the 

opportunity to offset the cost of CO2

capture. For example, captured 

anthropogenic CO2 may be stored in 

solid carbonate materials such as 

precipitated calcium carbonate (PCC) or 

magnesium or calcium carbonate, 

bauxite residue carbonation, and certain 

types of cement through mineralization. 

PCC is produced through a chemical 

reaction process that utilizes calcium 

oxide (quicklime), water, and CO2. 

Likewise, the combination of 

magnesium oxide and CO2 results in a 

precipitation reaction where the CO2

becomes mineralized. The carbonate 

materials produced can be tailored to 

optimize performance in specific 

industrial and commercial applications. 

These carbonate materials have been 

used in the construction industry and, 

more recently and innovatively, in 

cement production processes to replace 

Portland cement. 

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.401

A few commenters suggested that CO2

utilization technologies alternative to 

GS are being commercialized, and that 

these should be included as compliance 

options for this rule. The rule generally 

requires that captured CO2 be either 

injected on-site for geologic 

sequestration or transferred offsite to a 

facility reporting under 40 CFR subpart 

RR. The EPA does not believe that the 

emerging technologies just discussed are 

sufficiently advanced to unqualifiedly 

structure this final rule to allow for their 

use. Nor are there plenary systems of 

regulatory control and GHG reporting 

for these approaches, as there are for 

geologic sequestration. Nonetheless, as 

stated above, these technologies not 

only show promise, but could 

potentially be demonstrated to show 

permanent storage of CO2. 

In the January 2014 proposal, the EPA 

noted that it would need to adopt a 

mechanism to evaluate these alternative 

technologies before any could be used 

in lieu of geologic sequestration. 79 FR 

at 1484. The EPA is establishing such a 

mechanism in this final rule. See 

§ 60.5555(g). The rule provides for a 

case-by-case adjudication by the EPA of 

applications seeking to demonstrate to 

the EPA that a non-geologic 

sequestration technology would result 

in permanent confinement of captured 

CO2 from an affected EGU. The criteria 

to be addressed in the application, and 

evaluated by the EPA, are drawn from 

CAA section 111(j), which provides an 

analogous mechanism for case-by-case 

approval of innovative technological 

systems of continuous emission 

reduction which have not been 

adequately demonstrated. Applicants 

would need to demonstrate that the 

proposed technology would operate 

effectively, and that captured CO2

would be permanently stored. 

Applicants must also demonstrate that 

the proposed technology will not cause 

or contribute to an unreasonable risk to 

public health, welfare or safety. In 

evaluating applications, the EPA may 

conduct tests itself or require the 

applicant to conduct testing in support 

of its application. Any application 

would be publicly noticed, and the EPA 

would solicit comment on the 

application and on intended action the 

EPA might take. The EPA could also 

provide a conditional approval of an 

application on operating results from a 

proscribed period. The EPA could also 

terminate an approval, including a 

termination based on operating results 

calling into question a technology’s 

effectiveness. 

As noted at proposal, given the 

unlikelihood of new coal-fired EGUs 

being constructed, the EPA does not 

expect there to be many (if any) 

applications for use of non-geologic 

sequestration technology. 79 FR at 1484. 

5. Availability of Existing or Planned 

CO2 Pipelines 

CO2 pipelines are the most 

economical and efficient method of 

transporting large quantities of CO2.402

CO2 has been transported via pipelines 

in the United States for nearly 40 years. 

Over this time, the design, construction, 

operation, and safety requirements for 

CO2 pipelines have been proven, and 

the U.S. CO2 pipeline network has been 

safely used and expanded. The Pipeline 

and Hazardous Materials Safety 

Administration (PHMSA) reported that 

in 2013 there were 5,195 miles of CO2

pipelines operating in the United States. 

This represents a seven percent increase 

in CO2 pipeline miles over the previous 

year and a 38 percent increase in CO2

pipeline miles since 2004.403

Some commenters argued that the 

existing CO2 pipeline capacity is not 

adequate and that CO2 pipelines are not 

available in a majority of the United 

States. 

The EPA does not agree. The CO2

pipeline network in the United States 

has almost doubled in the past ten years 

in order to meet growing demands for 

CO2 for EOR. CO2 transport companies 

have recently proposed initiatives to 

expand the CO2 pipeline network. 

Several hundred miles of dedicated CO2

pipeline are under construction, 

planned, or proposed, including 

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404 ‘‘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.businesswire.com/files/

report/additional/KMI–2014–10K_Final.pdf. 

405 ‘‘2013 Annual Report’’, Denbury, April 2014. 

Available at http://www.denbury.com/files/doc_

financials/2013/Denbury_Final_040814.pdf. 

406 ‘‘CO2 Sources’’, Denbury, 2015. Available at: 

http://www.denbury.com/operations/rockymountain-region/co2-sources-and-pipelines/

default.aspx. 

407http://www.denbury.com/operations/gulfcoast-region/Pipelines/default.aspx. 

408 ‘‘CO2 Pipelines’’, Denbury, 2014. Available at: 

http://www.denbury.com/operations/rockymountain-region/COsub2-sub-Pipelines/

default.aspx. 

409 ‘‘The West Ranch CO2-EOR Project, NRG Fact 

Sheet’’, NRG, 2014. Available at: www.nrg.com/

documents/business/pla-2014-west-ranch-factsheet.pdf. 

410 ‘‘WA Parish Carbon Capture Project’’, NRG, 

2015. Available at: www.nrg.com/sustainability/

strategy/enhance-generation/carbon-capture/waparish-ccs-project/. 

411See the B31 Code for pressure piping, 

developed by the American Society of Mechanical 

Engineers, Pipeline Transportation Systems for 

liquid hydrocarbons and other liquids. 

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 

2015.404

Denbury reported that the company 

utilized approximately 70 million cubic 

feet per day of anthropogenic CO2 in 

2013 and that an additional 

approximately 115 million cubic feet 

per day of anthropogenic CO2 may be 

utilized in the future from currently 

planned or future construction of 

facilities and associated pipelines in the 

Gulf Coast region.405 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.406

Denbury completed the final section 

of the 325-mile Green Pipeline for 

transporting CO2 from Donaldsonville, 

Louisiana, to EOR oil fields in Texas.407

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.408

A project being constructed by NRG 

and JX Nippon Oil & Gas Exploration 

(Petra Nova) would capture CO2 from a 

power plant in Fort Bend County, Texas 

for transport to EOR sites in Jackson 

County, Texas through an 82-mile CO2

pipeline.409 The project is anticipated to 

commence operation in 2016.410

Some commenters suggested that 

there may be challenges associated with 

the safety of transporting supercritical 

CO2 over long distances, or that the EPA 

did not adequately consider the 

potential non-air environmental impacts 

of the construction of CO2 pipelines. 

The EPA has carefully evaluated the 

safety of pipelines used to transport 

captured CO2 and determined that 

pipelines can indeed convey captured 

CO2 to sequestration sites with certainty 

and provide full protection of human 

health and the environment. 76 FR at 

48082–83 (Aug. 8, 2011); 79 FR 352, 354 

(Jan. 3, 2014). Existing and new CO2

pipelines are comprehensively regulated 

by the Department of Transportation’s 

Pipeline Hazardous Material Safety 

Administration. The regulations govern 

pipeline design, construction, operation 

and maintenance, and emergency 

response planning. See generally 49 

CFR 195.2. Additional regulations 

address pipeline integrity management 

by requiring heightened scrutiny to 

assure the quality of pipeline integrity 

in areas with a higher potential for 

adverse consequences. See 49 CFR 

195.450 and 195.452. On-site pipelines 

are not subject to the Department of 

Transportation standards, but rather 

adhere to the Pressure Piping standards 

of the American Society of Mechanical 

Engineers (ASME B31), which the EPA 

has found would ensure that piping and 

associated equipment meet certain 

quality and safety criteria sufficient to 

prevent releases of CO2, such that 

certain additional requirements were 

not necessary (See 79 FR 358–59 (Jan. 3, 

2014)).411 These existing controls over 

CO2 pipelines assure protective 

management, guard against releases, and 

assure that captured CO2 will be 

securely conveyed to a sequestration 

site. 

6. States With Emission Standards That 

Would Require CCS 

Several states have established 

emission performance standards or 

other measures to limit emissions of 

GHGs from new EGUs that are 

comparable to or more stringent than 

the final standard in this rulemaking. 

For example, in September 2006, 

California Governor Schwarzenegger 

signed into law Senate Bill 1368. The 

law limits long-term investments in base 

load generation by the state’s utilities to 

power plants that meet an emissions 

performance standard jointly 

established by the California Energy 

Commission and the California Public 

Utilities Commission. The Energy 

Commission has designed regulations 

that establish a standard for new and 

existing base load generation owned by, 

or under long-term contract to publicly 

owned utilities, of 1,100 lb CO2/MWh. 

In May 2007, Washington Governor 

Gregoire signed Substitute Senate Bill 

6001, which established statewide GHG 

emissions reduction goals, and imposed 

an emission standard that applies to any 

base load electric generation that 

commenced operation after June 1, 2008 

and is located in Washington, whether 

or not that generation serves load 

located within the state. Base load 

generation facilities must initially 

comply with an emission limit of 1,100 

lb CO2/MWh. 

In July 2009, Oregon Governor 

Kulongoski signed Senate Bill 101, 

which mandated that facilities 

generating base load electricity, whether 

gas- or coal-fired, must have emissions 

equal to or less than 1,100 lb CO2/MWh, 

and prohibited utilities from entering 

into long-term purchase agreements for 

base load electricity with out-of-state 

facilities that do not meet that standard. 

In 2012 New York established 

emission standards of CO2 at 925 lb 

CO2/MWh for new and expanded base 

load fossil fuel-fired plants. 

In May 2007, Montana Governor 

Schweitzer signed House Bill 25, 

adopting a CO2 emissions performance 

standard for EGUs in the state. House 

Bill 25 prohibits the state Public Utility 

Commission from approving new EGUs 

primarily fueled by coal unless a 

minimum of 50 percent of the CO2

produced by the facility is captured and 

sequestered. 

On January 12, 2009, Illinois 

Governor Blagojevich signed Senate Bill 

1987, the Clean Coal Portfolio Standard 

Law. The legislation establishes 

emission standards for new power 

plants that use coal as their primary 

feedstock. From 2009–2015, new coalfueled power plants must capture and 

store 50 percent of the carbon emissions 

that the facility would otherwise emit; 

from 2016–2017, 70 percent must be 

captured and stored; and after 2017, 90 

percent must be captured and stored. 

7. Coal-by-Wire 

In addition, as discussed in the 

proposal, electricity demand in states 

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412The NETL cost estimates for CO2 transport 

assume a pipeline of 100 kilometers. NETL (2015) 

at p. 44. 

413The data in Figure 1 is based on estimates 

compiled by the DOE’s National Carbon 

Sequestration Database and Geographic Information 

System (NATCARB) and published in the United 

States 2012 Carbon Utilization and Storage Atlas, 

Fourth Edition. As discussed in the TSD, deep 

saline formation potential was not assessed for 

Alaska, Connecticut, Hawaii, Massachusetts, 

Nevada, Rhode Island, and Vermont. Oil and gas 

storage potential was not assessed for Alaska, 

Washington, Nevada, and Oregon. Unmineable coal 

seams were not assessed for Nevada, Oregon, 

California, Idaho, and New York. We are assuming 

for purposes of our analysis here that they do not 

have storage potential in those formations. 

414 In this discussion, we use the term RTO to 

indicate both ISOs and RTOs. 

415 In that rulemaking, we stated that ‘‘most 

commenters encouraged the EPA not to 

automatically exclude any potential injection 

formations for GS at this stage of deployment.’’ We 

added that 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). 

that may not have geologic sequestration 

sites may be served by coal-fired 

electricity generation built in nearby 

areas with geologic sequestration, and 

this electricity can be delivered through 

transmission lines. This method, known 

as ‘‘coal-by-wire,’’ has long been used in 

the electricity sector because siting a 

coal-fired power plant near the coal 

mine and transmitting the generation 

long distances to the load area is 

generally less expensive than siting the 

plant near the load area and shipping 

the coal long distances. 

For example, we noted in the 

proposal that there are many examples 

where coal-fired power generated in one 

state is used to supply electricity in 

other states. In the proposal we 

specifically noted that 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 and Idaho Power, 

which serves customers in Idaho and 

Eastern Oregon, meets its demand in 

part from coal-fired power plants 

located in Wyoming and Nevada. 79 FR 

at 1478. 

In the Technical Support Document 

on Geographic Availability (Geographic 

Availability TSD), we explore in greater 

detail the issue of coal-by-wire and the 

ability of demand in areas without 

geologic sequestration to be served by 

coal generation located in areas that 

have access to geologic sequestration. 

Figure 1 of this preamble (a color 

version of which is provided as Figure 

1 of the Geographic Availability TSD) 

depicts areas of the country with: (1) 

existing CO2 pipeline; (2) probable, 

planned, or under study CO2 pipeline; 

(3) counties with active CO2-EOR 

operations; (4) oil and natural gas 

reservoirs; (5) deep saline formations; 

(6) unmineable coal seams; and (7) areas 

100 kilometers from geologic 

sequestration. As demonstrated by 

Figure 1, the vast majority of the 

country has existing or planned CO2

pipeline, active CO2-EOR operations, 

the necessary geology for CO2 storage, or 

is within 100 kilometers of areas with 

geologic sequestration.412 A review of 

Figure 1 indicates limited areas that do 

not fall into these categories. 

As an initial matter, we note that the 

data included in Figure 1 is a 

conservative outlook of potential areas 

available for the development of CO2

storage in that we include only areas 

that have been assessed to date. Portions 

of the United States—such as the State 

of Minnesota—have not yet been 

assessed and thus are depicted as not 

having geological formations suitable for 

CO2 storage, even though assessment 

could in fact reveal additional 

formations.413

As one considers the areas on the map 

depicted in Figure 1 that fall outside of 

the above enumerated categories, in 

many instances, we find areas with low 

population density, areas that are 

already served by transmission lines 

that could deliver coal-by-wire, and/or 

areas that have made policy or other 

decisions not to pursue a resource mix 

that includes coal. In many of these 

areas, utilities, electric cooperatives, 

and municipalities have a history of 

joint ownership of coal-fired generation 

outside the region or contracting with 

coal and other generation in outside 

areas to meet their demand. Some of the 

relevant areas are in RTOs 414 which 

engage in planning across the RTO, 

balancing supply and demand in real 

time throughout the RTO. Accordingly, 

generating resources in one part of the 

RTO such as a coal generator can serve 

load in other parts of the RTO, as well 

as load outside of the RTO. As we 

consider each of these geographic areas 

in the Geographic Availability TSD, we 

make key points as to why this final rule 

does not negatively impact the ability of 

these regions to access new coal 

generation to the extent that coal is 

needed to supply demand and/or those 

regions want to include new coal-fired 

generation in their resource mix. 

N. Final Requirements for Disposition of 

Captured CO2

This section discusses the different 

regulatory components, already in 

place, that assure the safety and 

effectiveness of GS. This section, by 

demonstrating that GS is already 

covered by an effective regulatory 

structure, complements the analysis of 

the technical feasibility of GS contained 

in Sec. V.M. Together, these sections 

affirm that the technical feasibility of GS 

is adequately demonstrated. 

In 2010, the EPA finalized an effective 

and coherent regulatory framework to 

ensure the long-term, secure and safe 

storage of large volumes of CO2. The 

EPA developed these Underground 

Injection Control (UIC) Class VI well 

regulations under authority of the Safe 

Drinking Water Act (SDWA) to facilitate 

injection of CO2 for GS, while protecting 

human health and the environment by 

ensuring the protection of underground 

sources of drinking water (USDWs). The 

Class VI regulations are built upon 35 

years of federal experience regulating 

underground injection wells, and many 

additional years of state UIC program 

expertise. The EPA and states have 

decades of UIC experience with the 

Class II program, which provides a 

regulatory framework for the protection 

of USDWs for CO2 injected for purposes 

of EOR. 

In addition, to complement both the 

Class VI and Class II rules, the EPA used 

CAA authority to develop air-side 

monitoring and reporting requirements 

for CO2 capture, underground injection, 

and geologic sequestration through the 

GHGRP. Information collected under the 

GHGRP provides a transparent means 

for the EPA and the public to continue 

to evaluate the effectiveness of GS. 

As explained below, these 

requirements help ensure that 

sequestered CO2 will remain in place, 

and, using SDWA and CAA authorities, 

provide the monitoring mechanisms to 

identify and address potential leakage. 

We note the near consensus in the 

public responses to the Class VI 

rulemaking that saline and oil and gas 

reservoirs provide ready means for 

secure GS of CO2.415

1. Requirements for UIC Class VI and 

Class II Wells 

Under SDWA, the EPA developed the 

UIC Program to regulate the 

underground injection of fluids in a 

manner that ensures protection of 

USDWs. UIC regulations establish six 

different well classes that manage a 

range of injectates (e.g., industrial and 

municipal wastes; fluids associated with 

oil and gas activities; solution mining 

fluids; and CO2 for geologic 

sequestration) and which accommodate 

varying geologic, hydrogeological, and 

other conditions. The standards apply to 

injection into any type of formation that 

meets the rule’s rigorous criteria, and so 

apply not only to injection into deep 

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416 40 CFR 144.3. 

417The Class VI rule rests on a robust technical 

and scientific foundation, reflecting scientific 

oversight and peer review. In developing these 

Class VI rules, the EPA engaged with the SAB, 

providing detailed information on key issues 

relating to geologic sequestration—including 

monitoring schemes; methods to predict and verify 

capacity, injectivity, and effectiveness of subsurface 

CO2 storage; and characterization and management 

of risks associated with plume migration and 

pressure increases in the subsurface. See: http://

yosemite.epa.gov/sab/sabproduct.nsf/0/

AD09B42B75D9E36D85257704004882CF?Open

Document. In addition, the EPA developed a peer 

reviewed Vulnerability Evaluation Framework, 

which served as a technical support document for 

both the Class VI and Subpart RR rules. See: http:// 

www.epa.gov/climatechange/Downloads/

ghgemissions/VEF-Technical_Document_

072408.pdf. In the section 111(b) rulemaking here, 

the SAB Work Group, in a letter endorsed by the 

full SAB Committee, found that ‘‘while the 

scientific and technical basis for carbon storage 

provisions is new and emerging science, the agency 

is using the best available science and has 

conducted peer review at a level required by agency 

guidance.’’ Memorandum of Jan. 7, 2014, from SAB 

Work Group Chair to Members of the Chartered 

SAB and SAB Liaisons, p. 3. The letter was 

subsequently endorsed by the full SAB. Work 

Group Letter of Jan. 24, 2014, as edited by the full 

Committee. 

418 75 FR 77240 and 75 FR 77247 (December 10, 

2010). 

419 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 (Docket entry: EPA–HQ– 

OAR–2013–0495–9666).) 

420 40 CFR 146.81(d). 

421 40 CFR 146.95. 

422 40 CFR 146.84(a). 

423 40 CFR 146.84(c)(1)(3) and 146.90(d)(1). 

424 40 CFR 146.81(d) and 146.84. 

425 40 CFR 146.84(b)(2)(iv). 

426 40 CFR 146.84(e)(1). 

427 40 CFR 146.86(b). 

428 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. 

429 40 CFR 146.88. 

430 40 CFR 146.90. 

431 40 CFR 146.90(j). 

saline formations, but also can apply to 

injection into unmineable coal seams 

and other formations. See 75 FR 77256 

(Dec. 10, 2010). 

The EPA’s UIC regulations define the 

term USDWs to include current and 

future sources of drinking water and 

aquifers that contain a sufficient 

quantity of ground water to supply a 

public water system, where formation 

fluids either are currently being used for 

human consumption or that contain less 

than 10,000 ppm total dissolved 

solids.416 UIC requirements have been 

in place for over three decades and have 

been used by the EPA and states to 

manage hundreds of thousands of 

injection wells nationwide. 

a. Class VI Requirements 

In 2010, the EPA established a new 

class of well, Class VI. Class VI wells are 

used to inject CO2 into the subsurface 

for the purpose of long-term 

sequestration. See 75 FR 77230 (Dec. 10, 

2010). This rule accounts for the unique 

nature of CO2 injection for large-scale 

GS. Specifically, the EPA addressed the 

unique characteristics of CO2 injection 

for GS including the large CO2 injection 

volumes anticipated at GS projects, 

relative buoyancy of CO2, its mobility 

within subsurface geologic formations, 

and its corrosivity in the presence of 

water. The UIC Class VI rule was 

developed to facilitate GS and ensure 

protection of USDWs from the particular 

risks that may be posed by large scale 

CO2 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.417

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 transmissive faults or 

fractures to ensure USDW 

protection.418 419 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.420 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.421

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.422 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 fluids into or 

between USDWs.423 424 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.425 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.426

Well construction must use materials 

that can withstand contact with CO2

over the operational and post-injection 

life of the project.427 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 large-scale GS including 

buoyancy, corrosivity, and high 

sustained pressures over long periods of 

operation.428 429

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.430 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.431 Robust monitoring of 

the CO2 stream, injection pressures, 

integrity of the injection well, ground 

water quality and geochemistry, and 

monitoring of the CO2 plume and 

position of the pressure front 

throughout injection will ensure 

protection of USDWs from 

endangerment, preserve water quality, 

and allow for timely detection of any 

leakage of CO2 or displaced formation 

fluids. 

Although subsurface monitoring is the 

primary and effective means of 

determining if there are any risks to a 

USDW, the Class VI rule also authorizes 

the UIC Program Director to require 

surface air and/or soil gas monitoring on 

a site-specific basis. 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 

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432 40 CFR 146.90(h)(1) and 75 FR at 77259 (Dec. 

10, 2010). 

433 40 CFR 146.94. 

434 40 CFR 146.85. 

435 40 CFR 146.93. 

436 40 CFR 146.92. 

437 40 CFR 146.93. 

438 40 CFR 146.93(b). 

439 40 CFR 146.93(c). 

440http://water.epa.gov/type/groundwater/uic/

class6/upload/epa816r13004.pdf. 

441http://water.epa.gov/type/groundwater/uic/

class6/upload/epa816r13005.pdf. 

442http://water.epa.gov/type/groundwater/uic/

class6/upload/epa816r13001.pdf. 

443http://water.epa.gov/type/groundwater/uic/

class6/upload/epa816r11017.pdf. 

444http://water.epa.gov/type/groundwater/uic/

class6/upload/epa816r11020.pdf. 

445http://water.epa.gov/type/groundwater/uic/

class6/upload/uicfinancialresponsibilityguidance

final072011v.pdf. 

446http://water.epa.gov/type/groundwater/uic/

class6/upload/epa816p13004.pdf. See also 40 CFR 

144.19 and ‘‘Key Principles in EPA’s Underground 

Injection Control Program Class VI Rule Related to 

Transition of Class II Enhanced Oil Recovery or Gas 

Recovery Wells to Class VI’’, April 23, 2015, 

Available at: http://water.epa.gov/type/ground

water/uic/class6/upload/class2eorclass6memo.pdf. 

447http://water.epa.gov/type/groundwater/uic/

class6/upload/epa816p13005.pdf. 

448http://water.epa.gov/type/groundwater/uic/

class6/upload/epa816p13001.pdf. 

449http://water.epa.gov/type/groundwater/uic/

class6/upload/epa816p13002.pdf. 

450http://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. 

451http://www.epa.gov/region5/water/uic/adm/. 

452After 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. 

453http://www.epa.gov/r5water/uic/futuregen/. 

454http://www.epa.gov/r5water/uic/futuregen/; 

http://www.epa.gov/region5/water/uic/adm/. 

455 40 CFR 144.6(b). 

an indicator of potential leakage and 

USDW endangerment.432

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 postinjection site care periods of the 

project.433

Financial responsibility 

demonstrations are required to ensure 

that funds will be available for all area 

of review corrective action, injection 

well plugging, post-injection site care, 

site closure, and emergency and 

remedial response.434

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.435 The 

injection well also must be plugged, and 

following a demonstration of nonendangerment of USDWs by the Class VI 

owner or operator, the site must be 

closed.436 437 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.438 Following successful 

closure, the facility property deed must 

record that the underlying land is used 

for GS.439

The EPA has completed technical 

guidance documents on Class VI well 

site characterization, area of review and 

corrective action, well testing and 

monitoring, project plan development, 

well construction, and financial 

responsibility.440 441 442 443 444 445 The 

EPA has also issued 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.446 447 448 449

To inform the development of the UIC 

Class VI rule, the EPA solicited 

stakeholder input and reviewed ongoing 

domestic and international GS research, 

demonstration, and deployment 

projects. The EPA also leveraged 

injection experience of the UIC Program, 

such as injection via Class II wells for 

EOR. A description of the work 

conducted by the EPA in support of the 

UIC Class VI rule can be found in the 

preamble for the final rule (see 75 FR 

77230 and 77237–240(December 10, 

2010)). 

The EPA has issued Class VI permits 

for six wells under two projects. In 

September 2014, a UIC Class VI 

injection well permit (to construct) was 

issued by the EPA to Archer Daniels 

Midland for an ethanol facility in 

Decatur, Illinois. The goal 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.450

Following the operational period, 

Archer Daniels Midland plans a postinjection site care period of ten years.451

In September 2014, the EPA also issued 

four Class VI injection well permits (to 

construct) to the FutureGen Industrial 

Alliance project in Jacksonville, Illinois, 

which proposed to capture CO2

emissions from a coal-fired power plant 

in Meredosia, Illinois and transport the 

CO2 by pipeline approximately 30 miles 

to the deep saline GS site.452 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.453

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.454

The permitting of these projects 

illustrates that permit applicants were 

able to address perceived challenges to 

issuance of Class VI permits. These 

permits demonstrate that these projects 

are capable of safely and securely 

sequestering large volumes of CO2— 

including from steam generating units— 

for long-term storage since the EPA 

would not otherwise have issued the 

permits. 

b. Class II Requirements 

As explained in Section M.3 above, 

CO2 has been injected into the 

subsurface via injection wells for EOR, 

boosting production efficiency by repressurizing 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.455 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 well construction and operational 

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456 40 CFR 98.420(a)(1). 

457 40 CFR 98.426. 

458 40 CFR 98.426(h). 

459 40 CFR 98.440. 

460 40 CFR 98.446. 

461 40 CFR 98.448. 

462 40 CFR 98.446(f)(9) and (10). 

463 40 CFR 98.446(f)(12). 

464See 75 FR at 77263 (Dec. 10, 2010). 

465 40 CFR 98.448(a)(1). 

466 40 CFR 98.448(a)(2). 

467 40 CFR 98.448(a)(3). 

468 40 CFR 98.448(a)(4). 

469 40 CFR 98.448(a)(5). 

470Technical 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. 

471See § 60.5555(f). 

conditions that could lead to loss of 

injectate and migration into USDWs. 

Section 1425 of SDWA allows states 

to demonstrate that their program is 

effective in preventing endangerment of 

USDWs. These programs must include 

permitting, inspection, monitoring, 

record-keeping, and reporting 

components. 

2. Relevant Requirements of the GHGRP 

The GHGRP requires reporting of 

facility-level GHG data and other 

relevant information from large sources 

and suppliers in the United States. The 

final rules under 40 CFR part 60 

specifically require that if an affected 

EGU captures CO2 to meet the 

applicable emissions limit, the EGU 

must report in accordance with 40 CFR 

part 98, subpart PP (Suppliers of Carbon 

Dioxide) and the captured CO2 must be 

injected at a facility or facilities that 

reports in accordance with 40 CFR part 

98, subpart RR (Geologic Sequestration 

of Carbon Dioxide). See § 60.5555(f). 

Taken together, these requirements 

ensure that the amount of captured and 

sequestered CO2 will be tracked as 

appropriate at project- and 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 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.456 CO2

suppliers are required to report the 

annual quantity of CO2 transferred 

offsite and its end use, including GS.457

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.458

As noted, this final rule also requires 

that any affected EGU unit that captures 

CO2 to meet the applicable emissions 

limit must transfer the captured CO2 to 

a facility that reports under GHGRP 

subpart RR. In order to provide clarity 

on this requirement, the EPA reworded 

the proposed language under 

§ 60.5555(f) to use the phrase ‘‘If your 

affected unit captures CO2’’ in place of 

the phrase ‘‘If your affected unit 

employs geologic sequestration’’. This 

revision is not a change from the EPA’s 

initial intent. 

Reporting under subpart RR is 

required for all facilities that have 

received a Class VI UIC permit for 

injection of CO2.459 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.460 461 462 463

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.464 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.465

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.466

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.467

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.468

A summary of considerations made to 

calculate site-specific variables for the 

mass balance equation. Site-specific 

variables may include calculating CO2

emissions from equipment leaks and 

vented emissions of CO2 from surface 

equipment, and considerations for 

calculating CO2 from produced 

fluids.469

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.470

Under this final rule, any well 

receiving CO2 captured from an affected 

EGU, be it a Class VI or Class II well, 

must report under subpart RR.471 As 

explained below in Section V.N.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 requirements. The monitoring 

required by GHGRP subpart RR is 

complementary to and builds on UIC 

monitoring and testing requirements. 75 

FR 77263. Although the regulations for 

Class VI and Class II injection wells are 

designed to ensure protection of USDWs 

from endangerment the practical effect 

of these complementary technical 

requirements, as explained below, is 

that they also prevent releases of CO2 to 

the atmosphere. 

The UIC and GHGRP programs are 

built upon an understanding of the 

mechanisms by which CO2 is retained 

in geologic formations, which are well 

understood and proven. 

Structural and stratigraphic trapping 

is a physical trapping mechanism that 

occurs when the CO2 reaches a 

stratigraphic zone with low 

permeability (i.e., geologic confining 

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472 40 CFR 146.82(a) and (c). 

473 40 CFR 146.94(b). 

474 79 FR at 353 (January 3, 2014) (Final 

Hazardous Waste Management System: Conditional 

Exclusion for Carbon Dioxide (CO2) Streams in 

Geologic Sequestration Activities under subtitle C 

of RCRA). See Section N.5.c below. 

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. 

Solubility trapping is a geochemical 

trapping mechanism where a portion of 

the CO2 from the pure fluid phase 

dissolves into native ground water and 

hydrocarbons. 

Mineral trapping is a geochemical 

trapping mechanism that occurs when 

chemical reactions between the 

dissolved CO2 and minerals in the 

formation lead to the precipitation of 

solid carbonate minerals. 

a. Class VI Wells 

As just discussed in Section V.N.1, 

the UIC Class VI rule provides a 

framework to ensure the safety of 

underground injection of CO2 such that 

USDWs are not endangered. As 

explained below, protection against 

releases to USDWs likewise assures 

against releases to ambient air. Through 

the injection well permit application 

process, the Class VI permit applicant 

(i.e., a prospective Class VI well owner 

or operator) must demonstrate that the 

injected CO2 will be trapped and 

retained in the geologic formation, and 

not migrate out of the injection zone or 

the approved project area (i.e., the area 

of review). To assure that CO2 is 

confined within the injection zone, 

major components to be considered and 

included in Class VI permits are site 

characterization, area of review 

delineation and corrective action, well 

construction and operation, testing and 

monitoring, financial responsibility, 

post-injection site care, well plugging, 

emergency and remedial response, and 

site closure as described in Section 

V.N.1. 

Site characterization provides the 

foundation for successful GS projects. It 

includes evaluation of the chemical and 

physical mechanisms that will occur in 

the subsurface to immobilize and 

securely store the CO2 within the 

injection zone over the long-term (see 

above). Site characterization requires a 

detailed assessment of the geologic, 

hydrogeologic, geochemical, and 

geomechanical properties of the 

proposed GS site to ensure that wells 

are sited in suitable locations.472 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 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.473 Once the anomalous 

operating conditions are verified, the 

cessation of injection, as required by 

UIC permits, will minimize any risk of 

release to air. 

Following cessation of injection, the 

operator must conduct comprehensive 

post-injection site care to show the 

position of the CO2 plume and the 

associated area of elevated pressure to 

demonstrate that neither poses an 

endangerment to USDWs—also having 

the practical effect of preventing 

releases of CO2 to the atmosphere. Postinjection site care includes appropriate 

monitoring and other needed actions 

(including corrective action). The 

default duration for the post-injection 

site care period is 50 years, with 

flexibility for demonstrating that an 

alternative period is appropriate if it 

ensures non-endangerment of USDWs. 

As the EPA has found, the UIC Class 

VI injection well requirements protect 

against releases from all exposure 

pathways. Specifically, the EPA stated 

that the Class VI rules ‘‘[are] specifically 

designed to ensure that the CO2 (and 

any incidental associated substances 

derived from the source materials and 

the capture process) will be isolated 

within the injection zone.’’ The EPA 

further stated that ‘‘[t]he 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. . .’’.474

GHGRP subpart RR complements 

these UIC Class VI requirements. 

Requirements under the UIC program 

are focused on demonstrating that 

USDWs are not endangered as a result 

of CO2 injection into the subsurface, 

while requirements under the GHGRP 

through subpart RR enable accounting 

for CO2 that is geologically sequestered. 

A methodology to account for potential 

leakage is developed as part of the 

subpart RR MRV plan (see Section 

V.N.2). The MRV plan submitted for 

subpart RR may describe (or provide by 

reference to the UIC permit) the relevant 

elements of the UIC permit (e.g. 

assessment of leakage pathways in the 

monitoring area) and how those 

elements satisfy the subpart RR 

requirements. The MRV plan required 

under subpart RR may rely upon the 

knowledge of the subsurface location of 

CO2 and site characteristics that are 

developed in the permit application 

process, and operational monitoring 

results for UIC Class VI permitted wells. 

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 postclosure 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 

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475See, e.g. Comments of Southern Company, p. 

41 (Docket entry: EPA–HQ–OAR–2013–0495– 

10095). 

476The EPA anticipates EOR projects may be 

early GS projects because these formations have 

been previously well characterized for hydrocarbon 

recovery, likely already have suitable infrastructure 

(e.g., wells, pipelines, etc.), and have an associated 

economic benefit of oil production. 

477 Greenhouse Gas Reporting Program, data 

reported as of August 18, 2014. 

478 Grude, S. M. Landr<a, and J. Dvorkinb, 2014, 

Pressure effects caused by CO2 injection in the 

Tuba ̊en Fm., the Sn<hvit 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 

(Docket entry: EPA–HQ–OAR–2013–0495–9666). In 

fact, injection resumed successfully, as described in 

the text above. 

provides back up assurance that 

sequestered CO2 has not been released 

to the atmosphere. 

b. Class II Wells 

The Class II rules likewise are 

designed to protect USDWs during EOR 

operation, including the injection of 

CO2 for EOR. For example, UIC Class II 

minimum federal requirements 

promulgated under SDWA address site 

characterization, area of review, well 

construction (e.g., casing and 

cementing), well operation (e.g., 

injection pressure), injectate sampling, 

mechanical integrity testing, plugging 

and abandonment, financial 

responsibility, and reporting. Class II 

wells must undergo periodic 

mechanical integrity testing which will 

detect well construction and operational 

conditions that could lead to loss of 

injectate and migration into USDWs. 

The establishment of maximum 

injection pressures, designed to ensure 

that the pressure in the injection zone 

during injection does not initiate new 

fractures or propagate existing fractures 

in the confining zone, prevents injection 

from causing the movement of fluids 

into an underground source of drinking 

water. The safeguards that protect 

USDWs also serve as an early warning 

mechanism for releases of CO2 to the 

atmosphere. 

CO2 injected via Class II wells 

becomes sequestered by the trapping 

mechanisms described above in this 

Section V.N.3. As with Class VI wells, 

for Class II wells that report under 

subpart RR, there is monitoring to 

evaluate whether CO2 used for EOR will 

remain safely in place both during and 

after the injection period. Subpart RR 

provides a CO2 accounting framework 

that will enable the EPA to assess both 

the project-level and national efficacy of 

geologic sequestration to determine 

whether additional requirements are 

necessary and, if so, inform the design 

of such regulations. 

c. Response to Comments 

Commenters maintained that GS was 

not demonstrated for CO2 captured from 

EGUs. In addition, commenters noted 

that the volumes of captured CO2 would 

be considerably larger than from 

existing GS sites, and could quadruple 

amounts injected into Class II EOR 

wells. In addition to volumes of CO2 to 

be injected, commenters opined on the 

possibility of sporadic CO2 supply due 

to the nature of EGU operation.475

The EPA does not agree. CO2 capture 

from EGUs is demonstrated as discussed 

in Sections V.D and V.E. As discussed 

below, the volumes of CO2 are 

comparable to the amounts that have 

been injected at large scale commercial 

operations. The EPA also disagrees that 

the volume of CO2 would quadruple 

amounts injected into Class II EOR wells 

because CO2 may be sequestered in deep 

saline formations, which have 

widespread geographic availability (see 

Section M.1). The BSER determination 

and regulatory impact analysis for this 

rule relies on GS in deep saline 

formations.476 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 2013.477 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 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 

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. 

Sn<hvit 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.478 In 2011, 

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479 ‘‘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 Docket entry: EPA–HQ– 

OAR–2013–0495–8925). 

480Comments of UARG, pp. 37–38 (Docket entry: 

EPA–HQ–OAR–2013–0495–9666). 

the injection well was modified and 

injection was initiated in a second 

interval (St< Formation) in the field to 

increase the storage capacity. 

Approximately 3 million metric tons of 

CO2 have been injected since 2008. 

Monitoring demonstrates that no 

leakage has occurred, again 

demonstrating that large volumes of 

CO2, of the same order of magnitude 

expected for an EGU, can be safely 

injected and stored in deep saline 

formations over an extended period. 

As discussed above in Sections 

V.E.2.a and M, CO2 from the Great 

Plains Synfuels plant in North Dakota 

has been injected into the Weyburn oil 

field in Saskatchewan Canada since 

2000. Over that time period the project 

has injected more than 16 million 

metric tons of CO2. It is anticipated that 

approximately 40 million metric tons of 

CO2 will be permanently sequestered 

over the lifespan of the project. 

Extensive monitoring by U.S. and 

international partners has demonstrated 

that no leakage has occurred. The 

sources of CO2 for EOR may vary (e.g., 

industrial processes, power generation); 

however, this does not impact the 

effectiveness of EOR operations (see 

Section V.M.3). 

CO2 used for EOR may come from 

anthropogenic or natural sources. The 

source of the CO2 does not impact the 

effectiveness of the EOR operation. CO2

capture, treatment and processing steps 

provide a concentrated stream of CO2 in 

order to meet the needs of the intended 

end use. CO2 pipeline specifications of 

the U.S. Department of Transportation 

Pipeline Hazardous Materials Safety 

Administration found at 49 CFR part 

195 (Transportation of Hazardous 

Liquids by Pipeline) apply regardless of 

the source of the CO2 and take into 

account CO2 composition, impurities, 

and phase behavior. Additionally, EOR 

operators and transport companies have 

specifications to ensure related to the 

composition of CO2. These requirements 

and specifications ensure EOR operators 

receive a known and consistent CO2

stream. 

At the In Salah CO2 storage project in 

Algeria, CO2 is removed from natural 

gas produced at three nearby gas fields 

in order to meet export quality 

specification. The CO2 is transported by 

pipeline approximately 3 miles to the 

injection site. Three horizontal wells are 

used to inject the CO2 into the down-dip 

aquifer leg of the gas reservoir 

approximately 6,200 feet deep. Between 

2004 and 2011 over 3.8 million metric 

tons of CO2 were stored. Injection rates 

in 2010 and 2011 were approximately 1 

million metric tons per year. Storage 

integrity has been monitored by several 

U.S. and international organizations and 

the monitoring program has employed a 

wide range of geophysical and 

geochemical methods, including time 

lapse seismic, microseismic, wellhead 

sampling, tracers, down-hole logging, 

core analysis, surface gas monitoring, 

groundwater aquifer monitoring and 

satellite data. The data have been used 

to support periodic risk assessments 

during the operational phase of the 

project. In 2010 new data from seismic, 

satellite and geomechanical models 

were used to inform the risk assessment 

and led to the decision to reduce CO2

injection pressures due to risk of 

vertical leakage into the lower caprock, 

and risk of loss of well integrity. The 

caprock at the site consisted of main 

caprock units, providing the primary 

seal, and lower caprock units, providing 

additional buffers. There was no leakage 

from the well or through the caprock, 

but the risk analysis identified an 

increased risk of leakage, therefore, the 

aforementioned precautions were taken. 

Additional analysis of the reservoir, 

seismic and geomechanical data led to 

the decision to suspend CO2 injection in 

June 2011. No leakage has occurred and 

the injected CO2 remains safely stored 

in the subsurface. The decision to 

proceed with safe shutdown of injection 

resulted from the analysis of seismic 

and geomechanical data to identify and 

respond to storage site risk. The In Salah 

project demonstrates the value of 

developing an integrated and 

comprehensive set of baseline site data 

prior to the start of injection, and the 

importance of regular review of 

monitoring data. Commenters also noted 

that the data collection and analysis had 

proven effective at preventing any 

release of sequestered CO2 to either 

underground drinking water sources or 

to the atmosphere.479

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 

Sn<hvit), 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 longterm, safe storage of CO2. Each project 

was designed to address the site-specific 

characteristics and operated to 

successfully inject CO2 for safe storage. 

4. Must the standard of performance for 

CO2 include CAA requirements on the 

sequestration site? 

One commenter maintained as a 

matter of law that a standard predicated 

on use of CCS is not a ‘‘system of 

emission reduction’’, and therefore is 

not a ‘‘standard of performance’’ within 

the meaning of section 111 (a)(1) of the 

Act. The commenter argued that the 

standard does not require sequestration 

of captured CO2 but only capture, so 

that no emission reductions are 

associated with the standard. A gloss on 

this argument is that there are no 

enforceable requirements for the 

captured CO2 (‘‘[t]he fate of that 

[captured] CO2 is something that the 

proposed standard does not proscribe 

with enforceable requirements’’). The 

commenter further argues that a ‘‘system 

of emission reduction’’ under section 

111 must be ‘‘designed into the new 

source itself’’ so that off-site 

underground sequestration of captured 

CO2 emissions ‘‘could never satisfy the 

statutory requirements governing a 

‘standard of performance’’’ (emphasis 

original).480

The EPA disagrees with both the legal 

and factual assertions in this comment. 

As to the legal point, the commenter 

fails to distinguish capture and 

sequestration of carbon from every other 

section 111 standard which is 

predicated on capture of a pollutant. 

Indeed, all emission standards not 

predicated on outright pollutant 

destruction involve capture of the 

pollutant and its subsequent disposition 

in the capturing medium. Thus, metals 

are captured in devices like baghouses 

or scrubbers, leaving a solid waste or 

wastewater to be managed. Gases can be 

captured with activated carbon or under 

pressure, again requiring further 

management of the captured 

pollutant(s). The EPA is required to 

consider these potential implications in 

promulgating an NSPS. See section 

111(a)(1) (in promulgating a standard of 

performance under section 111, the EPA 

must ‘‘tak[e] into account . . . any 

nonair quality health and environmental 

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481Comments of UARG, p. 63 (Docket entry: 

EPA–HQ–OAR–2013–0495–9666). 

482 ‘‘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/ground

water/uic/class6/upload/class2eorclass6memo.pdf. 

483 In this regard, the Class VI rules provide that, 

owners 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. 484See e.g., comments of UARG, p, 63 (Docket 

entry: EPA–HQ–OAR–2013–0495–9666); Southern 

Co., p. 37 (Docket entry: EPA–HQ–OAR–2013– 

0495–10095); American Petroleum Institute pp. 40– 

50 Docket entry: EPA–HQ–OAR–2013–0495– 

10098). 

485Subpart RR costs are presented in 2008 US 

dollars. 

impact’’). The EPA thus considers such 

issues as solid waste and wastewater 

generation as part of determining if a 

system of emission reduction is ‘‘best’’ 

and ‘‘adequately demonstrated’’ under 

section 111. See Section V.O below 

(discussion of this rule’s potential crossmedia impacts). 

The further comment that the 

standard is arbitrary because it fails to 

impose any requirements on the 

captured CO2 is misplaced. The 

commenter mischaracterizes the 

standard as requiring capture only. The 

BSER is not just capturing a certain 

amount of CO2, but sequestering it. 

Sequestration can occur either on-site or 

off-site. Sequestration sites receiving 

and injecting the captured CO2 are 

required to obtain UIC permits and 

report under subpart RR of the GHGRP. 

They must conduct comprehensive 

monitoring as part of these obligations. 

Although the NSPS does not impose 

regulatory requirements on the 

transportation pipeline or the 

sequestration site, such requirements 

already exist under other regulatory 

programs of the Department of 

Transportation and the EPA. In 

particular, the EPA is reasonably relying 

on the already-adopted, and very 

rigorous, Class VI well requirements in 

combination with the subpart RR 

requirements to provide secure 

sequestration of captured CO2. The EPA 

has also considered carefully the 

requirements and operating history of 

the Class II requirements for EOR wells, 

which, in combination with the subpart 

RR requirements, ensure protection of 

USDWs from endangerment, provide the 

monitoring mechanisms to identify and 

address potential leakage using SDWA 

and CAA authorities, and have the 

practical effect of preventing releases of 

CO2 to the atmosphere. This is 

analogous to the many section 111 

standards of performance for metals 

which result in a captured air pollution 

control residue to be disposed of 

pursuant to waste management 

requirements of the rules implementing 

the Resource Conservation and 

Recovery Act. It is also analogous to the 

many section 111 standards of 

performance for metals or organics 

captured in wet air pollution control 

systems resulting in wastewater 

discharged to a navigable water where 

pollutant loadings are controlled under 

rules implementing the Clean Water 

Act. Again, these are non-air 

environmental impacts for which the 

EPA must account in establishing a 

section 111(a) standard. The EPA has 

reasonably done so here based on the 

regulatory regimes of the Class VI and 

Class II UIC requirements in 

combination with the monitoring regime 

of the subpart RR reporting rules, as 

well as the CO2 pipeline standards of 

the Department of Transportation. 

In this regard, the EPA notes that at 

proposal it acknowledged the possibility 

‘‘that there can be downstream losses of 

CO2 after capture, for example during 

transportation, injection or storage.’’ 79 

FR at 1484. Given the rigorous 

substantive requirements and the 

monitoring required by the Class VI 

rules, the complementary monitoring 

regime of the subpart RR MRV plan and 

reporting rules, as well as the regulatory 

requirements for Class II wells, any such 

losses would be de minimis. Indeed, the 

same commenter maintained that the 

monitoring requirements of the Class VI 

rule are overly stringent and that a 50- 

year post-injection site care period is 

unnecessarily long.481 As it happens, as 

noted above, the Class VI rules allow for 

an alternative post-injection site care 

period based on a site-specific 

demonstration. See 40 CFR 146.93(b). 

The EPA addresses this comment in 

more detail in Chapter 2 of the 

Response-to-Comment Document. 

5. Other Perceived Obstacles to Geologic 

Sequestration 

a. Class II to Class VI transition 

A number of commenters maintained 

that the Class VI rules could effectively 

force all Class II wells to transition to 

Class VI wells if they inject 

anthropogenic CO2, and further 

maintained that, as a practical matter, 

this would render EOR unavailable for 

such CO2. The EPA disagrees with these 

comments. Injection of anthropogenic 

CO2 into Class II wells does not force 

transition of these wells to Class VI 

wells—not during the well’s active 

operation and not when EOR operations 

cease. We recognize the widespread use 

of EOR and the expectation that injected 

CO2 can remain underground. The EPA 

issued a memorandum to its regional 

offices on April 23, 2015 reflecting these 

principles: 482

Geologic storage of CO2 can continue 

to be permitted under the UIC Class II 

program. 

Use of anthropogenic CO2 in EOR 

operations does not necessitate a Class 

VI permit. 

Class VI site closure requirements are 

not required for Class II CO2 injection 

operations. 

EOR operations that are focused on oil 

or gas production will be managed 

under the Class II program. If oil or gas 

recovery is no longer a significant aspect 

of a Class II permitted EOR operation, 

the key factor in determining the 

potential need to transition an EOR 

operation from Class II to Class VI is 

increased risk to USDWs related to 

significant storage of CO2 in the 

reservoir, where the regulatory tools of 

the Class II program cannot successfully 

manage the risk.483

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.484

They noted that preparing a subpart RR 

MRV plan could cost upwards of 

$100,000 which would be cost 

prohibitive given other available sources 

of CO2. 

The EPA disagrees with this comment 

in several respects. First, the BSER 

determination and regulatory impact 

analysis for this rule relies on GS in 

deep saline formations, not on EOR. 

However, the EPA also recognizes the 

potential for sequestering CO2 via EOR, 

but disagrees that subpart RR 

requirements effectively preclude or 

substantially inhibit the use of EOR. 

The cost of compliance with subpart 

RR is not significant enough to offset the 

potential revenue for the EOR operator 

from the sale of produced oil for CCS 

projects that are reliant on EOR. First, 

the costs associated with subpart RR are 

relatively modest, especially in 

comparison with revenues from an EOR 

field. In the economic impact analysis 

for subpart RR, the EPA estimated that 

an EOR project with a Class II permit 

would incur a first year cost of up to 

$147,030 to develop an MRV plan, and 

an annual cost of $27,787 to maintain 

the plan; the EPA estimated annual 

reporting and recordkeeping costs at 

$13,262 per year.485 Monitoring costs 

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486 ‘‘Near Term Projections of CO2 Utilization for 

Enhanced Oil Recovery’’. DOE/NETL–2014/1648. 

April 2014. 

487http://www.irs.gov/irb/2009-44_IRB/ar11.html. 

The section 45Q tax credit for calendar year 2015 

is $10.92 per metric ton of qualified CO2 that is 

captured and used in a qualified EOR project and 

$21.85 per metric ton of qualified CO2 that is 

captured and used in a qualified non-EOR GS 

project. http://www.irs.gov/irb/2015-26_IRB/ 

ar14.html. 

488No hazardous waste listings apply to CO2

streams. Therefore, a CO2 stream could be identified 

(i.e. defined) as a hazardous waste only if it exhibits 

one or more of the hazardous characteristics. 79 FR 

355 (Jan 3. 2014). 489 79 FR 350 (Jan. 3, 2014). 490The 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 an 

impediment to use of anthropogenic CO2 for EOR. 

491See e.g. Comments of Duke Energy, p. 28 

Docket entry: EPA–HQ–OAR–2013–0495–9426); 

UARG, p. 62 (Docket entry: EPA–HQ–OAR–2013– 

0495–9666); AEP, p. 91 (Docket entry: EPA–HQ– 

OAR–2013–0495–10618). 

492See e.g. Comments of UARG, pp. 26 (Docket 

entry: EPA–HQ–OAR–2013–0495–9666), 62; EEI, p. 

92 Docket entry: EPA–HQ–OAR–2013–0495–9780); 

Duke Energy, pp. 27, 28 Docket entry: EPA–HQ– 

OAR–2013–0495–9426). 

493 Intergovernmental Panel on Climate Change. 

(2005). Special Report on Carbon Dioxide Capture 

and Storage. 

494http://www.epa.gov/climatechange/ 

Downloads/ccs/CCS-Task-Force-Report-2010.pdf. 

495AEP Comments at pp. 93, 96 (Docket entry: 

EPA–HQ–OAR–2013–0495–10618). 

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 

CO2.486 Thus, the argument that EOR 

operators will obtain CO2 from other 

sources without triggering subpart RR 

responsibilities, which assumes 

adequate supplies of CO2 from other 

sources, lacks foundation. In addition, 

the Internal Revenue Code section 45Q 

provides a tax credit for CO2

sequestration which is far greater than 

subpart RR costs.487 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 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.488 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.489 In that 

rulemaking, the EPA determined that if 

any such CO2 streams would be 

hazardous wastes, further RCRA 

regulation is unnecessary to protect 

human health and the environment 

provided certain conditions are met. 

Specifically, the rule conditionally 

excludes from Subtitle C regulations 

CO2 streams if they are (1) transported 

in compliance with U.S. Department of 

Transportation or state requirements; (2) 

injected in compliance with UIC Class 

VI requirements (summarized above); 

(3) no other hazardous wastes are mixed 

with or co-injected with the CO2 stream; 

and (4) generators (e.g., emission 

sources) and Class VI well owners or 

operators sign certification statements. 

See 40 CFR 261.4(h)).490 The D.C. 

Circuit recently dismissed all challenges 

to this rule in Carbon Sequestration 

Council and Southern Company 

Services v. EPA, No. 787 F. 3d 1129 

(D.C. Cir. 2015). 

d. Other perceived uncertainties 

Other commenters claimed that 

various legal uncertainties preclude a 

finding that geologic sequestration of 

CO2 from EGUs can be considered to be 

adequately demonstrated. Many of the 

issues referred to in comments relate to 

property rights: issues of ownership of 

pore space, relationship of sequestration 

to ownership of mineral rights, issues of 

dealing with multiple landowners, lack 

of state law frameworks, or competing, 

inconsistent state laws.491 Other 

commenters noted the lack of long-term 

liability insurance, and noted 

uncertainties regarding long-term 

liability generally.492

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.493 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.494 As noted earlier, both 

the Archer Daniels Midland (ADM) and 

FutureGen projects addressed siting and 

operational aspects of GS (including 

issues relating to volumes of the CO2

and the nature of the CO2 injectate) in 

their permit applications. The fact that 

these applicants pursued permits 

indicates that they regarded any 

potential property rights issues as 

resolvable. 

Commenter American Electric Power 

(AEP) referred to its own experience 

with the Mountaineer demonstration 

project. AEP noted that although this 

project was not full scale, finding a 

suitable repository, notwithstanding a 

generally favorable geologic area, 

proved difficult. The company referred 

to years spent in site characterization 

and digging multiple wells.495 Other 

commenters noted more generally that 

site characterization issues can be timeconsuming and difficult, and quoted 

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496See e.g. Comments of UARG, p. 55 (Docket 

entry: EPA–HQ–OAR–2013–0495–9666), citing to 

Cichanowitz CCS Report (2012). 497See AEP FEED Study at pp. 36–43. The 

company likewise explained the monitoring regime 

it would utilize to verify containment, and the well 

construction it would utilize to guarantee secure 

sequestration. Id. at pp. 44–54. Available at: 

www.globalccsinstitute.com/publications/aepmountaineer-ii-project-front-end-engineering-anddesign-feed-report. 

498The 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/. 

499See comments of UARG at p. 84 (Docket entry: 

EPA–HQ–OAR–2013–0495–9666) referencing Haibo 

Zhai, et al., Water Use at Pulverized Coal Power 

Plants with Post-combustion Carbon Capture and 

Storage, 45 Environ. Sci. Technol., 2479–85 (2011). 

500 Id at p. 84 referencing DOE/NETL–402/ 

080108, ‘‘Water Requirements for Existing and 

Emerging Thermoelectric Plant Technologies’’ at 13 

(Aug. 2008, Apr. 2009 revision). 

studies suggesting that it could take 5 

years to obtain a Class VI permit.496

The EPA agrees that robust site 

characterization and selection is 

important to ensuring capacity needs 

are met and that the sequestered CO2 is 

safely stored. Efforts to characterize 

geologic formations suitable for GS have 

been underway at DOE through the 

RCSPs since 2003 (see Section V.M). 

Additionally, since 2007, the USGS has 

been assessing U.S. geologic storage 

resources for CO2. As noted earlier, 

DOE, in partnership with researchers, 

universities, and organizations across 

the country, is demonstrating that GS 

can be achieved safely, permanently, 

and economically at large scales, and 

projects supported by the department 

have safely and permanently stored 10 

million metric tons of CO2. 

In the time since the commenter 

submitted comments several Class VI 

permits have been issued by the EPA. 

These projects demonstrate that a GS 

site permit applicant could potentially 

prepare and obtain a UIC permit 

concurrent with permits required for an 

EGU. With respect to AEP’s experience 

with the Mountaineer demonstration 

project, notwithstanding difficulties, the 

company was able to successfully dig 

wells, and safely inject captured CO2. 

Moreover, the company indicated it 

fully expected to be able to do so at full 

scale and explained how.497 The EPA 

notes further that a monitoring program 

and its associated infrastructure (e.g., 

monitoring wells) and costs will be 

dependent on site-specific 

characteristics, such as CO2 injection 

rate and volume, geology, the presence 

of artificial penetrations, among other 

factors. It is thus not appropriate to 

generalize from AEP’s experience, and 

assume that other sites will require the 

same number of wells for site 

characterization or injection. In this 

regard, we note that the ADM and 

FutureGen construction permits for 

Class VI wells involved far fewer 

injection wells than AEP references.498

See also discussion of this issue in 

Section V.I.5 above. 

O. Non-air Quality Impacts and Energy 

Requirements 

As part of the determination that 

SCPC with partial CCS is the best 

system of emission reduction 

adequately demonstrated, the EPA has 

given careful consideration to non-air 

quality health and environmental 

impacts and energy requirements, as 

required by CAA section 111 (a). We 

have also considered those factors for 

alternative potential compliance paths 

to assure that the standard does not 

have unintended adverse health, 

environmental or energy-related 

consequences. The EPA finds that 

neither the BSER, nor the possible 

alternative compliance pathways, would 

have adverse consequences from either 

a non-air quality impact or energy 

requirement perspective. 

1. Transport and Sequestration of 

Captured CO2

As just discussed in detail, the EPA 

finds that the Class VI and II rules, as 

complemented by the subpart RR 

GHGRP reporting and monitoring 

requirements, amply safeguard against 

potential of injected CO2 to degrade 

underground sources of drinking water 

and amply protect against any releases 

of sequestered CO2 to the atmosphere. 

The EPA likewise finds that the plenary 

regulatory controls on CO2 pipelines 

assure that CO2 can be safely conveyed 

without environmental release, and that 

these rules, plus the complementary 

tracking and reporting rules in subpart 

RR, assure that captured CO2 will be 

properly tracked and conveyed to a 

sequestration site. 

2. Water Use Impacts 

Commenters claimed that the EPA 

ignored the negative environmental 

impacts of the use of CCS for the 

mitigation of CO2 emissions from fossil 

fuel-fired steam generating EGUs. In 

particular, commenters noted that the 

use of CCS will increase the water usage 

at units that implement CCS to meet the 

proposed standard of performance. At 

least one commenter claimed that 

addition of an amine-based CCS system 

would double the consumptive water 

use of a power plant, which would be 

unacceptable, especially in droughtridden states and in the arid west and 

referenced a study in the scientific 

literature as support.499 The commenter 

also references a DOE/NETL report that 

likewise notes significant increases in 

the amount of cooling and process water 

required with the use of carbon capture 

technology.500 However, those studies 

discuss increased water use for cases 

where full CCS (90 percent or greater 

capture) is implemented. As we 

discussed in both the proposal and in 

this preamble, the EPA does not find 

that highly efficient new generation 

technology implementing full CCS is the 

BSER for new steam generating EGUs. 

The EPA examined water use 

predicted from the updated DOE/NETL 

studies in order to determine the 

magnitude of increased water usage for 

a new SCPC implementing partial CCS 

to meet the final standard of 1,400 lb 

CO2/MWh-g. The predicted water 

consumption for varying levels of 

partial and full CCS are provided in 

Table 13. The results show that a new 

SCPC unit that implements 16 percent 

partial CCS to meet the final standard 

would see an increase in water 

consumption (the difference between 

the predicted water withdraw and 

discharge) of about 6.4 percent 

compared to an SCPC with no CCS and 

the same net power output. By 

comparison, a unit implementing 35 

percent CCS to meet the proposed 

emission limitation of 1,100 lb CO2/ 

MWh-g would see an increase in water 

consumption of 16.0 percent and a new 

unit implementing full (90 percent) CCS 

would see an increase of almost 50 

percent. 

TABLE 13—PREDICTED WATER CONSUMPTION WITH IMPLEMENTATION OF VARIOUS LEVELS OF PARTIAL CCS 501

Technology 

Raw water 

consumption, 

gpm 

Increase 

compared to 

SCPC, % 

SCPC ....................................................................................................................................................................... 4,095 — 

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501Exhibits A–1 and A–2 at p. 16–17 from ‘‘Cost 

and Performance Baseline for Fossil Energy Plants 

Supplement: Sensitivity to CO2 Capture Rate in 

Coal-Fired Power Plants’’, DOE/NETL–2015/1720 

(June 22, 2015). 

502The EPA also finds that the standards would 

not result in any significant impact on solid waste 

generation or management. See Section XIII.D 

below. 503Exhibits A–1 and A–2 at p. 16–17 from ‘‘Cost 

and Performance Baseline for Fossil Energy Plants 

Supplement: Sensitivity to CO2 Capture Rate in 

Coal-Fired Power Plants’’, DOE/NETL–2015/1720 

(June 2015). 

504Note that this auxiliary power demand is not 

necessarily met from power or steam generated 

from the EGU. External sources can also be utilized 

for this purpose. 

TABLE 13—PREDICTED WATER CONSUMPTION WITH IMPLEMENTATION OF VARIOUS LEVELS OF PARTIAL CCS 501— 

Continued 

Technology 

Raw water 

consumption, 

gpm 

Increase 

compared to 

SCPC, % 

SCPC + 16% CCS .................................................................................................................................................. 4,359 6.4 

SCPC + 35% CCS .................................................................................................................................................. 4,751 16.0 

SCPC + 90% CCS .................................................................................................................................................. 6,069 48.2 

IGCC* ....................................................................................................................................................................... 3,334 ¥18.6 

IGCC + 90% CCS* .................................................................................................................................................. 4,815 17.6 

* The IGCC results presented in the DOE/NETL report are for an IGCC with net output of 622 MWe and an IGCC with full CCS with net output 

of 543 MWe. The water consumption for each was normalized to 550 MWe to be consistent with the SPCP cases. 

Similar to other air pollution 

controls—such as a wet flue gas 

desulfurization scrubber—utilization of 

post-combustion amine-based capture 

systems results in increased 

consumption of water. However, by 

finalizing a standard that is less 

stringent than the proposed limitation 

and by rejecting full CCS as the BSER, 

the EPA has reduced the increased 

amount of water needed as compared to 

a similar unit without CCS. Further, the 

EPA notes that there are additional 

opportunities to minimize the water 

usage at such a facility. For example, the 

SaskPower Boundary Dam Unit #3 postcombustion capture project captures 

water from the coal and from the 

combustion process and recycles the 

captured water in the process, resulting 

in decreased need for withdrawal of 

fresh water. 

The EPA also examined the predicted 

water usage for a new IGCC and for a 

new IGCC implementing 90 percent 

CCS. The predicted water consumption 

for the new IGCC unit is nearly 20 

percent less than that predicted for the 

new SCPC unit without CCS (and 

almost 25 percent less than the SCPC 

unit meeting the final standard). The 

EPA rejected new IGCC implementing 

full CCS as BSER because the predicted 

costs were significantly more than 

alternative technologies. The EPA also 

does not find that a new IGCC EGU is 

part of the final BSER (for reasons 

discussed in Section V.P). However, the 

EPA does note that IGCC is a viable 

alternative compliance option and, as 

shown here, would result in less water 

consumption than a compliant SCPC 

EGU. The EPA also notes that predicted 

water consumption at a new NGCC unit 

would be less than half that for a new 

SCPC EGU with the same net output.502

3. Energy Requirements 

The EPA also examined the expected 

impacts on energy requirements for a 

new unit meeting the final promulgated 

standard and finds impacts to be 

minimal. Specifically, the EPA 

examined the increased auxiliary load 

or parasitic energy requirements of a 

system implementing CCS. The EPA 

examined the predicted auxiliary power 

demand from the updated DOE/NETL 

studies in order to determine the 

increased energy requirement for a new 

SCPC implementing partial CCS to meet 

the final standard of 1,400 lb CO2/MWhg. The predicted gross power output, the 

auxiliary power demand, and the 

parasitic power demand (percent of 

gross output) are provided in Table 14 

for varying levels of partial and full 

CCS. 

TABLE 14—PREDICTED PARASITIC POWER DEMAND WITH IMPLEMENTATION OF VARIOUS LEVELS OF PARTIAL CCS 503

Generation technology Gross power 

output, MWe 

Auxiliary 

power, MWe 

Parasitic 

demand (%) 

SCPC .................................................................................................................................... 580 30 5.2 

SCPC + 16% CCS ............................................................................................................... 599 38 6.3 

SCPC + 35% CCS ....................................................................................................................... 603 53 8.8 

SCPC + 90% CCS ............................................................................................................... 642 91 14.2 

IGCC ..................................................................................................................................... 748 126 16.8 

IGCC + 90% CCS ................................................................................................................ 734 191 26.0 

CCS ............................................................................................................................................. 734 191 26.0 

The auxiliary power demand is the 

amount of the gross power output that 

is utilized within the facility rather than 

used to produce electricity for sale to 

the grid. The parasitic power demand 

(or parasitic load) is the percentage of 

the gross power output that is needed to 

meet the auxiliary power demand.504 In 

an SCPC EGU without CCS, the 

auxiliary power is used to primarily to 

operate fans, motors, pumps, etc. 

associated with operation of the facility 

and the associated pollution control 

equipment. When carbon capture 

equipment is incorporated, additional 

power is needed to operate associated 

equipment, and steam is need to 

regenerate the capture solvents (i.e., the 

solvents are heated to release the 

captured CO2). 

The results in Table 14 show that a 

new SCPC unit without CCS can expect 

a parasitic power demand of about 5.2 

percent. A new SCPC unit meeting the 

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505 ‘‘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). 

506The EPA also finds that the standards would 

not result in any significant impact on solid waste 

generation or management. See Section XII.D 

below. 

507Subcritical 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. 

508Exhibit 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). 

509 ‘‘Cost and Performance Baseline for Fossil 

Energy Plants Supplement: Sensitivity to CO2

Capture Rate in Coal-Fired Power Plants’’, DOE/ 

NETL–2015/1720 (June 2015); SCPC rates come 

from Exhibit A–2 and IGCC rates come from Exhibit 

A–4. 

510The comparable emissions on a net basis are: 

subcritical PC—1,890 lb CO2/MWh-n; SCPC–1,705 

lb CO2/MWh-n; and IGCC—1,724 lb CO2/MWh-n. 

(See same references as for gross emissions 

provided in the text). 

511Exhibit 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). 

512Ultra-supercritical (U.S.C.) and advanced 

ultra-supercritical (A–U.S.C.) are terms often used 

to designate a coal-fired power plant design with 

steam conditions well above the critical point. 

final standard of performance by 

implementing 16 percent partial CCS 

will see a parasitic power demand of 

about 6.3 percent, which is not a 

significant increase in energy 

requirement. Of course, new SCPC 

EGUs that implement higher levels of 

CCS will expect higher amounts of 

parasitic power demand. As shown in 

Table 14, a new SCPC EGU 

implementing full CCS would expect to 

utilize over 14 percent of its gross power 

output to operate the facility and the 

carbon capture system. But, the EPA 

does not find that a new SCPC 

implementing full CCS is the BSER for 

new fossil-fired steam generating units. 

See Section V.P.2 below. 

The EPA also notes that there is ongoing research sponsored by DOE/NETL 

and others to further reduce the energy 

requirements of the carbon capture 

systems. Progress is being made. As was 

mentioned previously, the heat duty 

(the energy required to regenerate the 

capture solvent) for the amine scrubbing 

process used at the Searles Valley 

facility in the mid-70’s was about 12 MJ/ 

mt CO2 removed as compared to a heat 

duty of about 2.5 MJ/mt CO2 removed 

for the amine processes used at 

Boundary Dam and for the amine 

system that will be used at the WA 

Parish facility.505

The EPA also examined the predicted 

parasitic power demand for a new IGCC 

and for a new IGCC implementing 90 

percent CCS. As we have noted 

elsewhere, the auxiliary power demand 

for a new IGCC unit is more than that 

for that of a new SCPC. As one can see 

in Table 14, a new IGCC unit can expect 

to see a nearly 17 percent parasitic 

power demand; and a new IGCC unit 

implementing full CCS would expect a 

parasitic power demand of nearly 30 

percent. Of course, the EPA rejected 

new IGCC implementing full CCS as 

BSER because of the potentially 

unreasonable costs. The EPA also does 

not find that a new IGCC EGU is part of 

the final BSER (for reasons discussed 

elsewhere in Section V.P.1 below). 

However, as we have noted, the EPA 

does find IGCC to be a viable alternative 

compliance option. Utilities and project 

developers should consider the 

increased auxiliary power demand for 

an IGCC when considering their options 

for new power generation. The EPA also 

notes that the predicted parasitic load 

for a new NGCC unit would be about 2 

percent—less than half that for a new 

SCPC EGU with the same net output.506

With respect to potential nationwide 

impacts on energy requirements, as 

described above in Section V.H.3 and 

more extensively in the RIA chapter 4, 

the EPA reasonably projects that no new 

non-compliant fossil-fuel fired steam 

electric capacity will be constructed 

through 2022 (the end of the 8 year 

review cycle for NSPS). It is possible, as 

described earlier, that some new sources 

could be built to preserve fuel diversity, 

but even so, the number of such sources 

would be small and therefore would not 

significantly impact national energy 

requirements (assuming that such 

sources would not already be reflected 

in the baseline conditions just noted). 

P. Options That Were Considered by the 

EPA but Were Ultimately Not 

Determined To Be the BSER 

In light of the comments received, the 

EPA re-examined several alternative 

systems of emission reduction and 

reaffirms in this rulemaking our 

proposed determination that those 

alternatives do not represent the ‘‘best’’ 

system of emission reduction when 

compared against the other available 

emission reduction options. These are 

described below. See also Section IV.B.1 

above. 

1. Highly Efficient Generation 

Technology (e.g., Supercritical or Ultrasupercritical Boilers) 

In the January 2014 proposal, we 

considered whether ‘Highly Efficient 

New Generation without CCS 

Technology’ should constitute the BSER 

for new steam generating units. 79 FR at 

1468–69. The discussion focused on the 

performance of highly efficient 

generation technology (that does not 

include any implementation of CCS), 

such as a supercritical 507 pulverized 

coal (SCPC) or a supercritical CFB 

boiler, or a modern, well-performing 

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 

estimates, a newly constructed 

subcritical PC unit firing bituminous 

coal would emit approximately 1,800 lb 

CO2/MWh-g,508 a new highly efficient 

SCPC unit using bituminous coal would 

emit nearly 1,720 lb CO2/MWh-g, and a 

new IGCC unit would emit about 1,430 

lb CO2/MWh-g.509 510 Emissions from 

comparable sources utilizing subbituminous coal or lignite will have 

somewhat higher CO2 emissions.511

Some commenters noted that new 

coal-fired plants utilizing supercritical 

boiler design or IGCC would provide 

substantial emission reductions 

compared to the emissions from the 

existing subcritical coal plants that are 

currently in wide use in the power 

sector. However, most of the recent new 

power sector projects using solid fossil 

fuel (coal or petroleum coke) as the 

primary fuel—both those that have been 

constructed and those that have been 

proposed—are supercritical boilers and 

IGCC units. About 60 percent of new 

coal-fired utility boiler capacity that has 

come on-line since 2005 was 

supercritical and of the new capacity 

that came on-line since 2010, about 70 

percent was supercritical. No new coalfired utility boilers began operation in 

either 2013 or 2014. Coal-fired power 

plants that have come on-line most 

recently include AEP’s John W. Turk, Jr. 

Power Plant, which is a 600 MW ultrasupercritical 512 PC (USCPC) facility 

located in the southwest corner of 

Arkansas, and Duke Energy’s 

Edwardsport plant, which is a 618 MW 

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513A ‘‘CCS ready’’ facility is one that is designed 

such that the CCS equipment can be more easily 

added at a later time. 

514Available in the rulemaking docket (entry: 

EPA–HQ–OAR–2013–0495–0024). 515Sierra Club, 657 F.2d at 327 & n. 83. 

516 IPCC, Working Group III, Climate Change 

2014: Mitigation of Climate Change, http:// 

mitigation2014.org/report/publication/. 

517CCS LESSONS LEARNED REPORT American 

Electric Power Mountaineer CCS II Project Phase 1, 

Prepared for The Global CCS Institute Project # PRO 

004, January 23, 2012, page 2. See also AEP FEED 

Study at pp. 4, 63 (same). Available at: http:// 

www.globalccsinstitute.com/publications/aepmountaineer-ii-project-front-end-engineering-anddesign-feed-report. 

‘‘CCS ready’’ 513 IGCC unit located in 

Knox County, Indiana. Both of those 

facilities came on-line in 2012. It is 

likely that the units that initiated 

operation in 2010 or later were 

conceived of, planned, designed, and 

permitted well before 2010—likely in 

the early 2000s. Thus, it seems clear that 

the power sector had already, at that 

point, transitioned to the selection of 

supercritical boiler technology as 

‘‘business as usual’’ for new coal-fired 

power plants. Since that time, there 

have been other coal-fired power plants 

that have been proposed and almost all 

of them have been either supercritical 

boiler designs or IGCC units. In Table 1 

of the Technical Support Document 

Fossil Fuel-Fired Boiler and IGCC EGU 

Projects Under Development: Status and 

Approach 514 for the January 2014 

proposal, the EPA listed the 

development status of ‘‘potential 

transitional sources’’ (i.e., projects that 

had been proposed and had received 

Prevention of Significant Deterioration 

(PSD) preconstruction permits as of 

April 13, 2012). Of the 16 proposed EGU 

projects in Table 1—most of which have 

been cancelled or converted to or 

replaced with NGCC projects—the 

majority (nine) are either supercritical 

PC or IGCC designs. Five of the 

proposed projects were CFB designs 

with only one being a subcritical PC 

design. 

The EPA is aware of only one new 

coal-fired power plant that is actively in 

the construction phase. That plant is 

Mississippi Power’s Kemper County 

Energy Facility in Kemper County, 

MS—an IGCC unit that plans to begin 

operations in 2016 and will implement 

partial CCS to capture approximately 65 

percent of the available CO2, which will 

be sold for use in EOR operations. 

Considering the direction that the 

power sector has been taking and the 

changes that it is undergoing, 

identifying a new supercritical unit as 

the BSER and requiring an emission 

limitation based on the performance of 

such units thus would provide few, if 

any, additional CO2 emission reductions 

beyond the sector’s ‘‘business as usual’’. 

As noted, for the most part, new sources 

are already designed to achieve at least 

that emission limitation. This criterion 

does not itself eliminate supercritical 

technology from consideration as BSER. 

However, existing technologies must be 

considered in the context of the range of 

technically feasible technologies and, as 

we discuss elsewhere in this final 

preamble, partial CCS can achieve 

emission limitations beyond business as 

usual and do so at a reasonable cost. 

The EPA also considered IGCC 

technology and whether it represents 

the BSER for new power plants utilizing 

coal or other solid fossil fuels. IGCC 

units, on a gross-output basis, have 

inherently lower CO2 emission rates 

when compared to similarly-sized 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 grossoutput-based emission limitation 

consistent with the expected 

performance of a new IGCC unit would 

still require some additional control, 

such as partial CCS, on a new 

supercritical boiler. 

As is shown in Section V.J and H, 

additional emission reductions beyond 

those that would result from an 

emission standard based on a new SCPC 

boiler or even a new IGCC unit as the 

BSER can be achieved at a reasonable 

cost. Because practicable emission 

controls are available that are of 

reasonable cost at the source level and 

that will have little cost and energy 

impact at the national level, the EPA is 

according significant weight to the 

factor of amount of emissions 

reductions in determining the BSER. As 

discussed above, the D.C. Circuit has 

emphasized this factor in describing the 

purpose of CAA section 111 as to 

achieve ‘‘as much [emission reduction] 

as practicable.’’ 515

b. Lack of Incentive for Technological 

Innovation 

As discussed above, the EPA is 

justifying its identification of the BSER 

based on its weighing of the factors 

explicitly identified in CAA section 

111(a)(1), including the amount of the 

emission reduction. Under the D.C. 

Circuit case law, encouraging the 

development and implementation of 

advanced control technology must also 

be considered (and, in any case, may 

reasonably be considered; see Section 

V.H.3.d above). Consideration of this 

factor confirms the EPA’s decision not 

to identify highly efficient generation 

technology (without CCS) as the BSER. 

At present, CCS technologies are the 

most promising options to achieve 

significant reductions in CO2 emissions 

from newly constructed fossil fuel-fired 

steam generating units. CCS technology 

is also now a viable retrofit option for 

some modified, reconstructed and 

existing sources—depending upon the 

configuration, location and age of those 

sources. As CCS technologies are 

deployed and used more there is an 

expectation that, based on previous 

experience with advanced technologies, 

the performance will improve and the 

implementation costs will decline. The 

improved performance and lower costs 

will provide additional incentive for 

further implementation in the future. 

The Intergovernmental Panel on 

Climate Change (IPCC) recently released 

its Fifth Assessment report, 516 which 

recognizes that widespread deployment 

of CCS is crucial to reach the long term 

climate goals. The authors of the report 

used models to predict the likelihood of 

stabilizing the atmospheric 

concentration of CO2 at 450 ppm by 

2050 with or without carbon capture 

and storage (CCS). They found that 

several of the models were not able to 

reach this goal without CCS, which 

underlines the importance of deploying 

and further developing CCS on a large 

scale. 

American Electric Power (AEP), in an 

evaluation of lessons learned from the 

Phase 1 of its Mountaineer CCS project, 

wrote: ‘‘AEP still believes the 

advancement of CCS is critical for the 

sustainability of coal-fired 

generation.’’ 517

Some commenters felt that the 

proposed standard of performance for 

new steam generating units, based on 

implementation of partial CCS at an 

emission rate of 1,100 lb/MWh-g, would 

not serve to promote the increased 

deployment and implementation of 

CCS. The commenters argued that such 

a standard could instead have the 

unintended result of discouraging the 

further development of advanced coal 

generating technologies such as ultrasupercritical boilers and improved IGCC 

designs. 

Commenters further argued that such 

a standard will stifle further 

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518http://www.aep.com/newsroom/newsreleases/

?id=1704. 

development of CCS technologies. 

Commenters felt that the standard 

would effectively deter the construction 

of new coal-fired generation—and, if 

there is no new coal-fired generation, 

then there will be no implementation of 

CCS technology and, therefore, no need 

for continued research and development 

of CCS technologies. They argued, in 

fact, that the best way to promote the 

development of CCS was to set a 

standard that did not rely on it. 

The EPA does not agree with these 

arguments and, in particular, does not 

see how a standard that is not 

predicated on performance of an 

advanced control technology would 

serve to promote development and 

deployment of that advanced control 

technology. On the contrary, the history 

of regulatory actions has shown that 

emission standards that are based on 

performance of advanced control 

equipment lead to increased use of that 

control equipment, and that the absence 

of a requirement stifles technology 

development. 

There is a dramatic instance of this 

paradigm presented in the present 

record. In 2011, AEP deferred 

construction of a large-scale CCS retrofit 

demonstration project on one of its coalfired power plants because the state’s 

utility regulators would not approve 

cost recovery for CCS investments 

without a regulatory requirement to 

reduce CO2 emissions. AEP’s chairman 

was explicit on this point, stating in a 

July 17, 2011 press release announcing 

the deferral: 

We are placing the project on hold 

until economic and policy conditions 

create a viable path forward . . . We are 

clearly in a classic ‘which comes first?’ 

situation. The commercialization of this 

technology is vital if owners of coalfueled generation are to comply with 

potential future climate regulations 

without prematurely retiring efficient, 

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 uncertainty also makes it 

difficult to attract partners to help fund 

the industry’s share.518

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. The final 

standard is less stringent than that 

proposed, and can be met at a lower cost 

than the proposed standard, and as 

explained above in Section V.H, the 

EPA has carefully evaluated those costs 

and finds them to be reasonable. 

Further, the record and current 

economic conditions (fuel costs, 

renewables, demand growth, etc.) show 

that non-economic factors such as a 

desire for fuel diversity will likely drive 

future development of any new coalfired EGUs. For this reason, the EPA 

does not find the commenters’ bare 

assertions that the incremental cost of 

CCS (particularly as reasonably 

modulated for this final standard) 

would make the difference between 

constructing and not constructing new 

coal capacity to be persuasive. Rather, a 

cost-reasonable standard reflecting use 

of the new technology is what will drive 

new technology deployment. 

The EPA expects that it is unlikely 

that a new IGCC unit would install 

partial CCS to meet the final standard 

unless the facility is built to take 

advantage of EOR opportunities or to 

operate as a poly-generation facility (i.e., 

to co-produce power along with 

chemicals or other products). For new 

IGCC units, the final standard of 

performance can be met by co-firing a 

small amount of natural gas. Some 

commenters argued that IGCC is an 

advanced technology that, like CCS, 

should be promoted. The EPA 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 postcombustion facilities, but our final 

standard moots that argument for IGCC 

facilities because the final emission 

limitation of 1,400 lb CO2/MWh-g will 

not itself deter installation of IGCC 

technology, by the terms of the 

commenters’ own argument. 

2. ‘‘Full’’ Carbon Capture and Storage 

(i.e., 90 Percent Capture) 

We also reconsidered whether the 

emission limitation for new coal-fired 

EGUs should be based on the 

performance of full implementation of 

CCS technology. For a newly 

constructed utility boiler, this would 

mean that a post-combustion capture 

system would be used to treat the entire 

flue gas stream to achieve an 

approximately 90 percent reduction in 

CO2 emissions. For a newly constructed 

IGCC unit, a pre-combustion capture 

system would be used to capture CO2

from a fully shifted gasification syngas 

stream to achieve an approximately 90 

percent reduction in CO2 emissions. 

In the proposal for newly constructed 

sources, we found that ‘‘full CCS’’ 

would certainly result in significant CO2

reductions from any new source 

implementing the technology. However, 

we also found that the costs associated 

with implementation, on either a new 

utility boiler system or a new IGCC unit, 

are predicted to substantially exceed the 

costs for other dispatchable non-NGCC 

generating options that are being 

considered by utilities and project 

developers (e.g., new nuclear plants and 

new biomass-fired units). See 79 FR at 

1477. This remains the case, and 

indeed, the difference between cost of 

full capture and new nuclear technology 

is estimated to be even greater than at 

proposal. The EPA thus is not selecting 

full capture CCS as BSER. 

Q. Summary 

The EPA finds that the best system of 

emission reduction adequately 

demonstrated is a highly efficient 

supercritical pulverized coal boiler 

using post-combustion partial CCS so 

that CO2 is captured, compressed and 

safely stored over the long-term. 

Properly designed, operated, and 

maintained, this best system can 

achieve a standard of performance of 

1,400 lb CO2/MWh-g, an emission 

limitation that is achievable over the 12- 

operating-month compliance period 

considering usual operating variability 

(including use of different coal types, 

periods of startup and shutdown, and 

malfunction conditions). This standard 

of performance is technically feasible, 

given that the BSER technology is 

already operating reliably in full-scale 

commercial application. The technology 

adds cost to a new facility which the 

EPA has evaluated and finds to be 

reasonable because the costs are in the 

same range as those for new nuclear 

generating capacity—a competing nonNGCC, dispatchable technology that 

utilities and project developers are also 

considering for base load application. 

The EPA has also considered capital 

cost increases associated with use of 

post-combustion partial CCS at the level 

needed to meet the final standard and 

found them to be reasonable, and within 

the range of capital cost increases for 

this industry in prior NSPS which have 

been adjudicated as reasonable. The 

EPA’s consideration of costs is also 

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519CAA section 111(a)(4); See also 40 CFR 60.14 

concerning what constitutes a modification, how to 

determine the emission rate, how to determine an 

emission increase, and specific actions that are not, 

by themselves, considered modifications. 

520NSPS modifications resulting in increases in 

hourly emissions of criteria pollutants. 

fired capacity would be constructed not 

as the most economic option, but for 

such purposes as preserving fuel 

diversity in an energy portfolio, and so 

would not be cost competitive with 

natural gas-fired capacity, so that some 

additional cost premium may therefore 

be reasonable. The EPA has carefully 

evaluated the non-air quality health and 

environmental impacts of the final 

standard and found them to be 

reasonable: CO2 pipelines and CO2

sequestration via deep well injection are 

subject already to rigorous control under 

established regulatory programs which 

assure prevention of environmental 

release during transport and storage. In 

addition, water use associated with use 

of partial CCS at the level to meet the 

final standard is acceptable, and use of 

the technology does not impose 

significant burdens on energy 

requirements at either the plant or 

national level. The 1,400 lb CO2/MWhg standard reflecting performance of the 

BSER may be achieved without 

geographic constraint, both because 

geologic sequestration and EOR capacity 

are widely available and accessible, and 

also because alternative compliance 

pathways are available in the unusual 

circumstance where a new coal-fired 

plant is sited in an area without such 

access, that area has not already limited 

construction of new coal-fired capacity 

in some way, and the area cannot be 

serviced by coal-by-wire. Accordingly, 

the EPA finds that the promulgated 

standard of performance for new fossil 

fuel-fired steam electric generating units 

satisfies the requirements of CAA 

section 111(a). 

VI. Rationale for Final Standards for 

Modified Fossil Fuel-Fired Electric 

Utility Steam Generating Units 

The EPA has determined that, as 

proposed, the BSER for steam generating 

units that trigger the modification 

provisions is each affected unit’s own 

best potential performance as 

determined by that unit’s historical 

performance. The final standards of 

performance are similar to those 

proposed in the June 2014 proposal. 

Differences between the proposed 

standards and the final standards issued 

in this action reflect responses to 

comments received on the proposal. 

Those changes are described below. 

As noted previously, the EPA is 

issuing final emission standards only for 

affected modified steam generating units 

that conduct modifications resulting in 

a hourly increase in CO2 emissions 

(mass per hour) of more than 10 percent 

(‘‘large’’ modifications). The EPA is 

continuing to review the appropriate 

standards for modified sources that 

conduct modifications resulting in a 

hourly increase in CO2 emissions (mass 

per hour) of less than or equal to 10 

percent (‘‘small’’ modifications), is not 

issuing final standards for those sources 

in this action, and is withdrawing the 

proposed standards for those sources. 

See Section XV below. 

A. Rationale for Final Applicability 

Criteria for Modified Steam Generating 

Units 

Final applicability criteria for 

modified steam generating EGUs 

include those discussed earlier in 

Section III.A.1 (General Applicability) 

and Section III.A.3 (Applicability 

Specific to Modified Sources). 

CAA section 111(a)(4) defines a 

‘‘modification’’ as ‘‘any physical change 

in, or change in the method of operation 

of, a stationary source’’ that either 

‘‘increases the amount of any air 

pollutant emitted by such source or . . . 

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.519

A modified steam generating unit is a 

source that fits the definition and 

applicability criteria of a fossil fuel-fired 

steam generating unit and that 

commences a qualifying modification 

on or after June 18, 2014 (the 

publication date of the proposed 

modification standards). 79 FR 34960. 

For the reasons discussed below, the 

EPA in this final action is finalizing 

requirements only for steam generating 

units that conduct modifications 

resulting in an increase in hourly CO2

emissions (mass per hour) of more than 

10 percent as compared to the source’s 

highest hourly emission during the 

previous five years. With respect to 

modifications with smaller increases in 

CO2 emissions (specifically, steam 

generating units that conduct 

modifications resulting in an increase in 

hourly CO2 emissions (mass per hour) of 

10 percent or less compared to the 

source’s highest hourly emission during 

the previous 5 years), the EPA is not 

finalizing any standard or other 

requirements, and is withdrawing the 

June 2014 proposal with respect to these 

sources (see Section XV below). 

The effect of the EPA’s deferral on 

setting standards for sources 

undertaking modifications resulting in 

smaller increases in CO2 emissions and 

the withdrawal of the June 2014 

proposal with respect to such sources is 

that such sources will continue to be 

existing sources and subject to 

requirements under section 111(d). This 

is because an existing source does not 

always become a new source when it 

modifies. Under the definition of ‘‘new 

source’’ in section 111(a)(2), an existing 

source only becomes a new source if it 

modifies after the publication of 

proposed or final regulations that will 

be applicable to it. Thus, if an existing 

source modifies at a time that there is 

no promulgated final standard or 

pending proposed standard that will be 

applicable to it as a modified ‘‘new’’ 

source, that source is not a new source 

and continues to be an existing source. 

Here, because the EPA is not finalizing 

standards for sources undertaking 

modifications resulting in smaller 

increases in CO2 emissions and is 

withdrawing the proposal with respect 

to such sources, these sources do not 

fall within the definition of ‘‘new 

source’’ in section 111(a)(2) and 

continue to be an ‘‘existing source’’ as 

defined in section 111(a)(6). See Section 

XV below. 

As we discussed in the June 2014 

proposal, the EPA has historically been 

notified of only a limited number of 

NSPS modifications 520 involving fossil 

steam generating units and therefore 

predicted that very few of these units 

would trigger the modification 

provisions and be subject to the 

proposed standards. Given the limited 

information that we have about past 

modifications, the agency has 

concluded that it lacks sufficient 

information to establish standards of 

performance for all types of 

modifications at steam generating units 

at this time. Instead, the EPA has 

determined that it is appropriate to 

establish standards of performance at 

this time for larger modifications, such 

as major facility upgrades involving, for 

example, the refurbishing or 

replacement of steam turbines and other 

equipment upgrades that result in 

substantial increases in a unit’s hourly 

CO2 emissions rate. The agency has 

determined, based on its review of 

public comments and other publicly 

available information, that it has 

adequate information regarding the 

types of modifications that could result 

in large increases in hourly CO2

emissions, as well as on the types of 

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521As the U.S. Supreme Court recently stated in 

Massachusetts v. EPA, 549 U.S. 497, 524 (2007): 

‘‘ ‘Agencies, like legislatures, do not generally 

resolve massive problems in one fell regulatory 

swoop;’ ’’ and instead they may permissibly 

implement such regulatory programs over time, 

‘‘ ‘refining their preferred approach as 

circumstances change and as they develop a more 

nuanced understanding of how best to proceed.’ ’’ 

See Grand Canyon Air Tour Coalition v. F.A.A., 154 

F.3d 455 (D.C. Cir. 1998), City of Las Vegas v. Lujan, 

891 F.2d 927, 935 (D.C. Cir. 1989), National 

Association of Broadcasters v. FCC, 740 F.2d 1190, 

1209–14 (D.C. Cir. 1984). See also, Hazardous 

Waste Treatment Council v. U.S. E.P.A., 861 F.2d 

277, 287 (D.C. Cir. 1988) (‘‘[A]n agency’s failure to 

regulate more comprehensively is not ordinarily a 

basis for concluding that the regulations already 

promulgated are invalid. ‘The agency might 

properly take one step at a time.’ United States 

Brewers Assoc. v. EPA, 600 F.2d 974,982 (D.C. Cir. 

1979). Unless the agency’s first step takes it down 

a path that forecloses more comprehensive 

regulation, the first step is not assailable merely 

because the agency failed to take a second. The 

steps may be too plodding, but that raises an 

entirely different issue... .’’). 

522See e.g., Power Engineering, Steam Turbine 

Upgrades Boost Plant Reliability, Efficiency, 

available at www.power-eng.com/articles/print/

volume-116/issue-11/features/steam-turbineupgrades-boost-plant-reliability-efficiency.html. 

523 ‘‘Steam turbine upgrading: Low-hanging 

fruit’’, Power (04/15/2006), www.powermag.com/

steam-turbine-upgrading-low-hanging-fruit. 

524Note that a change in coal-type or change in 

the use of other raw material does not necessarily 

constitute an ‘‘operational change’’. See 40 CFR 

60.14(e)(4). 

525www.alstom.com/press-centre/2006/10/

alstom-signs-power-plant-upgrade-and-retrofitcontract-with-eskom-in-south-africa/. 

526See ‘‘U.S. DOE Information Relevant to 

Technical Basis for ‘‘Large Modification’’ 

Threshold’’ available in the rulemaking docket 

EPA–HQ–OAR–2013–0495. 

measures available to control emissions 

from sources that undergo such 

modifications, and on the costs and 

effectiveness of such control measures, 

upon which to establish standards of 

performance for modifications with 

large emissions increases at this time. 

In establishing standards of 

performance at this time for 

modifications with large emissions 

increases, but not for those with small 

increases, the EPA is exercising its 

policy discretion to promulgate 

regulatory requirements in a sequential 

fashion for classes of modifications 

within a source category, accounting for 

the information available to the agency, 

while also focusing initially on those 

modifications with the greatest potential 

environmental impact. This approach is 

consistent with the case law that 

authorizes agencies to establish a 

regulatory framework in an incremental 

fashion, that is, a step at a time.521

To be clear, the EPA is not reaching 

a final decision as to whether it will 

regulate modifications with smaller 

increases, or even that such 

modifications should be subject to 

different requirements than we are 

finalizing in this rule for the 

modifications with larger increases. We 

have made no decisions and this matter 

is not concluded. We plan to continue 

to gather information, consider the 

options for modifications with smaller 

increases, and, in the future, develop a 

proposal for these modifications or 

otherwise take appropriate steps. 

As a means of determining the proper 

threshold between the larger and 

smaller increases in CO2 emissions, the 

EPA examined changes in CO2

emissions that may result from large, 

capital-intensive projects, such as major 

facility upgrades involving the 

refurbishing or replacement of steam 

turbines and other equipment upgrades 

that would significantly increase a 

unit’s capacity to burn more fossil fuel, 

thereby resulting in large emissions 

increases. Major upgrades such as these 

could increase a steam generating unit’s 

hourly CO2 emissions by well over 10 

percent.522

An example of such major upgrade 

would be work performed at 

AmerenUE’s Labadie Plant, a facility 

with four 600–MW (nominal) coal-fired 

units located 35 miles west of St. Louis. 

In the early 2000s, plant staff conducted 

process improvements that raised 

maximum unit capacity by nearly 10 

percent (from 580 MW to 630 MW).523

Those changes included boiler 

improvements necessitated by its switch 

from bituminous to subbituminous 

coal,524 installation of low-NOX burners, 

an overfire air system, and advanced 

computer controls. One of the 

performance gains came from upgrading 

all four steam turbines, which 

AmerenUE chose to replace as modules 

allowing engineers more freedom to 

maximize performance unconstrained 

by the units’ existing outer casing. 

Another example is the refurbishment 

of the 2,100 MW Eskom Arnot coal-fired 

power plant in South Africa with a 

resulting increase in its power output by 

300 MW to 2,400 MW—an increase in 

capacity of 14 percent.525 For each of 

the plant’s six steam generating units, 

the company conducted a complete 

retrofit of the high pressure and 

intermediate pressure steam turbines, a 

capacity upgrade of the low pressure 

steam turbine, and the replacement and 

upgrade of associated turbine side 

pumps and auxiliaries. In addition, 

major upgrades to the boiler plant were 

conducted, including supply of new 

pressure part components, new burners, 

and modification to other equipment 

such as the coal mills and classifiers, 

fans, and heaters. Other examples are 

provided in a technical memo available 

in the rulemaking docket.526

The EPA does not intend to imply 

that these specific projects would have 

resulted in an increase in hourly CO2

emissions of greater than 10 percent. 

Capacity increases are often the result of 

efficient improvements or are 

accompanied by other facility 

improvements that can offset emissions 

increases due to increased fuel input 

capacity. However, these examples are 

intended to show the types of large, 

more capital intensive projects that can 

potentially result in increases in hourly 

emissions of CO2 of at least 10 percent. 

The EPA believes that it is reasonable 

to set the threshold between ‘‘large’’ 

modifications and ‘‘small’’ 

modifications at 10 percent, a level 

commensurate with the magnitude of 

the emissions increases that could result 

from the types of projects described 

above, and we are issuing a final 

standard of performance for those 

sources that conduct modifications 

resulting in hourly CO2 emission 

increases that exceed that threshold. We 

are not issuing standards of performance 

for those sources that conduct 

modifications resulting in an hourly 

increase of CO2 emissions of less than 

or equal to 10 percent. 

Therefore, the EPA is withdrawing the 

proposed standards for those sources 

that conduct modifications resulting in 

a hourly increase in CO2 emissions 

(mass per hour) of less than or equal to 

ten percent and is not issuing final 

standards for those sources at this time. 

See Section XV below. Utilities, states 

and others should be aware that the 

differentiation between modifications 

with larger and smaller increases in CO2

emissions only applies to sources 

covered under 40 CFR part 60, subpart 

TTTT, i.e., it is only applicable to CO2

emissions from fossil fuel-fired steam 

generating units. There is no similar 

provision for criteria pollutants or for 

other source categories. Utilities, states 

and others should also be aware that the 

distinction between large and small 

modifications only applies to NSPS 

modifications. Sources undertaking 

modifications may still be subject to 

requirements of New Source Review 

under CAA Title I part C or D (which 

have different standards for 

modifications than the NSPS and 

require a case-by-case analysis) or other 

CAA requirements. 

The EPA notes that some commenters 

expressed concern that a number of 

existing fossil steam generating units, in 

order to 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 

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527Technical Support Documents ‘‘GHG 

Abatement Measures’’ (proposal) and ‘‘GHG 

Mitigation Measures’’ (final) available in the 

rulemaking docket EPA–HQ–OAR–2013–0495. 

modifications. Some commenters 

suggested that the EPA should exempt 

projects undertaken specifically for the 

purpose of complying with CAA section 

111(d). 

The EPA does not have sufficient 

information at this time to predict the 

full array of actions that existing steam 

generating units may undertake in 

response to applicable requirements 

under an approved CAA section 111(d) 

plan, or which, if any, of these actions 

may result in increases in CO2 hourly 

emissions. Nevertheless, the EPA 

expects that, to the extent actions 

undertaken by existing steam generating 

units in response to 111(d) requirements 

trigger modifications, the magnitude of 

the increases in hourly CO2 emissions 

associated with such modifications 

would generally be smaller and would 

therefore generally not subject such 

modifications to the standards of 

performance that the EPA is finalizing 

in this rule for modified steam 

generating units with larger increases in 

hourly CO2 emissions. 

B. Identification of the Best System of 

Emission Reduction 

The EPA has determined that, as was 

proposed, the BSER for steam generating 

units that trigger the modification 

provisions is the affected EGU’s own 

best potential performance as 

determined by that source’s historical 

performance. 

The EPA proposed that the BSER for 

modified steam generating EGUs is each 

unit’s own best potential performance 

based on a combination of best 

operating practices and equipment 

upgrades. Specifically, the EPA coproposed two alternative standards for 

modified utility steam generating units. 

In the first co-proposed alternative, 

modified steam generating EGUs would 

be subject to a single emission standard 

determined by the affected EGU’s best 

demonstrated historical performance (in 

the years from 2002 to the time of the 

modification) with an additional 2 

percent emission reduction. The EPA 

proposed that the standard could be met 

through a combination of best operating 

practices and equipment upgrades. To 

account for facilities that have already 

implemented best practices and 

equipment upgrades, the proposal also 

specified that modified facilities would 

not have to meet an emission standard 

more stringent than the corresponding 

standard for reconstructed EGUs. 

The EPA also co-proposed that the 

specific standard for modified sources 

would be dependent on the timing of 

the modification. We proposed that 

sources that modify prior to becoming 

subject to a CAA section 111(d) plan 

would be required to meet the same 

standard described in the first coproposal—that is, the modified source 

would be required to meet a unitspecific emission limit determined by 

the affected EGU’s best demonstrated 

historical performance (in the years 

from 2002 to the time of the 

modification) with an additional 2 

percent emission reduction (based on 

equipment upgrades). We also proposed 

that sources that modify after becoming 

subject to a CAA section 111(d) plan 

would be required to meet a unitspecific emission limit that would be 

determined by the CAA section 111(d) 

implementing authority and would be 

based on the source’s expected 

performance after implementation of 

identified unit-specific energy efficiency 

improvement opportunities. 

The final standards in this action do 

not depend upon when the modification 

commences (as long as it commences 

after June 8, 2014). The EPA received 

comments on the June 2014 proposal 

that called into question the need to 

differentiate the standard based on 

when the modification was undertaken. 

Further, commenters noted that the 

proposed requirements for sources 

modifying after becoming subject to a 

CAA section 111(d) plan, which were 

based on energy efficiency improvement 

opportunities were vague and that 

standard setting under CAA section 

111(b) is a federal duty and would 

require notice-and-comment 

rulemaking. The EPA considered those 

comments and has determined that we 

agree that there is no need for 

subcategories based on the timing of the 

modification. 

C. BSER Criteria 

1. Technical Feasibility 

The EPA based technical feasibility of 

the unit-specific efficiency 

improvement on analyses done to 

support heat rate improvement for the 

proposed CAA section 111(d) emission 

guidelines (Clean Power Plan). That 

work was summarized in Chapter 2 of 

the TSD, ‘‘GHG Abatement 

Measures’’.527 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. 

We recognize that our cost analysis 

just described will represent the costs 

for some EGUs better than others 

because of differences in EGUs’ 

individual circumstances. We further 

recognize that reduced generation from 

coal-fired EGUs will tend to reduce the 

fuel savings associated with heat rate 

improvements, thereby raising the 

effective cost of achieving the CO2

emission reductions from the heat rate 

improvements. Nevertheless, we still 

expect that the majority of the 

investment required to capture the 

technical potential for CO2 emission 

reductions from heat rate improvements 

would be offset by fuel savings, and that 

the net costs of implementing heat rate 

improvements as an approach to 

reducing CO2 emissions from modified 

fossil fuel-fired EGUs are reasonable. 

The EPA further notes that the types of 

large, more capital intensive projects 

that may trigger the ‘‘larger 

modifications’’ threshold (i.e., result in 

an hourly increase in CO2 emissions of 

more than 10 percent) often are 

undertaken in order to increase the 

capacity of the source but also to 

improve the heat rate or efficiency of the 

unit. 

3. Emission Reductions 

This approach would achieve 

reasonable reductions in CO2 emissions 

from the affected modified units as 

those units will be required to meet an 

emission standard that is consistent 

with more efficient operation. In light of 

the limited opportunities for emission 

reductions from retrofits, these 

reductions are adequate. 

4. Promotion of Technology and Other 

Systems of Emission Reduction 

As noted previously, the case law 

makes clear that the EPA is to consider 

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the effect of its selection of the BSER on 

technological innovation or 

development, but that the EPA also has 

the authority to weigh this factor, along 

with the various other factors. With the 

selection of emissions controls, 

modified sources face inherent 

constraints that newly constructed 

greenfield and even reconstructed 

sources do not; as a result, modified 

sources present different, and in some 

ways more limited, opportunities for 

technological innovation or 

development. In this case, the standards 

promote technological development by 

promoting further development and 

market penetration of equipment 

upgrades and process changes that 

improve plant efficiency. 

VII. Rationale for Final Standards for 

Reconstructed Fossil Fuel-Fired Electric 

Utility Steam Generating Units 

A. Rationale for Final Applicability 

Criteria for Reconstructed Sources 

The applicability rationale for 

reconstructed utility steam generating 

units is the same as for newly 

constructed utility steam generating 

units. We are finalizing the same general 

criteria and not amending the 

reconstruction provisions included in 

the general provisions. 

B. Identification of the Best System of 

Emission Reduction 

In the proposal, the EPA evaluated 

seven different control technology 

configurations to determine the BSER 

for reconstructed fossil fuel-fired boiler 

and IGCC EGUs: (1) The use of partial 

CCS, (2) conversion to (or co-firing with) 

natural gas, (3) the use of CHP, (4) 

hybrid power plants, (5) reductions in 

generation associated with dispatch 

changes, renewable generation, and 

demand side energy efficiency, (6) 

efficiency improvements achieved 

through the use of the most efficient 

generation technology, and (7) 

efficiency improvements achieved 

through a combination of best operating 

practices and equipment upgrades. 

Although the EPA concluded that the 

first 4 technologies met most of the 

evaluation criteria, namely they are 

adequately demonstrated, have 

reasonable costs and provide GHG 

emissions reductions, they were 

inappropriate for BSER due to site 

specific constraints for existing EGUs on 

a nationwide basis. We rejected best 

operating practices and equipment 

upgrades because we concluded the 

GHG reductions are not sufficient to 

qualify as BSER. The majority of 

commenters agree with the EPA’s 

decision that these technologies are not 

BSER. In contrast, as described in more 

detail later in this section a few 

commenters did support partial CCS as 

BSER. 

The fifth option, reductions in 

generation associated with dispatch 

changes, renewable generation, and 

demand side energy efficiency, is 

comparable to application of measures 

identified in building blocks two, three 

and four in the emissions guidelines 

that we proposed under CAA section 

111(d). We solicited comment on any 

additional considerations that the EPA 

should take into account in the 

applicability of building blocks two, 

three and four in the BSER 

determination. Most commenters stated 

that building blocks two, three and four 

should not be considered for 

reconstructed sources. 

The proposed BSER was based on the 

performance of the most efficient 

generation technology available, which 

we concluded was the use of the best 

available subcritical steam conditions 

for small units and the use of 

supercritical steam conditions for large 

units. We concluded this technology to 

be technically feasible, to have 

sufficient emission reductions, to have 

reasonable costs, and some opportunity 

for technological innovation. The 

proposed emission standard for these 

sources was 1,900 lb CO2/MWh-n for 

units with a heat input rating of greater 

than 2,000 MMBtu/h and 2,100 lb CO2/ 

MWh-n for units with a heat input 

rating of 2,000 MMBtu/h or less. The 

difference in the proposed standards for 

larger and smaller units was based on 

greater availability of higher pressure/

temperature steam turbines (e.g. 

supercritical steam turbines) for larger 

units. As explained in Section III of this 

preamble, we are finalizing the standard 

on a gross output basis for utility steam 

generating units. The equivalent grossoutput-based standards are 1,800 lb 

CO2/MWh and 2,000 lb CO2/MWh 

respectively. 

We solicited comment on multiple 

aspects of the proposed standards. First, 

we solicited comment on a range of 

1,600 to 2,000 lb CO2/MWh-g for large 

units and 1,800 to 2,200 lb CO2/MWhg for small units. We also solicited 

comment on whether the standards for 

utility boilers and IGCC units should be 

subcategorized by primary fuel type. In 

addition, we solicited comment on if 

there are sufficient alternate compliance 

technologies (e.g., co-firing natural gas) 

that the small unit subcategory is 

unnecessary and should be eliminated. 

Those small sources would be required 

to meet the same emission standard as 

large utility boilers and IGCC units. 

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 

coal-fired utility boilers and IGCC units, 

since IGCC units have demonstrated 

limits closer to 1,500 lb CO2/MWh-n 

and the units’ designs are so 

fundamentally different. Some 

commenters said that CFB (due to lower 

maximum steam temperatures), IGCC, 

and traditional boilers each need their 

own subcategory. Some commenters 

suggested that due to high moisture 

content and high relative CO2 emissions 

of lignite, lignite-fired units should have 

its own subcategory. Other commenters 

opposed the proposed standards for 

reconstructed units because they 

thought the BSER determination for 

reconstructed subpart Da units was 

inconsistent with the BSER 

determination for newly constructed 

units. These commenters stated that the 

EPA did not provide sufficient 

justification for eliminating partial 

carbon capture and sequestration (CCS). 

These commenters also stated that the 

reason the EPA gave for dismissing CCS 

in the proposal was a lack of ‘‘sufficient 

information about costs.’’ These 

commenters hold that the cost rationale 

does not apply for reconstructed coalfired 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-g for sources with a heat 

input rating of greater than 2,000 

MMBtu/h and 2,000 lb CO2/MWh-g for 

sources with a heat input rating of 2,000 

MMBtu/h or less. 

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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-bycase reconstruction determinations in 

the light of considerations of economic 

and technological feasibility. However, 

this case-by-case determination would 

consider the identified BSER (the use of 

the best available steam conditions), as 

well as—at a minimum—the first four 

technologies the EPA considered, but 

rejected, as BSER for a nationwide rule. 

One or more of these technologies could 

be technically feasible and reasonable 

cost, depending on site specific 

considerations and, if so, would likely 

result in sufficient GHG reductions to 

comply with the applicable 

reconstructed standards. Finally, in 

some cases, equipment upgrades and 

best operating practices would result in 

sufficient reductions to achieve the 

reconstructed standards. 

VIII. Summary of Final Standards for 

Newly Constructed and Reconstructed 

Stationary Combustion Turbines 

This section summarizes the final 

applicability requirements, BSER 

determinations, and emission standards 

for newly constructed and reconstructed 

stationary combustion turbines. In 

addition, it also summarizes significant 

differences between the proposed and 

final provisions. 

A. Applicability Requirements 

We are finalizing BSER 

determinations and emission standards 

for newly constructed and reconstructed 

stationary combustion turbines that (1) 

have a base load rating for fossil fuels 

greater than 260 GJ/h (250 MMBtu/h) 

and (2) serve a generator capable of 

selling more than 25 MW-net of 

electricity to the grid. We also are 

finalizing applicability requirements 

that will exempt from the final 

standards (1) all stationary combustion 

turbines that are dedicated non-fossil 

fuel-fired units (i.e., combustion 

turbines capable of combusting 50 

percent or more non-fossil fuel) and 

subject to a federally enforceable permit 

condition restricting annual fossil fuel 

use to 10 percent or less of a unit’s 

annual heat input capacity; (2) the large 

majority of industrial CHP units (i.e., 

CHP combustion turbines that are 

subject to a federally enforceable permit 

condition limiting annual net-electric 

sales to the product of the unit’s net 

design efficiency multiplied by the 

unit’s potential output, or 219,000 

MWh, whichever is greater); (3) 

combustion turbines that are physically 

incapable of burning natural gas (i.e., 

not connected to a natural gas pipeline); 

and (4) municipal waste combustors and 

commercial or industrial solid waste 

incinerators (units subject to subparts 

Eb or CCCC of this part). 

For combustion turbines subject to an 

emission standard, we are finalizing 

three subcategories: base load natural 

gas-fired units, non-base load natural 

gas-fired units, and multi-fuel-fired 

units. We use the term base load natural 

gas-fired units to refer to stationary 

combustion turbines that (1) burn over 

90 percent natural gas and (2) sell 

electricity in excess of their design 

efficiency (not to exceed 50 percent) 

multiplied by their potential electric 

output. To be in this subcategory, a 

stationary combustion turbine must 

exceed the ‘‘natural gas-use criterion’’ 

on a 12-operating-month rolling average 

and the ‘‘percentage electric sales’’ 

criterion on both a 12-operating-month 

and 3-year rolling average basis. We use 

the term non-base load natural gas-fired 

units to refer to stationary combustion 

turbines that (1) burn over 90 percent 

natural gas and (2) have net-electric 

sales equal to or below their design 

efficiency (not to exceed 50 percent) 

multiplied by their potential electric 

output. These criteria are calculated on 

the same rolling average bases as for the 

base load subcategory. Finally, we use 

the term multi-fuel-fired units to refer to 

stationary combustion turbines that 

burn 10 percent or more non-natural gas 

on a 12-operating-month rolling average 

basis. We are not finalizing the 

proposed emission standards for 

modified sources and are withdrawing 

those standards. We explain our 

rationale for these final decisions in 

Sections IX and XV of this preamble. 

B. Best System of Emission Reduction 

We are finalizing BSER 

determinations for the three 

subcategories of stationary combustion 

turbines referred to above: base load 

natural gas-fired units, non-base load 

natural gas-fired units, and multi-fuelfired units. For newly constructed and 

reconstructed base load natural gas-fired 

stationary combustion turbines, the 

BSER is the use of efficient NGCC 

technology. For newly constructed and 

reconstructed non-base load natural gasfired stationary combustion turbines, 

the BSER is the use of clean fuels (i.e., 

natural gas with an allowance for a 

small amount of distillate oil). For 

multi-fuel-fired stationary combustion 

turbines, the BSER is also the use of 

clean fuels (e.g., natural gas, ethylene, 

propane, naphtha, jet fuel kerosene, fuel 

oils No. 1 and 2, biodiesel, and landfill 

gas). 

C. Final Emission Standards 

For all newly constructed and 

reconstructed base load natural gas-fired 

combustion turbines, we are finalizing 

an emission standard of 1,000 lb CO2/ 

MWh-g, calculated on a 12-operatingmonth rolling average basis. We are also 

finalizing an optional emission standard 

of 1,030 lb CO2/MWh-n, calculated on a 

12-operating-month rolling average 

basis, for stationary combustion turbines 

in this subcategory. For newly 

constructed and reconstructed non-base 

load natural gas-fired combustion 

turbines, we are finalizing a standard of 

120 lb CO2/MMBtu, calculated on a 12- 

operating-month rolling average basis. 

For newly constructed and 

reconstructed multi-fuel-fired 

combustion turbines, we are finalizing a 

standard of 120 to 160 lb CO2/MMBtu, 

calculated on a 12-operating-month 

rolling average basis. The emission 

standard for multi-fuel-fired combustion 

turbines co-firing natural gas with other 

fuels shall be determined at the end of 

each operating month based on the 

percentage of co-fired natural gas. Table 

15 summarizes the subcategories, BSER 

determinations, and emission standards 

for combustion turbines. 

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528The emission standard for combustion 

turbines co-firing natural gas with other fuels shall 

be determined based on the amount of co-fired 

natural gas at the end of each operating month. 

TABLE 15—COMBUSTION TURBINE SUBCATEGORIES AND BSER 

Subcategory BSER Emission standard 

Base load natural gas-fired combusiton turbines ................. Efficient NGCC ................................ 1,000 lb CO2/MWh-g or 1,030 lb CO2/MWh-n 

Non-base load natural gas-fired combustion turbines ......... Clean fuels ....................................... 120 lb CO2/MMBtu 

Multi-fuel-fired combustion turbines ..................................... Clean fuels ....................................... 120 to 160 lb CO2/MMBtu 528

D. Significant Differences Between 

Proposed and Final Combustion 

Turbine Provisions 

As shown in Tables 16 and 17 below, 

the proposed rule included several 

general applicability criteria and two 

subcategorization criteria for 

combustion turbines. In addition to the 

proposed applicability and 

subcategorization framework, we 

solicited comment on a ‘‘broad 

applicability approach’’ that included 

most combustion turbines irrespective 

of the actual amount of electricity sold 

to the grid or the actual amount of 

natural gas burned (i.e., non-base load 

units and multi-fuel-fired units, 

respectively). The broad applicability 

approach changed the proposed 

‘‘percentage electric sales’’ and ‘‘natural 

gas-use’’ criteria to distinguish among 

subcategory-specific emissions 

standards. Specifically, in the broad 

applicability approach, we solicited 

comment on subjecting non-base load 

units and multi-fuel-fired units to ‘‘no 

emissions standard,’’ while still 

including them in the general 

applicability. We also solicited 

comment on establishing a separate 

numerical standard for non-base load 

units. The final rule retains all of the 

proposed applicability criteria in some 

form, but most closely tracks the broad 

applicability approach by finalizing the 

percentage electric sales and natural 

gas-use criteria as thresholds that 

distinguish among three subcategories 

of combustion turbines with separate 

emissions standards. 

The final rule also includes 

exceptions to the broad applicability 

approach that we solicited comment on, 

with some changes that are responsive 

to public comments. Categorical 

exceptions to the broad applicability 

criteria are the exclusions for CHP units, 

non-fossil fuel units, and combustion 

turbines not able to combust natural gas. 

First, the proposed applicability criteria 

did not include CHP units that were 

constructed for the purpose of or that 

actually sell one-third or less of their 

potential electric output or 219,000 

MWh, whichever is greater, to the grid. 

The final rule eliminates the 

‘‘constructed for the purpose of’’ and 

actual sales aspects of the proposal and 

replaces them with an exemption for 

CHP units that take federally 

enforceable permit conditions 

restricting net-electric sales to a 

percentage of potential electric sales 

based on the unit’s design efficiency or 

219,000 MWh, whichever is greater. 

Second, the proposed applicability 

criteria did not include non-fossil fuel 

units that burn 10 percent or less fossil 

fuel on a 3-year rolling average. The 

final rule similarly replaces the actual 

fuel-use aspect of the proposal with an 

exemption for non-fossil fuel units that 

take federally enforceable permit 

conditions limiting fossil-fuel use to 10 

percent or less of annual heat input 

capacity. Finally, the proposed 

applicability criteria did not include 

combustion turbines that burn 90 

percent or less natural gas on a 3-year 

rolling average basis. In contrast, the 

final rule includes most fossil fuel-fired 

combustion turbines regardless of the 

amount of natural gas burned, with an 

exception for combustion turbines that 

are not connected to natural gas 

pipelines. Finally, in response to public 

comments, we are not finalizing the 

subcategories for large and small 

combustion turbines that were 

contained in the proposal. Instead, all 

base load natural gas-fired combustion 

turbines must meet an emission 

standard of 1,000 lb CO2/MWh-g. 

TABLE 16—PROPOSED APPLICABILITY CRITERIA VERSUS FINAL APPLICABILITY CRITERIA

Applicability Criteria Proposed Applicability Final Applicability 

Base load rating criterion ................................. Base load rating > 73 MW (250 MMBtu/h) .... Base load rating > 260 GJ/h 529 (250 MMBtu/h) 

Total electric sales criterion ............................. Constructed for purpose of and actually selling > 219,000 MWh-n to the grid.Ability to sell > 25 MW-n to the grid 

Percentage electric sales criterion ................... Constructed for purpose of and having actual 

net-sales to the grid > one-third of potential 

electric output.

Changed to subcategorization criterion per 

broad applicability approach 

Natural gas-use criterion .................................. Actually burns > 90 percent natural gas ........ • Changed to subcategorization criterion per 

broad applicability approach 

• Exemption for combustion turbines that are 

not connected to a natural gas supply 

Fossil fuel-use criterion .................................... Actually burns > 10 percent fossil fuel ........... Exemption based on permit condition limiting 

amount of fossil fuel burned to ≤ 10 percent 

of annual heat input capacity 

Combined Heat and Power (CHP) exemption NA ................................................................... Exemption based on permit condition limiting 

net-electric sales to ≤ design efficiency multiplied by potential electric output, or 219,000 

MWh-n, whichever is greater 

Non-EGU exemption ........................................ Exemption for municipal solid waste combustors and commercial or industrial solid 

waste incinerators.

Same as proposal 

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529 73 MW is equivalent to 260 GJ/h. We changed 

units to avoid potential confusion of MW referring 

to electric output rather than heat input. 

TABLE 17—PROPOSED SUBCATEGORIES VERSUS FINAL SUBCATEGORIES

Subcategory Proposed Criteria Final Criteria 

Small combustion turbine subcategory ............. Base load rating ≤ 850 MMBtu/h ..................... NA 

Large combustion turbine subcategory ............. Base load rating > 850 MMBtu/h ..................... NA 

Base load natural gas-fired base load combustion turbine subcategory.NA ..................................................................... • Actually burns > 90 percent natural gas 

• Net-electric sales > design efficiency (not to 

exceed 50 percent) multiplied by potential 

electric output 

Non-base load natural gas-fired combustion 

turbine subcategory.

NA ..................................................................... • Actually burns > 90 percent natural gas 

• Net-electric sales ≤ design efficiency (not to 

exceed 50 percent) multiplied by potential 

electric output 

Multi-fuel-fired combustion turbine subcategory NA ..................................................................... Actually burns ≤ 90 percent natural gas 

IX. Rationale for Final Standards for 

Newly Constructed and Reconstructed 

Stationary Combustion Turbines 

This section discusses the EPA’s 

rationale for the final applicability 

criteria, BSER determinations, and 

standards of performance for newly 

constructed and reconstructed 

stationary combustion turbines. In this 

section, we present a summary of what 

we proposed, a selection of the 

significant comments we received, and 

our rationale for the final 

determinations, including how the 

comments influenced our decisionmaking. 

A. Applicability 

This section describes the proposed 

applicability criteria, applicability 

issues we specifically solicited 

comment on, the relevant significant 

comments, and the final applicability 

criteria. We also provide our rationale 

for finalizing applicability criteria based 

strictly on design and permit 

restrictions rather than actual operating 

characteristics. Finally, we explain why 

the proposed percentage electric sales 

and natural gas-use applicability criteria 

are being finalized instead as criteria to 

distinguish between separate 

subcategories of stationary combustion 

turbines. 

1. Proposed Applicability Criteria 

In the January 2014 proposal, we 

proposed several applicability criteria 

for stationary combustion turbines. 

Specifically, to be subject to the 

proposed emission standards, we 

proposed that a unit must (1) be capable 

of combusting more than 73 MW (250 

MMBtu/h) heat input of fossil fuel; (2) 

be constructed for the purpose of 

supplying and actually supply more 

than one-third of its potential electric 

output capacity to a utility power 

distribution system for sale (that is, to 

the grid) on a 3-year rolling average; (3) 

be constructed for the purpose of 

supplying and actually supply more 

than 219,000 MWh net-electric output 

to the grid on a 3-year rolling average; 

(4) combust over 10 percent fossil fuel 

on a 3-year rolling average; and (5) 

combust over 90 percent natural gas on 

a 3-year rolling average. We proposed 

exempting municipal solid waste 

combustors and commercial and 

industrial solid waste incinerators. 

Under these proposed applicability 

criteria, two types of stationary 

combustion turbines that are currently 

subject to criteria pollutant standards 

under subpart KKKK would not have 

been subject to CO2 standards. The first 

type was stationary combustion turbines 

that are constructed for the purpose of 

selling and that actually sell one-third 

or less of their potential output or 

219,000 MWh or less to the grid on a 3- 

year rolling average basis (i.e., non-base 

load units). The second type was 

combustion turbines that actually 

combust 90 percent or less natural gas 

on a 3-year rolling average basis (i.e., 

multi-fuel-fired units). 

We proposed the electric sales criteria 

in part because they already exist in 

other regulatory contexts (e.g., the coalfired EGU criteria pollutant NSPS) and 

would promote consistency between 

regulations. Our understanding at 

proposal was that the percentage 

electric sales criterion would 

distinguish between non-base load units 

(e.g., low capital cost, flexible, but 

relatively inefficient simple cycle units) 

and base load units (i.e., higher capital 

cost, less flexible, but relatively efficient 

combined cycle units). 

While the proposed applicability 

criteria did not explicitly exempt simple 

cycle combustion turbines from the 

emission standards, we concluded that, 

as a practical matter, the vast majority 

of simple cycle turbines would be 

excluded because they historically have 

operated as peaking units and, on 

average, have sold less than five percent 

of their potential electric output on an 

annual basis, well below the proposed 

one-third electric sales threshold. 

a. Solicitation of comment on 

applicability, generally 

We solicited comment on a range of 

issues related to applicability. In 

conjunction with the proposed onethird (i.e., 33.3 percent) electric sales 

threshold, we solicited comment on a 

threshold between 20 to 40 percent of 

potential electric output. We also 

solicited comment on a variable 

percentage electric sales criterion, 

which would allow more efficient, 

lower emitting turbines to run for longer 

periods of operation before becoming 

subject to the standards of performance. 

Under this ‘‘sliding scale’’ approach, the 

percentage electric sales criterion would 

be based on the net design efficiency of 

the combustion turbine being installed. 

In this way, more efficient combustion 

turbines would be able to sell a greater 

portion of their potential electric output 

compared with less efficient combustion 

turbines before becoming subject to an 

emission standard. This approach had 

the benefit of incentivizing the 

development and installation of more 

efficient simple cycle combustion 

turbines to serve peak load. 

We also solicited comment on 

whether the percentage electric sales 

criterion for stationary combustion 

turbines should be defined on a single 

calendar year basis. In addition, we 

solicited comment on eliminating the 

219,000 MWh aspect of the total electric 

sales criterion to eliminate any 

incentive for generators to install 

multiple, small, less-efficient stationary 

combustion turbines that would be 

exempt due to their lower output. We 

further solicited comment on whether to 

provide an explicit exemption for all 

simple cycle combustion turbines 

regardless of the amount of electricity 

sold. We additionally solicited comment 

on how to implement the proposed 

electric sales, fossil fuel-use, and natural 

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gas-use criteria given that they were to 

be evaluated as 3-year rolling averages 

during the first three years of operation, 

and we requested comment on 

appropriate monitoring, recordkeeping, 

and reporting requirements. We 

specifically solicited comment on 

whether these proposed requirements 

raised implementation issues because 

they were based on source operation 

after construction has occurred. 

We also solicited comment on 

excluding electricity sold during system 

emergencies from the calculation of 

percentage electric sales. The rationale 

for this exclusion was that simple cycle 

combustion turbines intended only for 

peaking applications might be required 

to operate above the proposed 

percentage electric sales threshold if a 

major power plant or transmission line 

became unexpectedly unavailable for an 

extended period of time. The EPA 

proposed that this flexibility would be 

appropriate if the unit were called upon 

to run after all other available generating 

assets were already running at full load. 

b. Solicitation of comment on broad 

applicability approach 

In both the January 2014 proposal for 

newly constructed EGUs and the June 

2014 proposal for modified and 

reconstructed EGUs, the EPA solicited 

comment on finalizing a broad 

applicability approach instead of the 

proposed approach. Under the proposed 

approach, a stationary combustion 

turbine could be an affected EGU one 

year, but not the next, depending on the 

unit’s actual electric sales and the 

composition of fuel burned. The broad 

applicability approach is consistent 

with historical NSPS applicability 

approaches that are based on design 

criteria and include different emission 

standards for subcategories that are 

distinguished by operating 

characteristics. Specifically, we 

solicited comment on whether we 

should completely remove the electric 

sales and natural gas-use criteria from 

the general applicability framework. 

Instead, the percentage electric sales 

and natural gas-use thresholds would 

serve as subcategorization criteria for 

distinguishing among classes of EGUs 

and subcategory-specific emissions 

standards. Under this broad 

applicability approach, the ‘‘constructed 

for the purpose of’’ component of the 

percentage electric sales criterion would 

be completely eliminated so that 

applicability for combustion turbines 

would be determined only by a unit’s 

base load rating (i.e., greater than 260 

GJ/h (250 MMBtu/h)) and its capability 

to sell power to a utility distribution 

system (i.e., serving a generator capable 

of selling more than 25 MW). In contrast 

to the proposed applicability criteria, 

under the broad applicability approach, 

non-base load (e.g., simple cycle) and 

multi-fuel-fired (e.g., oil-fired) 

combustion turbines would remain 

subject to the rule regardless of their 

electric sales or fuel use. We solicited 

comment on all aspects of this ‘‘broad 

applicability approach,’’ including the 

extent to which it would achieve our 

policy objective of assuring that owners 

and operators install NGCC combustion 

turbines if they plan to sell more than 

the specified electric sales threshold to 

the grid. 

2. Comments on Applicability 

This section summarizes the 

comments we received specific to each 

of the proposed applicability criteria. 

We also received more general 

comments on the scope of the proposed 

framework as compared to the scope of 

the broad applicability approach. 

Comments on applicability for 

dedicated non-fossil and CHP units are 

discussed in Section III. 

a. Base load rating criterion 

Many commenters supported a base 

load rating of 260 GJ/h (250 MMBtu/h) 

because it is generally consistent with 

the threshold used in states 

participating in the Regional 

Greenhouse Gas Initiative (RGGI) and 

under Title IV programs. Other 

commenters opposed the proposed 

applicability thresholds and stated that 

all new, modified, and reconstructed 

units that sell electricity to the grid, 

including small EGUs and simple cycle 

combustion turbines, should be affected 

EGUs because they would otherwise 

have a competitive advantage in energy 

markets as they would not be required 

to internalize the costs of compliance. 

b. Total electric sales criterion 

Commenters noted that the 219,000 

MWh total electric sales threshold put 

larger combustion turbines at a 

competitive disadvantage by distorting 

the market and could have the perverse 

impact of increasing CO2 emissions. 

These commenters noted that the 

219,000 MWh total electric sales 

threshold would allow combustion 

turbines smaller than approximately 80 

MW to sell more than one-third of their 

potential electric output, but larger, 

more efficient combustion turbines 

would still be restricted to selling onethird of their potential electric output to 

avoid triggering the NSPS. They argued 

that this would result in a regulatory 

incentive for generators to install 

multiple, less-efficient combustion 

turbines instead of fewer, more-efficient 

combustion turbines and could have the 

unintended consequence of increasing 

CO2 emissions. 

c. Percentage electric sales criterion 

Commenters from the power sector 

generally supported a complete 

exemption for simple cycle turbines. 

These commenters stated that simple 

cycle turbines are uniquely capable of 

achieving the ramp rates (the rate at 

which a power plant can increase or 

decrease output) necessary to respond to 

emergency conditions and hourly 

variations in output from intermittent 

renewables. Commenters noted that 

simple cycle combustion turbines serve 

a different purpose than NGCC power 

blocks. In addition, commenters noted 

that electricity generation dispatch is 

based on the incremental cost to 

generate electricity and that because 

NGCC units have a lower incremental 

generation cost than simple cycle units, 

economics will drive the use of NGCC 

technologies over simple cycle units. 

However, commenters also stated that 

historic simple cycle operating data may 

not be representative of future system 

requirements as coal units retire, 

generation from intermittent renewable 

generation increases, and numerous 

market and regulatory drivers impact 

plant operations. In the absence of a 

complete exemption, these commenters 

supported a percentage electric sales 

threshold between 40 to 60 percent of a 

unit’s potential electric output. 

Some commenters said that because 

the proposed percentage electric sales 

criterion applied over a three-year 

period, it would adversely affect grid 

reliability because operators 

conservatively would hedge short-term 

operating decisions to ensure that they 

have sufficient capacity to respond to 

unexpected scenarios during future 

compliance periods when the demand 

for electricity is higher. These 

commenters were concerned that such 

compliance decisions would drive up 

the cost of electricity as the most 

efficient new units are taken out of 

service to avoid triggering the NSPS and 

older, less efficient units with no 

capacity factor limitations are ramped 

up instead. 

Some commenters supported the 

sliding-scale approach (i.e., a percentage 

electric sales threshold based on the 

design efficiency of the combustion 

turbine) and stated that incentives for 

manufacturers to develop (and end 

users to purchase) higher efficiency 

combustion turbines could help mitigate 

concerns about a monolithic national 

constraint on simple cycle capacity 

factors. 

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In contrast, others commented that 

fast-start NGCC units intended for 

peaking and intermediate load 

applications can achieve comparable 

ramp rates to simple cycle combustion 

turbines, but with lower CO2 emission 

rates. These commenters said that 

simple cycle turbines should be 

restricted to their historical role as true 

peaking units and that the proposed 

one-third electric sales threshold 

provided sufficient flexibility. Some 

commenters suggested that the one-third 

electric sales threshold could be 

reduced to 20 percent or lower without 

adverse impacts on grid reliability. 

Commenters noted that a complete 

exclusion for simple cycle turbines 

would create a regulatory incentive for 

generators to install and operate less 

efficient unaffected units instead of 

more efficient affected units, thereby 

increasing CO2 emissions. According to 

these commenters, any applicability 

distinctions should be based on 

utilization and function rather than 

purpose or technology. 

Commenters in general supported the 

use of 3-year rolling averages instead of 

a single-year average for the percentage 

and total electric sales criteria because, 

in their view, the 3-year rolling averages 

would provide a better overall picture of 

normal operations. Some commenters 

stated that a rolling 12-month or 

calendar-year average could be severely 

skewed in a given year because of 

unforeseen or unpredicted events. They 

said that using a 3-year averaging 

methodology would provide system 

operators with needed flexibility to 

dispatch simple cycle units at higher 

than normal capacity factors. In 

contrast, some commenters stated that, 

because capacity is forward-looking 

(e.g., payments for capacity are often 

made several years in advance), the 3- 

year averaging period provides limited 

benefit because owner/operators need to 

reserve the ability to respond to 

unforeseen events. 

Commenters noted that potential 

compliance issues could result from the 

inconsistent time frame between the 3- 

calendar-year applicability period and 

the 12-operating-month compliance 

period. For example, a facility could sell 

more than one-third of its potential 

electric output over a 3-year period, but 

sell less than one-third of its potential 

electric output during any given 12- 

operating-month compliance period 

within that 3-year period. During a 12- 

operating-month period with electric 

sales of less than one-third of potential 

electric output, a unit could be 

operating for long periods at part load 

and have multiple starts and stops. 

These operating conditions have the 

potential to increase CO2 emissions, 

regardless of the deign efficiency of the 

turbine. Therefore, a unit could have an 

emission rate in excess of the proposed 

standard. 

Regarding the relationship between 

the percentage electric sales criterion 

and system emergencies, multiple 

commenters supported exclusion of 

electricity generated as a result of a 

system emergency from counting 

towards net sales. These commenters 

stated that the exclusion was 

appropriate because the benefits of 

operating these units to generate 

electrical power during emergency 

conditions would outweigh any adverse 

impacts from short-term increases in 

CO2 emissions. One commenter stated 

that, in addition to declared grid 

emergencies, other circumstances might 

warrant emergency exemption under the 

rule, including extreme market 

conditions, limitations on fuel supply, 

and reliability responses. 

Multiple commenters opposed the 

exclusion of system emergencies when 

calculating a source’s percentage 

electric sales for applicability purposes 

because NSPS must apply continuously, 

even during system emergencies. These 

commenters stated that the EPA does 

not have the authority under the CAA 

to suspend the applicability of a 

standard during periods of system 

emergency. Some commenters stated 

that an exclusion would be unnecessary 

because the EPA Assistant 

Administrator for Enforcement has the 

authority to advise a source that the 

government will not sue the source for 

taking certain actions during an 

emergency. Commenters said that this 

enforcement discretion approach has 

provided prompt, flexible relief that is 

tailored to the needs of the particular 

emergency and the communities being 

served and is only utilized where the 

relief will address the particular 

emergency at hand. 

Commenters added that this 

enforcement discretion approach is 

consistent with the CAA’s mandate that 

emission limits apply continuously and 

provide safeguards against abuse. One 

commenter stated that emergencies 

happen rarely and typically last for 

short periods, that the proposed 

percentage electric sales threshold 

would allow a source to operate at its 

full rated capacity for up to 2,920 hours 

per year without triggering applicability, 

and that the potential occurrence of grid 

emergencies would represent a tiny 

fraction of this time. Another 

commenter stated that no emergency 

short of large scale destruction of power 

generating capacity by terrorism, war, 

accident, or natural disaster could 

justify operating a peaking unit above a 

10-percent capacity factor on a 3-year 

rolling average. 

d. Broad applicability approach 

In response to the EPA’s request for 

comments on whether the proposed 

applicability requirements that 

retrospectively look back at actual 

events (i.e., the electric sales and fuel 

use criteria) would create 

implementation issues, several 

permitting authorities opposed the 

provisions because units could be 

subject to coverage one year but not the 

next, resulting in compliance issues and 

difficulties in determining proper preconstruction and operating permit 

conditions. These permitting authorities 

suggested that in order for a source to 

avoid applicability, the source should 

be subject to a federally enforceable 

permit condition with associated 

monitoring, recordkeeping, and 

reporting conditions for assessing 

applicability on an ongoing basis. Other 

commenters stated that an applicability 

test that concludes after construction 

and operation have commenced is 

inconsistent with the general purpose of 

an applicability test—to provide clear 

and predictable standards of 

performance for new sources that would 

apply when they begin operations. 

Some commenters opposed the 

proposed retrospective applicability 

criteria related to actual output supplied 

during a preceding compliance period 

because EGUs must know what 

performance standards will apply to 

them during the licensing process, and 

such criteria do not allow the permitting 

authority and the public to know in 

advance whether an emission standard 

applies to a proposed new unit. Other 

commenters said that EGUs undergoing 

permitting should be allowed to request 

limits in their operating permit 

conditions in order to remain below the 

applicability thresholds, as this 

methodology is consistent with the preconstruction permitting requirements in 

many federally approved SIPs and the 

current approach under the Title V 

permitting program. 

Many commenters stated a preference 

for the ‘‘proposed applicability 

approach’’ over the ‘‘broad applicability 

approach.’’ These commenters did not 

think it was necessary to require nonbase load or multi-fuel-fired combustion 

turbines to be subject to emission 

standards. They stated that there is no 

justification for imposing burdensome 

monitoring, reporting, and 

recordkeeping requirements that would 

have no environmental benefit (i.e., 

would not reduce CO2 emissions) 

because these units would be subject to 

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‘‘no emissions standards.’’ Other 

commenters supported the broad 

applicability approach and stated that 

all new, modified, and reconstructed 

units that sell electricity to the grid, 

including small EGUs, oil-fired 

combustion turbines, and simple cycle 

combustion turbines should be affected 

EGUs because they would otherwise 

have a competitive advantage in energy 

markets as they would not be required 

to internalize the costs of compliance. 

In contrast, to preserve the discretion 

of state planners under section 111(d), 

many other commenters supported the 

broad applicability approach and the 

inclusion of new simple cycle units 

within the scope of the section 111(b) 

emission standards so that similar, 

existing simple cycle units could be 

subject to the 111(d) standards. 

Numerous other commenters stated that 

all units that sell electricity to the grid 

should be subject to a standard, 

including simple cycle units, because 

they view the utility grid as a single 

integrated system and that doing so may 

simplify development of future 

frameworks for cost-effective carbon 

reductions from existing units, such as 

frameworks based on system-wide 

approaches. 

3. Final Applicability Criteria and 

Rationale 

Based on our consideration of the 

comments received related to the 

proposed applicability criteria and 

practical implementation issues, we are 

revising how those criteria will be 

implemented. The final applicability 

criteria for combustion turbines are 

generally consistent with the broad 

applicability approach on which we 

solicited comment. Section VIII of this 

preamble presents each proposed 

applicability criterion together with the 

form of the criterion in the final rule. 

The final general applicability 

framework includes the proposed 

criteria based on the combustion 

turbine’s base load rating and the 

combustion turbine’s total electric sales 

capacity. The final general applicability 

framework also includes multiple 

exemptions that are relevant to 

combustion turbines: combustion 

turbines that are not connected to 

natural gas pipelines; CHP facilities 

with federally enforceable limits on 

total electric sales; dedicated non-fossil 

units with federally enforceable limits 

on the use of fossil fuels; and municipal 

waste combustors and incineration 

units. 

The final applicability framework 

reflects multiple variations from the 

proposal that are responsive to public 

comments. First, consistent with the 

broad applicability approach, we are 

finalizing the percentage electric sales 

and natural gas-use thresholds as 

subcategorization criteria instead of as 

applicability criteria. In addition, for 

non-CHP combustion turbines, we are 

eliminating the proposed 219,000 MWh 

total electric sales criterion. Finally, we 

are eliminating the proposed 

‘‘constructed for the purpose of’’ 

qualifier for the total and percentage 

electric sales criteria. We are also not 

finalizing CO2 standards for dedicated 

non-fossil fuel-fired or industrial CHP 

combustion turbines. The rationale for 

not finalizing CO2 standards for 

dedicated non-fossil and industrial CHP 

units is discussed in more detail in 

Section III. 

The EPA agrees with commenters that 

the NSPS applicability framework 

should be structured so that permitting 

authorities, the regulated community, 

and the public can determine what 

standards apply prior to a unit having 

commenced construction. With this in 

mind, the EPA has concluded that the 

proposed fossil fuel-use, natural gas-use, 

percentage electric sales, and total 

electric sales applicability criteria for 

combustion turbines are not ideal 

approaches. Because applicability 

determinations based on these criteria 

could change from year to year (i.e., 

units could move in and out of coverage 

each year depending on actual operating 

parameters), some operators would not 

know the extent of their compliance 

obligations until after the compliance 

period. 

Further, from a practical 

implementation standpoint, existing 

permitting rules generally require preconstruction permitting authorities to 

include enforceable conditions limiting 

operations such that unaffected units 

will not trigger applicability thresholds. 

Such conditions are often called 

‘‘avoidance’’ or ‘‘synthetic minor’’ 

conditions, and these conditions 

typically include ongoing monitoring, 

recordkeeping, and reporting 

requirements to ensure that operations 

remain below a particular regulatory 

threshold. 

The following sections provide 

further discussion of the final general 

applicability criteria and the rationale 

for changing certain proposed 

applicability criteria to 

subcategorization criteria. 

a. Base load rating criterion 

We are retaining the applicability 

criterion that a combustion turbine must 

be capable of combusting more than 260 

GJ/h (250 MMBtu/h) heat input of fossil 

fuel. We revised the proposed 73 MW 

form of the base load rating criterion to 

260 GJ/h because some commenters 

misinterpreted the 73 MW form (which 

is mathematically equivalent to 250 

MMBtu/h) as the electrical output rating 

of the generator. This change is a nonsubstantive unit conversion intended to 

limit misinterpretation. While some 

commenters suggested that we expand 

this applicability criterion to cover 

smaller EGUs as well, we did not 

propose to cover smaller units. Because 

smaller units emit relatively few CO2

emissions compared to larger units and 

because we currently do not have 

enough information to identify an 

appropriate BSER for these units, we are 

not finalizing CO2 standards for smaller 

units. 

b. Total electric sales criterion 

The proposed 219,000 MWh total 

sales criterion was based on a 25 MW 

unit operating at base load the entire 

year (i.e., 25 MW * 8,760 h/y = 219,000 

MWh/y). This criterion was included in 

the original subpart Da coal-fired EGU 

criteria pollutant NSPS. Coal-fired EGUs 

tend to be much larger than 25 MW, and 

the criterion’s primary purpose was to 

exempt industrial CHP facilities from 

the criteria pollutant NSPS. In the 

context of combustion turbines, 

however, commenters expressed 

concerns that the 219,000 MWh electric 

sales threshold would actually 

encourage owners and operators to 

install multiple, smaller, less-efficient 

simple cycle combustion turbines 

instead of a single, larger, more-efficient 

simple cycle turbine. The reason for this 

is that the 219,000 MWh threshold 

would allow smaller simple cycle 

combustion turbines of less than 80 MW 

to sell significantly more electricity 

relative to their potential electric output 

than larger turbines. Many commenters 

also indicated that having the flexibility 

to operate a simple cycle turbine at a 

higher capacity factor is important 

because it allows for capacity payments 

from the transmission authority. In light 

of these comments, we are not finalizing 

the 219,000 MWh total electric sales 

criterion for non-CHP combustion 

turbines. Instead, we are finalizing a 

criterion that will exempt combustion 

turbines that do not have the ability to 

sell at least 25 MW to the grid. This 

approach will maintain our goal of 

exempting smaller EGUs, while 

avoiding the perverse environmental 

incentives mentioned by the 

commenters. As explained in Section 

III, however, industrial CHP units are 

sized based on demand for useful 

thermal output, so there is less of an 

incentive for owners and operators to 

install multiple smaller units. Therefore, 

we are maintaining the 219,000 MWh 

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530This approach could also be written as ‘‘an 

emission standard would apply to all combustion 

turbines with a permit restriction limiting the use 

of non-natural gas fuels to 10 percent or less of the 

total heat input.’’ Applicability could then be 

avoided by simply being permitted to burn nonnatural gas fuels for more than 876 hours per year 

even if they actually intended to seldom, if ever, 

combust the alternate fuels. 

531This approach could also be written as ‘‘an 

emission standard would apply to all combustion 

turbines without permit restrictions mandating that 

non-natural gas use contribute over 10 percent or 

more of total heat input.’’ 

total electric sales criterion for CHP 

units. 

c. Percentage electric sales criterion 

Commenters generally opposed the 

proposed percentage electric sales 

criterion approach because it was based 

in part on actual electric sales, meaning 

applicability could change periodically 

(i.e., a unit’s electric sales may change 

over time, rising above and falling 

below the electric sales threshold). The 

EPA agrees this situation is not ideal. To 

avoid situations in which applicability 

changes from year to year, we first 

considered two approaches using permit 

restrictions. Under the first approach, a 

standard would apply to all sources 

with permit restrictions mandating 

electric sales above a threshold (i.e., an 

approach that closely mirrors the 

proposed percentage electric sales 

criterion). Under the second approach, a 

standard would apply to all sources 

without permit restrictions limiting 

electric sales to a level below that 

threshold (i.e., effectively identifying 

non-base load units and excluding them 

from applicability). As stated in the 

proposal, we did not think it was 

critical to include peaking and cycling 

units because peaking turbines operate 

less and because it would be much more 

expensive to lower their emission 

profile to that of a combined cycle 

power plant or a coal-fired plant with 

CCS. 

The first approach is not practical, 

however, because new combustion 

turbines could avoid applicability by 

simply not having a permit restriction at 

all. Moreover, even if a combustion 

turbine were subject to the restriction, it 

could violate its permit if it did not 

operate enough to sell the requisite 

amount of electricity. This would be 

nonsensical, especially because system 

demand would not always be sufficient 

to allow all permitted units to operate 

above the threshold. Therefore, we 

rejected the first permitting approach. 

In contrast, the second approach 

would be a viable method for 

identifying and exempting peaking units 

from applicability. However, there are 

multiple drawbacks to such an 

applicability approach. First, this 

approach would subject those turbines 

without a permit restricting electric 

sales to the final emission standards, 

which raises concerns as to whether 

turbines with lower actual sales could 

achieve the standards. For example, 

new NGCC units tend to dispatch prior 

to older existing units and will generally 

operate for extended periods of time 

near full load and sell electricity above 

the percentage electric sales threshold. 

However, as NGCC units age, they tend 

to start and stop more frequently and 

operate at part load. Yet, even if these 

units sell below the percentage electric 

sales threshold, they would still be 

affected units if they did not take a 

permit restriction. As commenters 

noted, part-load operation and frequent 

starts and stops can reduce the 

efficiency of a combustion turbine. 

While we are confident that our final 

standards for base load natural gas-fired 

combustion turbines can be achieved by 

units serving either base or intermediate 

load, we are not as confident that 

affected NGCC units that might someday 

be operated as non-base load units (e.g., 

as NSPS units age, their incremental 

generating costs will tend to be higher 

than newer units and they will dispatch 

less) could achieve the standards. 

More importantly, however, we are 

concerned that using a permitting 

approach for the percentage electric 

sales criterion would create problems 

due to the interaction between 111(b) 

and 111(d). Under the second 

permitting approach we considered, 

units with low electric sales would be 

excluded from applicability, while units 

with high electric sales would be 

included. While these low-electric sales 

units would generally be simple cycle 

combustion turbines and the highelectric sales units would generally be 

NGCC combustion turbines, this would 

not always be the case. In contrast, we 

are finalizing an applicability approach 

in the 111(d) emission guidelines that is 

based on a combustion turbine’s design 

characteristics rather than electric sales. 

Simple cycle combustion turbines are 

excluded from applicability, while 

NGCC units are included. As a result, 

the universe of sources covered by the 

111(b) standards would not necessarily 

be the same universe of sources covered 

by the 111(d) standards. 

To resolve this issue, we considered 

whether we could change the 111(d) 

applicability criteria to be based on 

historical operation rather than design 

characteristics. For example, if an 

existing combustion turbine had 

historically sold less than one-third of 

its potential output to the grid, then it 

would be exempt from the emission 

guidelines. However, many existing 

NGCC units have historically sold less 

than this amount of electricity, meaning 

that they would not be subject to the 

rule. We ran into similar issues when 

considering other thresholds. For 

example, a percentage electric sales 

threshold of 10 percent would still 

exempt roughly 5 percent of existing 

NGCC units from 111(d), while 

simultaneously raising achievability 

concerns with the 111(b) standard. 

Moreover, even if we had finalized 

111(d) applicability criteria based on 

historical operations, existing NGCC 

units could have decided to take a 

permit restriction limiting their electric 

sales going forward to avoid 

applicability. Under any of these 

scenarios, our goals with respect to 

111(d) would not be accomplished. 

To avoid this result, the EPA has 

concluded that it is appropriate to 

finalize the broad applicability 

approach and set standards for 

combustion turbines regardless of what 

percentage of their potential electric 

output they sell to the grid. To 

accommodate the continued use of 

simple cycle and fast-start NGCC 

combustion turbines for peaking and 

cycling applications, however, the EPA 

has subcategorized natural gas-fired 

combustion turbines based on a 

variation of the proposed percentage 

electric sales criterion. Specifically, and 

as explained in more detail in Section 

IX.B.2, we are finalizing the slidingscale approach on which we solicited 

comment. 

d. Natural gas-use criterion 

Similar to the proposed electric sales 

criteria, commenters generally opposed 

the proposed natural gas-use criterion 

being based on actual operating 

parameters. As with the electric sales 

criteria, the EPA agrees that 

applicability that can switch 

periodically due to operating parameters 

is not ideal. The EPA evaluated two 

approaches for implementing the intent 

of the proposed natural gas-use criterion 

(i.e., to exclude non-natural gas-fired 

combustion turbines) through operating 

permit restrictions. Under the first 

approach, an emission standard would 

apply to all combustion turbines with a 

permit restriction mandating that 

natural gas contribute over 90 percent of 

total heat input.530 Under the second 

approach, an emission standard would 

apply to all combustion turbines 

without a permit restriction limiting 

natural gas use to 90 percent or less of 

total heat input.531 As with the 

percentage electric sales criterion, the 

first approach is not practical because 

combustion turbines could avoid 

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532 Duct burners are optional supplemental 

burners located in the HRSG that are used to 

generate additional steam. Heat input to duct 

burners could in theory be twice that of the 

combustion turbine engine, but are more commonly 

sized at 10 to 30 percent of the heat input to the 

combustion turbine engine. 

applicability by simply not having a 

permit that requires the use of more 

than 90 percent natural gas, even if they 

intend to only burn natural gas. We 

disregarded this approach because it 

would essentially provide a pathway for 

all NGCC units to avoid applicability 

under both 111(b) and 111(d). The 

second approach is problematic because 

operating permit restrictions to improve 

air quality are typically written to limit 

high emission activities (e.g., limiting 

the use of distillate oil to 500 hours 

annually), not to limit lower emitting 

activities. This approach could lead to 

perverse environmental impacts by 

incentivizing the use of non-natural gas 

fuels, which would typically result in 

higher CO2 emissions. Furthermore, the 

second approach would not limit the 

fuels that can be burned by affected 

units (i.e., combustion turbines not 

required to use non-natural gas fuels) 

and would continue to cover 

combustion turbines even when they 

burn over 10 percent non–natural gas 

fuels. Because all non-natural gas fuels 

except H2 have CO2 emission rates 

higher than natural gas, this approach 

would exacerbate the concerns raised by 

commenters about the achievability of 

the 111(b) requirements when burning 

back up fuels. 

In light of these issues, the EPA has 

concluded that permit restrictions are 

not an ideal approach to distinguishing 

between natural gas-fired and multifuel-fired combustion turbines and are 

finalizing a variation of the broad 

applicability approach. The EPA has 

concluded that the only practical 

approach to implement the natural gasuse criterion is to look at the turbine’s 

physical ability to burn natural gas. 

Therefore, we are not finalizing CO2

standards for combustion turbines that 

are not capable of firing any natural gas 

(i.e., not connected to a natural gas 

pipeline). From a practical standpoint, 

the burners of most combustion turbines 

can be modified to burn natural gas, so 

this exemption is essentially limited to 

combustion turbines that are built in 

remote or offshore locations without 

access to natural gas. Consistent with 

the broad applicability approach, we are 

finalizing standards for all other 

combustion turbines, but are 

subcategorizing between natural gasfired turbines and multi-fuel-fired 

turbines. Specifically, and as explained 

in more detail in Section IX.B.3, we are 

distinguishing between these classes of 

turbines based on whether they burn 

greater than 90 percent natural gas or 

not. 

B. Subcategories 

We are finalizing a variation of the 

broad applicability approach for 

combustion turbines where the 

percentage electric sales and natural 

gas-use criteria serve as thresholds that 

distinguish between three subcategories. 

These subcategories are base load 

natural gas-fired units, non-base load 

natural gas-fired units, and multi-fuelfired units. Under the final 

subcategorization approach, multi-fuelfired combustion turbines are 

distinguished from natural gas-fired 

turbines if fuels other than natural gas 

(e.g., distillate oil) supply 10 percent or 

more of heat input. Natural gas-fired 

turbines are further subcategorized as 

base load or non-base load units based 

on the percentage electric sales 

criterion. The percentage electric sales 

threshold that distinguishes base load 

and non-base load units is based on the 

specific turbine’s design efficiency (i.e., 

the sliding-scale approach). The 

percentage electric sales threshold is 

capped at 50 percent. 

This section describes comments we 

received regarding the proposed sizebased subcategories and our rationale 

for not finalizing them. In addition, it 

describes comments we received 

regarding sales-based subcategories and 

our rationale for adopting the sliding 

scale to distinguish between 

subcategories. Finally, it describes 

comments we received regarding fuelbased subcategories and our rationale 

for adopting fuel-based subcategories. 

1. Size-Based Subcategories 

At proposal, the EPA identified two 

size-based subcategories: (1) large 

natural gas-fired stationary combustion 

turbines with a base load rating greater 

than 850 MMBtu/h and (2) small natural 

gas-fired stationary combustion turbines 

with a base load rating of 850 MMBtu/ 

h or less. The EPA received numerous 

comments regarding our proposal to 

subcategorize combustion turbines by 

size. Some commenters agreed with the 

850 MMBtu/h cut-point between large 

and small units, some suggested 

increasing it to 1,500 MMBtu/h, and 

others suggested eliminating size-based 

subcategorization altogether. For 

example, some commenters stated that 

the 850 MMBtu/h cut-point was 

inappropriate because it was originally 

calculated based on NOX performance, 

not CO2 performance. These 

commenters stated that 850 MMBtu/h 

was not a logical demarcation between 

more efficient and less efficient 

combustion turbines, but rather would 

divide the units into arbitrary size 

classifications. These commenters 

suggested that 1,500 MMBtu/h would be 

a better cut-point because data reported 

to Gas Turbine World (GTW) showed 

that new combustion turbines are not 

currently offered with a heat input 

rating between 1,300 MMBtu/h and 

1,800 MMBtu/h, so the higher cut-point 

would more accurately reflect when 

more efficient technologies are 

available. 

In contrast, other commenters said 

that differentiation between small and 

large combustion turbines was not 

justified at all because many of the same 

efficiency technologies that reduce the 

emission rates of larger units could be 

incorporated into smaller units (e.g., 

upgrades that increase the turbine 

engine operating temperature, increase 

the turbine engine pressure ratio, or add 

multi-pressure steam and a steam reheat 

cycle). These commenters also said that 

separate standards for small and large 

turbines would undermine the incentive 

for technology innovation, which they 

described as a key purpose of the NSPS 

program, and that relaxing standards for 

smaller units would discourage 

investment in more efficient 

technologies, resulting in increased CO2

emissions. These commenters 

recommended that the limit for both 

large and small units be no higher than 

1,000 lb CO2/MWh-g. 

After evaluating these comments, the 

EPA has decided not to subcategorize 

combustion turbines based on size for 

several reasons. First, the heat input 

values listed in Gas Turbine World do 

not include potential heat input from 

duct burners.532 Because the heat input 

from duct burners is necessary to 

accurately determine potential electric 

output, our definition of ‘‘base load 

rating’’ includes the heat input from any 

installed duct burners. The EPA 

reviewed the heat input data for existing 

NGCC units that has been submitted to 

CAMD. These data include the heat 

input from duct burners and show that 

multiple NGCC power blocks have been 

built in the past with heat input 

capacities that fall within the range that 

commenters suggested new turbines are 

not offered. Therefore, the EPA has 

concluded that the regulated 

community uses various sizes of NGCC 

turbines and when the heat input from 

duct burners is included, there is no 

clear break between the NGCC unit sizes 

that could distinguish between small 

and large units. In fact, subcategorizing 

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by size could unduly influence the 

development of future NGCC offerings 

because manufacturers could be 

incentivized to design new products at 

the top end of the small subcategory to 

take advantage of the less stringent 

emission standard. 

Second, commenters suggested that a 

cut-point of 1,500 MMBtu/h reflects 

when more efficient technologies 

become available. However, when we 

reviewed actual operating data and 

design data, we only found a relatively 

weak correlation between turbine size 

and CO2 emission rates and did not see 

a dramatic drop in CO2 emission rates 

at 1,500 MMBtu/h. The variability of 

emission rates among similar size units 

far exceeds any difference that could be 

attributed to a difference in size. In 

addition, the most efficient one-to-one 

configuration NGCC power block with a 

base load rating of 1,500 MMBtu/h or 

less has a design emission rate of the 

767 lb CO2/MWh-n (984 MMBtu/h). The 

most efficient one-to-one configuration 

NGCC power block with a base load 

rating just greater than 1,500 MMBtu/h 

has a design emission rate of 772 lb 

CO2/MWh-n (1,825 MMBtu/h). Because 

the smaller unit has a lower design 

emission rate than the larger unit, 

increasing the cut-point does not make 

sense. 

Finally, the EPA has concluded that, 

while certain smaller NGCC designs 

may be less efficient than larger NGCC 

designs, most existing small units have 

demonstrated emission rates below the 

range of emission rates on which we 

solicited comment. We have concluded 

that the lower design efficiencies of 

some small NGCC units are primarily 

related to model-specific design choices 

in both the turbine engine and HRSG, 

not an inherent limitation in the ability 

of small NGCC units to have comparable 

efficiencies to large NGCC units. 

Specifically, manufacturers could 

improve the efficiency of the turbine 

engine by using turbine engines with 

higher firing temperatures and high 

compression ratios and could improve 

the efficiency of the steam cycle by 

switching from single or doublepressure steam to triple-pressure steam 

and adding a reheat cycle. For all of 

these reasons, we have decided against 

subcategorizing combustion turbines 

based on size. Our rationale for setting 

a single standard for small and large 

combustion turbines is explained in 

more detail in Section IX.D.3.a below. 

2. Sales-Based Subcategories 

As described above in Section 

IX.A.3.c, the final applicability criteria 

do not include an exemption for nonCHP units based on actual electric sales 

or permit restrictions limiting the 

amount of electricity that can be sold. 

Instead, we are finalizing the percentage 

electric sales criterion as a threshold to 

distinguish between two natural gasfired combustion turbine subcategories. 

The industry uses a number of terms to 

describe combustion turbines with 

different operating characteristics based 

on electric sales (e.g., capacity factors). 

Combustion turbines that operate at 

near-steady, high loads are generally 

referred to as ‘‘base load’’ or 

‘‘intermediate load’’ units, depending 

on how many hours the units operate 

annually. Combustion turbines that 

operate continuously with variable 

loads that correspond to variable 

demand are referred to as ‘‘load 

following’’ or ‘‘cycling’’ units. 

Combustion turbines that only operate 

during periods with the highest 

electricity demand are referred to as 

‘‘peaking’’ units. However, it is difficult 

to characterize a particular unit using 

just one of these terms. For example, a 

particular unit may serve as a load 

following unit during winter, but serve 

as a base load unit during summer. In 

addition, none of these terms has a 

precise universal definition. In this 

preamble, we refer to the subcategory of 

combustion turbines that sell a 

significant portion of their potential 

electric output as ‘‘base load units.’’ 

This subcategory includes units that 

would colloquially be referred to as base 

load units, as well as some intermediate 

load and load following units. We refer 

to all other units as ‘‘non-base load 

units.’’ This subcategory includes 

peaking units, as well as some load 

following and intermediate load units. 

The threshold that distinguishes 

between these two subcategories is 

determined by a unit’s design efficiency 

and varies from 33 to 50 percent, hence 

the term ‘‘slide scale’’ approach. 

Numerous commenters supported 

three sales-based subcategories for 

peaking, intermediate load, and base 

load units. These commenters said that 

each subcategory should be 

distinguished by annual hours of 

operation and that each should have a 

different BSER and emission standard. 

Other commenters opposed the tiered 

approach. These commenters said that 

separate standards for different 

operating conditions would be 

complicated to implement and enforce, 

while providing few benefits. These 

commenters said that a tiered approach 

could also have the unintended 

consequence of encouraging less 

efficient technologies because it would 

create a regulatory incentive to install 

lower-capital-cost, less-efficient units 

that would operate under the percentage 

electric sales threshold instead of 

higher-capital-cost, more-efficient units 

that would operate above the threshold. 

After evaluating these comments, the 

EPA has concluded that it is appropriate 

to adopt a two-tiered subcategorization 

approach based on a percentage electric 

sales threshold to distinguish between 

non-base load and base load units. 

While we agree with commenters that 

separate standards for peaking, 

intermediate, and base load units is 

attractive on the surface, we ultimately 

concluded that a three-tiered approach 

is not appropriate for several reasons. 

First, the increased generation from 

renewable sources that is anticipated in 

the coming years makes it very difficult 

to determine appropriate thresholds to 

distinguish among peaking, 

intermediate, and base load 

subcategories. Indeed, the boundaries 

between these demand-serving 

functions may blur or shift in the years 

to come. The task is further complicated 

because each transmission region has a 

different mix of generation technologies 

and load profiles with different peaking, 

intermediate, and base load 

requirements. 

Second, there are only two distinct 

combustion turbine technologies— 

simple cycle units and NGCC units. In 

theory, the BSER for the intermediate 

load subcategory could be based on 

high-efficiency simple cycle units or 

fast-start NGCC units, but these are 

variations on traditional technologies 

and not necessarily distinct. Moreover, 

we do not have specific cost information 

on either high-efficiency simple cycle 

turbines or fast-start NGCC units, so our 

ability to make cost comparisons to 

conventional designs is limited. 

Finally, even if we could identify 

appropriate sales thresholds to 

distinguish between peaking, 

intermediate load, and base load 

subcategories, we do not have sufficient 

information to establish a meaningful 

output-based standard for an 

intermediate load subcategory at this 

time. In the transition zone from 

peaking to base load operation (i.e., 

cycling and intermediate load), 

combustion turbines may have similar 

electric sales, but very different 

operating characteristics. For example, 

despite having similar sales, one unit 

might have relatively steady operation 

for a short period of time, while another 

could have variable operation 

throughout the entire year. The latter 

unit would likely have a higher CO2

emission rate. For all of these reasons, 

the EPA has concluded that we do not 

have sufficient information at this time 

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to establish three sales-based 

subcategories. 

Instead, as we explained above, we 

are finalizing two sales-based 

subcategories. To determine an 

appropriate threshold to distinguish 

between base load and non-base load 

units, the EPA considered the important 

characteristics of the combustion 

turbines that serve each type of demand. 

For non-base load units, low capital 

costs and the ability to start, stop, and 

change load quickly are key. Simple 

cycle combustion turbines meet these 

criteria and thus serve the bulk of peak 

demand. In contrast, for base load units, 

efficiency is the key consideration, 

while capital costs and the ability to 

start and stop quickly are less 

important. While NGCC units have 

relatively high capital costs and are less 

flexible operationally, they are more 

efficient than simple cycle units. NGCC 

units recover the exhaust heat from the 

combustion turbine with a HRSG to 

power a steam turbine, which reduces 

fuel use and CO2 emissions by 

approximately one-third compared to a 

simple cycle design. Consequently, base 

load units use NGCC technology. 

Because simple cycle turbines have 

historically been non-base load units, 

we have concluded that it is appropriate 

to distinguish between the non-base 

load and base load subcategories in a 

way that recognizes the distinct roles of 

the different turbine designs on the 

market. 

The challenge, however, is setting a 

threshold that will not distort the 

market. The future distinction between 

non-base load and base load units is 

unclear. For example, some commenters 

indicated that increased generation from 

intermittent renewable sources has 

created a perceived need for additional 

cycling and load following generation 

that will operate between the traditional 

roles of peaking and base load units. To 

fulfill this perceived need, some 

manufacturers have developed highefficiency simple cycle turbines. These 

high-efficiency turbines have higher 

capital costs than traditional simple 

cycle turbine designs, but maintain 

similar flexibilities, such as the ability 

to start, stop, and change load rapidly. 

Other manufacturers have developed 

fast-start NGCC turbines to fill the same 

role. These newer NGCC designs have 

lower design efficiencies than NGCC 

designs intended to only operate as base 

load units, but are able to startup more 

quickly to respond to rapid changes in 

electricity demand. As a result of these 

new technological developments, both 

high-efficiency simple cycle and faststart NGCC units can be used for 

traditional peaking applications, as well 

as for higher capacity applications, such 

as supporting the growth of intermittent 

renewable generation. 

With the changing electric sector in 

mind, we set out to identify an 

appropriate percentage electric sales 

threshold to distinguish between nonbase load and base load natural gas-fired 

units. Two factors were of primary 

importance to our decision. First, the 

threshold needed to be high enough to 

address commenters’ concerns about the 

need to maintain flexibility for simple 

cycle units to support the growth of 

intermittent renewable generation. 

Second, the threshold needed to be low 

enough to avoid creating a perverse 

incentive for owners and operators to 

avoid the base load subcategory by 

installing multiple, less efficient 

turbines instead of fewer, more efficient 

turbines. 

To determine the potential impact of 

intermittent renewable generation on 

the operation of simple cycle units, we 

examined the average electric sales of 

simple cycle turbines in the lower 48 

states between 2005 and 2014 using 

information submitted to CAMD. We 

combined this data with information 

reported to the EIA on total in-state 

electricity generation, including wind 

and solar, from 2008 through 2014. We 

focused on data from the Southwest 

Power Pool (data approximated by EGUs 

in Nebraska, Kansas, and Oklahoma), 

Texas, and California. All of these 

regions have relatively large amounts of 

generation from wind and solar and 

experienced increases in the portion of 

total electric generation provided by 

wind and solar during the 2008–2014 

period. 

a. Southwest Power Pool 

The portion of in-state generation 

from wind and solar in the Southwest 

Power Pool increased from 3 to 16 

percent between 2008 and 2014. The 

average growth rate of wind and solar 

was 28 percent, while overall electricity 

demand grew 1 percent annually on 

average. Based on statements in some of 

the comments, we expected to see a 

large change in the operation of simple 

cycle turbines in this region. However, 

the average electric sales from simple 

cycle turbines only increased at an 

annual rate of 1.7 percent, and remained 

essentially unchanged at 3 percent of 

potential electric output between 2008 

and 2014. Total generation from simple 

cycle turbines in the Southwest Power 

Pool increased slightly more, at an 

annual rate of 2.5 percent, which was 

the result of additional simple cycle 

capacity being added to address 

increased electricity demand. 

This lack of a significant change in 

the operation of simple cycle turbines 

could be explained by the Southwest 

Power Pool’s relatively large amount of 

exported power. If most of the region’s 

renewable generation was being 

exported, the intermittent nature of this 

power would primarily impact other 

transmission regions. An alternate 

explanation, however, is that other 

generating assets are flexible enough to 

respond to the intermittent nature of 

wind and solar generation and that 

simple cycle turbines are not necessary 

to back up these assets to the degree 

some commenters suggested. If this is 

the case, then new simple cycle turbines 

may primarily continue to fill their 

historical role as peaking units going 

forward, while other technologies, such 

as fast-start NGCC units, may provide 

the primary back up capacity for new 

wind and solar. 

b. Texas 

The portion of in-state generation 

from wind and solar in Texas increased 

from 4 to 9 percent between 2008 and 

2014. The average growth rate of wind 

and solar was 13 percent, while overall 

demand grew at an average rate of 2 

percent annually. Similar to the 

Southwest Power Pool, the average 

electric sales of simple cycle turbines 

has remained relatively unchanged. In 

fact, the average electric sales of these 

turbines decreased at an annual rate of 

1.1 percent. Total generation from 

simple cycle turbines increased at an 

annual rate of 6.6 percent, however, due 

to simple cycle capacity additions that 

occurred at approximately four times 

the rate one would expect from the 

growth in overall demand. 

The most likely technologies to back 

up intermittent renewable generation 

have low incremental generating costs 

and can start up and stop quickly. 

Highly efficient simple cycle units meet 

these criteria. As such, the EPA has 

concluded that the most efficient simple 

cycle turbines in a given region are the 

most likely to support intermittent 

renewable generation. Focusing on these 

simple cycle turbines will address 

concerns raised by commenters about 

the future percentage electric sales of 

highly efficient simple cycle turbines 

and give an indication of the impact of 

increased renewable generation on nonbase load units intended to back up 

wind and solar. There are two highly 

efficient intercooled simple cycle 

turbines installed in Texas. These two 

combustion turbines sell an average of 

10 percent of their potential electric 

output annually, compared to an 

average of 3 percent for the remaining 

simple cycle turbines. No simple cycle 

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turbine in Texas sold more than 25 

percent of its potential electric output 

annually. The rapid growth in simple 

cycle capacity, but not overall capacity 

factors, could indicate that the 

additional generation assets are 

providing firm capacity for intermittent 

generation sources such as wind and 

solar, but that capacity is infrequently 

required. Based on the data, even highly 

efficient simple cycle turbines are 

expected to continue to sell less than 

one-third of their potential electric 

output. 

c. California 

The portion of in-state generation 

from wind and solar in California 

increased from 3 to 11 percent between 

2008 and 2014. The average growth rate 

of wind and solar was 25 percent, while 

overall demand has remained stable. 

The operation of simple cycle turbines 

in California has changed more 

significantly than in the other evaluated 

regions. The average electric sales from 

simple cycle turbines increased from 5.1 

to 5.9 percent, an annual rate increase 

of 4.5 percent. As in Texas, considerable 

additional simple cycle capacity has 

been added in recent years. The total 

capacity of simple cycle turbines is 

increasing at 15 percent annually even 

though overall demand has remained 

relatively steady. In addition, the 

newest simple cycle turbines are 

operating at higher capacity factors than 

the existing fleet of simple cycle 

turbines, resulting in an average 

increase in generation from simple cycle 

turbines of 21 percent. Many of the new 

additions are intercooled simple cycle 

turbines that may have been installed 

with the specific intent to back up wind 

and solar generation. 

The average electric sales for the 

intercooled turbines ranged from 3 to 25 

percent, with a 7 percent average. No 

simple cycle turbines in California have 

sold more than one-third of their 

potential electric output on an annual 

basis. The operation of simple cycle 

turbines that existed prior to 2008 has 

not changed significantly. Average 

electric sales for these turbines 

increased at an annual rate of 0.1 

percent. This indicates that support for 

new renewable generation is being 

provided by new units and not by the 

installed base of simple cycle units. 

These units are still serving their 

historical role of providing power 

during peak periods of demand. 

Based on our data analysis, the 

proposed one-third electric sales 

threshold would appear to offer 

sufficient operational flexibility for new 

simple cycle turbines. Existing NGCC 

units, other generation assets, and 

demand-response programs are 

currently providing adequate back up to 

intermittent renewable generation. In 

the future, however, existing NGCC 

units will likely operate at higher 

capacity factors. They will therefore be 

less available to provide back up power 

for intermittent generation. In addition, 

the amount of power generated by 

intermittent sources is expected to 

increase in the future. Both of these 

factors could require additional 

flexibility from the remaining 

generation sources to maintain grid 

reliability. 

Even though fast-start NGCC units, 

reciprocating internal combustion 

engines, energy storage technologies, 

and demand-response programs are 

promising technologies for providing 

back up power for renewable 

generation, none of them historically 

have been deployed in sufficient 

capacity to provide the potential 

capacity needed in the future to 

facilitate the continued growth of 

renewable generation. While we 

anticipate that state and federally issued 

permits for new electric generating 

sources will consider the CO2 benefits of 

these technologies compared to simple 

cycle turbines, the EPA has concluded 

at this time that it is appropriate to 

finalize a percentage electric sales 

threshold that provides additional 

flexibility for simple cycle turbines. 

Specifically, we have concluded that 

a percentage electric sales threshold 

based on a unit’s design net efficiency 

at standard conditions is appropriate. 

This is the sliding-scale approach on 

which we solicited comment. Several 

commenters supported this approach 

because it provides sufficient 

operational flexibility for new simple 

cycle and fast-start NGCC combustion 

turbines and simultaneously promotes 

the installation of the most efficient 

generating technologies. By allowing 

more efficient turbines to sell more 

electricity before becoming subject to 

the standard for the base load 

subcategory, the sliding scale should 

reduce the perverse incentive for 

owners and operators to install more 

lower-capital-cost, less-efficient units 

instead of fewer higher-capital-cost, 

more-efficient units. At the same time, 

the sliding scale should incentivize 

turbine manufacturers to design higher 

efficiency simple cycle turbines that 

owners and operators can run more 

frequently. 

The net design efficiencies for 

aeroderivative simple cycle combustion 

turbines range from approximately 32 

percent for smaller designs to 39 percent 

for the largest intercooled designs. The 

net design efficiencies of industrial 

frame units range from 30 percent for 

smaller designs to 36 percent for the 

largest designs. These efficiency values 

follow the methodology the EPA has 

historically used and are based on the 

higher heating value (HHV) of the fuel. 

In contrast, combustion turbine vendors 

in the U.S. often quote efficiencies 

based on the lower heating value (LHV) 

of the fuel. The LHV of a fuel is 

determined by subtracting the heat of 

vaporization of water vapor generated 

during combustion of fuel from the 

HHV. For natural gas, the LHV is 

approximately 10 percent lower than 

the HHV. Therefore, the corresponding 

LHV efficiency ranges would be 35 to 44 

percent for aeroderivative designs and 

33 to 40 percent for frame designs. We 

considered basing the percentage 

electric sales threshold on both the HHV 

and LHV. The EPA typically uses the 

HHV, but in light of commenters’ 

concerns regarding uncertainty in the 

operation of non-base load units in the 

future, we opted to be conservative and 

use the LHV efficiency. 

We anticipate that high-efficiency 

simple cycle and fast-start NGCC 

turbines will make up the majority of 

new capacity intended for non-base load 

applications. Based on the sliding-scale 

approach, owners and operators of new 

simple cycle combustion turbines will 

be able to sell between 33 to 44 percent 

of the turbine’s potential electric output. 

Our analysis showed that 99.5 percent 

of existing simple cycle turbines have 

not sold more than one-third of their 

potential electric output on an annual 

basis. In addition, 99.9 percent of 

existing simple cycle turbines have not 

sold more than 36 percent of their 

potential electric output on an annual 

basis. The two simple cycle turbines 

that exceeded the 36 percent threshold 

had annual electric sales of 39 and 45 

percent and are located in Montana and 

New York, respectively. As noted 

earlier, the most efficient simple cycle 

turbine currently available is 44 percent 

efficient and would accommodate the 

operations at the Montana facility. The 

only existing simple cycle turbine that 

exceeded the maximum allowable 

percentage electric sales threshold of 44 

percent, which is based on current 

simple cycle designs, sold an 

abnormally high amount of electricity in 

2014. It is possible that this unit was 

operating under emergency conditions. 

As explained below, the incremental 

generation due to the emergency would 

not have counted against the percentage 

electric sales threshold. 

We are capping the percentage 

electric sales threshold at 50 percent of 

potential electric output for multiple 

reasons. First, NGCC emission rates are 

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533Hydrogen would only be considered a fossil 

fuel if it were derived for the purpose of creating 

useful heat from coal, oil, or natural gas. 

relatively steady above 50 percent 

electric sales, so there is no reason that 

a NGCC unit with sales greater than this 

amount should not have to comply with 

the output-based standard for the base 

load subcategory. Second, the net design 

efficiency of the fast-start NGCC units 

intended for peaking and intermediate 

load applications is 49 percent. As 

described earlier, this technology can 

serve the same purpose as highefficiency simple cycle turbines. If we 

were to set a cap any lower than 50 

percent, it could create a disincentive 

for owners and operators to choose this 

promising new technology. 

Finally, the EPA solicited comment 

on excluding electricity sold during 

system emergencies from counting 

towards the percentage electric sales 

threshold. After considering the 

comments, we have concluded that this 

exclusion is necessary to provide 

flexibility, maintain system reliability, 

and minimize overall costs to the sector. 

We disagree with commenters that 

suggested that the EPA’s existing 

enforcement discretion would be a 

viable alternative. An enforcement 

discretion-based approach would not 

provide certainty to the regulated 

community, public, and regulatory 

authorities on the applicability of the 

emission standards, which is a primary 

reason why we are finalizing the broad 

applicability approach. Moreover, 

system emergencies are defined events, 

so commenters’ fears that the exclusion 

will be subject to abuse are overstated. 

Therefore, electricity sold during hours 

of operation when a unit is called upon 

to operate due to a system emergency 

will not be counted toward the 

percentage electric sales threshold. 

However, electricity sold by units that 

are not called upon to operate due to a 

system emergency (e.g., units already 

operating when the system emergency is 

declared) will be counted toward the 

percentage electric sales threshold. 

In summary, the EPA is finalizing the 

percentage electric sales criterion as a 

threshold to distinguish between two 

natural gas-fired combustion turbine 

subcategories. Specifically, all units that 

have electric sales greater than their net 

LHV design efficiencies (as a percentage 

of potential electric output) are base 

load units. All units that have electric 

sales less than or equal to their net LHV 

design efficiencies are non-base load 

units. We are capping the percentage 

electric sales threshold at 50 percent of 

potential electric output. This slidingscale approach will limit the operation 

of the least efficient units, provide 

flexibility for renewable energy growth, 

and incentivize the development of 

more efficient simple cycle units. 

3. Fuel-Based Subcategories 

As described in Section IX.A.3.d, we 

are finalizing a version of the broad 

applicability approach. Under the broad 

applicability approach, the EPA 

solicited comment on a 

subcategorization approach based in 

part on natural gas-use. We received few 

comments on this issue. One of the 

comments we did receive was that 

combustion turbines that burn fuels 

other than natural gas have higher CO2

emissions due to the higher relative 

carbon content of alternate fuels. 

Besides hydrogen,533 natural gas has the 

lowest CO2 emission rate on a lb/

MMBtu basis of any fossil fuel. 

Therefore, burning fuels other than 

natural gas will result in a higher CO2

emission rate. We interpret this 

comment to mean that, if we were to 

subcategorize based on fuel use, 

turbines that burn non-natural gas fuels 

should receive a less stringent emission 

standard. 

For the reasons described in the 

applicability section, we have decided 

to set emission standards for all 

combustion turbines capable of burning 

natural gas, regardless of the actual fuel 

burned, to avoid the practical problems 

that would have arisen under the 

proposed approach. However, as 

commenters explained, multi-fuel-fired 

combustion turbines cannot achieve the 

emission standards achieved by naturalgas fired turbines. For this reason, it 

would not be reasonable to require 

affected EGUs to comply with a 

standard based on the use of natural gas 

during periods when significant 

quantities of non-natural gas fuels are 

being burned. If we did not 

subcategorize, owners and operators 

would not be able to combust other 

fuels in their turbines, including process 

gas, blast furnace gas, and petroleumbased liquid wastes, which might 

otherwise be wasted. In addition, 

without the ability to burn back up fuels 

during natural gas curtailments, grid 

reliability could be jeopardized. 

Therefore, we are finalizing a separate 

fuel-based subcategory for multi-fuelfired combustion turbines. To 

distinguish between this subcategory 

and the natural gas-fired subcategories, 

we are using the same threshold as 

proposed. Specifically, combustion 

turbines that burn ninety percent or less 

natural gas on a 12-operating-month 

rolling average basis will be included in 

this subcategory and subject to a 

separate emission standard, which is 

discussed in Section IX.D.3.d. 

C. Identification of the Best System of 

Emission Reduction 

This section summarizes the EPA’s 

proposed BSER determinations for 

stationary combustion turbines, 

provides a summary of the comments 

we received, and explains our final 

BSER determinations for each of the 

three subcategories we are now 

finalizing. For natural gas-fired 

stationary combustion turbines 

operating as base load units, we 

proposed and are finalizing the use of 

NGCC technology as the BSER. For the 

other two subcategories of affected 

combustion turbines—non-base load 

natural gas-fired combustion turbines 

and multi-fuel-fired combustion 

turbines—we are finalizing the use of 

clean fuels as the BSER. 

1. Proposed BSER 

We considered three alternatives in 

evaluating the BSER for base load 

natural gas-fired combustion turbines: 

(1) Partial CCS, (2) high-efficiency 

simple cycle aeroderivative turbines, 

and (3) modern, efficient NGCC 

turbines. We rejected partial CCS as the 

BSER because we concluded that we did 

not have sufficient information to 

determine whether implementing CCS 

for combustion turbines was technically 

feasible. We rejected high-efficiency 

simple cycle aeroderivative turbines as 

the BSER because this standalone 

technology does not provide emission 

reductions and generally is more 

expensive than NGCC technology for 

base load applications. In contrast, 

NGCC is the most common type of new 

fossil fuel-fired EGU currently being 

planned and built for generating base 

load power. NGCC is technically 

feasible, and NGCC units are currently 

the lowest-cost, most efficient option for 

new base load fossil fuel-fired power 

generation. After considering the 

options, the EPA proposed to find that 

modern, efficient NGCC technology is 

the BSER for base load natural gas-fired 

combustion turbines. 

For non-base load natural gas-fired 

units and multi-fuel-fired units, we did 

not propose a specific BSER or 

associated numeric emission standards, 

but instead solicited comment on these 

issues. 

2. Comments on the Proposed BSER for 

Base Load Natural Gas-Fired 

Combustion Turbines 

This section summarizes the differing 

comments submitted on the proposed 

BSER for base load natural gas-fired 

combustion turbines. Some commenters 

supported partial CCS as the BSER, 

others supported advanced NGCC 

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534Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. 

Cir. 1981). 

designs as the BSER, and others 

supported the proposed BSER. 

a. Partial CCS 

Some commenters stated that our 

proposed BSER analysis for stationary 

combustion turbines was inconsistent 

with our proposed BSER analysis for 

coal-fired units. They stated that the 

EPA had determined that the use of CCS 

was feasible for coal-fired generation 

based on current CCS projects under 

development at coal-fired generating 

stations, but did not come to the same 

conclusion for combustion turbines. 

These commenters stated that CO2

removal is just as technologically 

feasible and economically reasonable for 

a natural gas-fired EGU as for a coalfired EGU. While some of these 

commenters wanted the EPA to 

reconsider CCS as the BSER for NGCC, 

many of these commenters were 

attempting to prove that if the agency 

did not choose CCS as the BSER for 

NGCC units, then the agency should not 

for coal-fired units either. 

Some commenters referenced the 

Northeast Energy Association NGCC 

plant in Bellingham, MA, which 

operated from 1991–2005 with 85–95 

percent carbon capture on a 320 MW 

unit for use in the food and beverage 

industry, that was referred to in the 

proposal. This plant captured 330 tons 

of CO2 per day from a 40 MW slip 

stream and was decommissioned as a 

result of financial difficulties, including 

rising gas prices and discontinuation of 

tax credits. According to these 

commenters, this plant provided 

sufficient proof that CCS technology is 

adequately demonstrated for NGCC 

units. Additionally, these commenters 

referred to other NGCC plants that are 

planned or in development that will 

incorporate CCS. The plants mentioned 

were the Sumitomo Chemical Plant in 

Japan, the Peterhead CCS project in 

Scotland, and the GE-Sargas Plant in 

Texas. The Sumitomo Chemical Plant 

has a base load NGCC unit with CCS 

operating on an 8 MW slip-stream that 

captures about 150 tons of CO2 per day 

for commercial use in the food and 

beverage industry. This carbon capture 

system has been operating since 1994. 

The Peterhead CCS project in Scotland 

is in the planning stages. It is a 

collaboration between Shell and SSE to 

provide 320 MW of electricity to its 

customers from a base load NGCC unit 

with 90 percent carbon capture. The 

CO2 will be transported to the depleted 

Goldeneye reservoir in the ocean where 

it will be stored and continuously 

monitored. The GE-Sargas Plant in 

Texas is a planned joint venture that 

does not currently have a location 

selected, but is intended to be a base 

load NGCC unit with CCS used for EOR. 

These commenters also referenced 

reports authored by DOE, NETL, the 

Clean Air Task Force (CATF), CCS Task 

Force, ICF Inc., and Global CCS 

Institute, suggesting that, because CCS 

technology for NGCC is included in 

these reports, it is adequately 

demonstrated. Some commenters 

referred to a DOE/NETL study that 

suggested that the cost of CCS for NGCC 

units would be more cost-effective than 

for coal-fired EGUs. One non-industry 

commenter emphasized that a 

technology does not have to be in use 

to be considered adequately 

demonstrated. 

In addition, some commenters 

disagreed with the EPA’s decision to 

treat combustion turbines differently 

than coal-fired units with respect to CCS 

on the basis that combustion turbines 

startup, shutdown, and cycle load more 

frequently than coal-fired units. 

According to these commenters, the 

operating characteristics of combustion 

turbines do fluctuate, but so do those of 

coal-fired units. Another commenter 

said that even if NGCC operations vary 

more than they do for coal-fired units, 

it is not an impediment to using CCS 

because combustion turbine operators 

could bypass the carbon capture system 

during startup and shutdown modes 

(which are typically shorter and less 

intensive efforts compared to the startup 

or shutdown of a coal facility) and then 

employ the carbon capture system when 

operating normally. One commenter 

stated that most future base load fossil 

fuel-fired generation will be NGCC and 

that not making CCS the BSER for NGCC 

would result in significant CO2

emissions. 

Other commenters supported the 

EPA’s determination that CCS is not the 

BSER for combustion turbines. These 

commenters said that CCS is not 

adequately demonstrated for 

combustion turbines because none are 

currently operating, under construction, 

or in the advanced stages of 

development. They also noted that CCS 

would have to be demonstrated for the 

range of facilities included in the 

regulated source category, which they 

alleged includes both simple cycle and 

NGCC units. They specifically noted 

that the Bellingham, MA demonstration 

facility was not a full-scale commercial 

NGCC power plant operating with CCS. 

These commenters agreed with the 

EPA that CCS does not match well with 

the operating flexibilities of NGCC and 

simple cycle units. They agreed with the 

EPA that frequent cycling restricts the 

efficacy of CCS on these units, a 

problem which would only get worse as 

more renewable energy sources are 

integrated into the grid. These 

commenters added that NGCC units 

operate differently than coal-fired units 

because the former start, stop, and cycle 

frequently, whereas the latter tend to 

operate at relatively steady loads and do 

not start and stop frequently. They 

stated that even if technical barriers 

could be overcome, the application of 

CCS to combustion turbines would be 

more costly (compared to the 

application of CCS to coal-fired units) 

on a dollars-per-ton basis. In addition, 

these commenters said that other 

industries’ experience with CCS could 

not be transferred to NGCC units due to 

differences in flue gas CO2

concentration. 

Some commenters stated that CAA 

section 111(a) requires the EPA to 

account not only for the cost of 

achieving emission reductions, but also 

for impacts on energy requirements and 

the environment. The commenters cited 

to Sierra Club v. Costle, where the D.C. 

Circuit observed that the EPA ‘‘must 

exercise its discretion to choose an 

achievable emission level which 

represents the best balance of economic, 

environmental, and energy 

considerations.’’ 534 The commenters 

stated that requiring CCS on combustion 

turbines would adversely affect the 

nation’s energy needs and the 

environment because imposing CCS on 

combustion turbines would invariably 

delay the emission reductions that can 

be obtained from new NGCC projects 

that displace load from older, less 

efficient generating technologies. In 

addition, the commenters stated that, 

because combustion turbines are 

projected to provide a significant share 

of new power generation, the EPA 

should recognize that requiring CCS on 

these units would have a 

disproportionally higher impact on 

electricity prices when compared to the 

projected number of new coal-fired 

projects. These commenters concluded 

that the EPA could not determine that 

CCS is the BSER for combustion 

turbines without producing severe and 

unacceptable consequences for the 

availability of affordable electricity in 

the U.S. 

b. NGCC Turbines 

Some commenters stated that the 

proposed BSER analysis should have 

reflected the emission rates achieved by 

the latest designs deployed at advanced, 

state-of-the-art NGCC installations. 

These commenters stated that advanced 

NGCC technologies are the best system 

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535As explained in Section V.J above, a new fossil 

fuel-fired steam generating EGU would, most likely, 

be built to serve base load power demand 

exclusively and would not be expected to routinely 

startup, shut down, or ramp its capacity factor in 

order to follow load demand. Thus, planned startup and shutdown events would only be expected 

to occur a few times during the course of a 12- 

operating-month compliance period. 

for reducing CO2 emissions with no 

negative environmental impacts and no 

negative economic impacts on rate 

payers. They stated that advanced 

NGCC technologies are capable of 

achieving emission rates that are 8 

percent lower than conventional NGCC 

facilities. They also said that the 

majority of existing sources that do not 

deploy these advanced technologies are 

currently able to meet the standard and 

that the proposal failed to explain why 

these lower-emitting advanced 

technologies that are more than 

adequately demonstrated were not 

selected as the BSER. 

c. Simple Cycle Turbines 

Many commenters opposed the EPA’s 

proposal to set emission standards for 

combustion turbines based on their 

function rather than based on their 

design. These commenters stated that 

the EPA’s determination that NGCC 

technology is the BSER for base load 

natural gas-fired combustion turbines 

would apply equally to simple cycle 

turbines if they sell electricity in excess 

of the percentage electric sales 

threshold. They pointed to the word 

‘‘achievable’’ in CAA section 111(a)(1) 

and stated that applying an emission 

standard based on NGCC technology to 

simple cycle units was legally 

indefensible because simple cycle units 

cannot achieve emission rates as low as 

NGCC units. In contrast, many other 

commenters agreed with the EPA’s basic 

approach and stated that NGCC 

technology should be the BSER for baseload functions, while simple cycle 

technology should be the BSER for 

peak-load functions. 

3. Comments on Non-Base Load and 

Multi-Fuel-Fired Combustion Turbines 

Multiple commenters suggested that 

high efficiency simple cycle or fast-start 

NGCC technologies should be the BSER 

for non-base natural gas-fired load units. 

They explained that high efficiency 

simple cycle units and fast-start NGCC 

units are actually more efficient when 

serving non-base load demand than 

NGCC units that are designed strictly for 

base load operation. Some commenters 

also suggested that we should 

subcategorize multi-fuel-fired 

combustion turbines, but did not 

provide any specific technologies that 

should be considered in the BSER 

analysis. 

4. Identification of the BSER 

After our evaluation of the comments 

and additional analysis, we identified 

the BSER for each subcategory of 

combustion turbine that we are 

finalizing: base load natural gas-fired 

units, non-base load natural gas-fired 

units, and multi-fuel-fired units. 

a. Base Load Natural Gas-Fired Units 

As described in the proposal, we 

evaluated CCS, NGCC, and highefficiency simple cycle combustion 

turbines as the potential BSER for this 

subcategory. We selected NGCC as the 

BSER because it met all the BSER 

criteria. This section describes our 

response to issues raised by commenters 

and our rationale for maintaining that 

NGCC is the BSER for base load natural 

gas-fried combustion turbines. 

(1) Partial CCS 

Some commenters stated that CCS 

could be applied equally to both coalfired and natural gas-fired EGUs. To 

support this conclusion, the 

commenters pointed to a retired NGCCwith-CCS demonstration project, as well 

as a few overseas projects and projects 

in the early stages of development. 

While we have concluded that these 

commenters made strong arguments that 

the technical issues we raised at 

proposal could in many instances be 

overcome, we have concluded that there 

is not sufficient information at this time 

for us to determine that CCS is 

adequately demonstrated for all base 

load natural-gas fired combustion 

turbines. 

While the commenters make a strong 

case that the existing and planned 

NGCC-with-CCS projects demonstrate 

the feasibility of CCS for NGCC units 

operating at steady state conditions, 

many NGCC units do not operate this 

way. For example, the Bellingham, MA 

and Sumitomo NGCC units cited by the 

commenters operated at steady load 

conditions with a limited number of 

starts and stops, similar to the operation 

of coal-fired boilers.535 In contrast, our 

base load natural gas-fired combustion 

turbine subcategory includes not only 

true base load units, but also some 

intermediate units that cycle more 

frequently, including fast-start NGCC 

units that sell more than 50 percent of 

their potential output to the grid. Faststart NGCC units are designed to be able 

to start and stop multiple times in a 

single day and can ramp to full load in 

less than an hour. In contrast, coal-fired 

EGUs take multiple hours to start and 

ramp relatively slowly. These 

differences are important because we 

are not aware of any pilot-scale CCS 

projects that have demonstrated how 

fast and frequent starts, stops, and 

cycling will impact the efficiency and 

reliability of CCS. Furthermore, for 

those periods in which a NGCC unit is 

operating infrequently, the CCS system 

might not have sufficient time to 

startup. During these periods, no CO2

control would occur. Thus, if the NGCC 

unit is intended to operate for relatively 

short intervals for at least a portion of 

the year, the owner or operator could 

have to oversize the CCS to increase 

control during periods of steady-state 

operation to make up for those periods 

when no control is achieved by the CCS, 

leading to increased costs and energy 

penalties. While we are optimistic that 

these hurdles are surmountable, it is 

simply premature at this point to make 

a finding that CCS is technically feasible 

for the universe of combustion turbines 

that are covered by this rule. 

Notably, the Department of Energy 

has not yet funded a CCS demonstration 

project for a NGCC unit, and no NGCCwith-CCS demonstration projects are 

currently operational or being 

constructed in the U.S. In contrast, 

multiple CCS demonstration projects for 

coal-fired units are in various stages of 

development throughout the U.S., and a 

full-capture system is in operation at the 

Boundary Dam facility in Canada. See 

Sections V.E and D above. 

One commenter suggested that not 

having CCS as the BSER for combustion 

turbines would ultimately halt the 

development of CCS in the U.S. We 

disagree. A number of coal-fired power 

plants are currently being built with 

CSS, while some existing plants are 

considering CCS retrofits. Moreover, the 

NSPS sets the minimum level of control 

for new sources. We expect that state air 

agencies and other air permitting 

authorities will evaluate CCS when 

permitting new NGCC power plants, 

taking into consideration case-specific 

parameters, like operating 

characteristics, to determine whether 

CCS could be BACT or LAER in specific 

instances. While the NGCC-with-CCS 

units that currently are in the planning 

stages do not provide us with enough 

assurance to determine that CCS is 

adequately demonstrated for 

combustion turbines, it is our 

expectation that these units and others 

to come will provide additional 

information for both permitting reviews 

and the next NSPS review in eight 

years. 

(2) NGCC Turbines 

Regarding the advanced NGCC 

technologies advocated by several 

commenters, the EPA has concluded 

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that the term ‘‘advanced’’ simply refers 

to incremental improvements to 

traditional NGCC designs, not a new 

and unique technology. These 

incremental improvements include 

higher firing temperatures in the turbine 

engine, increasing the number of steam 

pressures, and adding a reheat cycle to 

the steam cycle. The emission rates 

achieved by these so-called ‘‘advanced’’ 

technologies were included within the 

data set of newer NGCC designs that we 

used to establish the final emission 

standards. In addition, our review of the 

operating data for NGCC power blocks 

installed since 2000 indicates that a 

unit’s mode of operation in response to 

system demand (e.g., capacity factor) 

affects efficiencies achieved to the 

extent that we cannot evaluate the 

impact of particular subcomponents 

used within the power block. As a 

result, a conventional NGCC power 

block located in a region of the country 

where system demand requires the 

power block to run continuously at a 

steady high load can achieve higher 

efficiencies than an ‘‘advanced’’ NGCC 

power block located in a region where 

system demand requires the power 

block to cycle on and off to match 

system demand. For this reason, our 

data set included a large population of 

technologies and load conditions to 

ensure that new NGCC power blocks 

can achieve the final emission standards 

in all regions of the country. 

As we explained in the proposal, 

NGCC technology meets all of the BSER 

criteria. For base load functions, NGCC 

units are technically feasible, costeffective (indeed, less expensive than 

simple cycle combustion turbines), and 

have no adverse energy or 

environmental impacts. Moreover, 

NGCC units reduce emissions because 

they have a lower CO2 emission rate 

than simple cycle units. Finally, 

selecting NGCC as the BSER will 

promote the development of new 

technology, such as the incremental 

improvements advocated by the 

commenters, which will further reduce 

emissions in the future. 

Some commenters suggested that the 

costs and efficiency impacts of startup 

and shutdown events are higher for 

NGCC units than for simple cycle units. 

Consequently, we refined the LCOE 

costing approach used at proposal by 

adding these additional costs and 

efficiency impacts to our cost 

comparison. Even accounting for these 

new costs and impacts, we found that 

NGCC technology results in a lower cost 

of electricity than simple cycle 

technology when a unit’s electric sales 

exceed approximately one-third of its 

potential electric output. The final 

percentage electric sales criterion for the 

base load natural gas-fired combustion 

turbine subcategory is based on the 

sliding scale. This means that the 

dividing line between the base load 

subcategory and the non-base load 

subcategory will change depending on a 

unit’s nameplate design efficiency. For 

a conventional simple cycle turbine, the 

base load subcategory will begin at 

around 33 percent electric sales, while 

for a newer fast-start NGCC turbine, the 

base load subcategory will begin at 

approximately 50 percent electric sales. 

Anywhere within this range, our cost 

calculations have shown that NGCC 

technology is more cost-effective than 

simple cycle technology. Therefore, we 

are finalizing our determination that 

modern, efficient NGCC technology is 

the BSER for base load natural-gas fired 

combustion turbines. 

(3) Simple Cycle Turbines 

Many commenters mistakenly thought 

that the EPA proposed to require some 

simple cycle combustion turbines to 

meet an emission standard of 1,000 lb 

CO2/MWh-g, a level that they assert is 

unachievable. On the contrary, the EPA 

is not finding that NGCC technology and 

a corresponding emission standard of 

1,000 lb CO2/MWh-g is the BSER for 

simple cycle turbines. Instead, the EPA 

is finding that NGCC technology is the 

BSER for base load turbine applications. 

This means that if an owner or operator 

wants to sell more electricity to the grid 

than the amount derived from a unit’s 

nameplate design efficiency calculated 

as a percentage of potential electric 

output, then the owner or operator 

should install a NGCC unit. If the owner 

or operator elects to install a simple 

cycle turbine instead, then the practical 

effect of our final standards will be to 

limit the electric sales of that unit so 

that it serves primarily peak demand, 

not to subject it to an unachievable 

emission standard. 

b. Non-base Load Natural Gas-Fired 

Load Units 

To identify the BSER for non-base 

load natural gas-fired units, we 

evaluated a range of technologies, 

including partial CCS, high-efficiency 

NGCC technology designed for base load 

applications, fast-start NGCC, highefficiency simple cycle units (i.e., 

aeroderivative turbines), and clean 

fuels. For each of these technologies, we 

considered technical feasibility, costs, 

energy and non-air quality impacts, 

potential for emission reductions, and 

ability to promote technology. 

While CCS would result in emission 

reductions and promote the 

development of new technology, we 

concluded that CCS does not meet the 

BSER criteria because the low capacity 

factors and irregular operating patterns 

(e.g., frequent starting and stopping and 

operating at part load) of non-base load 

units make the technical challenges 

associated with CCS even greater than 

those associated with base load units. In 

addition, because the CCS system would 

remain idle for much of the time while 

these units are not running, CCS would 

be less cost-effective for these units than 

for base load units. 

We have also concluded that the highefficiency NGCC units designed for base 

load applications do not meet any of the 

BSER criteria for non-base load units. 

First, non-base load units need to be 

able to start and stop quickly, and NGCC 

units designed for base load 

applications require relatively long 

startup and shutdown periods. 

Therefore, conventional NGCC designs 

are not technically feasible for the nonbase load subcategory. Also, non-base 

load units operate less than 10 percent 

of the time on average. As a result, 

conventional NGCC units designed for 

base load applications, which have 

relatively high capital costs, will not be 

cost-effective if operated as non-base 

load units. In addition, it is not clear 

that a conventional NGCC unit will lead 

to emission reductions if used for nonbase load applications. As some 

commenters noted, conventional NGCC 

units have relatively high startup and 

shutdown emissions and poor part-load 

efficiency, so emissions may actually be 

higher compared with simple cycle 

technologies that have lower overall 

design efficiencies but better cycling 

efficiencies. Finally, requiring 

conventional NGCC units as the BSER 

for non-base load combustion turbines 

would not promote technology because 

these units would not be fulfilling their 

intended role. In fact, it could hamper 

the development of technologies with 

lower design efficiencies that are 

specifically designed to operate 

efficiently as non-base load units (i.e., 

high-efficiency simple cycle and faststart NGCC units). For all these reasons, 

we have concluded that conventional 

NGCC units designed for base load 

applications are not the BSER for nonbase load natural gas-fired units. 

Compared to conventional NGCC 

technology, fast-start NGCC units have 

lower design efficiencies, but are able to 

start and ramp to full load more quickly. 

Therefore, it is possible that requiring 

fast-start NGCC as the BSER for nonbase load units would result in emission 

reductions and further promote the 

development of fast-start NGCC 

technology, which is relatively new and 

advanced. However, because the 

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536http://www.eia.gov/electricity/data/eia923/. 

majority of non-base load combustion 

turbines operate less than 10 percent of 

the time, it would be cost-prohibitive to 

require fast-start NGCC, which have 

relatively high capital costs compared to 

simple cycle turbines, as the BSER for 

all non-base load applications. Also, as 

we explained above in Section IX.B.2, 

we do not have sufficient emissions data 

for fast-start NGCC units operating over 

the full range of non-base load 

conditions (e.g., peaking, cycling, etc.), 

so we would not be able to establish a 

reasonable emission standard. 

High-efficiency simple cycle turbines 

are primarily used for peaking 

applications. High-efficiency simple 

cycle turbines often employ 

aeroderivative designs because they are 

more efficient at a given size and are 

able to startup and ramp to full load 

more quickly than industrial frame 

designs. Requiring high-efficiency 

simple cycle turbines as the BSER could 

result in some emission reductions 

compared with conventional simple 

cycle turbines. It would also promote 

technology development by 

incentivizing manufacturers to increase 

the efficiency of their simple cycle 

turbine models. However, 

aeroderivative designs have higher 

initial costs that must be weighed 

against the specific peak-load profiles 

anticipated for a particular new nonbase load unit. Many utility companies 

have elected to install the heavier 

industrial frame turbines because the 

ramping capabilities of aeroderivative 

turbines are not required for their 

system demand profiles (i.e., the speed 

and durations of daily changes in 

electricity demand), and the fuel savings 

do not justify the higher initial costs. 

We currently do not have precise 

enough costing information to compare 

the cost-effectiveness of aeroderivative 

turbines and industrial frame turbines 

for all non-base load applications. 

Determining cost-effectiveness is further 

complicated because the efficiencies of 

the available aeroderivative and 

industrial frame technologies 

significantly overlap. For example, the 

efficiencies of aeroderivative turbines 

range from 32 to 39 percent, while the 

efficiencies of industrial frame turbines 

range from 30 to 36 percent. Based on 

these cost uncertainties, we cannot 

conclude that high-efficiency simple 

cycle turbines are the BSER for natural 

gas-fired non-base load applications at 

this time. 

The final option that we considered 

for the BSER was clean fuels, 

specifically natural gas with a small 

allowance for distillate oil. The use of 

clean fuels is technically feasible for 

non-base load units. Based on available 

EIA data,536 natural gas comprises more 

than 96 percent of total heat input for 

simple cycle combustion turbines. In 

addition, natural gas is frequently the 

lowest cost fossil fuel used in 

combustion turbines, so it is costeffective. Clean fuels will also result in 

some emission reductions by limiting 

the use of fuels with higher carbon 

content, such as residual oil. Finally, 

the use of clean fuels will not have any 

significant energy or non-air quality 

impacts. Based on these factors, the EPA 

has determined that the BSER for nonbase load natural gas-fired units is the 

use of clean fuels, specifically natural 

gas with a small allowance for distillate 

oil. Natural gas has approximately thirty 

percent lower CO2 emissions per 

million Btu than other fossil fuels 

commonly used by utility sector nonbase load units. 

c. Multi-Fuel-Fired Units 

To identify the BSER for multi-fuelfired units, we again evaluated CCS, 

NGCC technology, high-efficiency 

simple cycle units (i.e., aeroderivative 

turbines), and clean fuels. For each of 

these technologies we considered 

technical feasibility, costs, energy and 

non-air quality impacts, emission 

reductions, and technology promotion. 

For many of the same reasons we 

provided above in our discussion of the 

BSER for non-base load natural gas-fired 

combustion turbines, only clean fuels 

meets the BSER criteria for multi-fuelfired units. 

While CCS would result in emission 

reductions and the promotion of 

technology, we concluded that CCS 

does not meet the BSER criteria because 

multi-fuel-fired units tend to start, stop, 

and operate at part load frequently. 

Also, there are impurities and 

contaminants in some alternate fuels 

which make the technical challenges of 

applying CCS to multi-fuel-fired units 

greater than for natural gas-fired units. 

In regards to NGCC technology, we 

have concluded that it is technically 

feasible, would result in emission 

reductions, is cost-effective, and would 

promote the development of technology. 

However, a BSER determination based 

on the use of NGCC technology could 

pose challenges for facilities operating 

in remote locations and certain 

industrial facilities. In remote locations, 

the construction of a NGCC facility is 

often not practical because it requires 

larger capital investments and 

significant staffing for construction and 

operation. In contrast, simple cycle 

turbines are cheaper and can be 

operated with minimal staffing. Also, 

many industrial facilities do not have 

the space available to build a HRSG and 

the associated cooling tower. Therefore, 

requiring NGCC as the BSER could have 

unforeseen energy impacts at these 

types of facilities. Moreover, these same 

kinds of facilities also burn by-product 

fuels. Faced with a decision to install an 

NGCC unit, these facilities might seek 

alternative energy options, which could 

lead to increased flaring or venting of 

by-product fuels because they are no 

longer being burned onsite for energy 

recovery. Therefore, in light of these 

potential energy and non-air quality 

impacts, we have concluded that NGCC 

technology is not the BSER for multifuel-fired combustion turbines. 

Similarly, while high-efficiency 

simple cycle turbines would result in 

emission reductions and promote the 

advancement of this technology, we are 

not confident that high-efficiency 

simple cycle units are technically 

feasible or cost-effective for this 

subcategory. Aeroderivative turbines are 

not as flexible with regards to what fuels 

that can be burned. Because by-product 

fuels vary in composition, it is not clear 

that all by-products fuels could be 

burned in a high-efficiency simple cycle 

turbine. In addition, even if a byproduct fuel could be burned in an 

aeroderivative turbine, we do not have 

information on the potential for 

increased maintenance costs, so we 

cannot determine whether using highefficiency simple cycle turbines would 

be cost-effective. 

The final option that we considered 

for the BSER was clean fuels. The use 

of clean fuels is technically feasible and 

cost-effective. The use of clean fuels 

also provides an environmentally 

beneficial alternative to the flaring or 

venting of by-product fuels and limits 

the use of dirtier fuels with higher CO2

emission rates, such as residual oils. 

Clean fuels also promote technology 

development by allowing manufacturers 

to develop new combustion turbine 

designs that are capable of burning byproduct fuels that currently cannot be 

burned in combustion turbines. Finally, 

the use of clean fuels does not have any 

significant energy or non-air quality 

impacts. Based on these factors, the EPA 

has determined that the BSER for multifuel-fired combustion turbines is the use 

of clean fuels. 

D. Achievability of the Final Standards 

We are finalizing emission standards 

for three subcategories of combustion 

turbines. Specifically, units that sell 

electricity in excess of a threshold based 

on their design efficiency and that burn 

more than 90 percent natural gas (i.e., 

base load natural gas-fired units) will be 

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subject to an output- based standard. 

The output-based standard is based on 

the performance of existing NGCC units 

and takes into account a range of 

operating conditions, future 

degradation, etc. Units not meeting 

either the percentage electric sales or 

natural gas-use criteria (i.e., non-base 

load natural gas-fired and multi-fuel 

units, respectively) will be subject to an 

input-based standard based on the use 

of clean fuels. This section summarizes 

what emission standards we proposed 

and related issues we solicited comment 

on, describes the comments we received 

regarding the proposed emission 

standards and our responses to those 

comments, and provides our rationale 

for the final emission standards. 

1. Proposed Standards 

For large newly constructed, 

modified, and reconstructed stationary 

combustion turbines (base load rating 

greater than 850 MMBtu/h), we 

proposed an emission standard of 1,000 

lb CO2/MWh-g. For small stationary 

combustion turbines (base load rating of 

850 MMBtu/h or less), we proposed an 

emission standard of 1,100 lb CO2/

MWh-g. We also solicited comment on 

a range of 950–1,100 lb CO2/MWh-g for 

large stationary combustion turbines 

and a range of 1,000–1,200 lb CO2/

MWh-g for small stationary combustion 

turbines. 

In addition, we solicited comment on 

increasing the size distinction between 

large and small stationary combustion 

turbines to 900 MMBtu/h to account for 

larger aeroderivative designs; increasing 

the size distinction to 1,000 MMBtu/h to 

account for future incremental increases 

in base load ratings; increasing the size 

distinction to between 1,300 to 1,800 

MMBtu/h; and eliminating the size 

subcategories altogether. To account for 

potential reduced efficiencies when 

units are not operating at base load, we 

also solicited comment on whether a 

separate, less stringent standard should 

be established for non-base load 

combustion turbines. 

2. Comments 

As described previously, we are not 

finalizing the size-based subcategories 

that we proposed and instead are 

finalizing emission standards for salesand fuel-based subcategories. 

Specifically, we are finalizing emission 

standards for three subcategories of 

stationary combustion turbines: base 

load natural-gas fired units, non-base 

load natural gas-fired units and multifuel-fired units. The relevant comments 

concerning the emission standards for 

the first two subcategories are discussed 

below. Any comments we received 

supporting tiered emission standards 

are included in the discussion of nonbase load natural gas-fired units. We did 

not receive comments on an appropriate 

emission standard for multi-fuel-fired 

units. 

a. Emission standards for Base Load 

Natural Gas-Fired Units 

Many commenters stated that the 

proposed emission standards did not 

properly take into account the losses in 

efficiency that occur due to long-term 

degradation over multiple decades, 

operation at non-base load conditions 

(load cycling, frequent startups and 

shutdowns, and part-load operations), 

site-specific factors such as ambient 

conditions and cooling technology, and 

secondary fuel use (e.g., distillate oil). 

These commenters stated that the EPA 

should conduct a more comprehensive 

analysis that addresses worst-case 

conditions for each of these factors. 

They also stated that all of the units 

included in the analysis supporting the 

proposal were relatively new and 

therefore have experienced limited 

degradation. The commenters stated 

that, while some degradation in 

efficiency can be recovered during 

periodic maintenance outages, it is not 

always possible or feasible to repair a 

degraded component immediately 

because repairs often involve extended 

outages that must be scheduled well in 

advance. They stated that a new unit 

that initially could meet the standard at 

base load conditions can experience 

increasing heat rates with age even 

when adhering to the manufacturer’s 

recommended maintenance program. 

Some commenters stated that the 

proposed standards were derived by 

looking at emissions data from years 

with historically low natural gas prices. 

They surmised that the NGCC units 

were taking advantage of these prices by 

running at historically high capacity 

factors and concluded that the 

efficiencies and CO2 emission rates 

underlying the proposed standards were 

not representative of periods with 

higher natural gas prices. Other 

commenters said that many NGCC units 

are increasingly required to cycle and 

operate at lower capacities (compared to 

the proposal’s baseline) to accommodate 

hourly variations in intermittent 

renewable generation. They anticipated 

that this type of generation will 

increase, requiring NGCC units to start, 

stop, and operate at part load more 

frequently than in the past, increasing 

CO2 emissions. 

Some commenters indicated that, 

during startup, combustion turbines 

must be operated at low load for 

extended periods to gradually warm up 

the HRSG to minimize thermal stresses 

on pressure vessels and boiler tubes. 

During these startup periods, significant 

CO2 emissions occur, but steam 

production is not sufficient for the 

steam turbine generator to produce 

electricity. They also stated that a 

similar situation occurs during 

shutdown when the steam cycle does 

not generate electricity, but the 

combustion turbine is still combusting 

fuel as it proceeds through the 

shutdown process. These commenters 

recommended that the EPA could 

address these issues by creating a 

subcategory for NGCC units that cycle 

and operate at intermediate load. 

Many commenters said that sitespecific factors can often preclude 

operators from achieving design 

efficiencies based on ISO conditions. 

These factors include high elevations, 

high ambient temperatures, and cooling 

system constraints. They stated that 

local water temperatures can impact 

condenser operating pressure and heat 

rates. They also said that areas with 

limited water resources could require 

systems that rely on air-cooled 

condensers, which cannot achieve 

thermal efficiencies comparable to 

water-cooled plants. These commenters 

stated that the final rule should include 

provisions for addressing site-specific 

constraints that preclude individual 

affected EGUs from achieving the 

emissions rates achieved on average by 

other sources. 

Some commenters stated that the 

proposed standards for modified and 

reconstructed combustion turbines 

would foreclose future opportunities for 

operators to undertake projects to 

restore the performance of both 

degraded units subject to the NSPS and 

existing, pre-NSPS units. They said that 

it is not possible to bring older 

combustion turbines (built prior to the 

year 2000) up to the efficiency levels of 

modern units because many newer 

technological options that deploy higher 

temperatures are not available for pre2000 combustion turbines. 

Commenters from the power sector 

generally supported increasing the 

standards to 1,100 lb CO2/MWh-g and 

1,200 lb CO2/MWh-g for the newly 

constructed large and small turbines, 

respectively. They also advocated 

finalizing standards for modified and 

reconstructed standards that are 10 

percent higher than the final standards 

for new sources because combustion 

turbines constructed prior to 2000 were 

not included in the EPA’s analysis. 

Conversely, some commenters stated 

that the proposed standards for 

combustion turbines do not reflect the 

emission rates that are achievable by 

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537For emission standards of 1,000 lb CO2/MWhg and above, the emission standard uses three 

significant figures. See Section X.D. 

modern, efficient NGCC power blocks. 

These commenters stated that the 

appropriate standard, consistent with 

Congressional objectives under CAA 

section 111, should be 800 lb CO2/

MWh-g based on the performance of the 

lowest emitters in the CAMD database. 

Some commenters stated that a standard 

of 850 lb CO2/MWh-g reflects BSER for 

high-capacity factor units because half 

of the NGCC units in the CAMD 

database are achieving this level of 

emissions. One commenter from the 

power sector who operates NGCC power 

plants stated that the final standard for 

new large combustion turbines should 

be 925 lb CO2/MWh-g. Another 

commenter also supported an emission 

standard of 925 lb CO2/MWh-g, which 

is consistent with recent BACT 

determinations in the state of New York. 

Several other commenters stated that a 

reasonable standard for new large 

combustion turbines should be 950 lb 

CO2/MWh-g and that the final standard 

for new small combustion turbines 

should be 1,000 lb CO2/MWh-g. 

Numerous commenters stated that the 

final standards for new sources should 

not exceed 1,000 lb CO2/MWh-g for 

either large or small combustion 

turbines. Other commenters stated that, 

because the standards were developed 

based on emission rates that are being 

achieved by the majority of existing 

units, the final standards should be the 

same for new, modified, and 

reconstructed units. 

b. Emission Standards for Non-Base 

Load Natural Gas-Fired Units and MultiFuel-Fired Units 

Many commenters stated that the EPA 

cannot finalize ‘‘no emission standard’’ 

for non-base load units, which the EPA 

solicited comment on in the broad 

applicability approach. They argued 

that this approach was not consistent 

with the definition of ‘‘standard of 

performance’’ in CAA section 111(a)(1), 

which requires there to be an ‘‘emission 

limitation’’ that reflects a ‘‘system of 

emission reduction.’’ Some commenters 

recommended that non-base load units 

should be subject to work practice 

standards, such as operating safely with 

good air pollution control practices, 

including CO2 monitoring and reporting 

requirements. Other commenters 

pointed to recent PSD permits that 

include tiered emission limits for the 

different roles served by combustion 

turbines. They cited BACT limits from 

1,328 to 1,450 lb CO2/MWh-g for 

peaking units. One commenter 

supported tiered limits consistent with 

recent BACT determinations in the state 

of New York, which include limits for 

simple cycle combustion turbines of 

1,450 lb CO2/MWh-g. An air quality 

regulator from a state with rapidly 

increasing renewable generation 

supported a limit of 825 lb CO2/MWhg for all base load NGCC units; 1,000 lb 

CO2/MWh-g for large intermediate load 

NGCC units; 1,100 lb CO2/MWh-g for 

small intermediate load NGCC units. 

This commenter also recommended that 

the EPA set a numerical limit 

specifically for peaking units after the 

completion of a peaking unit-specific 

BSER analysis. Several commenters 

supported tiered standards based on 

capacity factor. They proposed 825 lb 

CO2/MWh-g for base load units (those 

operating over 4,000 hours annually), 

875 lb CO2/MWh-g for intermediate and 

load-following units (those operating 

between 1,200 and 4,000 hours 

annually), and 1,100 lb CO2/MWh-g for 

peaking units (those operating less than 

1,200 hours per year). 

3. Final Standards 

a. Newly Constructed Base Load Natural 

Gas-Fired Units 

In evaluating the achievability of the 

base load natural gas-fired emission 

standard, we focused on three types of 

data. Specifically, we looked at existing 

NGCC emission rates, recent PSD permit 

limits for CO2 emissions, and NGCC 

design efficiency data and 

specifications. Based on this analysis, 

we have concluded that an emission 

rate of 1,000 lb CO2/MWh-g is 

appropriate for all base load natural gasfired combustion turbines, regardless of 

size. 

Since the standards were proposed, 

the EPA has expanded the NGCC 

emission rate analysis that supported 

the proposed emission standards to 

include emissions information for 

NGCC units that commenced operation 

in 2011, 2012, and 2013, and updated 

the emissions data to include emissions 

through 2014. In our analysis, we 

evaluated 345 NGCC units with online 

dates ranging from 2000 to 2013. The 

analysis included emissions data from 

2007 to 2014 as submitted to the EPA’s 

CAMD. The average maximum 12- 

operating-month CO2 emission rate for 

all NGCC units was 897 lb CO2/MWhg, with individual unit maximums 

ranging from 751 to 1,334 lb CO2/MWhg. 

Consistent with our proposed sizebased subcategories, we also reviewed 

the emissions data for small and large 

NGCC units separately. For small units, 

we evaluated emissions data from 17 

NGCC units with heat input ratings of 

850 MMBtu/h or less. These units had 

an average maximum 12-operatingmonth CO2 emission rate of 953 lb/

MWh-g. Individual unit maximum 

emission rates ranged from 898 to 1,175 

lb CO2/MWh-g. Two of the units had a 

maximum emissions rate equal to or 

greater than 1,000 lb CO2/MWh-g.537

However, one of the units with a 

maximum emission rate above 1,000 lb 

CO2/MWh-g was only selling 

approximately 20 percent of its 

potential electric output (significantly 

below the design-specific percentage 

electric sales threshold) when the 

emission rate occurred. If this unit were 

a new unit, the applicable emission 

standard would be the heat input-based 

clean fuels standard, and the unit would 

not be out of compliance. Therefore, 16 

of the 17 existing small NGCC units 

have demonstrated that an emission rate 

of 1,000 lb CO2/MWh-g is achievable. In 

addition, the six newest units, which 

commenced construction between 2007 

and 2012, all have maximum 12- 

operating-month emission rates of less 

than 950 lb CO2/MWh-g. While these 

units might not be old enough to have 

experienced degradation, their 

maximum emission rates demonstrate 

that the final standard of 1,000 lb CO2/ 

MWh-g includes a significant 

compliance margin for any future 

degradation. 

For large units, the average maximum 

12-operating-month emission rate was 

895 lb CO2/MWh-g, with individual unit 

maximum emission rates ranging from 

751 to 1,334 lb CO2/MWh-g. Twentythree of the 328 large NGCC units had 

maximum 12-operating-month emission 

rates greater than 1,000 lb CO2/MWh-g. 

While we do not have precise design 

efficiency information for each of these 

units, and thus cannot calculate the 

precise percentage electric sales 

threshold to which each unit would be 

subject, it appears that all of the 

emission rates in excess of 1,000 lb CO2/ 

MWh-g occurred during periods when 

electric sales were low and would be 

below the threshold. Thus, if these units 

were new units, they would only have 

to comply with the heat input-based 

clean fuels standard. Therefore, 

essentially all existing NGCC units 

would have been in compliance with 

the final emission standard. We note 

also that there are 51 new NGCC units 

that have started operation since 2010, 

and the average maximum 12-operatingmonth emission rate for these units is 

833 lb CO2/MWh-g. Therefore, the final 

emission standard includes a very 

significant compliance margin to 

account for any potential future 

degradation of large units. 

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To evaluate degradation further, the 

EPA reviewed the emission rate 

information for the 55 oldest NGCC 

units in our data set (i.e., units that 

came online in 2000 and 2001). 

According to the commenters, we 

should expect to see degradation when 

reviewing the annual emissions data for 

these turbines because they are 14 to 15 

years old. However, we did not see any 

sign of degradation. The CO2 rates for 

these turbines have little standard 

deviation between 2007 and 2014. In 

addition, there were many instances 

where the CO2 emission rate of a unit 

actually decreased with age. This 

indicates that the efficiency of the unit 

is increasing, possibly as a result of 

good operating and maintenance 

procedures or upgrades to equipment 

that improved efficiency beyond the 

original design. Based on these findings, 

we have concluded that our analysis 

adequately accounts for potential 

degradation. 

We also evaluated the impact of 

elevation, ambient temperature, cooling 

type, and operating conditions (startups, 

shutdowns, and average run time per 

start) because commenters indicated 

that these could affect a unit’s ability to 

achieve the standard. We saw little 

correlation between elevation or 

ambient temperature and emission rate. 

In addition, any correlation was 

relatively small and would have an 

insignificant impact on the ability of a 

unit to achieve the final standard. We 

identified 32 large NGCC units with dry 

cooling towers. The average maximum 

12-operating-month emission rate for 

this group of units was 875 lb CO2/

MWh. This rate was actually lower than 

the average rate for the large NGCC 

group as a whole. Based on these 

findings, we have concluded that the 

final emission standard will not limit 

the use of dry cooling technologies. 

Finally, the EPA evaluated the impact of 

run time per start, average duty cycle, 

and number of starts on emission rates. 

While these factors do influence 

emission rates, the non-base load 

natural gas-fired subcategory inherently 

addresses efficiency issues related to 

operating conditions. 

In addition to evaluating existing 

NGCC emissions data, the EPA reviewed 

the CO2 emission limits included in 

PSD preconstruction permits issued 

since January 1, 2011. We evaluated all 

permit limits over an annual period. In 

total, we identified 31 major source PSD 

permits with 39 discrete limits on CO2

emissions. Eight of the limits were 

expressed in terms of lb/h or tons per 

year, so we did not include them in the 

analysis. In addition, one CHP unit that 

generates electricity and supplies steam 

to a chemical plant was in the data set. 

This facility had a permit limit of 1,362 

lb CO2/MWh based only on gross 

electrical output and does not account 

for useful thermal output. Therefore, we 

did not include it in the analysis either. 

Finally, we excluded two permits that 

did not clearly specify if the outputbased standard was on a gross or net 

basis. 

The remaining 28 permit limits were 

expressed in lb CO2/MWh or a heat rate 

basis that could be converted to lb CO2/ 

MWh. Eight permit limits were based on 

net output, ranging from 774–936 lb 

CO2/MWh-n. The lowest emission limit 

was for a hybrid power plant with a 

solar component that could contribute 

up to 50 MW. Twenty permit limits 

were based on gross output, ranging 

from 833–1,100 lb CO2/MWh-g. Of these 

28 permit limits, the only limit in excess 

of our final emission standard of 1,000 

lb CO2/MWh-g is for a relatively small 

NGCC unit (base load rating of 366 

MMBtu/h) that commenced 

construction prior to the proposal and 

thus will not be subject to the 

requirements of this final rule. 

Each of the permit limits discussed 

above that is 1,000 lb CO2/MWh or less 

includes all periods of operation, 

including startup, shutdown, and 

malfunction events. In addition, each 

permit limit was set after back up and 

additional fuel use were taken into 

consideration. While some permits 

restrict fuel use to only natural gas, 

others allow limited usage (duration and 

type) of back up and other fuels. For 

example, the Pioneer Valley Energy 

Center has unrestricted use of natural 

gas, but can burn ultra-low sulfur diesel 

(ULSD) for up to 1,440 hours per 12- 

month period. This permit requires the 

unit to comply with a limit of 895 lb 

CO2/MWh-n even when burning up to 

16 percent distillate oil. Each permit 

limit takes into account the mode of 

operation for the combustion turbine. 

For example, the permit for the Lower 

Colorado River Authority’s Ferguson 

plant evaluated emission limits for the 

plant at 50, 75, and 100 percent gross 

load. The emission limit of 918 lb CO2/ 

MWh-n accounts for the unit’s expected 

operation at 50 percent gross load. For 

NGCC units with duct burners on their 

HRSGs, the permit limits account for the 

hours of operation with duct burners 

firing. Finally, most of these permits 

include compliance margins to account 

for efficiency losses due to degradation 

and other factors (e.g., actual operating 

parameters, site-specific design 

considerations, and the use of back up 

fuel). In total, these compliance margins 

result in a 10 to 13 percent increase in 

the permitted CO2 emission limits, yet 

all of the limits except one were still 

below 1,000 lb CO2/MWh-g. 

Finally, we also reviewed NGCC 

design efficiency data and specifications 

submitted to Gas Turbine World. 

Specifically, we reviewed the reported 

efficiency data for 88 different 60 Hz 

NGCC units manufactured by Alstom, 

GE Energy Aeroderivative and Heavy 

Duty, Mitsubishi Heavy Industries, Pratt 

& Whitney, Rolls-Royce, and Siemens 

Energy. The designs ranged in model 

year from 1977 to 2011, capacities 

ranged from 31 to 1,026 MW, and base 

load ratings ranged from 236 to 3,551 

MMBtu/h. The average reported design 

emission rate for these units was 834 lb 

CO2/MWh-n and ranged from 725 to 941 

lb CO2/MWh-n. Therefore, our optional 

standard of 1,030 lb CO2/MWh-n would 

allow for an average compliance margin 

of 24 percent, with a range from 10 to 

42 percent, over the design rate. Ninetyfive percent of designs would have a 

compliance margin of 13 percent or 

more, the top end of the range of 

compliance margins determined to be 

appropriate in the PSD permits we 

reviewed. 

Because some commenters were 

concerned that smaller NGCC units will 

not be able to achieve the emission 

standard, we specifically considered the 

design rates for smaller units. For the 52 

small units (base load rating of 850 

MMBtu/h or less), the average design 

emission rate was 865 lb CO2/MWh and 

ranged from 796 to 941 lb CO2/MWh-n. 

Therefore, our optional standard of 

1,030 lb CO2/MWh-n would allow for an 

average compliance margin of 19 

percent, with a range of 10 to 29 

percent, over the design rate. Ninetyfive percent of small NGCC designs 

would have a compliance margin of 13 

percent or more. 

We further refined our analysis by 

only considering the most efficient 

design for a given combustion turbine 

engine. For example, GE Energy 

Aeroderivative offers four design 

options for its LM2500 model-type, all 

with a rating of approximately 45 MW. 

The design emission rates for these 

various options range from 827 to 914 

lb CO2/MWh-n. When only the most 

efficient models for a particular 

combustion turbine engine design are 

considered, all NGCC models have over 

a 13 percent compliance margin. In 

other words, developers of new base 

load natural gas-fired combustion 

turbines concerned about the 

achievability of the final standard have 

multiple more efficient options offered 

by the same manufacturer. Therefore, 

we have concluded that the final 

emission standard allows sufficient 

flexibility for end users to select an 

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64620 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

538 ‘‘Exergetic and Economic Evaluation of the 

Effects of HRSG Configurations on the Performance 

of Combined Cycle Power Plants.’’ M. Mansouri, et 

al. Energy Conversion and Management 58:47–58, 

2012. 

539 ‘‘Combined Cycle Power Plant Performance 

Analyses Based on Single-Pressure and 

Multipressure Heat Recovery Steam Generator.’’ M. 

Rahim, Journal of Energy Engineering, 138:136–145, 

2012. 

540 ‘‘Thermodynamic Evaluation of Combined 

Cycle Plants.’’ N. Woudstras et al. Energy 

Conversion and Management 51:1099–1110, 2010. 

NGCC design appropriate for their 

specific requirements. 

After considering these three sources 

of information—actual NGCC emission 

rate data, PSD permit limits for NGCC 

facilities, and NGCC design 

information—we have concluded that a 

standard of 1,000 lb CO2/MWh is both 

achievable and appropriate for newly 

constructed base load natural gas-fired 

combustion turbines. While we 

anticipate that the large majority of new 

NGCC units will operate well below this 

emission rate, this standard provides 

flexibility for developers to take into 

account site-specific conditions (e.g., 

ambient conditions and cooling system), 

operating characteristics (e.g., part-load 

operation and frequent starting and 

stopping), and reduced efficiency due to 

degradation. The standard also 

accommodates the full size range of 

turbines. 

We also expect multiple technology 

developments to further increase the 

performance of new base load natural 

gas-fired stationary combustion 

turbines. Vendors continue to improve 

the single cycle efficiency of 

combustion turbines. The use of more 

efficient combustion turbine engines 

improves the overall efficiency of NGCC 

facilities. In addition, existing smaller 

NGCC facilities were likely designed 

using single or dual pressure HRSGs 

without a reheat cycle. New designs can 

incorporate three pressure steam 

generators with a reheat cycle to 

improve the overall efficiency of the 

NGCC facility. Finally, additional 

technologies to reduce emission rates 

for new combustion turbines include 

CHP and integrated non-emitting 

technologies. For example, an NGCC 

unit that is designed as a CHP unit 

where ten percent of the overall output 

is useful thermal output would have an 

emission rate approximately five 

percent less than an electric-only NGCC. 

In sum, we believe that our final 

emission standards of 1,000 lb CO2/

MWh-g and 1,030 lb CO2/MW-n are not 

only readily achievable, but likely 

conservative. 

b. Reconstructed Base Load Natural GasFired Units 

We disagree with commenters that 

stated that reconstructed combustion 

turbines will not be able to achieve the 

proposed emission standards. For the 

reasons listed below, we have 

concluded that an existing base load 

natural-gas fired unit that reconstructs 

can achieve an emission rate of 1,000 lb 

CO2/MWh-g, regardless of its size. 

Highly efficient NGCC units include 

(1) an efficient combustion turbine 

engine, (2) an efficient steam cycle, and 

(3) a combustion turbine exhaust system 

that is ‘‘matched’’ to the steam cycle for 

maximum efficiency. In order for an 

existing NGCC unit to trigger the 

reconstruction provisions, the unit 

would have to essentially be entirely 

rebuilt. This would involve extensive 

upgrades to both the combustion turbine 

engine and the HRSG. Therefore, a 

reconstructed NGCC unit will be able to 

maximize the efficiency of the turbine 

engine and the steam cycle and match 

the two for maximum efficiency. 

According to comments submitted in 

response to the proposal for existing 

sources under CAA section 111(d), there 

are various options available to improve 

the efficiency of existing combustion 

turbines. One combustion turbine 

manufacturer provided comments 

describing specific technology upgrades 

for the compressor, combustor, and gas 

turbine components. This manufacturer 

stated that operators of existing turbines 

can replace older internal components 

along the gas path with state-of-the-art 

components that have higher 

aerodynamic efficiencies and improved 

seal designs. These gas-path 

enhancements enable existing sources to 

both improve the efficiency of the 

turbine engine and improve the systems 

used for cooling the metal parts along 

the hot-gas path to allow existing 

systems to achieve higher operating 

temperatures. In total, the manufacturer 

stated that utilities deploying these gaspath improvements on reconstructed 

industrial frame combustion turbines 

with nominal output ratings of 170 to 

180 MW can increase their output by 10 

MW while reducing CO2 emissions by 

more than 2.6 percent compared to 

baseline. In addition to gas-path and 

software improvements, the 

manufacturer stated that the newest 

low-NOX combustor designs can be 

retrofitted on modified and 

reconstructed turbines to achieve lower 

NOX emissions, which improves 

turndown (i.e., to enable stable 

operations at lower loads compared to 

the lowest stable load achievable at 

baseline conditions) and efficiencies 

across all load conditions. The 

manufacturer indicated that operators of 

existing combustion turbines deploying 

both state-of-the-art gas-path and 

software upgrades and combustor 

upgrades can increase output on framestyle turbines with nominal output 

ratings of 170 to 180 MW by 14 MW, 

while reducing CO2 emissions by 2.8 

percent. In addition to the preceding 

upgrades, the manufacturer stated that 

existing combustion turbines can 

achieve the largest efficiency 

improvements by upgrading existing 

compressors with more advanced 

compressor technologies, potentially 

improving the combustion turbine’s 

efficiency by an additional 3.8 percent. 

Thus, the total potential CO2 emissions 

reductions for just the combustion 

turbine portion of a combined cycle unit 

is 6.6 percent. 

In addition to upgrades to the 

combustion turbine engine, an operator 

reconstructing a NGCC unit will have 

the opportunity to improve the 

efficiency of the HRSG and steam cycle. 

For example, a steam turbine 

manufacturer identified three retrofit 

technologies available for reducing the 

CO2 emissions rate of existing steam 

turbines by 1.5 to 3 percent: (1) Steampath upgrades can minimize 

aerodynamic and steam leakage losses; 

(2) replacement of the existing high 

pressure turbine stages with state-of-theart stages capable of extracting more 

energy from the same steam supply; and 

(3) replacement of low-pressure turbine 

stages with larger diameter components 

that extract additional energy and that 

reduce velocities, wear, and corrosion. 

In addition, an operator 

reconstructing a NGCC unit could 

upgrade the entire steam cycle. For 

example, combined cycle units 

originally constructed with only a single 

pressure level can be upgraded to also 

include second and third pressure 

levels. Studies 538 539 540 show that 

converting a single pressure HRSG with 

steam reheat to a double pressure 

configuration with steam reheat can 

reduce the CO2 emission rate of a NGCC 

unit by 1.5 to 1.7 percent. These same 

studies show that converting from a 

single pressure configuration with 

reheat to a triple pressure configuration 

with reheat can yield a 1.8 to 2 percent 

reduction in the CO2 emission rate. 

Similarly, units constructed with only a 

double pressure configuration without 

reheat can obtain a 0.4 percent 

reduction by adding a reheat cycle or a 

0.9 percent reduction by converting to a 

triple pressure configuration and adding 

a reheat cycle. Existing NGCC turbines 

that convert to these advanced HRSG 

configurations and that deploy the 

previously discussed combustion 

turbine and steam turbine upgrades can 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64621 

realize CO2 emission rate reductions 

ranging from 6 to 10 percent, depending 

on their baseline design and condition. 

Based on the available options to 

improve the efficiency of existing NGCC 

units and the fact that the vast majority 

of existing NGCC units are already 

achieving emission rates of 1,000 lb 

CO2/MWh-g or less, we have concluded 

that all reconstructed NGCC units can 

achieve this emission rate. 

Finally, we note that an owner or 

operator that is considering 

reconstructing an existing simple cycle 

turbine should decide how they wish to 

operate that turbine in the future. If they 

anticipate operating above the 

percentage electric sales threshold, then 

they should install a HRSG and steam 

turbine and convert to a NGCC power 

block in accordance with our 

determination that NGCC is the BSER 

for base load applications. If they intend 

to operate the turbine below the 

percentage electric sales threshold, 

however, then the clean fuels standard, 

described below, will apply. 

c. Newly Constructed and 

Reconstructed Non-Base Load Natural 

Gas-Fired Units 

The EPA agrees with the commenters 

who stated that ‘‘no emission limit’’ 

would be inconsistent with the 

requirements of CAA 111(a)(1). We 

therefore are finalizing an input-based 

standard based on the use of clean fuels 

for non-base load natural gas-fired 

combustion turbines in recognition that 

efficiency can be reduced due to 

operation at low loads, cycling, and 

frequent startups. The EPA has 

concluded that, at this time, we do not 

have sufficient information to set a 

meaningful output-based standard for 

non-base load natural gas-fired 

combustion turbines. The input-based 

standard requires non-base load units to 

burn fuels with an average emission rate 

of 120 lb CO2/MMBtu or less. This 

standard is readily achievable because 

the CO2 emission rate of natural gas is 

117 lb CO2/MMBtu. The most common 

back up fuel is distillate oil, which has 

a CO2 emission rate of 163 lb CO2/

MMBtu. A non-base load natural gasfired combustion turbine burning 9 

percent distillate oil and 91 percent 

natural gas has an emission rate of 121 

lb CO2/MMBtu, which rounds to 120 lb 

CO2/MMBtu using two significant 

digits. Therefore, the vast majority of 

owners and operators of non-base load 

natural gas-fired combustion turbines 

will be able to achieve the standard 

using business-as-usual fuels. 

While the emission reductions that 

will result from restricting the use of 

fuels with higher CO2 emission rates is 

minor, the compliance burden is also 

minimal. Owners and operators of nonbase load natural gas-fired combustion 

turbines burning fuels with consistent 

chemical compositions that meet the 

clean fuels requirement (e.g., natural 

gas, ethane, ethylene, propane, naphtha, 

jet fuel kerosene, fuel oils No. 1 and 2, 

and biodiesel) will only need to 

maintain records that they burned these 

fuels in the combustion turbine. No 

additional recordkeeping or reporting 

will be required. Owners and operators 

burning fuels with higher CO2 emission 

rates and/or chemical compositions that 

vary (e.g., residual oil, non-jet fuel 

kerosene, landfill gas) will have to 

follow the procedures in part 98 of this 

part to determine the average CO2

emission rate of the fuels burned during 

the applicable 12-operating-month 

compliance period and submit quarterly 

reports to verify that they are in 

compliance with the required emission 

standard. 

d. Newly Constructed and 

Reconstructed Multi-Fuel-Fired Units 

We also are finalizing an input-based 

standard based on the use of clean fuels, 

as opposed to an output-based standard, 

for multi-fuel units for several reasons. 

Specifically, we do not currently have 

continuous CO2 emissions data for 

multi-fuel-fired units, we have not 

evaluated the potential efficiency 

impacts of different fuels, and the range 

of carbon content of non-natural gas 

fuels complicates establishing an 

appropriate output-based standard. 

Based on this lack of data, we have 

concluded that we cannot establish an 

output-based emission standard for 

multi-fuel-fired combustion turbines at 

this time. 

The input-based emissions standard 

for this subcategory is based on the use 

of clean fuels. The use of clean fuels 

will ensure that newly constructed and 

reconstructed combustion turbines 

minimize CO2 emissions during all 

periods of operation by limiting the use 

of fuels with higher CO2 emission rates. 

To accurately represent the BSER and 

limit the ability of units to co-fire higher 

CO2 emitting fuels with natural gas, we 

have concluded that it is necessary to 

use an equation based on the heat input 

from natural gas to determine the 

applicable emission standard. The 12- 

operating-month standard will vary 

from 120 lb CO2/MMBtu to 160 lb CO2/ 

MMBtu depending on the fraction of 

heat input from natural gas. The 

standard will be calculated by adding 

the product of the percent of heat input 

from natural gas and 120 with the 

product of the heat input from nonnatural gas fuels and 160. For example, 

a combustion turbine that burns 80 

percent natural gas and 20 percent 

distillate oil would be subject to an 

emission standard of 130 lb CO2/MMBtu 

(rounded to two significant figures), 

which is equivalent to the actual 

emission rate of a unit burning this 

combination of fuels. On the other hand, 

a combustion turbine that burns 100 

percent residual oil would be subject to 

an emission standard of 160 lb CO2/

MMBtu, but would have a higher actual 

emission rate, and would thus be out of 

compliance. In this way, the standard 

will restrict higher carbon fuels from 

being burned in multi-fuel-fired units, 

but will be readily achievable by units 

burning clean fuels. 

According to information submitted 

to the EIA, the primary, non-natural gas 

fuels used by combustion turbines today 

for the production of electricity should 

all meet our definition of a clean fuel. 

Thus, while the emission reductions 

that will result from restricting the use 

of fuels with higher CO2 emission rates 

is minor, the compliance burden is also 

minimal. Owners and operators of 

multi-fuel-fired combustion turbines 

burning fuels with consistent chemical 

compositions that meet the clean fuels 

requirement (e.g., natural gas, ethylene, 

propane, naphtha, jet fuel kerosene, fuel 

oils No. 1 and 2, and biodiesel) will 

only need to maintain records that they 

burned these fuels in the combustion 

turbine. No additional recordkeeping or 

reporting will be required. Owners and 

operators burning fuels with higher CO2

emission rates and/or chemical 

compositions that vary (e.g., residual 

oil, non-jet fuel kerosene, landfill gas) 

will have to follow the procedures in 

part 98 of this part to determine the 

average CO2 emission rate of the fuels 

burned during the applicable 12- 

operating-month compliance period and 

submit quarterly reports to verify that 

they are in compliance with the 

required emission standard. 

e. Modified Units 

The EPA is not finalizing the 

proposed emission standards for 

stationary combustion turbines that 

conduct modifications. As explained in 

Section XV below, we are withdrawing 

the June 2014 proposal with respect to 

these sources. We received a significant 

number of comments asserting that 

modified combustion turbines could not 

meet the proposed emission standards 

of 1,000 lb/MWh-g for large turbines 

and 1,100 lb/MWh-g for small turbines. 

For the reasons explained in Section 

IX.B.1 above, we have decided not to 

subcategorize combustion turbines 

based on size for a number of reasons 

and are setting a single standard of 

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64622 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

541As discussed above in Section VI.A of this 

preamble, a modified source that is not covered by 

a final or pending proposed standard continues to 

be an ‘‘existing source’’ and so will be covered by 

requirements under section 111(d). Under the 

definition of ‘‘existing source’’ in section 111(a)(6), 

an existing source is any source that is not a new 

source. Under the definition of ‘‘new source’’ in 

section 111(a)(2), a modified source is a new source 

only if the modification occurs after the publication 

of regulations (or proposed regulations, if earlier) 

that will be applicable to that source. Because we 

are not finalizing regulations with respect to 

modified steam turbines, and are withdrawing the 

proposal with respect to such sources, there are 

neither final regulations nor pending proposed 

regulations which will be applicable to such 

modifications. 

1,000 lb/MWh-g for all base load natural 

gas-fired turbines instead. While we are 

confident that all new and reconstructed 

units will be able to achieve this 

standard, we are less confident that all 

smaller combustion turbines that 

undertake a modification, specifically 

those that were constructed prior to 

2000, will be able to do so. Until we 

have the opportunity to further 

investigate the full range of 

modifications that turbine owners and 

operators might undertake, we consider 

it premature to finalize emission 

standards for these sources. 

Combustion turbines have unique 

characteristics that make determining an 

appropriate emission standard for 

modified sources a more challenging 

task than for coal-fired boilers. For 

example, each combustion turbine 

engine has a specific corresponding 

combustor. The development of more 

efficient combustor upgrades for 

existing turbine designs typically 

requires manufacturers to expend 

considerable resources. Consequently, 

not all manufacturers offer combustor 

upgrades for smaller or older designs 

because it would be difficult to recoup 

their investment. In contrast, efficiency 

upgrades for boilers can generally be 

installed regardless of the specific 

boiler’s characteristics. 

In addition, natural gas has the lowest 

CO2 emission rate (in terms of lb CO2/ 

MMBtu) of any fossil fuel. As a result, 

an owner or operator that adds the 

ability to burn a back up fuel, such as 

distillate oil, to an existing turbine 

would likely trigger an NSPS 

modification. This is a relatively lowcapital-cost upgrade that would 

significantly increase a unit’s potential 

hourly emission rate, even though the 

annual emissions increase would be 

relatively minor because operating 

permits generally limit the amount of 

distillate oil that a unit can burn. We 

need to conduct additional analysis to 

determine an appropriate emission 

standard for units that undertake this 

type of modification, which does not 

involve any of the combustion turbine 

components that impact efficiency. 

To be clear, the EPA is not reaching 

a final decision that modifications 

should be subject to different 

requirements than we are finalizing in 

this rule for new and reconstructed 

sources. We have made no decisions, 

and this matter is not concluded. We 

plan to continue to gather information, 

consider the options for modifications, 

and develop a new proposal for 

modifications in the future. Therefore, 

the EPA is withdrawing the proposed 

standards for all combustion turbines 

that conduct modifications and is not 

issuing final standards for those sources 

at this time. See Section XV below. We 

note that the effect of this withdrawal is 

that modified combustion turbines will 

continue to be existing sources subject 

to section 111(d).541

X. Summary of Other Final 

Requirements for Newly Constructed, 

Modified, and Reconstructed Fossil 

Fuel-Fired Electric Utility Steam 

Generating Units and Stationary 

Combustion Turbines 

This section describes the final 

action’s requirements regarding startup, 

shutdown, and malfunction; continuous 

monitoring; emissions performance 

testing; continuous compliance; and 

notification, recordkeeping, and 

reporting for newly constructed, 

modified, and reconstructed affected 

steam generating units and combustion 

turbines. We also explain final decisions 

regarding several of these requirements. 

A. Startup, Shutdown, and Malfunction 

Requirements 

In its 2008 decision in Sierra Club v. 

EPA, 551 F.3d 1019 (D.C. Cir. 2008), the 

D.C. Circuit vacated portions of two 

provisions in the EPA’s CAA section 

112 regulations governing the emissions 

of hazardous air pollutants (HAP) 

during periods of startup, shutdown, 

and malfunction (SSM). Specifically, 

the Court vacated the SSM exemption 

contained in 40 CFR 63.6(f)(1) and 40 

CFR 63.6(h)(1), holding that under 

section 302(k) of the CAA, emissions 

standards or limitations must be 

continuous in nature and that the SSM 

exemption violates the CAA’s 

requirement that some CAA section 112 

standards apply continuously. 

Consistent with Sierra Club v. EPA, 

the EPA has established standards in 

this rule that apply at all times. In 

establishing the standards in this rule, 

the EPA has taken into account startup 

and shutdown periods and, for the 

reasons explained below as well as in 

Section V.J.1 above, has not established 

alternate standards for those periods. 

Specifically, startup and shutdown 

periods are included in the compliance 

calculation as periods of partial load. 

The final method to calculate 

compliance is to sum the emissions for 

all operating hours and to divide that 

value by the sum of the electric energy 

output (and useful thermal energy 

output, where applicable for affected 

CHP EGUs), over a rolling 12-operatingmonth period. In their compliance 

determinations, sources must 

incorporate emissions from all periods, 

including startup or shutdown, during 

which fuel is combusted and emissions 

are being monitored, in addition to all 

power produced over the periods of 

emissions measurements. As explained 

in Section V.J.1, given that the duration 

of startup or shutdown periods is 

expected to be small relative to the 

duration of periods of normal operation 

and that the fraction of power generated 

during periods of startup or shutdown is 

expected to be very small, the impact of 

these periods on the total average over 

a 12-operating-month period is expected 

to be minimal. 

Periods of startup, normal operations, 

and shutdown are all predictable and 

routine aspects of a source’s operations. 

Malfunctions, in contrast, are neither 

predictable nor routine. Instead they 

are, by definition sudden, infrequent 

and not reasonably preventable failures 

of emissions control, process or 

monitoring equipment. (40 CFR 60.2). 

The EPA interprets CAA section 111 as 

not requiring emissions that occur 

during periods of malfunction to be 

factored into development of section 

111 standards. Nothing in CAA section 

111 or in case law requires that the EPA 

consider malfunctions when 

determining what standards of 

performance reflect the degree of 

emission limitation achievable through 

‘‘the application of the best system of 

emission reduction’’ that the EPA 

determines is adequately demonstrated. 

While the EPA accounts for variability 

in setting emissions standards, nothing 

in CAA section 111 requires the agency 

to consider malfunctions as part of that 

analysis. A malfunction should not be 

treated in the same manner as the type 

of variation in performance that occurs 

during routine operations of a source. A 

malfunction is a failure of the source to 

perform in a ‘‘normal or usual manner’’ 

and no statutory language compels the 

EPA to consider such events in setting 

CAA section 111 standards of 

performance. 

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 

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542The 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. 

543Although 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 

Continued 

category and given the difficulties 

associated with predicting or accounting 

for the frequency, degree, and duration 

of various malfunctions that might 

occur. As such, the performance of units 

that are malfunctioning is not 

‘‘reasonably’’ foreseeable. See, e.g., 

Sierra Club v. EPA, 167 F.3d 658, 662 

(D.C. Cir. 1999) (‘‘The EPA typically has 

wide latitude in determining the extent 

of data-gathering necessary to solve a 

problem. We generally defer to an 

agency’s decision to proceed on the 

basis of imperfect scientific information, 

rather than to ‘invest the resources to 

conduct the perfect study.’ ’’) See also, 

Weyerhaeuser v Costle, 590 F.2d 1011, 

1058 (D.C. Cir. 1978) (‘‘In the nature of 

things, no general limit, individual 

permit, or even any upset provision can 

anticipate all upset situations. After a 

certain point, the transgression of 

regulatory limits caused by 

‘uncontrollable acts of third parties,’ 

such as strikes, sabotage, operator 

intoxication or insanity, and a variety of 

other eventualities, must be a matter for 

the administrative exercise of case-bycase 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 offline as a result of a malfunction (as 

might happen if, for example, the bags 

in a baghouse catch fire) and the 

emission unit is a steady state type unit 

that would take days to shut down, the 

source would go from 99 percent control 

to zero control until the control device 

was repaired. The source’s emissions 

during the malfunction would be 100 

times higher than during normal 

operations. As such, the emissions over 

a 4-day malfunction period would 

exceed the annual emissions of the 

source during normal operations. As 

this example illustrates, accounting for 

malfunctions could lead to standards 

that are not reflective of (and 

significantly less stringent than) levels 

that are achieved by a well-performing, 

non-malfunctioning source. It is 

reasonable to interpret CAA section 111 

to avoid such a result. The EPA’s 

approach to malfunctions is consistent 

with CAA section 111 and is a 

reasonable interpretation of the statute. 

Given that compliance with the 

emission standard is determined on a 

12-operating-month rolling average 

basis, the impact of periods of 

malfunctions on the total average over a 

12-operating-month period is expected 

to be minimal. Thus, malfunctions over 

that period are not likely to result in a 

violation of the standard. 

In the unlikely event that a source 

fails to comply with the applicable CAA 

section 111 standards as a result of a 

malfunction event, the EPA would 

determine an appropriate response 

based on, among other things, the good 

faith efforts of the source to minimize 

emissions during malfunction periods, 

including preventative and corrective 

actions, as well as root cause analyses 

to ascertain and rectify excess 

emissions. The EPA would also 

consider whether the source’s failure to 

comply with the CAA section 111 

standard was, in fact, sudden, 

infrequent, not reasonably preventable 

and was not instead caused in part by 

poor maintenance or careless operation. 

40 CFR 60.2 (definition of malfunction). 

If the EPA determines in a particular 

case that an enforcement action against 

a source for violation of an emission 

standard is warranted, the source can 

raise any and all defenses in that 

enforcement action and the federal 

district court will determine what, if 

any, relief is appropriate. The same is 

true for citizen enforcement actions. 

Similarly, the presiding officer in an 

administrative proceeding can consider 

any defense raised and determine 

whether administrative penalties are 

appropriate. 

In summary, the EPA interpretation of 

the CAA and, in particular, CAA section 

111 is reasonable and encourages 

practices that will avoid malfunctions. 

Administrative and 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 

case-by-case enforcement discretion 

approach is adequate); but see Marathon 

Oil Co. v. EPA, 564 F.2d 1253, 1272–73 

(9th Cir. 1977) (requiring a more 

formalized approach to consideration of 

‘‘upsets beyond the control of the permit 

holder’’). Under the EPA’s regulatory 

affirmative defense provisions, if a 

source could demonstrate in a judicial 

or administrative proceeding that it had 

met the requirements of the affirmative 

defense in 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.’’).542 In light of NRDC, 

the EPA is not including a regulatory 

affirmative defense provision in this 

final rule. As explained above, if a 

source is unable to comply with 

emissions standards as a result of a 

malfunction, the EPA may use its caseby-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.543

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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). 

B. Continuous Monitoring Requirements 

The majority of comments received on 

the proposal supported the EPA’s use of 

existing monitoring requirements under 

the Acid Rain Program, which are 

contained in 40 CFR part 75 

requirements. In response to this, the 

EPA is finalizing monitoring 

requirements that incorporate and 

reference the part 75 monitoring 

requirements for the majority of the CO2

and energy output monitoring 

requirements while ensuring accuracy 

and stringency required under the 

program. 

This final rule requires owners or 

operators of EGUs that combust solid 

fossil fuel to install, certify, maintain, 

and operate continuous emission 

monitoring systems (CEMS) to measure 

CO2 concentration, stack gas flow rate, 

and (if needed) stack gas moisture 

content in accordance with 40 CFR part 

75, in order to determine hourly CO2

mass emissions rates (tons/hr). 

The rule allows owners or operators 

of affected EGUs that burn exclusively 

gaseous or liquid fuels to install fuel 

flow meters as an alternative to CEMS 

and to calculate the hourly CO2 mass 

emissions rates using Equation G–4 in 

appendix G of part 75. To implement 

this option, hourly measurements of 

fuel flow rate and periodic 

determinations of the gross calorific 

value (GCV) of the fuel are also 

required, in accordance with appendix 

D of part 75. 

In addition to requiring monitoring of 

the CO2 mass emission rate, the rule 

requires EGU owners or operators to 

monitor the hourly unit operating time 

and ‘‘gross output’’, expressed in 

megawatt hours (MWh). The gross 

output includes electrical output plus 

any mechanical output, plus 75 percent 

of any useful thermal output. 

The rule requires EGU owners or 

operators to prepare and submit a 

monitoring plan that includes both 

electronic and hard copy components, 

in accordance with 40 CFR 75.53(g) and 

(h). The electronic portion of the 

monitoring plan should be submitted to 

the EPA’s CAMD using the Emissions 

Collection and Monitoring Plan System 

(ECMPS) Client Tool. The hard copy 

portion of the plan should be sent to the 

applicable state and EPA Regional 

office. Further, all monitoring systems 

used to determine the CO2 mass 

emission rates have to be certified 

according to 40 CFR 75.20 and section 

6 of part 75, appendix A within the 180- 

day window of time allotted under 40 

CFR 75.4(b), and are required to meet 

the applicable on-going quality 

assurance procedures in appendices B 

and D of part 75. 

The rule requires all valid data 

collected and recorded by the 

monitoring systems (including data 

recorded during startup, shutdown, and 

malfunction) to be used in assessing 

compliance. Failure to collect and 

record required data is a violation of the 

monitoring requirements, except for 

periods of monitoring system 

malfunctions, repairs associated with 

monitoring system malfunctions, and 

required monitoring system quality 

assurance or quality control activities 

that temporarily interrupt the 

measurement of stack emissions (e.g., 

calibration error tests, linearity checks, 

and required zero and span 

adjustments). 

The rule requires only those operating 

hours in which valid data are collected 

and recorded for all of the parameters in 

the CO2 mass emission rate equation to 

be used for calculating compliance with 

applicable emission limits. Additionally 

for EGUs using CO2 CEMS, only 

unadjusted stack gas flow rate values 

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 carbonbased F-factors using Equation F–7b in 

section 3.3.6 of appendix F of part 75 is 

allowed, and use of these Fc values in 

the emissions calculations instead of 

using the default Fc values in the 

Equation G–4 nomenclature is also 

allowed. 

This final rule includes the following 

special compliance provisions for units 

with common stack or multiple stack 

configurations; these provisions are 

consistent with 40 CFR 60.13(g): 

• If two or more EGUs share a 

common exhaust stack, are subject to 

the same emission limit, and the 

operator is required to (or elects to) 

determine compliance using CEMS, 

then monitoring the hourly CO2 mass 

emission rate at the common stack 

instead of monitoring each EGU 

separately is allowed. If this option is 

chosen, the hourly gross electrical load 

(or steam load) is the sum of the hourly 

loads for the individual EGUs and the 

operating time is expressed as ‘‘stack 

operating hours’’ (as defined in 40 CFR 

72.2). Then, if compliance with the 

applicable emission limit is attained at 

the common stack, each EGU sharing 

the stack will be in compliance with the 

CO2 emissions limit. 

• If the operator is required to (or 

elects to) determine compliance using 

CEMS and the effluent from the EGU 

discharges to the atmosphere through 

multiple stacks (or, if the effluent is fed 

to a stack through multiple ducts and is 

monitored in the ducts), then 

monitoring the hourly CO2 mass 

emission rate and the ‘‘stack operating 

time’’ at each stack or duct separately is 

required. In this case, compliance with 

the applicable emission limit is 

determined by summing the CO2 mass 

emissions measured at the individual 

stacks or ducts and dividing by the total 

gross output for the unit. 

The rule requires 95 percent of the 

operating hours in each compliance 

period (including the compliance 

periods for the intermediate emission 

limits) to be valid hours, i.e., operating 

hours in which quality-assured data are 

collected and recorded for all of the 

parameters used to calculate CO2 mass 

emissions. EGU owners or operators 

have the option to use back up 

monitoring systems, as provided in 40 

CFR 75.10(e) and 75.20(d), to help meet 

this data capture requirement. This 

requirement is separate from the 

requirement for a source to demonstrate 

compliance with an applicable emission 

standard. When demonstrating 

compliance with an emission standard 

the calculation must use all valid data 

to calculate a compliance average even 

if the percent of valid hours recorded in 

the period is less than the 95 percent 

requirement. 

C. Emissions Performance Testing 

Requirements 

Similarly to the comments received 

on monitoring for the proposal, 

commenters in general supported the 

use of current testing requirements 

required under the Acid Rain Program 

40 CFR part 75 requirements. Thus the 

EPA is finalizing requirements for 

performance testing as consistent with 

part 75 requirements where appropriate 

to ensure the quality and accuracy of 

data and measurements as required by 

the final rule. 

In accordance with 40 CFR 75.64(a), 

the final rule requires an EGU owner or 

operator to begin reporting emissions 

data when monitoring system 

certification is completed or when the 

180-day window in 40 CFR 75.4(b) 

allotted for initial certification of the 

monitoring systems expires (whichever 

date is earlier). For EGUs subject to the 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64625 

1,400 lb CO2/MWh-g) emission 

standard, the initial performance test 

consists of the first 12 operating months 

of data, starting with the month in 

which emissions are first required to be 

reported. The initial 12-operating-month 

compliance period begins with the first 

month of the first calendar year of EGU 

operation in which the facility exceeds 

the capacity factor applicability 

threshold. 

The traditional 3-run performance 

tests (i.e., stack tests) described in 40 

CFR 60.8 are not required for this rule. 

Following the initial compliance 

determination, the emission standard is 

met on a 12-operating-month rolling 

average basis. 

D. Continuous Compliance 

Requirements 

Commenters supported the use of a 

12-operating-month rolling average for 

the compliance period for the final 

standards. In response, this final rule 

specifies that compliance with the 1,400 

lb CO2/MWh-g emission limit is 

determined on a 12-operating-month 

rolling average basis, updated after each 

new operating month. For each 12- 

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 40 CFR 75.64(a), i.e., either the 

month in which monitoring system 

certification is completed or the month 

in which the 180-day window allotted 

to finish certification testing expires 

(whichever month is earlier). 

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-operating-month 

period. Affected EGUs continue to be 

subject to the standards and 

maintenance requirements in the CAA 

section 111 regulatory general 

provisions contained in 40 CFR part 60, 

subpart A. 

Several commenters stated that the 

final rule should require operators to 

round their calculated emissions rates to 

three significant figures when 

comparing their actual rates to the 

standard. These commenters said that 

allowing use of only two significant 

digits when calculating the 12- 

operating-month rolling average 

emission rate would constitute 

relaxation of the standard by 5 percent 

because an actual emission rate of 

1,049.9 lb CO2/MWh rounds to 1,000 lb 

of CO2 per MWh when only two 

significant figures are required in the 

final step of compliance calculations. 

Commenters also suggested that the 

emission limits be written in scientific 

notation (e.g., 1.10 x 10¥3 lb CO2/

MWh) to clarify the number of 

significant digits that should be used 

when evaluating compliance. Other 

commenters suggested that the final step 

in compliance calculations should 

reflect rounding the emission rate to the 

nearest whole number using the ASTM 

rounding convention (ASTM E29). 

The General Provisions of Part 60 

specify the rounding conventions for 

compliance calculations at 40 CFR 

60.13(h)(3) including the provision that 

‘‘after conversion into units of the 

standard, the data may be rounded to 

the same number of significant digits 

used in the applicable subpart to specify 

the emission limit.’’ 

The final rule requires that the 12- 

operating-month rolling average 

emission rate must be rounded to three 

significant figures if the applicable 

emissions standard is greater than or 

equal to 1,000 (e.g., an actual emission 

rate of 1,004.9 lb CO2/MWh is rounded 

to 1,000 lb CO2/MWh); for standards of 

1000 or less, the final rule requires 

rounding the actual emission rate to two 

significant figures (e.g., an actual 

emission rate of 454.9 kg CO2/MWh is 

rounded to 450 kg CO2/MWh). 

Historically, many of the emissions 

limits under part 60 have been 

expressed to two significant digits (e.g., 

the original SO2 emission standard for 

coal-fired units under Subpart D was 1.2 

lb SO2/MMBtu). The rounding 

conventions under the General 

Provisions allow the reporting of all 

emission rates in the range from 1.15 to 

1.249 as 1.2 lb SO2/MMBtu. During 

compliance periods with emissions at 

the lower end of this range, the operator 

is required to report higher emissions 

than actually occurred; during 

compliance periods at the upper end of 

this range the operator is allowed to 

report lower emissions than actually 

occurred. In either case the absolute 

error remains small because the 

emission rate in this example is a 

relatively small numerical value. In 

addition, the required emission 

reductions typically are large enough 

that rounding does not impact the 

emission control strategy of affected 

units. However, the final standards for 

CO2 emissions include numerical values 

that are larger than many historical 

emissions standards and require a 

relatively small percent reduction in 

emissions. Accordingly, it is appropriate 

to require the use of three significant 

digits when completing compliance 

calculations resulting in numerical 

values larger than 1,000. This is 

particularly important when 

considering the relatively small 

emission rate changes that may be 

required for compliance with the unitspecific emission standards being 

finalized for modified steam generating 

and IGCC units because a rounding error 

of 5 percent may be larger than the 

percent difference between the affected 

unit’s historically best emission rate and 

the emission rate immediately 

preceding the modification. 

The final rule requires rounding of 

emission rates with numerical values 

greater than or equal to 1,000 to three 

significant figures and rounding of rates 

with numerical values less than 1,000 to 

two significant figures. 

E. Notification, Recordkeeping, and 

Reporting Requirements 

Commenters supported the 

coordination of notification, 

recordkeeping, and reporting required 

under this rule in conjunction with the 

requirements already in place under 

part 75, so the EPA has made the 

requirements as efficient and 

streamlined as possible with the current 

requirements under part 75. The final 

rule requires an EGU owner or operator 

to comply with the applicable 

notification requirements in 40 CFR 

75.61, 40 CFR 60.7(a)(1) and (a)(3), and 

40 CFR 60.19. The rule also requires the 

applicable recordkeeping requirements 

in subpart F of part 75 to be met. For 

EGUs using CEMS, the data elements 

that are recorded include, among others, 

hourly CO2 concentration, stack gas 

flow rate, stack gas moisture content (if 

needed), unit operating time, and gross 

electric generation. For EGUs that 

exclusively combust liquid and/or 

gaseous fuel(s) and elect to determine 

CO2 emissions using Equation G–4 in 

appendix G of part 75, the key data 

elements in subpart F that are recorded 

include hourly fuel flow rates, fuel 

usage times, fuel GCV, gross electric 

generation. 

The rule requires EGU owners or 

operators to keep records of the 

calculations they perform to determine 

the total CO2 mass emissions and gross 

output for each operating month. 

Records of the calculations performed to 

determine the average CO2 mass 

emission rate (kg/MWh) and the 

percentage of valid CO2 mass emission 

rates in each compliance period are 

required to be kept. The rule also 

requires sources to keep records of 

calculations performed to determine 

site-specific carbon-based F-factors for 

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64626 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

544Although Congress expressed a clear 

preference that new sources would be ‘‘designed, 

built, equipped, operated, and maintained so as to 

reduce emissions to a minimum,’’ the Senate 

Committee Report also makes clear that the term 

standard of performance ‘‘refers to the degree of 

emission control which can be achieved through 

process changes, operation changes, direct emission 

control, or other methods.’’ Sen. Rep. No. 91–1196 

at 15–17, 1970 CAA Legis. Hist. at 415–17 

(emphasis added). 

545Sen. Rep. No. 91–1196 at 15–16, 1970 CAA 

Legis. Hist. at 416 (emphasis added). 

546See 1970 CAA Amendments, Pub. L. 91–604, 

section 4, 84 Stat. 1676, 1679 (Dec. 31, 1970) 

(describing information that the EPA must issue to 

the states and appropriate air pollution control 

agencies along with the issuance of ambient air 

quality criteria under Section 4 of the 1970 CAA 

titled ‘‘Ambient Air Quality and Emission 

Standards’’). 

547 In the 1977 CAA Amendments, Congress 

revised section 111(a)(1) to mandate that the EPA 

base standards for new sources on technological 

controls, but, at the same time, made clear that the 

EPA was not required to base the emission 

guidelines for existing sources on technological 

controls. In the 1990 CAA Amendments, Congress 

repealed the section 111(a)(1) requirements that 

distinguished between new and existing sources 

and largely restored the 1970 CAA Amendments 

version of section 111(a)(1). 

use in Equation G–4 of part 75, 

appendix G (if applicable). 

Sources are required to keep all 

records for a period of 3 years. All 

required records must be kept on-site for 

a minimum of two years, after which the 

records can be maintained 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 40 CFR 60.5555 

to be submitted using the ECMPS Client 

Tool. Except for a few EGUs that may 

be exempt from the Acid Rain Program 

(e.g., 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 agency-wide effort to 

streamline and facilitate the reporting of 

environmental data, the rule requires 

selected data elements that pertain to 

compliance under this rule, and that 

serve the purpose of identifying 

violations of an emission standard, to be 

reported periodically using ECMPS. 

Specifically, EGU owners/operators 

must submit quarterly electronic reports 

within 30 days after the end of each 

quarter consistent with current part 75 

reporting requirements. The first report 

is for the quarter that includes the final 

(12th) operating month of the initial 12- 

operating-month compliance period. For 

that initial report and any subsequent 

report in which the 12th operating 

month of a compliance period (or 

periods) occurs during the calendar 

quarter, the average CO2 mass emissions 

rate (kg/MWh) is reported for each 

compliance period, along with the dates 

(year and month) of the first and twelfth 

operating months in the compliance 

period and the percentage of valid CO2

mass emission rates obtained in the 

compliance period. The dates of the first 

and last operating months in the 

compliance period clearly bracket the 

period used in the determination, which 

facilitates auditing of the data. 

Reporting the percentage of valid CO2

mass emission rates is necessary to 

demonstrate compliance with the 

requirement to obtain valid data for 95 

percent of the operating hours in each 

compliance period. Any violations that 

occur during the quarter are identified. 

If there are no compliance periods that 

end in the quarter, a definitive 

statement to that effect must be 

included in the report. If one or more 

compliance periods end in the quarter 

but there are no violations, a statement 

to that effect must be included in the 

report. 

Currently, ECMPS is not programmed 

to receive the additional information 

included in the report required under 40 

CFR 60.5555(a)(2) for affected EGUs. 

However, we will make the necessary 

modifications to the system in order to 

fully implement the reporting 

requirements of this rule upon 

promulgation. 

XI. Consistency Between BSER 

Determinations for This Rule and the 

Rule for Existing EGUs 

In the CAA section 111(d) rule for 

existing steam units and combustion 

turbines that the EPA is promulgating at 

the same time as this CAA section 

111(b) rule, the EPA is identifying as 

part of the BSER for those sources, 

building block 1 (for steam units, 

efficient operation), building block 2 

(for steam units, dispatch shift to 

existing NGCC units), and building 

block 3 (for steam units and combustion 

turbines, substitution of generation with 

new renewable energy). In this section, 

we explain why the EPA is not 

identifying building blocks 1, 2, or 3 as 

part of the BSER for new, modified, or 

reconstructed steam generators or 

combustion turbines. 

A. Newly Constructed Steam Generating 

Units 

1. Preference for Technological Controls 

as the BSER for New EGUs 

As discussed in this preamble and in 

more detail in the preamble to the CAA 

section 111(d) rule for existing sources, 

the phrase ‘‘system of emission 

reduction’’ is undefined and provides 

the EPA with discretion in setting a 

standard of performance under CAA 

section 111(b) or emission guidelines 

under CAA section 111(d). Because the 

phrase by its plain language does not 

limit our review of potential systems in 

either context, the same systems could 

be considered for application in new 

and existing sources. That said, many 

other factors and considerations direct 

us to focus on different systems when 

establishing a standard of performance 

under CAA section 111(b) and an 

emission guideline under CAA section 

111(d). Thus, it is useful to describe part 

of the underlying basis for the BSER— 

partial CCS—that the EPA has 

determined for new steam units before 

discussing the building blocks that form 

the BSER for existing units. 

For new steam generating units, the 

EPA is identifying, as the BSER, systems 

of emission reduction that assure that 

these sources are inherently lowemitting at the time of construction. The 

following reasons support this approach 

to the BSER. 

New sources are expected to have 

long operating lives over which initial 

capital costs can be amortized. Thus, 

new construction is the preferred time 

to drive capital investment in emission 

controls. In this case, the BSER for new 

steam generators, partial CCS, requires 

substantial capital expenditures, which 

new sources are best able to 

accommodate. 

While CAA section 111(b)(1)(B) and 

(a)(1) by their terms do not mandate that 

the BSER assure that new sources are 

inherently low emitting, that approach 

to the BSER is consistent with the 

legislative history.544 See Section 

III.H.3.b.4 above. For instance, the 1970 

Senate Committee Report explains that 

‘‘[t]he overriding purpose of this section 

[concerning new source performance 

standards] would be to prevent new air 

pollution problems, and toward that 

end, maximum feasible control of new 

sources at the time of their construction 

is seen by the committee as the most 

effective and, in the long run, the least 

expensive approach.’’ 545 Existing 

sources, on the other hand, would be 

regulated through emission standards, 

which were broadly understood at the 

time to reflect available technology, 

alternative methods of prevention and 

control, alternative fuels, processes, and 

operating methods.546 547

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548For example, as early as a 1979 NSPS 

rulemaking for affected EGUs, the EPA recognized 

that it was not required to establish as the BSER the 

most stringent adequately demonstrated system of 

emission reduction available, and instead could 

weigh the amount of additional emission reductions 

against the costs. See 44 FR 52792, 52798 (Sept. 10, 

1979) (‘‘Although there may be emission control 

technology available that can reduce emissions 

below those levels required to comply with 

standards of performance, this technology might not 

be selected as the basis of standards of performance 

due to costs associated with its use. Accordingly, 

standards of performance should not be viewed as 

the ultimate in achievable emission control. In fact, 

the Act requires (or has potential for requiring) the 

imposition of a more stringent emission standard in 

several situations.’’). 

549At least in theory, we could consider 

promulgating a standard of performance for new 

affected EGUs that becomes more stringent 

beginning in 7 years, based on a more stringent 

BSER. We are not inclined to adopt that approach 

because section 111(b)(1)(B) requires that we review 

and, if necessary, revise the section 111(b) 

standards of performance no later than every 8 

years anyway. 

550The EPA is authorized to consider the BSER 

for new and existing sources in conjunction with 

each other. In the 1977 CAA Amendments, 

Congress revised section 111(a)(1) to require 

technological controls for new combustion sources 

at least in part because this requirement would 

preclude new sources from relying on low-sulfur 

coal to achieve their emission limits, which, in 

turn, would free up low-sulfur coal for existing 

sources. 

2. Practical Implications of Including 

the Building Blocks 

Several practical considerations make 

the building blocks inappropriate for 

new sources. Thus, for the following 

reasons, the EPA does not consider it 

appropriate to include the building 

blocks as part of the BSER for new 

sources: 

a. Additional Cost 

Partial CCS will impose substantial 

(albeit reasonable) costs on new steamgenerating EGUs, and, as a result, the 

EPA does not believe that including 

additional measures as part of the BSER 

would be appropriate. One disadvantage 

in adding additional costs is that doing 

so would make it more difficult for new 

steam-generating EGUs to compete with 

new nuclear units. Because the BSER is 

selected after considering cost (among 

other factors), the EPA is not required 

to,548 and in this case believes it would 

not be appropriate to, select the most 

stringent adequately demonstrated 

system of emission reduction (through 

the combination of partial CCS and the 

building blocks) for purposes of setting 

a standard of performance under CAA 

section 111(b). 

Building block 1 measures are not 

appropriate (or would be redundant) 

because the BSER for new steam 

generating units is based on highly 

efficient supercritical technology, i.e., 

state-of-the-art, efficient equipment. See 

Section V.K above. Accordingly, there is 

little improvement in efficiency that can 

be justified as part of the BSER. 

Building block 2 and 3 measures are 

not appropriate for the BSER because 

new steam units would have a 

significantly limited range of options to 

implement building blocks 2 and 3. The 

new source performance standard was 

proposed and is being finalized as a 

rate-based standard. Thus, if building 

blocks 2 and 3 were included in the 

BSER, a more stringent rate-based 

standard would be applicable to all new 

sources. However, it is conceivable that 

the EPA could propose a hybrid 

standard that would include both an 

emission-rate limit that reflects partial 

CCS and a requirement for allowances 

that reflects building blocks 2 and 3. 

Accordingly, the following discussion 

assumes either a rate-based or massbased standard, or part of a hybrid 

standard. 

In both a rate-based program and a 

mass-based program, building blocks 2 

and 3 measures can be implemented 

through a range of methods, including 

trading with other EGUs. While it is not 

necessarily the case that every existing 

source will be able to implement each 

of the methods, in general, existing 

sources will have a range of measures to 

choose from. However, at least some of 

those methods may not be available to 

new sources, which would render 

compliance with their emission limits 

more challenging and potentially more 

costly. 

One example is emission trading with 

other affected EGUs. For existing 

sources, emission trading is an 

important option for implementing the 

building blocks. There are large 

numbers of existing sources, and they 

will become subject to the section 

111(d) standards of performance at the 

same time. It may be more cost-effective 

for some to implement the building 

blocks than others, and, as a result, 

some may over-comply and some may 

under-comply, and the two groups may 

trade with each other. Because of the 

large numbers of existing sources, the 

trading market can be expected to be 

robust. Trading optimizes efficiency. As 

a result, existing sources have more 

flexibility in the overall amount of their 

investment in building blocks 2 and 3 

and can adjust investment obligations 

among themselves through emissions 

trading. 

In contrast, new sources construct one 

at a time, and it is unknown how many 

new sources there will be. Without a 

sizeable number of new sources, there 

will not be a robust trading market. 

Thus, a new source cannot count on 

being able to find a new source trading 

partner. In addition, it is not possible to 

count on new sources being able to 

trade with existing sources, for several 

reasons. First, as noted, there are 

indications in the legislative history that 

new sources should be well-controlled 

at the source, which casts doubt on 

whether new sources should be allowed 

to meet their standards through the 

purchase of emission credits. Second, 

new sources must meet their standards 

of performance as soon as they begin 

operations. If they do so before the year 

2022, when existing sources become 

subject to section 111(d) state plan 

standards of performance, no existing 

sources will be available as trading 

partners. 

In addition, for section 111(d) 

sources, we are granting a 7-year period 

of lead-time for the implementation of 

the building blocks. This is due, in part, 

to the benefits of allowing the ERC and 

allowance markets to develop. However, 

the new source standards take effect 

immediately, so new sources would not 

have the advantage of this lead time 

were they subject to more stringent 

standards that also reflected the 

building blocks.549

In addition, if there are an 

unexpectedly large number of new 

sources, then they would be obliged to 

invest in greater amounts of building 

blocks 2 and 3, and that could reduce 

the amounts of building blocks 2 and 3 

available for existing sources, and 

thereby raise the costs of building 

blocks 2 and 3 for existing sources. This 

could compromise the BSER under 

section 111(d) and undermine the 

ability of existing sources to comply 

with their section 111(d) obligations.550

B. New Combustion Turbines 

For new combustion turbines, the 

building blocks are not appropriate as 

part of the BSER either. Building block 

1 is limited to steam generating units, 

and therefore has no applicability to 

new combustion turbines. Measures 

comparable to those in building block 1 

would not be appropriate because new 

highly efficient NGCC construction 

already entails high efficiency 

equipment and operation. Building 

block 2 is also limited to steam 

generating units and is not appropriate 

as part of the BSER for new NGCC units 

because it would not result in any 

emission reductions. 

The reasons why building block 3 are 

not appropriate are the same as 

discussed above for why building blocks 

2 and 3 are not appropriate for new 

steam generating units (limited range of 

options for implementation (including 

lack of availability of trading), lack of 

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lead-time for implementation, and the 

possibility of reducing the availability of 

renewable energy for existing sources). 

C. Modified and Reconstructed Steam 

and NGCC Units 

For modified and reconstructed steam 

generators, the EPA identified the BSER 

as maintenance of high efficiency or 

implementation of a highly efficient 

unit. The resulting emission limit must 

be met over the specified time period 

and cannot be deviated from or 

averaged. As a result, a modified or 

reconstructed steam generator generally 

will require ongoing maintenance and 

may find it prudent to operate below its 

limit as a safety margin. This represents 

a substantial commitment of resources. 

For these units, the additional costs of 

implementing the building blocks 

would not be appropriate. 

In addition, building block 1 is not 

appropriate for modified or 

reconstructed steam generating units 

because the BSER for these units is 

already based on highly efficient 

performance. For the same reasons, it 

does not make sense to attempt to 

develop the analogue to building block 

1 for reconstructed NGCC units—the 

BSER for them, too, is already based on 

highly efficient performance. 

Building block 2 is not appropriate for 

reconstructed NGCC units because it 

would not yield any reductions. 

Building blocks 2 and 3 are not 

appropriate for modified or 

reconstructed steam generators, and 

building block 3 is not appropriate for 

reconstructed NGCC units, for the same 

reasons that they are not appropriate for 

new EGUs, as described above (limited 

range of options for implementation 

(including lack of availability of 

trading), lack of lead-time for 

implementation, and the possibility of 

reducing the availability of renewable 

energy for existing sources). 

XII. Interactions With Other EPA 

Programs and Rules 

A. Overview 

This final rule will, for the first time, 

regulate GHGs under CAA section 111. 

In Section IX of the preamble to the 

proposed rule, the EPA addressed how 

regulation of GHGs under CAA section 

111 could have implications for other 

EPA rules and for permits written under 

the CAA Prevention of Significant 

Deterioration (PSD) preconstruction 

permit program and the CAA Title V 

operating permit program. The EPA 

proposed to adopt provisions in the 

regulations that explicitly addressed 

some of these implications. 

For purpose of the PSD program, the 

EPA is finalizing provisions in part 60 

of its regulations that make clear that 

the threshold for determining whether a 

PSD source must satisfy the BACT 

requirement for GHGs continues to 

apply after promulgation of this rule. 

This rule does not require any 

additional revisions to State 

Implementation Plans. As discussed 

further below, this final rule may have 

bearing on the determination of BACT 

for new, modified, and reconstructed 

EGUs that require PSD permits. With 

respect to the Title V operating permits 

program, this rule does not affect 

whether sources are subject to the 

requirement to obtain a Title V 

operating permit based solely on 

emitting or having the potential to emit 

GHGs above major source thresholds. 

However, this rule does have some 

implications for Title V fees, which the 

EPA is addressing in this final rule. 

Finally, the fossil fuel-fired EGUs 

covered in this rule are or will be 

potentially impacted by several other 

recently finalized or proposed EPA 

rules, and such potential interactions 

with other EPA rules are discussed 

below. 

B. Applicability of Tailoring Rule 

Thresholds Under the PSD Program 

In our January 8, 2014 proposal, the 

EPA proposed to adopt regulatory 

language in 40 CFR part 60 that would 

ensure the promulgation of this NSPS 

would not undercut the application of 

rules that limit the application of the 

PSD permitting program requirements to 

only the largest sources of GHGs. An 

intervening decision of the United 

States Supreme Court has, to a large 

extent, resolved the legal issue that led 

the EPA to propose these part 60 

provisions. The Supreme Court has 

since clarified that the PSD program 

does not apply to smaller sources based 

on the amount of GHGs they emit. 

However, because the largest sources 

emitting GHGs remain subject to the 

PSD permitting requirements, the EPA 

has concluded that it remains 

appropriate to adopt the proposed 

regulatory provisions in 40 CFR part 60 

in this rule. We discuss our reasons for 

this action in detail below. 

Under the PSD program in part C of 

title I of the CAA, in areas that are 

classified as attainment or unclassifiable 

for NAAQS pollutants, a new or 

modified source that emits any air 

pollutant subject to regulation at or 

above specified thresholds is required to 

obtain a preconstruction permit. This 

permit assures that the source meets 

specific requirements, including 

application of BACT to each pollutant 

subject to regulation under the CAA. 

Many states (and local districts) are 

authorized by the EPA to administer the 

PSD program and to issue PSD permits. 

If a state is not authorized, then the EPA 

issues the PSD permits for facilities in 

that state. 

To identify the pollutants subject to 

the PSD permitting program, EPA 

regulations contain a definition of the 

term ‘‘regulated NSR pollutant.’’ 40 CFR 

52.21(b)(50); 40 CFR 51.166(b)(49). This 

definition contains four subparts, which 

cover pollutants regulated under various 

parts of the CAA. The second subpart 

covers pollutants regulated under 

section 111 of the CAA. The fourth 

subpart is a catch-all provision that 

applies to ‘‘[a]ny pollutant that is 

otherwise subjection to regulation under 

the Act.’’ 

This definition and the associated 

PSD permitting requirements applied to 

GHGs for the first time on January 2, 

2011, by virtue of the EPA’s regulation 

of GHG emissions from motor vehicles, 

which first took effect on that same date. 

75 FR 17004 (Apr. 2, 2010). As such, 

GHGs became subject to regulation 

under the CAA and the fourth subpart 

of the ‘‘regulated NSR pollutant’’ 

definition became applicable to GHGs. 

On June 3, 2010, the EPA issued a 

final rule, known as the Tailoring Rule, 

which phased in permitting 

requirements for GHG emissions from 

stationary sources under the CAA PSD 

and Title V permitting programs (75 FR 

31514). Under its understanding of the 

CAA at the time, the EPA believed the 

Tailoring Rule was necessary to avoid a 

sudden and unmanageable increase in 

the number of sources that would be 

required to obtain PSD and Title V 

permits under the CAA because the 

sources emitted GHGs emissions over 

applicable major source and major 

modification thresholds. In Step 1 of the 

Tailoring Rule, which began on January 

2, 2011, the EPA limited application of 

PSD or Title V requirements to sources 

of GHG emissions only if the sources 

were subject to PSD or Title V 

‘‘anyway’’ due to their emissions of nonGHG 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 

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term ‘‘subject to regulation.’’ The 

limitations in Step 1 of the Tailoring 

Rule are reflected in 40 CFR 

52.21(b)(49)(iv) and 40 CFR 

51.166(b)(48)(iv). With respect to 

‘‘anyway sources’’ covered by PSD 

during Step 1, this provision established 

that GHGs would not be subject to PSD 

requirements unless the source emitted 

GHGs in the amount of 75,000 tons per 

year (tpy) of carbon dioxide equivalent 

(CO2e) or more. The primary practical 

effect of this paragraph is that the PSD 

BACT requirement does not apply to 

GHG emissions from an ‘‘anyway 

source’’ unless the source emits GHGs at 

or above this threshold. The Tailoring 

Rule Step 2 limitations are reflected in 

40 CFR 52.21(b)(49)(v) and 

51.166(b)(48)(v). These provisions 

contain thresholds that, when applied 

through the definition of ‘‘regulated 

NSR pollutant,’’ function to limit the 

scope of the terms ‘‘major stationary 

source’’ and ‘‘major modification’’ that 

determine whether a source is required 

to obtain a PSD permit. See e.g. 40 CFR 

51.166(a)(7)(i) and (iii); 40 CFR 

51.166(b)(1); 40 CFR 51.166(b)(2). 

This structure of the EPA’s PSD 

regulations created questions regarding 

the extent to which the limitations in 

the Tailoring Rule would continue to 

apply to GHGs once they became 

regulated, through this final rule, under 

section 111 of the CAA. 79 FR 1487– 

1488. As discussed above, the definition 

of ‘‘regulated NSR pollutant’’ in the PSD 

regulations contains a separate PSD 

trigger for air pollutants regulated under 

the NSPS, 40 CFR 51.166(b)(49)(ii) (the 

‘‘NSPS trigger provision’’). Thus, when 

GHGs become subject to a standard 

promulgated under CAA section 111 for 

the first time under this rule, PSD 

requirements would presumably apply 

for GHGs on an additional basis besides 

through the regulation of GHGs from 

motor vehicles. However, the Tailoring 

Rule, on the face of its regulatory 

provisions, incorporated the revised 

thresholds it promulgated into only the 

fourth subpart of the PSD definition of 

regulated NSR pollutant (‘‘[a]ny 

pollutant that otherwise is subject to 

regulation under the Act’’). The 

regulatory text does not clearly 

incorporate the thresholds into the 

NSPS trigger provision in the second 

subpart (‘‘[a]ny pollutant that is subject 

to any standard promulgated under 

section 111 of the Act’’). For this reason, 

a question arose as to whether the 

Tailoring Rule limitations would 

continue to apply to the PSD 

requirements after they are 

independently triggered for GHGs by the 

NSPS that the EPA is now 

promulgating. Stakeholders questioned 

whether the EPA must revise its PSD 

regulations —and, by the same token, 

whether states must revise their SIPs— 

to assure that the Tailoring Rule 

thresholds will continue to apply to 

sources potentially subject to PSD under 

the CAA based on GHG emissions. 

In the January 8, 2014 proposed rule, 

the EPA explained that the agency had 

included an interpretation in the 

Tailoring Rule preamble, which means 

that the Tailoring Rule thresholds 

continue to apply if and when the EPA 

promulgates requirements under CAA 

section 111. 79 FR 1488 (citing 75 FR 

31582). Nevertheless, to ensure there 

would be no uncertainty as to this issue, 

the EPA proposed to adopt explicit 

language in 40 CFR 60.46Da(j), 40 CFR 

60.4315(b), and 40 CFR 60.5515 of the 

agency’s regulations. The proposed 

language makes clear that the thresholds 

for GHGs in the EPA’s PSD definition of 

‘‘subject to regulation’’ apply through 

the second subpart of the definition of 

‘‘regulated NSR pollutant’’ to GHGs 

regulated under this rule. 

The EPA received comments 

supporting the adoption of this 

proposed language, but several 

commenters also expressed concern that 

adding this language to part 60 alone 

would not be sufficient. Several 

commenters urged the EPA to instead 

revise the PSD regulations in parts 51 

and 52. In addition, commenters 

expressed concern that further steps 

were needed to amend the SIPs before 

there would be certainty that the 

Tailoring Rule limitations continued to 

apply after the adoption of CO2

standards under CAA section 111 in this 

final rule. 

On June 23, 2014, the United States 

Supreme Court, in Utility Air Regulatory 

Group v. Environmental Protection 

Agency, issued a decision addressing 

the application of PSD permitting 

requirements to GHG emissions. The 

Supreme Court held that the EPA may 

not treat GHGs as an air pollutant for 

purposes of determining whether a 

source is a major source (or 

modification thereof) for the purpose of 

PSD applicability. The Court also said 

that the EPA could continue to require 

that PSD permits, otherwise required 

based on emissions of pollutants other 

than GHGs, contain limitations on GHG 

emissions based on the application of 

BACT. The Supreme Court decision 

effectively upheld PSD permitting 

requirements for GHG emissions under 

Step 1 of the Tailoring Rule for ‘‘anyway 

sources’’ and invalidated application of 

PSD permitting requirements to Step 2 

sources based on GHG emissions. The 

Court also recognized that, although the 

EPA had not yet done so, it could 

‘‘establish an appropriate de minimis 

threshold below which BACT is not 

required for a source’s greenhouse gas 

emissions.’’ 134 S. Ct. at 2449. 

In accordance with the Supreme 

Court decision, on April 10, 2015, the 

U.S. Court of Appeals for the District of 

Columbia Circuit (the D.C. Circuit) 

issued an amended judgment vacating 

the regulations that implemented Step 2 

of the Tailoring Rule, but not the 

regulations that implement Step 1 of the 

Tailoring Rule. The court specifically 

vacated 40 CFR 51.166(b)(48)(v) and 40 

CFR 52.21(b)(49)(v) of the EPA’s 

regulations, but did not vacate 40 CFR 

51.166(b)(48)(iv) or 40 CFR 

52.21(b)(48)(iv). The court also directed 

the EPA to consider whether any further 

revisions to its regulations are 

appropriate in light of UARG v. EPA, 

and, if so, to undertake such revisions. 

The practical effect of the Supreme 

Court’s clarification of the reach of the 

CAA is that it eliminates the need for 

Step 2 of the Tailoring Rule and 

subsequent steps of the GHG permitting 

phase in that the EPA had planned to 

consider under the Tailoring Rule. This 

also eliminates the possibility that the 

promulgation of GHG standards under 

section 111 could result in additional 

sources becoming subject to PSD based 

solely on GHGs, notwithstanding the 

limitations the EPA adopted in the 

Tailoring Rule. However, for an interim 

period, the EPA and the states will need 

to continue applying parts of the PSD 

definition of ‘‘subject to regulation’’ to 

ensure that sources obtain PSD permits 

meeting the requirements of the CAA. 

The CAA continues to require that 

PSD permits issued to ‘‘anyway 

sources’’ satisfy the BACT requirement 

for GHGs. Based on the language that 

remains applicable under 40 CFR 

51.166(b)(48)(iv) and 40 CFR 

52.21(b)(49)(iv), the EPA and states may 

continue to limit the application of 

BACT to GHG emissions in those 

circumstances where a source emits 

GHGs in the amount of at least 75,000 

tpy on a CO2e basis. The EPA’s 

intention is for this to serve as an 

interim approach while the EPA moves 

forward to propose a GHG Significant 

Emission Rate (SER) that would 

establish a de minimis threshold level 

for permitting GHG emissions under 

PSD. Under this forthcoming rule, the 

EPA intends to propose restructuring 

the GHG provisions in its PSD 

regulations so that the de minimis 

threshold for GHGs will not reside 

within the definition of ‘‘subject to 

regulation.’’ This restructuring will be 

designed to make the PSD regulatory 

provisions on GHGs universally 

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applicable, without regard to the 

particular subparts of the definition of 

‘‘regulated NSR pollutant’’ that may 

cover GHGs. Upon promulgation of this 

PSD rule, it will then provide a 

framework that states may use when 

updating their SIPs consistent with the 

Supreme Court decision. 

While the PSD rulemaking described 

above is pending, the EPA and approved 

state, local, and tribal permitting 

authorities will still need to implement 

the BACT requirement for GHGs. In 

order to enable permitting authorities to 

continue applying the 75,000 tpy CO2e 

threshold to determine whether BACT 

applies to GHG emissions from an 

‘‘anyway source’’ after GHGs are subject 

to regulation under CAA section 111, 

the EPA has concluded that it continues 

to be appropriate to adopt the proposed 

language in 40 CFR 60.5515 (subpart 

TTTT). Because the EPA is not 

finalizing the proposed regulations in 

subparts Da and KKKK, it is not 

necessary to adopt the comparable 

provisions that the EPA proposed in 40 

CFR 60.46Da(j) and 40 CFR 60.4315(b). 

The EPA has evaluated 40 CFR 

60.5515 in light of the Supreme Court 

decision and the comments received on 

the question of whether this CAA 

section 111 standard will undermine the 

application of the Tailoring Rule 

limitations. While most of the Tailoring 

Rule limitations are no longer needed to 

avoid triggering the requirement to 

obtain a PSD permit based on GHGs 

alone, the limitation in 40 CFR 

51.166(b)(48)(iv) and 40 CFR 

52.21(b)(49)(iv) will remain important to 

provide an interim applicability level 

for the GHG BACT requirement in 

‘‘anyway source’’ PSD permits. Thus, 

there continues to be a need to ensure 

that the regulation of GHGs under CAA 

section 111 does not make this BACT 

applicability level for anyway sources 

effectively inoperable. The language in 

40 CFR 60.5515 will continue to be 

effective at avoiding this result after the 

judicial actions described above and the 

adoption of this final rule. The 

provisions in part 60 reference 40 CFR 

51.166(b)(48) and 40 CFR 52.21(b)(49) of 

the EPA’s regulations. However, the 

courts have now vacated 40 CFR 

51.166(b)(48)(v) and 40 CFR 

52.21(b)(49)(v), and the EPA will take 

steps soon to eliminate these subparts 

from the CFR. As a result of these steps, 

the language of final 40 CFR 60.5515 

will not incorporate the vacated parts of 

40 CFR 51.166(b)(48) and 40 CFR 

52.21(b)(49), but these provisions in part 

60 will continue to apply to those 

subparts of the PSD rules that are 

needed on an interim basis to limit 

application of BACT to GHGs only 

when emitted by an anyway source in 

amounts of 75,000 tpy CO2e or more. 

Thus, in this final rule, the EPA is 

adopting the proposed text of 40 CFR 

60.5515 for this purpose without 

substantial change. 

As to the concern expressed by some 

commenters that revisions to part 60 

alone are not sufficient, the GHG SER 

rulemaking described above will 

include proposed revisions to the PSD 

regulations in parts 51 and 52 that 

should ultimately address this concern. 

The EPA acknowledges that the 

commenters concern will not be fully 

addressed for an interim period of time, 

but (for the reasons discussed above) the 

part 60 provisions adopted in this rule 

are sufficient to make explicit that the 

75,000 tpy CO2e BACT applicability 

level for GHGs will apply to GHGs that 

are subject to regulation under the CAA 

section 111 standards adopted in this 

rule. 

Rather than adopting a temporary 

patch in its PSD regulations in this rule 

to address the implications for PSD of 

regulating GHGs under CAA section 

111, the EPA believes it will be most 

efficient for the EPA and the states if the 

EPA completes a comprehensive PSD 

rule that will address all the 

implications of the Supreme Court 

decision. The revisions the EPA will 

consider based on the Supreme Court 

decision will inherently address the 

commenters concerns about the 

definition of the ‘‘subject to regulation’’ 

and the proposed part 60 provisions. To 

the extent this PSD rule is not complete 

before the EPA proposes additional 

CAA section 111 standards for GHGs, 

the EPA will need to consider adding 

provisions like 40 CFR 60.5515 to other 

subparts of part 60. In a separate 

rulemaking finalized concurrently with 

this rule, the EPA is also finalizing 

corresponding edits to 40 CFR 60.5705 

in subpart UUUU to clarify that the 

regulated pollutant is the same for both 

the CAA section 111(b) and section 

111(d) rules. As of this time, the EPA 

has not proposed GHG standards for 

other source categories under CAA 

section 111. To the extent needed, this 

approach of adding provisions to a few 

subparts in part 60 would be less 

burdensome to states and more efficient 

than revising 40 CFR 51.166 at this time 

solely to address the implications of 

regulating GHGs under CAA section 

111. 

The EPA understands that many 

commenters expressed concern that PSD 

SIPs would also have to be amended to 

address the implications of regulating 

GHGs under CAA section 111. However, 

the language in 40 CFR 60.5515 is 

designed to avoid the need for states to 

make revisions to the PSD regulations in 

their SIPs at this time. The EPA has 

previously observed that the form of 

each pollutant regulated under the PSD 

program is derived from the form of the 

pollutant described in regulations, such 

as an NSPS, that make the pollutant 

regulated under the CAA. 56 FR 24468, 

24470 (May 30, 1991); 61 FR 9905, 

9912–18 (Mar. 12, 1996); 75 FR 31522. 

Moreover, it is more likely that states 

would need to consider a SIP revision 

if the EPA were to revise 40 CFR 51.166 

in this rule. Revisions to 51.166 can 

trigger requirements for states to revise 

their PSD program provisions under 40 

CFR 51.166(a)(6). 

Given the process required in states to 

review their SIPs and submit them to 

the EPA for approval, it is most efficient 

for all concerned when the EPA is able 

to consolidate its revisions to 40 CFR 

51.166. The EPA, thus, believes it will 

be less work for states if we issue a 

comprehensive set of rules addressing 

regulation of GHGs under the PSD 

program after the Supreme Court 

decision. 

In comments on the proposed rules, 

states generally did not express concern 

that the proposed revisions to part 60 

were insufficient to avoid the need for 

SIP revisions. In our proposal, we 

addressed any state with an approved 

PSD SIP program that applies to GHGs 

which believed that this final rule 

would require the state to revise its SIP 

so that the Tailoring Rule thresholds 

continue to apply. First, the EPA 

encouraged any state that considered 

such revisions necessary to make them 

as soon as possible. Second, if the state 

could do so promptly, the EPA said it 

would assess whether to proceed with a 

separate rulemaking action to narrow its 

approval of that state’s SIP so as to 

assure that, for federal purposes, the 

Tailoring Rule thresholds will continue 

to apply as of the effective date of the 

final NSPS rule. 79 FR 1487. The EPA 

did not receive any comments or other 

feedback from states requesting that the 

EPA narrow their program to ensure the 

Tailoring Rule thresholds continue to 

apply after promulgating this rule. We 

do not believe such action will be 

necessary in any state after the Supreme 

Court decision and our action in this 

rule is to adopt the proposed part 60 

provisions for purposes of ensuring the 

Step 1 BACT applicability level for 

GHGs continues to apply on an interim 

basis. 

C. Implications for BACT 

Determinations Under PSD 

New major stationary sources and 

major modifications at existing major 

stationary sources are required by the 

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551 In this regard, the 2011 GHG Permitting 

Guidance states that ‘‘although CCS is not in 

widespread use at this time, EPA generally 

considers CCS to be an ‘available’ add-on pollution 

control technology for facilities emitting CO2 in 

Continued 

CAA to, among other things, obtain a 

permit under the PSD program before 

commencing construction. The emission 

thresholds that define PSD applicability 

can be found in 40 CFR parts 51 and 52, 

and the PSD thresholds specific to 

GHGs are explained in the preceding 

section of this preamble. 

Sources that are subject to PSD must 

obtain a preconstruction permit that 

contains emission limitations based on 

application of BACT for each regulated 

NSR pollutant. The BACT requirement 

is set forth in section 165(a)(4) of the 

CAA, and in EPA regulations under 40 

CFR parts 51 and 52. These provisions 

require that BACT determinations be 

made on a case-by-case basis. CAA 

section 169(3) defines BACT, in general, 

as: 

‘‘an emissions limitation . . . based on the 

maximum degree of reduction for each 

pollutant . . . emitted from any proposed 

major stationary source or major modification 

which the Administrator . . . [considering 

energy, environmental, and economic 

impacts] . . . determines is achievable for 

such facility . . .’’ 

Furthermore, this definition in the CAA 

specifies that 

‘‘[i]n no event shall application of [BACT] 

result in emissions of any pollutants which 

will exceed the emissions allowed by any 

applicable standard established pursuant to 

section 111 or 112 of the Act.’’ 

This condition of CAA section 169(3) 

has historically been interpreted to 

mean that BACT cannot be less stringent 

than any applicable standard of 

performance under the NSPS. See, e.g., 

U.S. EPA, PSD and Title V Permitting 

Guidance for Greenhouse Gases, EPA– 

457/B–11–001 (March 2011) (‘‘GHG 

Permitting Guidance’’ or ‘‘Guidance’’) at 

20–21. Thus, upon completion of an 

NSPS, the NSPS establishes a ‘‘BACT 

Floor’’ for PSD permits that are issued 

to affected facilities covered by the 

NSPS. 

BACT is a case-by-case review that 

considers a number of factors. These 

factors include the availability, 

technical feasibility, control 

effectiveness, and the economic, 

environmental and energy impacts of 

the control option. See GHG Permitting 

Guidance at 17–46. The fact that a 

minimum control requirement (i.e., the 

BACT Floor) is established by the EPA 

through an applicable NSPS does not 

bar a permitting agency from justifying 

a more stringent control level as BACT 

for a specific PSD permit. 

It is important to understand how this 

NSPS may relate to determining BACT 

for new and existing EGUs that require 

PSD permits. PSD generally applies to 

major sources, while this NSPS applies 

to units that may be within a source. 

Under this NSPS, an affected facility is 

a new EGU or a modified or 

reconstructed EGU. The new source 

NSPS requirements apply, in general, to 

any stationary source that adds a new 

EGU that is an affected facility under 

this NSPS. This could, for example, 

include a proposed brand new 

(‘‘greenfield’’) power plant or an 

existing power plant that proposes to 

add a new EGU (e.g., to increase its 

generating capacity). While this latter 

scenario is considered a ‘‘new affected 

facility’’ under the NSPS, it is generally 

viewed under PSD as a ‘‘modification’’ 

of an existing stationary source. Thus, 

the new source NSPS requirements 

could apply to a modification, as that 

term is defined under PSD. 

In addition, this NSPS will apply to 

some modified and reconstructed units, 

as those terms are defined under part 

60. Consequently, this NSPS could 

establish a BACT floor for existing 

stationary sources that are modifying an 

existing EGU and experience an 

emissions increase that makes the 

source subject to PSD review. However, 

a physical change that triggers the NSPS 

modification or reconstruction 

requirements does not necessarily 

subject the source to PSD requirements, 

and vice versa. In general, in order to 

trigger the NSPS modification or 

reconstruction requirements, a physical 

change must increase the maximum 

hourly emission rate of the pollutant (to 

be an NSPS modification) or the fixed 

capital cost of the change must exceed 

50 percent of the fixed capital cost of a 

comparable entirely new facility (to be 

an NSPS reconstruction). See 40 CFR 

60.2, 60.14, 60.15. Under the PSD 

program, however, a physical change (or 

change in the method of operation) must 

result in an increase in annual 

emissions of the pollutant by a specified 

emission threshold in order to be 

subject to PSD requirements. This 

emission calculation considers the 

unit’s past annual emissions and its 

projected annual emissions. See, e.g., 40 

CFR 52.21(a)(2)(iv)(C). In addition, the 

PSD emissions test for a modification 

allows the existing source to consider 

qualifying emission reductions and 

increases at the source within a 

contemporaneous period to ‘‘net out’’ of, 

or avoid, triggering PSD review. Thus, it 

is important to understand the 

differences in how the term 

‘‘modification’’ is used in the NSPS and 

PSD programs, and that a physical 

change that is a modification under one 

program may not necessarily be a 

modification under the other program. 

In the preamble to the proposed NSPS 

for new sources, the EPA discussed 

whether a standard of performance for 

the new source NSPS, specifically the 

BSER for solid fuel-fired EGUs that is 

based on partial CCS, could become the 

BACT floor when permitting a modified 

or reconstructed EGU or non-EGU 

source. As noted above, BACT is a casespecific review by a permitting agency. 

In evaluating BACT, the permitting 

authority should consider all available 

control technologies that have the 

potential for practical application to the 

facility or emission unit under 

evaluation. See GHG Permitting 

Guidance at 24. This BACT review must 

include any technologies that are part of 

an applicable NSPS for the specific type 

of source and would therefore establish 

the minimum level of stringency for the 

BACT. Thus, it is possible that partial 

CCS could be considered in a BACT 

review as an available control option for 

a modified or reconstructed EGU 

facility, or for another type of source 

(e.g., natural gas processing plant), but 

this NSPS is not an applicable standard 

to such sources so it would not establish 

a requirement that partial CCS is a 

minimum level of stringency for the 

BACT for those sources. 

Some commenters expressed concern 

that, if the EPA finalizes a BSER for 

utility boilers and IGCC units that is 

based on partial CCS, it would establish 

a BACT Floor for new EGUs that would 

be inconsistent with prior BACT 

determinations for EGUs in both permits 

issued by EPA Regions and permits 

issued by state agencies on which the 

EPA has commented. Many of these 

comments were more directed at the 

development and deployment of CCS 

(i.e., the commenter did not believe CCS 

should be the basis for BSER) rather 

than examining whether an NSPS 

should establish the BACT floor for 

applicable sources, which is the legal 

consequence of setting an NSPS under 

the terms of the CAA. Consequently, we 

respond to these comments in other 

sections of this preamble that support 

the selection of partial CCS as the basis 

for the BSER for fossil fuel-fired electric 

utility steam generating units. 

With regard to the commenters who 

stated that a BSER for EGUs that is 

based on partial CCS would be 

inconsistent with BACT determinations 

in previous GHG PSD permits, it is 

important to recognize that a BACT 

determination is a case-by-case analysis 

and that technological capabilities and 

costs evolve over time.551 In addition, to 

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large amounts and industrial facilities with highpurity CO2 streams.’’ GHG Permitting Guidance at 

35. The Guidance goes on to note that CCS may not 

be technically feasible at modified sources (citing 

possible issues with ‘‘space for CO2 capture 

equipment at an existing facility’’), or in other 

specific circumstances. Id. at 36 (‘‘Logistical 

hurdles for CCS may include obtaining contracts for 

offsite land acquisition . . ., the need for funding 

. . ., timing of available transportation 

infrastructure, and developing a site for secure long 

term storage. Not every source has the resources to 

overcome the offsite logistical barriers necessary to 

apply CCS technology to its operations, and smaller 

sources will likely be more constrained in this 

regard’’). Id. at 42–3 EPA also noted that CCS may 

be expensive in individual instances and thus 

eliminated as a control option for that reason under 

step 4 of the BACT analysis, noting further that 

revenues from EOR may offset other costs. Id. at 42– 

3. See also UARG v. EPA, 134 S.Ct. 2427, 2448 

(2014) (noting that EPA’s GHG Permitting Guidance 

states that carbon capture is reasonably comparable 

to more traditional, end-of-stack BACT 

technologies, and that petitioners do not dispute 

that). 

As explained at Section V.I.5 above, in 

determining that partial CCS is BSER for new fossil 

fuel steam electric plants, the EPA has carefully 

considered the issue of logistics (including cost 

estimates for land acquisition, transportation, and 

sequestration) and costs generally. Nor would new 

plants face the same types of constraints as 

modified or reconstructed sources in a BACT 

determination, since a new source has more leeway 

in choosing where to site. See text at V.G.3. above. 

Moreover, the GHG Permitting Guidance considered 

BACT determinations for all types of sources, not 

just those for which the EPA has determined in this 

rule that partial CCS is the BSER, and the concerns 

expressed in the Guidance thus must be considered 

in that broader context. 

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 by setting a BSER of partial 

CCS in this NSPS. Although, in the 

course of a BACT review, some 

permitting authorities may have 

determined that CCS is not 

technologically feasible or economically 

achievable for a gas-fired EGU, because 

of the case-by-case nature of the BACT 

analysis it does not automatically follow 

that the same conclusion is appropriate 

for a solid fuel-fired EGU. Furthermore, 

PSD permitting requirements first 

applied to GHGs in January 2011 and 

more information about GHG control 

technology has been gained in this fourand-a-half year period. Thus, we would 

expect BACT decisions to evolve as 

well, such that a GHG BACT review for 

a coal-fired EGU in 2015 may look very 

different from a review that was done in 

2011. 

Additionally, if a state agency is 

processing a permit application for a 

solid fuel-fired EGU and does not 

propose CCS as BACT (or does not even 

consider CCS as an available control for 

BACT), the EPA is not necessarily 

required to comment negatively on the 

draft permit, or to otherwise request or 

require that the state agency amend the 

BACT to include CCS. For state agencies 

that have their own EPA-approved state 

implementation plan, the state has 

primacy over their permitting actions 

and discretion to interpret their 

approved rules and to apply the 

applicable federal and state regulatory 

requirements that are in place at the 

time for the facility in question. The 

EPA’s role is to provide oversight to 

ensure that the state operates their PSD 

program in accordance with the CAA 

and applicable rules. If the EPA does 

not adversely comment on a certain 

draft permit or BACT determination, it 

does not necessarily imply EPA 

endorsement of the proposed permit or 

determination. 

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 fullscale electric utility applications. It is 

important to recognize that the EPA’s 

Permitting Guidance is guidance, so it 

does not contain any final 

determination of BACT for any source. 

Furthermore, we disagree with the 

commenters’ characterization of the 

GHG Permitting Guidance. The 

Guidance specifically states ‘‘[f]or the 

purposes of a BACT analysis for GHGs, 

the EPA classifies CCS as an add-on 

pollution control technology that is 

‘‘available’’ for facilities emitting CO2 in 

large amounts, including fossil fuelfired 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 GHG Permitting 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 potential 

challenges when it was issued in March 

2011, the Guidance clearly does not rule 

out the selection of CCS as BACT for 

any source category and it is forward 

looking. GHG Permitting Guidance at 43 

(‘‘. . . as a result of ongoing research 

and development, . . . CCS may 

become less costly and warrant greater 

consideration . . . in the future’’) 

Nothing in the Guidance is inconsistent 

with EPA’s present position that CCS is 

adequately demonstrated for the types 

of sources covered by this NSPS, as 

articulated elsewhere in this preamble. 

A commenter asserted that the GHG 

Permitting Guidance should be 

amended because it calls for 

consideration of CCS in BACT 

determinations even though the 

proposed NSPS identified ‘‘partial CCS’’ 

as BSER for new boiler and IGCC EGUs. 

The Guidance explains that ‘‘the 

purpose of Step 1 of the process is to 

cast a wide net and identify all control 

options with potential application to the 

emissions unit under review.’’ GHG 

Permitting Guidance at 26. The EPA 

agrees that the GHG Permitting 

Guidance only uses the term ‘‘CCS’’ and 

does not distinguish ‘‘partial CCS’’ from 

‘‘full CCS.’’ But considering the purpose 

of Step 1 of the process, we believe that 

the term ‘‘CCS’’, as it is used in the GHG 

Permitting Guidance, adequately 

describes the varying levels of CO2

capture. A BACT review should analyze 

all available technologies in order to 

adequately support the BACT 

determination, and may require 

evaluation of partial CCS, full CCS, and/ 

or no CO2 capture. The specific facility 

type and CO2 capture conditions will 

dictate the level(s) of CO2 capture that 

are most appropriate to consider as 

‘‘available’’ in a BACT review. 

D. Implications for Title V Program 

Under the Title V program, certain 

stationary sources, including ‘‘major 

sources’’ are required to obtain an 

operating permit. This permit includes 

all of the CAA requirements applicable 

to the source, including adequate 

monitoring, recordkeeping, and 

reporting requirements to assure 

sources’ compliance. These permits are 

generally issued through EPA-approved 

state Title V programs. 

In the January 8, 2014 proposal, the 

EPA discussed whether this rulemaking 

would impact the applicability of Title 

V requirements to major sources of 

GHGs. 79 FR 1489–90. The relevant 

issue for Title V purposes was, in 

essence, whether promulgation of CAA 

section 111 requirements for GHGs 

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552As 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. 

553See Memorandum from Janet G. McCabe, 

Acting Assistant Administrator, Office of Air and 

Radiation, and Cynthia Giles, Assistant 

Administrator, Office of Enforcement and 

Compliance Assurance, to Regional Administrators, 

Regions 1–10, Next Steps and Preliminary Views on 

the Application of Clean Air Act Permitting 

Programs to Greenhouse Gases Following the 

Supreme Court’s Decision in Utility Regulatory 

Group v. Environmental Protection Agency (July 24, 

2014) at 5. 

554Hereafter, 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. 

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 

1489–90 (quoting 75 FR 31583). Under 

the Title V regulations, as revised by the 

Tailoring Rule, ‘‘major source’’ is 

defined to include, in relevant part, ‘‘a 

major stationary source . . . that 

directly emits, or has the potential to 

emit, 100 tpy or more of any air 

pollutant subject to regulation.’’ The 

proposal further explained that the GHG 

threshold that had been established in 

the Tailoring Rule had been 

incorporated into the definition of 

‘‘subject to regulation’’ under 40 CFR 

70.2 and 71.2, such that those 

definitions specify ‘‘ ‘that GHGs are not 

subject to regulation for purposes of 

defining a major source, unless as of 

July 1, 2011, the emissions of GHGs are 

from a source emitting or having the 

potential to emit 100,000 tpy of GHGs 

on a CO2e basis.’ ’’ Id. (quoting 75 FR 

31583). 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 1489–90. 

As noted elsewhere in this section, 

after the proposal for this rulemaking 

was published, the United States 

Supreme Court issued its opinion in 

UARG v. EPA, 134 S.Ct. 2427 (June 23, 

2014), and in accordance with that 

decision, the D.C. Circuit subsequently 

issued an amended judgment in 

Coalition for Responsible Regulation, 

Inc. v. Environmental Protection 

Agency, Nos. 09–1322, 10–073, 10–1092 

and 10–1167 (D.C. Cir., April 10, 2015). 

Those decisions support the same 

overall conclusion as the EPA discussed 

in the proposal, though for different 

reasons. 

With respect to Title V, the Supreme 

Court said in UARG v. EPA that the EPA 

may not treat GHGs as an air pollutant 

for purposes of determining whether a 

source is a major source required to 

obtain a Title V operating permit. In 

accordance with that decision, the D.C. 

Circuit’s amended judgment in 

Coalition for Responsible Regulation, 

Inc. v. Environmental Protection 

Agency, vacated the Title V regulations 

under review in that case to the extent 

that they require a stationary source to 

obtain a Title V permit solely because 

the source emits or has the potential to 

emit GHGs above the applicable major 

source thresholds. The D.C. Circuit also 

directed the EPA to consider whether 

any further revisions to its regulations 

are appropriate in light of UARG v. EPA, 

and, if so, to undertake to make such 

revisions. These court decisions make 

clear that promulgation of CAA section 

111 requirements for GHGs will not 

result in the EPA imposing a 

requirement that stationary sources 

obtain a Title V permit solely because 

such sources emit or have the potential 

to emit GHGs above the applicable 

major source thresholds.552

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.553

Consistent with the proposal, the EPA 

has concluded that this rule will not 

affect non-major sources and there is no 

need to consider whether to exempt 

non-major sources. Thus, sources that 

are subject to the CAA section 111 

standards promulgated in this rule are 

required to apply for, and operate 

pursuant to, a Title V permit that 

assures compliance with all applicable 

CAA requirements, including any GHGrelated 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, local 

and tribal permitting authorities 554 that 

rely on the ‘‘presumptive minimum’’ 

approach and the part 71 program 

implemented by the EPA would be 

required to account for GHGs in 

emissions-based fee calculations at the 

same dollar per ton ($/ton) rate as other 

air pollutants. The EPA believes this 

would result in the collection of fees in 

excess of what is required to cover the 

reasonable costs of an operating permit 

program. See NSPS proposal 79 FR 

1490. 

In response to these concerns, the 

EPA proposed regulatory changes to 

limit the fees collected based on GHG 

emissions and proposed two fee 

adjustment options to increase the fees 

collected based on the costs for 

permitting authorities to conduct certain 

review activities related to GHG 

emissions, while still providing 

sufficient funding for an operating 

permit program. Also, we proposed an 

option that would have provided for no 

fee adjustments to recover the costs of 

conducting review activities related to 

GHG emissions. Id. 79 FR 1490. The 

EPA did not propose any action related 

to state and local permitting authorities 

that do not use the presumptive 

minimum approach. 

Most commenters on the proposal, 

including state and local permitting 

authorities, were supportive of 

exempting GHGs from the emissionsbased fee calculations of the permit 

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555Hereafter 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.’’ 

556Burden is the hours of staff time necessary to 

perform a task. 

557The 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. 

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 that 

‘‘the program will result in the 

collection, in the aggregate, from all 

sources [required to get an operating 

permit]’’ of either ‘‘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 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 option that would 

provide no additional cost adjustment to 

account for GHGs (‘‘the GHG adjustment 

option 3’’). All of the GHG adjustment 

options are based on the assumption 

that the GHG exemption is finalized. 

See NSPS Proposal 79 FR 1493–1495. 

The EPA additionally proposed two 

clarifications. The first was regulatory 

text in 40 CFR part 60, subparts Da, 

KKKK, and TTTT, to clarify that GHGs, 

as opposed to CO2, is the regulated 

pollutant for fee purposes (‘‘the fee 

pollutant clarification’’). Id. at 1505, 

1506 and 1511. The second was a 

proposal to move the existing definition 

of ‘‘Greenhouse gases (GHGs)’’ within 

40 CFR 70.2 and 71.2 to promote clarity 

in the regulations (‘‘the GHG 

clarification’’). Id. 79 FR 1490, 1517, 

1518. 

For background purposes, below is a 

brief summary of each of the proposals. 

a. The GHG Exemption 

To address the fee issues discussed in 

the NSPS proposal, the EPA proposed to 

exempt GHG emissions from the 

definition of ‘‘regulated pollutant (for 

presumptive fee calculation)’’ in 40 CFR 

70.2 and the definition of ‘‘regulated 

pollutant (for fee calculation)’’ in 40 

CFR 71.2.555 See NSPS preamble 79 FR 

1493, 1495. 

b. The GHG Adjustment Option 1 

The first proposed ‘‘GHG adjustment’’ 

option (option 1) was to include an 

additional cost for each GHG-related 

activity of certain types that a 

permitting authority would process (an 

activity-based adjustment). The three 

activities identified for this option were 

‘‘GHG completeness determination (for 

initial permit or for updated 

application)’’ at 43 hours of burden,556

‘‘GHG evaluation for a modification or 

related permit action’’ at 7 hours of 

burden, and ‘‘GHG evaluation at permit 

renewal’’ at 10 hours of burden. See also 

79 FR 1494, fn. 280 (providing a 

description of each of these activities). 

For part 70, the burden hours per 

activity would be multiplied by the cost 

of staff time (in $/hour) specific to the 

state, including wages, benefits, and 

overhead, to determine the cost of each 

activity. All the activities for a given 

period would be totaled to determine 

the total GHG adjustment for the state. 

See 79 FR 1494. 

For part 71, we proposed a labor rate 

assumption of $52 per hour in 2011 

dollars. Using that labor rate, we 

proposed to determine the GHG fee 

adjustment for each GHG permitting 

program activity to be a specific dollar 

amount for each activity (‘‘set fees’’) that 

the source would pay for each activity 

performed. See 79 FR 1495. The EPA 

proposed to revise 40 CFR 70.9(b)(2)(v) 

and 40 CFR 71.9(c)(8) to implement this 

option. 

c. The GHG Adjustment Option 2 

The second proposed GHG 

adjustment option (option 2) was to 

increase the dollar per ton ($/ton) rates 

used in the fee calculations for each 

non-GHG fee pollutant. The revised 

$/ton rates would be multiplied by the 

total tons of non-GHG fee pollutants 

actually emitted by any source to 

determine the applicable total fees. The 

EPA proposed to increase the $/ton rates 

by 7 percent.557 See NSPS proposal 79 

FR 1494, 1495. 

d. The GHG Adjustment Option 3 

The EPA also solicited comment on 

not charging any fees related to GHGs 

(option 3). The basis for this proposed 

option was the observation that most 

sources that need to address GHGs in a 

permit would also emit non-GHG fee 

pollutants, and thus, the cost of 

permitting for any particular source may 

be accounted for adequately without 

charging any additional fees related to 

GHGs. Id. 79 FR 1494–1495. 

e. The Fee Pollutant Clarification 

Another fee-related proposal was to 

add regulatory text to 40 CFR part 60, 

subparts Da, KKKK, and TTTT, to 

clarify that the fee pollutant for 

operating permit purposes would be 

considered to be ‘‘GHGs,’’ (as defined in 

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558Note 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.’’ 

559We 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. 

40 CFR 70.2 and 71.2),558 rather than 

solely CO2, which would be regulated 

under the section 111 standards and 

implemented through the EGU GHG 

NSPS. Id. 79 FR 1505, 1506, and 1511. 

f. The GHG Clarification 

The EPA proposed to move the 

existing definition of ‘‘Greenhouse gases 

(GHGs)’’ within the definition of 

‘‘Subject to regulation’’ in 40 CFR 70.2 

and 71.2 to a separate definition within 

those sections to promote clarity in the 

regulations. Id. 79 FR 1490, 1517, 1518. 

4. What action is the EPA finalizing? 

In this action, the EPA is finalizing 

the following elements as proposed: (1) 

The GHG exemption, (2) the GHG 

adjustment option 1, and (3) the fee 

pollutant clarification. 

Public commenters on the proposal 

stated both support and opposition to 

using the NSPS rulemaking action to 

revise the Title V fee rules. Two 

commenters stated that proposing the 

Title V fee revisions within the NSPS 

rulemaking would result in fewer 

commenters, particularly state and local 

permitting authorities, having 

knowledge of the changes to the fee 

rules and sufficient opportunity to 

comment on the changes because the 

NSPS proposal is limited to a single 

source category, and one stated that a 

separate proposal for the fee rules 

would provide a sufficient opportunity 

for public comment. The EPA believes 

it is appropriate to move forward with 

final action amending the Title V fee 

regulations as part of this NSPS. As we 

explained in the preamble for the 

proposal and elsewhere in this final 

rule, the fee rules and the section 111 

standards are interrelated because, if we 

do not revise the fee rules, promulgation 

of the final NSPS will trigger certain 

requirements related to Title V fees for 

GHG emissions that the EPA believes 

will result in the collection of excessive 

fees in states that implement the 

presumptive minimum approach and in 

the part 71 program. Thus, it is 

important to finalize the revisions to the 

fee rules at the same time or prior to this 

NSPS, and it is within the EPA’s 

discretion to address the NSPS and the 

fee rules at the same time as part of the 

same rulemaking action. In response to 

the commenters who were concerned 

that including the fee rule proposal as 

part of the NSPS proposal would result 

in the public not having sufficient 

public comment opportunities, the EPA 

believes sufficient public comment 

opportunities were provided on the fee 

rule changes because the proposal met 

all public participation requirements 

and we provided additional public 

outreach, including to state and local 

permitting authorities, which discussed 

the fee rule proposal. In addition to the 

publication of the proposed rulemaking 

in the Federal Register, the EPA held 

numerous hearings, reached out to state 

partners and the public, and developed 

numerous fact sheets and other 

information to support public comment 

on this rule. The EPA has complied 

with the applicable public participation 

requirements and executive orders. The 

proposal met all the requirements for 

public notice—it contained a clear and 

detailed explanation of how the part 70 

and 71 rules would be affected by the 

promulgation of the CAA section 111 

standard for EGUs and how the EPA 

proposed to revise the related regulatory 

provisions. We received many 

comments on the proposal to revise the 

fee rule for operating permits programs, 

and we are taking those comments into 

consideration in the finalization of the 

rulemaking action. 

a. The GHG Exemption 

The EPA is taking final action to 

revise the definition of regulated 

pollutant (for presumptive fee 

calculation) in 40 CFR 70.2 and 

regulated pollutant (for fee calculation) 

in 40 CFR 71.2 to exempt GHG 

emissions. This regulatory amendment 

will have the effect of excluding GHG 

emissions from being subject to the 

statutory ($/ton) fee rate set for the 

presumptive minimum calculation 

requirement of part 70 and the fee 

calculation requirements of part 71. We 

received supportive comments from the 

majority of public commenters, 

including state and local permitting 

authorities and others, on revising the 

operating permit rules to exempt GHGs 

from the emission-based calculations 

that use the statutory fee rates. We are 

finalizing this portion of the proposal 

for the same reasons we explained in 

the proposal notice, including that 

leaving these regulations unchanged 

would have resulted in the collection of 

fee revenue far beyond the reasonable 

costs of an operating permit program. 

The EPA believes that these revisions 

(in conjunction with the GHG 

adjustment, see below) are consistent 

with the CAA requirements for fees 

pursuant to the authority of section 

502(b)(3)(B)(i). 

Some members of the public opposed 

the proposed GHG exemption for 

reasons including that it may limit 

permitting authorities’ ability to charge 

sufficient fees to cover the cost of GHG 

permitting 559 if the state is barred from 

exceeding minimum requirements set 

by the EPA. Despite this adverse 

comment, the EPA believes it is 

appropriate to finalize the GHG 

exemption because we are not finalizing 

any requirements that would require 

states to charge any particular fees to 

any particular sources. The changes we 

are finalizing to part 70 concern the 

presumptive minimum approach, which 

sets a minimum fee target for states that 

have decided to follow the presumptive 

minimum approach. Neither the statute 

nor the final rule require any state 

following the presumptive minimum 

approach (or any other approach) to 

charge fees to sources using any 

particular method. Thus, the GHG 

exemption will not limit states’ ability 

to structure their individual fee 

programs however they see fit in order 

to meet the requirement that they collect 

revenue sufficient to cover all 

reasonable costs of their permitting 

program. See CAA section 502(b)(3); 40 

CFR 70.9(b)(3). 

b. The GHG Adjustment Option 1 

The EPA is finalizing GHG adjustment 

option 1 because we believe it will 

result in a system for the calculation of 

costs for part 70 and fees for part 71 that 

is most directly related to the costs of 

GHG permitting. The EPA has 

determined that some adjustment to cost 

and fee accounting is important because 

the recent addition of GHG emissions to 

the operating permitting program does 

add new burdens for permitting 

authorities. Although GHG adjustment 

option 3 (no GHG permitting fee 

adjustments) was supported by many 

industrial commenters, the EPA rejected 

it because it is in tension with the 

statutory requirement that permitting 

authorities collect sufficient fees to 

cover all the reasonable costs of 

permitting. See CAA section 

502(b)(3)(A). Some state and local 

permitting authorities provided 

comments supporting option 1, while 

others supported option 2, and some 

supported either option, stating no 

preference. Also, a few state and local 

permitting authorities supported 

finalizing no adjustment and a few 

others asked for flexibility to set fee 

adjustments not proposed by the EPA, 

but that they believed would be 

appropriate for their program. 

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560A 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. 

561Note 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)). 

562The 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). 

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. 

Consistent with CAA section 

502(b)(3)(B)(i), the Administrator has 

determined that the final rule’s 

approach of exempting GHG emissions 

from fee-related calculations and 

accounting for the GHG permitting costs 

through option 1 will result in fees that 

will cover the reasonable costs of the 

permitting programs. 

The EPA is revising the part 70 

regulations through this final action, 

specifically 40 CFR 70.9(b)(2), to modify 

the presumptive minimum approach to 

add the activity-based cost of GHG 

permitting activities, outlined in the 

revised 40 CFR 70.9(b)(2)(v), to the 

emissions-based calculation of 40 CFR 

70.9(b)(2)(i), which is being revised to 

now exclude GHG emissions. To 

determine the activity-based GHG 

adjustment under 40 CFR 70.9(b)(2)(v), 

the permitting authority will multiply 

the burden hours for each activity (set 

forth in the regulation) by the cost of 

staff time (in $ per hour), including 

wages, benefits, and overhead, as 

determined by the state, for the 

particular activities undertaken during 

the particular time period. 

States that implement the 

presumptive minimum approach will 

need to follow the final rule’s option 1 

approach.560 States that use the detailed 

accounting approach are not directly 

affected by this rulemaking, but they 

must ensure that their fee collection 

programs are sufficient to fully fund all 

reasonable costs of the operating permit 

program, including costs attributable to 

GHG-related permitting. The EPA 

suggests states that use the detailed 

accounting approach consider the 7 

percent assumption for the costs of GHG 

permitting in any such analysis, 

consistent with the EPA analysis of 

options 1 and 2 in the proposal. 

Consistent with 40 CFR 70.4(i), a state 

that wishes to change its operating 

permit program as a result of this final 

rule must apprise the EPA. The EPA 

will review the materials submitted 

concerning the change and decide if a 

formal program revision process is 

needed and will inform the state of next 

steps. The communication apprising the 

EPA of any such changes should 

include at least a narrative description 

of the change and any other information 

that will assist the EPA in its assessment 

of the significance of the changes. 

Certain changes, such as switching from 

the presumptive minimum method to a 

detailed accounting method, will be 

considered substantial program 

revisions and be subject to the 

requirements of 40 CFR 70.4(i)(2). 

With respect to the part 71 program, 

in this final action the EPA is revising 

40 CFR 71.9(c) to require each part 71 

source to pay an annual fee which is the 

sum of the activity-based fee of 40 CFR 

71.9(c)(8) and the emissions-based fee of 

40 CFR 71.9(c)(1)–(4),561 which 

excludes GHG emissions. To determine 

the activity-based fee, the revised 40 

CFR 71.9(c)(8) requires the source to pay 

a ‘‘set fee’’ for each listed activity that 

has been initiated since the fee was last 

paid. Under part 71, fees are typically 

paid at the time of initial application 

submittal, and thereafter, annually on 

the anniversary of the initial fee 

payment, or on any other dates that may 

be established in the permit. These set 

fees would not change until such time 

as we may revise our part 71 rule to 

change the set fees. 

The final rule implements the option 

1 approach by listing three activities 

performed by permitting authorities that 

involve GHG reviews. The following 

describes the activities as described in 

our proposal and certain clarifications 

we are making in the final rule to ensure 

consistent implementation. 

The EPA is finalizing that the first 

listed activity under option 1 is ‘‘GHG 

completeness determination (for initial 

permit or updated application).’’ This 

activity must be counted for each new 

initial permit application, even for 

applications that do not include GHGs 

emissions or applicable requirements, 

since an important part of any 

completeness determination will be to 

determine that GHG emissions and 

applicable requirements have been 

properly addressed, as needed, in the 

application. The fee for this activity is 

a one-time charge that covers the initial 

application and any supplements or 

updates. The EPA believes that a single 

charge for a GHG completeness 

determination will be adequate to cover 

the reasonable costs for a permitting 

authority to review an initial 

application and any subsequent 

application updates related to initial 

permit issuance; thus, any updates to an 

initial application are included in a 

single ‘‘GHG completeness 

determination,’’ rather than as a 

separate activity for which the source 

would be charged in addition to the 

completeness determination for the 

initial application. This is an important 

distinction because many sources 

submit multiple 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.’’ 562 The EPA had proposed that 

the second listed activity under option 

1 would be ‘‘GHG evaluation for a 

modification or related permit action.’’ 

For the final rule, we are clarifying that 

we are adding a cost for a ‘‘permit 

modification’’ rather than for a 

‘‘modification.’’ The term 

‘‘modification’’ may be interpreted to 

refer to any change at a source, even a 

change that would not be required to be 

processed as a ‘‘permit modification,’’ 

while ‘‘permit modification’’ refers to 

any revision to an operating permit that 

cannot be processed as an 

administrative permit amendment and 

thus requires a review by a permitting 

authority as either a significant or minor 

permit modification. 

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 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64637 

563The EPA estimated in the proposal that option 

1 would result in about a 7 percent overall increase 

in the annual part 70 fees that are collected by all 

permitting authorities nationally. See 79 FR 1494. 

564The EPA does not, however, read the UARG 

decision to affect other grounds on which a Title 

V permit may be required or the applicable 

requirements that must be addressed in Title V 

permits. See Memorandum from Janet G. McCabe, 

Acting Assistant Administrator, Office of Air and 

Radiation, and Cynthia Giles, Assistant 

Administrator, Office of Enforcement and 

Compliance Assurance, to Regional Administrators, 

Regions 1–10, Next Steps and Preliminary Views on 

the Application of Clean Air Act Permitting 

Programs to Greenhouse Gases Following the 

Supreme Court’s Decision in Utility Regulatory 

Group v. Environmental Protection Agency (July 24, 

2014) at 5. 

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.563 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 GHGrelated permitting should be minimal 

because few applicable requirements 

will apply to GHGs. As stated earlier in 

this notice, the EPA’s cost estimate for 

the proposal concerned the incremental 

costs of GHG permitting for any source, 

not just those that would have, at the 

time of the analysis, triggered the 

requirement to get a permit based on 

GHG emissions or applicable 

requirements. 

Despite some comments received to 

the contrary, the EPA does not believe 

it is appropriate to delay the finalization 

of the GHG adjustment. The EPA does 

not believe such delays would be 

consistent with CAA section 

502(b)(3)(A) because states have been 

incurring costs attributable to GHG 

permitting for several years now and 

increased fees must be collected to 

cover the increased costs. The 

regulatory changes being finalized in 

this action provide the states with 

optimal flexibility and sufficient 

funding to implement their GHG 

permitting programs. Some commenters 

had specifically stated that the EPA 

should delay finalization of this rule 

until the completion of the next ICR 

renewal process. While we do not 

believe delaying this rule is appropriate, 

as explained above, the EPA notes that 

we remain committed to collecting and 

analyzing additional data on costs 

attributable to GHG permitting for 

operating permit programs. We may 

adjust the GHG cost adjustments in 

future rulemakings if necessary to 

comply with the requirements of the 

Act. 

As an alternative to the options 

proposed by the EPA, some commenters 

asserted that the EPA should make a 

GHG cost adjustment using a separate, 

but reduced fee rate ($/ton) for GHGs. 

We, however, believe that the option 1 

approach of the final rule will be more 

equitable for sources and more 

representative of actual costs because 

option 1 considers the costs of the 

actual permitting activities performed 

by a particular permitting authority, 

while any emissions-based approach 

would not be as directly related to 

actual costs incurred by permitting 

authorities. 

Some commenters alleged that the 

EPA’s proposal on adjustments to the 

operating permit programs was vague. 

The EPA provided a thorough 

discussion of our rationale in the 

proposal, including the basis for the 

GHG adjustments, and we proposed 

regulatory text to implement our 

proposal. We explained in the proposal 

that support for the cost adjustment for 

GHGs under option 1 is contained in 

several analyses performed by the EPA 

and approved by the OMB related to the 

effect of the addressing GHG 

requirements in operating permits. 

These analyses have been placed in the 

docket for this rulemaking. The analyses 

include: The Regulatory Impact 

Assessment (RIA) for the Tailoring Rule 

(see Regulatory Impact Analysis for the 

Final Prevention of Significant 

Deterioration and Title V Greenhouse 

Gas Tailoring Rule, Final Report, May 

2010); the part 70 ICR change request for 

the Tailoring Rule (which was based on 

the RIA for the Tailoring Rule); and the 

current ICR for part 70 (EPA ICR 

number 1587.12; OMB control number 

2060–0243). 

Several commenters asked that we 

make changes to the option 1 approach 

that we proposed, such as adding new 

activities or 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.564 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. 

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 part 60, 

subparts Da, KKKK, and TTTT. The 

final rule adds the clarification text only 

to subpart TTTT because the EPA is 

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64638 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

565We 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. 

566Following promulgation of the MATS rule, 

industry, states and environmental organizations 

challenged many aspects of the EPA’s threshold 

determination that regulation of EGUs is 

‘‘appropriate and necessary’’ and the final standards 

regulating hazardous air pollutants from EGUs. The 

U.S. Court of Appeals for the D.C. Circuit upheld 

all aspects of the MATS rule. White Stallion Energy 

Center v. EPA, 748 F.3d 1222 (D.C. Cir. 2014). The 

decision was unanimous on all issues except a 

dissent was filed because the EPA did not consider 

cost when determining regulation of EGUs is 

appropriate. In Michigan v. EPA, case no. 14–46, 

the Supreme Court reversed the D.C. Circuit 

decision upholding the MATS rule finding that EPA 

erred by not considering cost when determining 

that regulation of EGUs was ‘‘appropriate’’ pursuant 

to section 112(n)(1). The Supreme Court considered 

only the narrow question of cost and did not review 

the other holdings of the D.C. Circuit, nor did the 

Supreme Court vacate the MATS rule. 

567CWA section 316(b) provides that standards 

applicable to point sources under sections 301 and 

codifying all of the requirements for the 

affected EGUs in a new subpart TTTT 

and including all CO2 emission 

standards for the affected EGUs (electric 

utility steam generating units, as well as 

natural gas-fired stationary combustion 

turbines) in that newly created subpart. 

See Section III.B of this preamble for 

more on this subject. 

d. The GHG Clarification 

The EPA is taking no action at this 

time on the proposal to move the 

definitions of ‘‘Greenhouse gases 

(GHG)’’ within the definition of 

‘‘Subject to regulation’’ in 40 CFR parts 

70 and 71. No public comments were 

received on this proposed clarification; 

however, subsequent to the proposal, on 

June 23, 2014, the Supreme Court in 

UARG v. EPA decided that GHG 

emissions could not be used in making 

certain applicability determinations 

under the operating permit rules. More 

specifically with respect to title V, as 

described above, the Supreme Court 

said that the EPA may not treat GHGs 

as an air pollutant for purposes of 

determining whether a source is a major 

source required to obtain a title V 

operating permit. In accordance with 

the Supreme Court decision, on April 

10, 2015, the D.C. Circuit issued an 

amended judgment in Coalition for 

Responsible Regulation, Inc. v. 

Environmental Protection Agency, Nos. 

09–1322, 10–073, 10–1092 and 10–1167 

(D.C. Cir. April 10, 2015), which, among 

other things, vacated the title V 

regulations under review in that case to 

the extent that they require a stationary 

source to obtain a title V permit solely 

because the source emits or has the 

potential to emit GHGs above the 

applicable major source thresholds. The 

D.C. Circuit also directed the EPA to 

consider whether any further revisions 

to its regulations are appropriate in light 

of UARG v. EPA, and, if so, to undertake 

to make such revisions. 

In response to the Supreme Court 

decision and the D.C. Circuit’s amended 

judgment, the EPA intends to conduct 

future rulemaking action to make the 

appropriate revisions to the operating 

permit rules. As part of any such future 

rulemaking action, the EPA may 

consider finalizing the proposal to move 

the definitions of GHGs within the 

operating permit rules. 

F. Interactions With Other EPA Rules 

Fossil fuel-fired EGUs are, or 

potentially will be, impacted by several 

other recently finalized or proposed 

EPA rules.565 Many of the rules that 

impact fossil fuel-fired EGUs apply to 

existing facilities as well as newly 

constructed, modified, or reconstructed 

facilities. In fact, the rules described 

below are more applicable to existing 

EGUs than to newly constructed, 

modified, or reconstructed EGUs. 

Although those rules will affect EGUs as 

existing sources, because we expect that 

there will be few NSPS modifications or 

reconstructions, we don’t anticipate 

those rules affecting EGUs as modified 

or reconstructed sources. In 

constructing new EGUs, sources can 

take all applicable requirements of the 

various rules into consideration. 

1. Mercury and Air Toxics Standards 

(MATS) 

On February 16, 2012, the EPA issued 

the MATS rule (77 FR 9304) to reduce 

emissions of toxic air pollutants from 

new and existing coal- and oil-fired 

EGUs. The MATS rule will reduce 

emissions of heavy metals, including 

mercury (Hg), arsenic (As), chromium 

(Cr), and nickel (Ni); and acid gases, 

including hydrochloric acid (HCl) and 

hydrofluoric acid (HF). These toxic air 

pollutants, also known as hazardous air 

pollutants or air toxics, are known to 

cause, or suspected of causing, damage 

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 reliabilitycritical units to receive an 

administrative order that includes a 

compliance schedule of up to an 

additional year, if it is needed to ensure 

electricity reliability.566

2. Cross-State Air Pollution Rule 

(CSAPR) 

The CSAPR requires states to take 

action to improve air quality by 

reducing SO2 and NOX emissions that 

cross state lines. These pollutants react 

in the atmosphere to form fine particles 

and ground-level ozone and are 

transported long distances, making it 

difficult for other states to attain and 

maintain the NAAQS. The first phase of 

CSAPR became effective on January 1, 

2015, for SO2 and annual NOX, and May 

1, 2015, for ozone season NOX. The 

second phase will become effective on 

January 1, 2017, for SO2 and annual 

NOX, and May 1, 2017, for ozone season 

NOX. Many of the power plants 

participating in CSAPR have taken 

actions to reduce hazardous air 

pollutants for MATS compliance that 

will also reduce SO2 and/or NOX. In this 

way these two rules are complementary. 

Compliance with one helps facilities 

comply with the other. 

3. Requirements for Cooling Water 

Intake Structures at Power Plants 

(316(b) Rule) 

On May 19, 2014, the EPA issued a 

final rule under section 316(b) of the 

Clean Water Act (33 U.S. Code section 

1326(b)) (referred to hereinafter as the 

316(b) rule.) The rule was published on 

August 15, 2014 (79 FR 48300; August 

15, 2014), and became effective October 

14, 2014. The 316(b) rule establishes 

new standards to reduce injury and 

death of fish and other aquatic life 

caused by cooling water intake 

structures at existing power plants and 

manufacturing facilities.567 The 316(b) 

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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. 

568 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. 

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 sitespecific entrainment reduction controls 

based on the schedule of requirements 

established by the permitting authority. 

Additional information regarding the 

316(b) rule for existing sources is 

included in Section IX.C of the 

preamble to the CAA section 111(d) 

emission guidelines for existing EGUs 

that the EPA is finalizing 

simultaneously with this rule. Although 

the recently issued 316(b) rule 

discussed here applies to existing 

sources, there are also 316(b) 

technology-based standards for new 

sources with cooling water intake 

structures. 

4. Disposal of Coal Combustion 

Residuals From Electric Utilities (CCR 

Rule) 

On December 19, 2014, the EPA 

issued the final rule for the disposal of 

coal combustion residuals from electric 

utilities. The rule provides a 

comprehensive set of requirements for 

the safe disposal of coal combustion 

residuals (CCRs), commonly known as 

coal ash, from coal-fired power plants. 

The CCR rule establishes technical 

requirements for existing and new CCR 

landfills and surface impoundments 

under Subtitle D of the Resource 

Conservation and Recovery Act (RCRA), 

the nation’s primary law for regulating 

solid waste. New CCR landfills and 

surface impoundments are required to 

meet the technical criteria before any 

CCR is placed into the unit. Existing 

CCR surface impoundments and 

landfills are subject to implementation 

timeframes established in the rule for 

the individual technical criteria. For 

additional information regarding the 

CCR rule, see Section IX.C of the 

preamble to the CAA section 111(d) 

emission guidelines for existing EGUs 

that the EPA is finalizing along with this 

rule. 

5. Steam Electric Effluent Limitation 

Guidelines and Standards (SE ELG Rule) 

The EPA is reviewing public 

comments and working to finalize the 

proposed SE ELG rule which will 

impact fossil fuel-fired 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 

technology-based 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 

(E.O.) 13563, ‘‘Improving Regulation 

and Regulatory Review,’’ issued on 

January 18, 2011, states that ‘‘[i]n 

developing regulatory actions and 

identifying appropriate approaches, 

each agency shall attempt to promote 

. . . coordination, simplification, and 

harmonization.’’ E.O. 13563 further 

states that ‘‘[e]ach agency shall also seek 

to identify, as appropriate, means to 

achieve regulatory goals that are 

designed to promote innovation.’’ 

Within the EPA, we are paying careful 

attention to the interrelatedness and 

potential impacts on the industry, 

reliability and cost that these various 

rulemakings can have. 

As discussed in earlier sections of this 

preamble, the EPA has identified 

potential alternative compliance 

pathways for affected newly 

constructed, modified, and 

reconstructed fossil fuel-fired steam 

generating units. We are finalizing an 

emission standard for newly 

constructed highly efficient fossil fuelfired steam generating units that can be 

met by capturing and storing 

approximately 16 to 23 percent of the 

CO2 produced from the facility or by 

utilizing other technologies such as 

natural gas co-firing. For a subcategory 

of steam generating units that conduct 

‘‘large’’ modifications according to 

definitions in this final rule, we are 

finalizing an emission standard that is 

based on a unit-specific emission 

limitation consistent with each 

modified unit’s best one-year historical 

performance and can be met through a 

combination of best operating practices 

and equipment upgrades. For 

reconstructed steam generating units, 

the EPA is finalizing standards of 

performance based on the performance 

of the most efficient generation 

technology available, which we 

concluded is the use of the best 

available subcritical steam conditions 

for small units and the use of 

supercritical steam conditions for large 

units. The standards can also be met 

through other technology options such 

as natural gas co-firing. In light of these 

potential alternative compliance 

pathways, we believe that sources will 

have ample opportunity to coordinate 

their response to this rule with any 

obligations that may be applicable to 

affected EGUs as a result of the MATS, 

CSAPR, 316(b), SE ELG and CCR rules, 

all of which are or soon will be final 

rules—and to do so in a manner that 

will help reduce cost and ensure 

reliability, while also ensuring that all 

applicable environmental requirements 

are met.568

The EPA is also endeavoring to enable 

EGUs to comply with applicable 

obligations under other power sector 

rules as efficiently as possible (e.g., by 

facilitating their ability to coordinate 

planning and investment decisions with 

respect to those rules) and, where 

possible, implement integrated 

compliance strategies. Section IX.C of 

the preamble to the CAA section 111(d) 

emission guidelines for existing EGUs 

that the EPA is finalizing 

simultaneously with this rule describes 

such an example with respect to the SE 

ELG and CCR rules. 

In light of the compliance flexibilities 

we are offering in this action, we believe 

that sources will have ample 

opportunity to use cost-effective 

regulatory strategies and build on their 

longstanding, successful records of 

complying with multiple CAA, CWA, 

and other environmental requirements, 

while assuring an adequate, affordable, 

and reliable supply of electricity. 

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569Conditions in the analysis year of 2022 are 

represented by a model year of 2020. 

570Sharma, S.; Azzi, M.; ‘‘A critical review of 

existing strategies for emission control in the 

monoethanolamine-based carbon capture process 

and some recommendations for improved 

strategies’’, Fuel, 121, 178 (2014). 

571 Kamijo, T.; et al., ‘‘SO3 Impact on Amine 

Emission and Emission Reduction Technology’’, 

Energy Procedia, Volume 37, 1793 (2013). 

572Sharma, S. (2014). 

573Mertens, J.; et al., ‘‘Understanding 

ethanolamine (MEA) and ammonia emissions from 

amine based post combustion carbon capture: 

Lessons learned from field tests’’, Int’l J. of GHG 

Control, 13, 72 (2013). 

574See Endangered Species Consultation 

Handbook, U.S. Fish & Wildlife Service and 

National Marine Fisheries Service at 4–25(March 

1998) (providing examples of direct effects: e.g., 

driving an off road vehicle through the nesting 

habitat of a listed species of bird and destroying a 

ground nest; building a housing unit and destroying 

the habitat of a listed species). 

XIII. Impacts of This Action 

As explained in the ‘‘Regulatory 

Impact Analysis for the Standards of 

Performance for Greenhouse Gas 

Emissions for New, Modified, and 

Reconstructed Stationary Sources: 

Electric Utility Generating Units’’ (EPA– 

452/R–15–005, August 2015) (RIA), 

available data indicate that, even in the 

absence of the standards of performance 

for newly constructed EGUs, existing 

and anticipated economic conditions 

will lead electricity generators to choose 

new generation technologies that will 

meet the standards without installation 

of additional controls. Therefore, based 

on the analysis presented in Chapter 4 

of the RIA, the EPA projects that this 

final rule will result in negligible CO2

emission changes, quantified benefits, 

and costs on owners and operators of 

newly constructed EGUs by 2022.569

This conclusion is based on the EPA’s 

own modeling as well as projections by 

EIA. While the primary conclusion of 

the analysis presented in the RIA is that 

the standards for newly constructed 

EGUs will result in negligible costs and 

benefits, the EPA has also performed 

several illustrative analyses that show 

the potential impacts of the rule if 

certain key assumptions were to change. 

This includes an analysis of the impacts 

under a range of natural gas prices and 

the costs and benefits associated with 

building an illustrative coal-fired EGU 

with CCS. These are presented in 

Chapter 5 of the RIA. 

As also explained in the RIA for this 

final rule, the EPA also expects that few 

sources will trigger either the NSPS 

modification or reconstruction 

provisions that we are finalizing in this 

rule. In Chapter 6 of the RIA, we discuss 

factors that limit our ability to quantify 

the costs and benefits of the standards 

for modified and reconstructed sources. 

A. What are the air impacts? 

As explained immediately above, the 

EPA does not anticipate that this final 

rule will result in notable CO2 emission 

changes by 2022 as a result of the 

standards of performance for newly 

constructed EGUs. The owners of newly 

constructed EGUs will likely choose 

technologies, primarily NGCC, which 

meet the standards even in the absence 

of this rule due to existing economic 

conditions as normal business practice. 

As also explained immediately above, 

the EPA expects few EGUs to trigger the 

NSPS modification or reconstruction 

provisions in the period of analysis. 

New steam generating EGUs that 

choose to comply with the final 

standard of performance by 

implementing partial post-combustion 

CCS are likely to use commerciallyavailable amine-based capture systems. 

Some concern has been raised regarding 

emissions of amines and amine 

degradation by-products (e.g., NH3) from 

the capture process. To reduce the 

amine emissions, MHI introduced the 

first optimized washing system within 

an absorber column in 1994, and 

developed a proprietary washing system 

in 2003. In that system, a proprietary 

reagent is added to the water washing 

section to capture amine impurities 

such as amine, degraded amine, 

ammonia, formaldehyde, acetaldehyde, 

carbonic acids and nitrosamines.570

MHI has continued to improve this 

technology for further reduction of 

amine emissions and established an 

‘‘advanced amine emission reduction 

system’’. 

Research performed by MHI at 

Alabama Power’s Plant Barry indicated 

that an increasing SO3 content in the 

flue gas caused a significant increase of 

amine emissions. During testing, at 

Plant Barry, MHI applied its proprietary 

washing system and confirmed that the 

amine emission were drastically 

reduced.571 Others have also studied 

emissions and control strategies and 

have determined that a conventional 

multi-stage water wash and mist 

eliminator at the exit of the CO2

scrubber is effective at removal of 

gaseous amine and amine degradation 

products emissions.572 573 Additional 

research continues in this area. 

B. Endangered Species Act 

Consistent with the requirements of 

section 7(a)(2) of the Endangered 

Species Act (ESA), the EPA has also 

considered the effects of this rule and 

has reviewed applicable ESA 

regulations, case law, and guidance to 

determine what, if any, impact there 

may be to listed endangered or 

threatened species or the designated 

critical habitat of such species and 

whether consultation with the U.S. Fish 

and Wildlife Service (FWS) and/or 

National Marine Fisheries Service 

(together, the Services) is required by 

the ESA. Section 7(a)(2) of the ESA 

requires federal agencies, in 

consultation with the Service(s), to 

ensure that actions they authorize, fund, 

or carry out are not likely to jeopardize 

the continued existence of federally 

listed endangered or threatened species 

or result in the destruction or adverse 

modification of designated critical 

habitat of such species. 16 U.S.C. 

1536(a)(2). Under relevant 

implementing regulations, ESA section 

7(a)(2) applies only to actions where 

there is discretionary federal 

involvement or control. 50 CFR 402.03. 

Further, under the regulations 

consultation is required only for actions 

that ‘‘may affect’’ listed species or 

designated critical habitat. 50 CFR 

402.14. Consultation is not required 

where the action has no effect on such 

species or habitat. Under this standard, 

it is the federal agency taking the action 

that evaluates the action and determines 

whether consultation is required. See 51 

FR 19926, 19949 (June 3, 1986). Effects 

of an action include both the direct and 

indirect effects that will be added to the 

environmental baseline. 50 CFR 402.02. 

Direct effects are the direct or 

immediate effects of an action on a 

listed species or its habitat.574 Indirect 

effects are those that are ‘‘caused by the 

proposed action and are later in time, 

but still are reasonably certain to 

occur.’’ Id. To trigger the consultation 

requirement, there must thus be a causal 

connection between the federal action, 

the effect in question, and the listed 

species, and if the effect is indirect, it 

must be reasonably certain to occur. 

The EPA notes that the projected 

environmental effects of this final action 

are positive: Reductions in overall GHG 

emissions, and reductions in PM and 

ozone-precursor emissions (SOX and 

NOX). The EPA recognizes that 

beneficial effects to listed species can, 

as a general matter, result in a ‘‘may 

affect’’ determination under the ESA. 

However, the EPA’s assessment that the 

rule will have an overall net positive 

environmental effect by virtue of 

reducing emissions of certain air 

pollutants does not address whether the 

rule may affect any listed species or 

designated critical habitat for ESA 

section 7(a)(2) purposes and does not 

constitute any finding of effects for that 

purpose. The fact that the rule will have 

overall positive effects on the national 

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575See, e.g., 73 FR 28212, 28300 (May 15, 2008); 

Memorandum from David Longly Bernhardt, 

Solicitor, U.S. Department of the Interior re: 

‘‘Guidance on the Applicability of the Endangered 

Species Act’s Consultation Requirements to 

Proposed Actions Involving the Emission of 

Greenhouse Gases’’ (Oct. 3, 2008). 

576See 75 FR at 25438 Table I.C 2–4 (May 7, 

2010); 77 FR at 62894 Table III–68 (Oct. 15, 2012). 

577The EPA has received correspondence from 

Members of Congress asserting that the Services 

have identified several listed species affected by 

global climate change. The EPA’s assessment of 

ESA requirements in connection with the present 

rule does not address whether global climate 

change may, as a general matter, be a relevant 

consideration in the status of certain listed species. 

Rather, the requirements of ESA section 7(a)(2) 

must be considered and applied to the specific 

action at issue. As explained above, the EPA’s 

conclusion that ESA section 7(a)(2) consultation is 

not required here is premised on the specific facts 

and circumstances of the present rule and is fully 

consistent with prior relevant analyses conducted 

by DOI, FWS, and the EPA. 

578See Letter from David Vitter, James M. Inhofe, 

and Mike Crapo, United States Senate Committee 

on Environment and Public Works, to Gina 

McCarthy, Administrator, U.S. Environmental 

Protection Agency, and Dan Ashe, Director, U.S. 

Fish and Wildlife Service, dated March 6, 2014. 579Estimated costs for the rule include costs for 

fly ash and bottom ash disposal and for spent 

solvent recovery and handling. See ‘‘Cost and 

Performance Baseline for Fossil Energy Plants 

Volume 1a: Bituminous Coal (PC) and Natural Gas 

to Electricity, Revision 3’’, DOE/NETL–2015/1723 

(July 2015) at pp. 43, 130. 

and global environment does not mean 

that the rule may affect any listed 

species in its habitat or the designated 

critical habitat of such species within 

the meaning of ESA section 7(a)(2) or 

the implementing regulations or require 

ESA consultation. 

The EPA notes that the emission 

reductions achieved by the rule are 

projected to be minor. See Section XIII.F 

and G. below, and RIA chapter 4. 

Although the final rule imposes 

substantial controls on CO2 emissions, 

we project few if any new fossil fuelfired steam generating units to be built. 

Emissions reductions from turbines are 

likewise projected to be minimal. 

Moreover, we reasonably project that 

capacity additions during the analysis 

period out to 2022 would already be 

compliant with the rule’s requirements 

(e.g., natural gas combined cycle units, 

low capacity factor natural gas 

combustion turbines, and small 

amounts of coal-fired units with CCS 

supported by federal and state funding). 

See RIA chapter 4. 

With respect to the projected GHG 

emission reductions, the EPA does not 

believe that such minor reductions 

trigger ESA consultation requirements 

under section 7(a)(2). In reaching this 

conclusion, the EPA is mindful of 

significant legal and technical analysis 

undertaken by FWS and the U.S. 

Department of the Interior (DOI) in the 

context of listing the polar bear as a 

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.575 The DOI 

Solicitor concluded that where the 

effect at issue is climate change, 

proposed actions involving GHG 

emissions cannot pass the ‘‘may affect’’ 

test of the section 7 regulations and thus 

are not subject to ESA consultation. 

The EPA has also previously 

considered issues relating to GHG 

emissions in connection with the 

requirements of ESA section 7(a)(2) and 

has supplemented DOI’s analysis with 

additional consideration of GHG 

modeling tools and data regarding listed 

species. The EPA evaluated this same 

issue in the context of the light duty 

vehicle GHG emission standards for 

model years 2012–2016 and 2017–2025. 

There the agency projected GHG 

emission reductions many orders of 

magnitude greater over the lifetimes of 

the model years in question 576 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 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 EPA–OAR–HQ–2009–4782). 

The EPA reached this conclusion after 

evaluating issues relating to potential 

improvements relevant to both 

temperature and oceanographic pH 

outputs. The EPA’s ultimate finding was 

that ‘‘any potential for a specific impact 

on listed species in their habitats 

associated with these very small 

changes in average global temperature 

and ocean pH is too remote to trigger the 

threshold for ESA section 7(a)(2).’’Id. 

The EPA believes that the same 

conclusions apply to the present action, 

given that the projected CO2 emission 

reductions are far less than those 

projected for either of the light duty 

vehicle rules. See, e.g., Ground Zero 

Center for Non-Violent Action v. U.S. 

Dept. of Navy, 383 F. 3d 1082, 1091–92 

(9th Cir. 2004) (where the likelihood of 

jeopardy to a species from a federal 

action is extremely remote, ESA does 

not require consultation). The EPA’s 

conclusion is entirely consistent with 

DOI’s analysis regarding ESA 

requirements in the context of federal 

actions involving GHG emissions.577

The EPA received a comment on the 

proposal referencing a prior letter sent 

to the EPA by three U.S. Senators,578

which asserted that the rule will cause 

a shift to alternative sources of energy 

such as wind and solar and that such 

facilities may have impacts on listed 

species. The comment inquired 

regarding ESA consultation in 

connection with the rule. We reiterate 

that no consultation is required for a 

rule without potential for a specific 

impact on listed species in their 

habitats. 

C. What are the energy impacts? 

This final rule is not anticipated to 

have a notable effect on the supply, 

distribution, or use of energy. As 

previously stated, the EPA believes that 

electric power companies will choose to 

build new EGUs that comply with the 

regulatory requirements of this rule 

even in its absence, primarily NGCC 

units, because of existing and expected 

market conditions. As also previously 

stated, the EPA expects few EGUs to 

trigger the NSPS modification or 

reconstruction provisions in the period 

of analysis. 

D. What are the water and solid waste 

impacts? 

This final rule is not anticipated to 

have notable impacts on water or solid 

waste. As we have noted, the EPA 

believes that utilities and project 

developers will choose to build new 

EGUs that comply with the regulatory 

requirements of this rule even in its 

absence, primarily through the 

construction of new NGCC units. As 

also previously stated, the EPA expects 

few EGUs to trigger the NSPS 

modification or reconstruction 

provisions in the period of analysis. 

Still there are expected to be a small 

number of coal plants with CCS and the 

use of CCS systems (especially postcombustion system) will increase the 

amount of water used at the facility. If 

those plants utilize partial CCS to meet 

the final standard of performance (i.e., 

approximately 16 to 23 percent capture), 

the increased water use will not be 

significant. See Section V.O.2. The EPA 

is unaware of any solid waste impact 

resulting from this rule.579

E. What are the compliance costs? 

For steam generating EGUs, the EPA 

has carefully analyzed the costs of 

meeting the promulgated standard of 

performance for a highly efficient SCPC 

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580The employment analysis in the RIA is part of 

the EPA’s ongoing effort to ‘‘conduct continuing 

evaluations of potential loss or shifts of 

employment which may result from the 

administration or enforcement of [the Act]’’ 

pursuant to CAA section 321(a). 

using partial CCS and found these costs 

to be reasonable. See Sections V.H and 

I above. This analysis assumes new 

capacity not otherwise compliant with 

the standards would be constructed. 

Based on the analysis in chapter 4 of the 

RIA, the EPA believes the standards of 

performance for newly constructed 

EGUs will have no notable compliance 

costs, because electric power companies 

are expected to build new EGUs that 

comply with the regulatory 

requirements of this final rule even in 

the absence of the rule, primarily NGCC 

units, due to existing and expected 

market conditions. While the EPA’s 

analysis and projections from EIA 

continue to show that the rule is likely 

to result in negligible costs and benefits 

due to existing generation choices, the 

EPA recognizes that some companies 

may choose to construct coal or other 

fossil fuel-fired 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 EGUs to trigger the NSPS 

modification or reconstruction 

provisions in the period of analysis. 

F. What are the economic and 

employment impacts? 

The EPA does not anticipate that this 

final rule will result in notable CO2

emission changes, energy impacts, 

monetized benefits, costs, or economic 

impacts by 2022 as a result of the 

standards of performance for newly 

constructed EGUs. The owners of newly 

constructed EGUs will likely choose 

technologies that meet the standards 

even in the absence of this rule, due to 

existing economic conditions as normal 

business practice. Likewise, the EPA 

believes this rule will not have any 

impacts on the price of electricity, 

employment or labor markets, or the 

U.S. economy. See RIA chapter 4.6.580

As previously stated, the EPA 

anticipates few units will trigger the 

NSPS modification or reconstruction 

provisions. As with the new source 

standards, the EPA does not expect 

macroeconomic or employment impacts 

as a result of the standards. 

G. What are the benefits of the final 

standards? 

We are not projecting direct 

monetized climate benefits in terms of 

CO2 emission reductions associated 

with these standards of performance. 

This is because, as stated above, the 

EPA believes that electric power 

companies will choose to build new 

EGUs that comply with the regulatory 

requirements of this rule even in its 

absence, primarily NGCC units, because 

of existing and expected market 

conditions. See RIA chapter 4. 

Moreover, a cost-reasonable standard is, 

in fact, what will drive new technology 

deployment and provide a path forward 

for new coal-fired capacity. See Section 

V.L above. 

As also previously stated, the EPA 

anticipates few units will trigger the 

NSPS modification or reconstruction 

provisions. In Chapter 6 of the RIA, we 

discuss factors that limit our ability to 

quantify the costs and benefits of the 

standards for modified and 

reconstructed sources. 

XIV. Statutory and Executive Order 

Reviews 

Additional information about these 

Statutory and Executive Orders can be 

found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders. 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This final action is a significant 

regulatory action that was submitted to 

the Office of Management and Budget 

(OMB) for review. It is a significant 

regulatory action because it raises novel 

legal or policy issues arising out of legal 

mandates. Any changes made in 

response to OMB recommendations 

have been documented in the 

established dockets for this action under 

Docket ID No. EPA–HQ–OAR–2013– 

0495 (Standards of Performance for 

Greenhouse Gas Emissions from New 

Stationary Sources: Electric Utility 

Generating Units) and Docket ID No. 

EPA–HQ–OAR–2013–0603 (Carbon 

Pollution Standards for Modified and 

Reconstructed Stationary Sources: 

Electric Utility Generating Units). The 

EPA prepared an economic analysis of 

the potential costs and benefits 

associated with this action. This 

analysis, which is contained in the 

‘‘Regulatory Impact Analysis for the 

Standards of Performance for 

Greenhouse Gas Emissions for New, 

Modified, and Reconstructed Stationary 

Sources: Electric Utility Generating 

Units’’ (EPA–452/R–15–005, August 

2015), is available in both dockets. 

The EPA does not anticipate that this 

final action will result in any notable 

compliance costs. Specifically, we 

believe that the standards for newly 

constructed fossil fuel-fired EGUs 

(electric utility steam generating units 

and natural gas-fired stationary 

combustion turbines) will have 

negligible costs associated with it over 

a range of likely sensitivity conditions 

because electric power companies will 

choose to build new EGUs that comply 

with the regulatory requirements of this 

action even in the absence of the action, 

because of existing and expected market 

conditions. (See the RIA for further 

discussion of sensitivities). The EPA 

does not project any new coal-fired 

steam generating units without CCS to 

be built in the absence of this action. 

However, because some companies may 

choose to construct coal or other fossil 

fuel-fired EGUs, the RIA also analyzes 

project-level costs of a unit with and 

without CCS, to quantify the potential 

cost for a fossil fuel-fired EGU with 

CCS. 

The EPA also believes that the 

standards for modified and 

reconstructed fossil fuel-fired EGUs will 

result in minimal compliance costs, 

because, as previously stated, the EPA 

expects few EGUs to trigger the NSPS 

modification or reconstruction 

provisions in the period of analysis 

(through 2022). In Chapter 6 of the RIA, 

we discuss factors that limit our ability 

to quantify the costs and benefits of the 

standards for modified and 

reconstructed sources. 

B. Paperwork Reduction Act (PRA) 

The information collection activities 

in this final action have been submitted 

for approval to OMB under the PRA. 

The Information Collection Request 

(ICR) document that the EPA prepared 

has been assigned EPA ICR number 

2465.03. Separate ICR documents were 

prepared and submitted to OMB for the 

proposed standards for newly 

constructed EGUs (EPA ICR number 

2465.02) and the proposed standards for 

modified and reconstructed EGUs (EPA 

ICR number 2506.01). Because the CO2

standards for newly constructed, 

modified, and reconstructed EGUs will 

be included in the same new subpart (40 

CFR part 60, subpart TTTT) and are 

being finalized in the same action, the 

ICR document for this action includes 

estimates of the information collection 

burden on owners and operators of 

newly constructed, modified, and 

reconstructed EGUs. Estimated cost 

burden is based on 2013 Bureau of 

Labor Statistics (BLS) labor cost data. 

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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–HQ–OAR–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. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for the EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. When 

OMB approves this ICR, the agency will 

announce that approval in the Federal 

Register and publish a technical 

amendment to 40 CFR part 9 to display 

the OMB control number for the 

approved information collection 

activities contained in this final action. 

1. Newly Constructed EGUs 

This final action will impose minimal 

new information collection burden on 

owners and operators of affected newly 

constructed fossil fuel-fired EGUs 

(steam generating units and stationary 

combustion turbines) beyond what 

those sources would already be subject 

to under the authorities of CAA parts 75 

and 98. OMB has previously approved 

the information collection requirements 

contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR 

part 98) under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. and has assigned OMB 

control numbers 2060–0626 and 2060– 

0629, respectively. Apart from certain 

reporting costs to comply with the 

emission standards under the rule, there 

are no new information collection costs, 

as the information required by the 

standards for newly constructed EGUs is 

already collected and reported by other 

regulatory programs. 

The EPA believes that electric power 

companies will choose to build new 

EGUs that comply with the regulatory 

requirements of the rule because of 

existing and expected market 

conditions. The EPA does not project 

any newly constructed coal-fired steam 

generating units that commenced 

construction after proposal (January 8, 

2014) to commence operation over the 

3-year period covered by this ICR. We 

estimate that 12 affected newly 

constructed NGCC units and 25 affected 

newly constructed natural gas-fired 

simple cycle combustion turbines will 

commence operation during that time 

period. As a result of this final action, 

owners or operators of those newly 

constructed units will be required to 

prepare a summary report, which 

includes reporting of emissions and 

downtime, every 3 months. 

2. Modified and Reconstructed EGUs 

This final action is not expected to 

impose an information collection 

burden under the provisions of the PRA 

on owners and operators of affected 

modified and reconstructed fossil fuelfired EGUs (steam generating units and 

stationary combustion turbines). As 

previously stated, the EPA expects few 

EGUs to trigger the NSPS modification 

or reconstruction provisions in the 

period of analysis. Specifically, the EPA 

believes it unlikely that fossil fuel-fired 

electric utility steam generating units or 

stationary combustion turbines will take 

actions that would constitute 

modifications or reconstructions as 

defined under the EPA’s NSPS 

regulations. Accordingly, the standards 

for modified and reconstructed EGUs 

are not anticipated to impose any 

information collection burden over the 

3-year period covered by this ICR. We 

have estimated, however, the 

information collection burden that 

would be imposed on an affected EGU 

if it was modified or reconstructed. 

Although not anticipated, if an EGU 

were to modify or reconstruct, this final 

action would impose minimal 

information collection burden on those 

affected EGUs beyond what they would 

already be subject to under the 

authorities of CAA 40 CFR parts 75 and 

98. As described above, the OMB has 

previously approved the information 

collection requirements contained in the 

existing part 75 and 98 regulations. 

Apart from certain reporting costs to 

comply with the emission standards 

under the rule, there would be no new 

information collection costs, as the 

information required by the final rule is 

already collected and reported by other 

regulatory programs. 

As stated above, although the EPA 

expects few sources will trigger either 

the NSPS modification or reconstruction 

provisions, if an EGU were to modify or 

reconstruct during the 3-year period 

covered by this ICR, the owner or 

operator of the EGU will be required to 

prepare a summary report, which 

includes reporting of emissions and 

downtime, every 3 months. The annual 

reporting burden for such a unit is 

estimated to be $1,333 and 16 labor 

hours. There are no annualized capital 

costs or O&M costs associated with 

burden for modified or reconstructed 

EGUs. 

3. Information Collection Burden 

The annual information collection 

burden for newly constructed, modified, 

and reconstructed EGUs consists only of 

reporting burden as explained above. 

The annual reporting burden for this 

collection (averaged over the first 3 

years after the effective date of the 

standards) is estimated to be $60,977 

and 651 labor hours. There are no 

annualized capital costs or O&M costs 

associated with burden for newly 

constructed, modified, or reconstructed 

EGUs. Average burden hours per 

response are estimated to be 7 hours. 

The total number of respondents over 

the 3-year ICR period is estimated to be 

62. 

C. Regulatory Flexibility Act (RFA) 

I certify that this final action will not 

have a significant economic impact on 

a substantial number of small entities 

under the RFA. In making this 

determination, the impact of concern is 

any significant adverse economic 

impact on small entities. An agency may 

certify that a rule will not have a 

significant economic impact on a 

substantial number of small entities if 

the rule relieves regulatory burden, has 

no net burden or otherwise has a 

positive economic effect on the small 

entities subject to the rule. 

1. Newly Constructed EGUs 

The EPA believes that electric power 

companies will choose to build new 

fossil fuel-fired electric utility steam 

generating units or natural gas-fired 

stationary combustion turbines that 

comply with the regulatory 

requirements of the final rule because of 

existing and expected market 

conditions. RIA Chapter 4. The EPA 

does not project any new coal-fired 

steam generating units without CCS to 

be built. We expect that any newly 

constructed natural gas-fired stationary 

combustion turbines will meet the 

standards. We do not include an 

analysis of the illustrative impacts on 

small entities that may result from 

implementation of the final rule because 

we anticipate negligible compliance 

costs over a range of likely sensitivity 

conditions as a result of the standards 

for newly constructed EGUs. Thus the 

cost-to-sales ratios for any affected small 

entity would be zero costs as compared 

to annual sales revenue for the entity. 

Accordingly, there are no anticipated 

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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–15–005, August 

2015) for further discussion of 

sensitivities.) We have therefore 

concluded that this final action will 

have no net regulatory burden for all 

directly regulated small entities. 

2. Modified and Reconstructed EGUs 

The EPA expects few fossil fuel-fired 

electric utility steam generating units to 

trigger the NSPS modification 

provisions in the period of analysis. An 

NSPS modification is defined as a 

physical or operational change that 

increases the source’s maximum 

achievable hourly rate of emissions. The 

EPA does not believe that there are 

likely to be EGUs that will take actions 

that would constitute modifications as 

defined under the EPA’s NSPS 

regulations. 

In addition, the EPA expects few 

reconstructed fossil fuel-fired electric 

utility steam generating units or natural 

gas-fired 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 the 

‘‘Regulatory Impact Analysis for the 

Standards of Performance for 

Greenhouse Gas Emissions for New, 

Modified, and Reconstructed Stationary 

Sources: Electric Utility Generating 

Units’’ (EPA–452/R–15–005, August 

2015). 

D. Unfunded Mandates Reform Act 

(UMRA) 

This final action does not contain an 

unfunded mandate of $100 million or 

more as described in UMRA, 2 U.S.C. 

1531–1538, and does not significantly or 

uniquely affect small governments. 

The EPA believes the final rule will 

have negligible compliance costs on 

owners and operators of newly 

constructed EGUs over a range of likely 

sensitivity conditions because electric 

power companies will choose to build 

new fossil fuel-fired electric utility 

steam generating units or natural gasfired stationary combustion turbines 

that comply with the regulatory 

requirements of the rule because of 

existing and expected market 

conditions. The EPA does not project 

any new coal-fired steam generating 

units without CCS to be built and 

expects that any newly constructed 

natural gas-fired stationary combustion 

turbines will meet the standards. (See 

the ‘‘Regulatory Impact Analysis for the 

Standards of Performance for 

Greenhouse Gas Emissions for New, 

Modified, and Reconstructed Stationary 

Sources: Electric Utility Generating 

Units’’ (EPA–452/R–15–005, August 

2015) for further discussion of 

sensitivities.) 

As previously stated, the EPA expects 

few fossil fuel-fired electric utility steam 

generating units or natural gas-fired 

stationary combustion turbines to trigger 

the NSPS modification or reconstruction 

provisions in the period of analysis. In 

Chapter 6 of the RIA, we discuss factors 

that limit our ability to quantify the 

costs and benefits of the standards for 

modified and reconstructed sources. 

However, we do not anticipate that the 

rule would impose significant costs on 

those sources. (See the ‘‘Regulatory 

Impact Analysis for the Standards of 

Performance for Greenhouse Gas 

Emissions for New, Modified, and 

Reconstructed Stationary Sources: 

Electric Utility Generating Units’’ (EPA– 

452/R–15–005, August 2015).) 

We have therefore concluded that the 

standards for newly constructed, 

modified, and reconstructed EGUs do 

not impose enforceable duties on any 

state, local or tribal governments, or the 

private sector, that may result in 

expenditures by state, local and tribal 

governments, in the aggregate, or to the 

private sector, of $100 million or more 

in any one year. We have also 

concluded that this action does not have 

regulatory requirements that might 

significantly or uniquely affect small 

governments. The threshold amount 

established for determining whether 

regulatory requirements could 

significantly affect small governments is 

$100 million annually and, as stated 

above, we have concluded that the final 

action will not result in expenditures of 

$100 million or more in any one year. 

Specifically, the EPA does not project 

any new coal-fired steam generating 

units without CCS to be built and 

expects that any newly constructed 

natural gas-fired stationary combustion 

turbines will meet the standards. 

Further, the EPA expects few fossil fuelfired electric utility steam generating 

units or natural gas-fired stationary 

combustion turbines to trigger the NSPS 

modification or reconstruction 

provisions in the period of analysis. 

E. Executive Order 13132: Federalism 

This final action does not have 

federalism implications. It will not have 

substantial direct effects on the states, 

on the relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government. The EPA believes 

that electric power companies will 

choose to build new fossil fuel-fired 

electric utility steam generating units or 

natural gas-fired stationary combustion 

turbines that comply with the regulatory 

requirements of the final rule because of 

existing and expected market 

conditions. In addition, as previously 

stated, the EPA expects few fossil fuelfired electric utility steam generating 

units or natural gas-fired stationary 

combustion turbines to trigger the NSPS 

modification or reconstruction 

provisions in the period of analysis. We, 

therefore, anticipate that the final rule 

will impose minimal compliance costs. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This final action does not have tribal 

implications as specified in Executive 

Order 13175. The final rule will impose 

requirements on owners and operators 

of newly constructed, modified, and 

reconstructed EGUs. The EPA is aware 

of three facilities with coal-fired steam 

generating units, as well as one facility 

with natural gas-fired stationary 

combustion turbines, located in Indian 

Country, but is not aware of any EGUs 

owned or operated by tribal entities. We 

note that because the rule addresses CO2

emissions from newly constructed, 

modified, and reconstructed EGUs, it 

will affect existing EGUs such as those 

located at the four facilities in Indian 

Country only if those EGUs were to take 

actions constituting modifications or 

reconstructions as defined under the 

EPA’s NSPS regulations. As previously 

stated, the EPA expects few EGUs to 

trigger the NSPS modification or 

reconstruction provisions in the period 

of analysis. Thus, the rule will neither 

impose substantial direct compliance 

costs on tribal governments nor preempt 

Tribal law. Accordingly, Executive 

Order 13175 does not apply to this 

action. 

Nevertheless, because the EPA is 

aware of Tribal interest in carbon 

pollution standards for the power sector 

and, consistent with the EPA Policy on 

Consultation and Coordination with 

Indian Tribes, the EPA offered 

consultation with tribal officials during 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64645 

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. 

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 

children. Accordingly, the agency has 

evaluated the environmental health and 

welfare effects of climate change on 

children. 

CO2 is a potent GHG that contributes 

to climate change and is emitted in 

significant quantities by fossil fuel-fired 

power plants. As stated above, the EPA 

believes the final rule will have 

negligible effects on owners and 

operators of newly constructed EGUs 

over a range of likely sensitivity 

conditions because electric power 

companies will choose to build new 

fossil fuel-fired electric utility steam 

generating units or natural gas-fired 

stationary combustion turbines that 

comply with the regulatory 

requirements of the rule because of 

existing and expected market 

conditions. However, the RIA also 

analyzes project-level costs of a unit 

with and without CCS, to quantify the 

potential cost for a fossil fuel-fired unit 

with CCS. RIA chapter 5. Under these 

scenarios, the rule would result in 

substantial reductions of both CO2, and 

also fine particulate matter (sulfate PM 

2.5) such that net quantifiable benefits 

exceed regulatory costs under a range of 

assumptions. Under these same 

scenarios, this rule would have a 

positive effect for children’s health. 

The assessment literature cited in the 

EPA’s 2009 Endangerment Finding 

concluded that certain populations and 

lifestages, including children, the 

elderly, and the poor, are most 

vulnerable to climate-related health 

effects. The assessment literature since 

2009 strengthens these conclusions by 

providing more detailed findings 

regarding these groups’ vulnerabilities 

and the projected impacts they may 

experience. 

These assessments describe how 

children’s unique physiological and 

developmental factors contribute to 

making them particularly vulnerable to 

climate change. Impacts to children are 

expected from heat waves, air pollution, 

infectious and waterborne illnesses, and 

mental health effects resulting from 

extreme weather events. In addition, 

children are among those especially 

susceptible to most allergic diseases, as 

well as health effects associated with 

heat waves, storms, and floods. 

Additional health concerns may arise in 

low income households, especially 

those with children, if climate change 

reduces food availability and increases 

prices, leading to food insecurity within 

households. 

More detailed information on the 

impacts of climate change to human 

health and welfare is provided in 

Section II.A of this preamble. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This final action is not a ‘‘significant 

energy action’’ because it is not likely to 

have a significant adverse effect on the 

supply, distribution, or use of energy. 

See Section V.O.3 above. The EPA 

believes that electric power companies 

will choose to build new fossil fuel-fired 

electric utility steam generating units or 

natural gas-fired stationary combustion 

turbines that comply with the regulatory 

requirements of the final rule because of 

existing and expected market 

conditions. In addition, as previously 

stated, the EPA expects few fossil fuelfired electric utility steam generating 

units or natural gas-fired stationary 

combustion turbines to trigger the NSPS 

modification or reconstruction 

provisions in the period of analysis. 

Thus, this action is not anticipated to 

have notable impacts on emissions, 

costs or energy supply decisions for the 

affected electric utility industry. 

I. National Technology Transfer and 

Advancement Act (NTTAA) and 1 CFR 

Part 51 

This final action involves technical 

standards. The EPA has decided to use 

10 voluntary consensus standards (VCS) 

in the final rule. 

One VCS, American National 

Standards Institute (ANSI) Standard 

C12.20, ‘‘American National Standard 

for Electricity Meters—0.2 and 0.5 

Accuracy Classes,’’ is cited in the final 

rule to assure consistent monitoring of 

electric output. This standard 

establishes the physical aspects and 

acceptable performance criteria for 0.2 

and 0.5 accuracy class electricity 

meters. This standard is available at 

http://www.ansi.org or by mail at 

American National Standards Institute 

(ANSI), 25 W. 43rd Street, 4th Floor, 

New York, NY 10036. 

Six VCS, ASTM Methods D388–99, 

‘‘Standard Classification of Coals by 

Rank’’; D396–98, ‘‘Standard 

Specification for Fuel Oils’’; D975–08a, 

‘‘Standard Specification for Diesel Fuel 

Oils’’; D3699–08, ‘‘Standard 

Specification for Kerosine’’; D6751–11b, 

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64646 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

‘‘Standard Specification for Biodiesel 

Fuel Blend Stock (B100) for Middle 

Distillate Fuels’’; and D7467–10, 

‘‘Standard Specification for Diesel Fuel 

Oil, Biodiesel Blend (B6 to B20)’’ are 

cited in the final rule to identify the 

different fuel types. ASTM D388 covers 

the classification of coals by rank, that 

is, according to their degree of 

metamorphism, or progressive 

alteration, in the natural series from 

lignite to anthracite. ASTM D396 covers 

grades of fuel oil intended for use in 

various types of fuel-oil-burning 

equipment under various climatic and 

operating conditions. These include 

Grades 1 and 2 (for use in domestic and 

small industrial burners), Grade 4 

(heavy distillate fuels or distillate/

residual fuel blends used in 

commercial/industrial burners equipped 

for this viscosity range), and Grades 5 

and 6 (residual fuels of increasing 

viscosity and boiling range, used in 

industrial burners). ASTM D975 covers 

seven grades of diesel fuel oils based on 

grade, sulfur content, and volatility. 

These grades range from Grade No. 1– 

D S15 (a special-purpose, light middle 

distillate fuel for use in diesel engine 

applications requiring a fuel with 15 

ppm sulfur (maximum) and higher 

volatility than that provided by Grade 

No. 2–D S15 fuel) to Grade No. 4–D (a 

heavy distillate fuel, or a blend of 

distillate and residual oil, for use in 

low- and medium-speed diesel engines 

in applications involving predominantly 

constant speed and load). ASTM D3699 

covers two grades of kerosene suitable 

for use in critical kerosene burner 

applications: No. 1–K (a special lowsulfur grade kerosene suitable for use in 

non-flue-connected kerosene burner 

appliances and for use in wick-fed 

illuminating lamps) and No. 2–K (a 

regular grade kerosene suitable for use 

in flue-connected burner appliances and 

for use in wick-fed illuminating lamps). 

ASTM D6751 covers biodiesel (B100) 

Grades S15 and S500 for use as a blend 

component with middle distillate fuels. 

ASTM D7467 covers fuel blend grades 

of 6 to 20 volume percent biodiesel with 

the remainder being a light middle or 

middle distillate diesel fuel, collectively 

designated as B6 to B20. These 

standards are available at http://

www.astm.org or by mail at ASTM 

International, 100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, 

PA 19428–2959. 

Two VCS, American Society of 

Mechanical Engineers (ASME) 

Performance Test Codes PTC 22–2014, 

‘‘Performance Test Codes on Gas 

Turbines’’ and PTC 46–1996, 

‘‘Performance Test Codes on Overall 

Plant Performance’’ are cited in the final 

rule for their guidance on measuring the 

performance of stationary combustion 

turbines. PTC–22 provides directions 

and rules for conduct and report of 

results of thermal performance tests for 

open cycle simple cycle combustion 

turbines. The object is to determine the 

thermal performance of the combustion 

turbine when operating at test 

conditions, and correcting these test 

results to specified reference conditions. 

PTC 22 provides explicit procedures for 

the determination of the following 

performance results: corrected power, 

corrected heat rate (efficiency), 

corrected exhaust flow, corrected 

exhaust energy, and corrected exhaust 

temperature. Tests may be designed to 

satisfy different goals, including 

absolute performance and comparative 

performance. The objective of PTC 46 is 

to provide uniform test methods and 

procedures for the determination of the 

thermal performance and electrical 

output of heat-cycle electric power 

plants and combined heat and power 

units (PTC 46 is not applicable to 

simple cycle combustion turbines). Test 

results provide a measure of the 

performance of a power plant or thermal 

island at a specified cycle configuration, 

operating disposition and/or fixed 

power level, and at a unique set of base 

reference conditions. PTC 46 provides 

explicit procedures for the 

determination of the following 

performance results: corrected net 

power, corrected heat rate, and 

corrected heat input. These standards 

are available at http://www.asme.org or 

by mail at American Society of 

Mechanical Engineers (ASME), Two 

Park Avenue, New York, NY 10016– 

5990. 

One VCS, International Organization 

for Standardization method ISO 

2314:2009, ‘‘Gas Turbines—Acceptance 

Tests’’ is cited in the final rule for its 

guidance on determining performance 

characteristics of stationary combustion 

turbines. ISO 2314 specifies guidelines 

and procedures for preparing, 

conducting and reporting thermalacceptance tests in order to determine 

and/or verify electrical power output, 

mechanical power, thermal efficiency 

(heat rate), turbine exhaust gas energy 

and/or other performance characteristics 

of open-cycle simple cycle combustion 

turbines using combustion systems 

supplied with gaseous and/or liquid 

fuels as well as closed-cycle and semiclosed-cycle simple cycle combustion 

turbines. It can also be applied to simple 

cycle combustion turbines in combined 

cycle power plants or in connection 

with other heat recovery systems. ISO 

2314 includes procedures for the 

determination of the following 

performance parameters, corrected to 

the reference operating parameters: 

electrical or mechanical power output 

(gas power, if only gas is supplied), 

thermal efficiency or heat rate; and 

combustion turbine engine exhaust 

energy (optionally exhaust temperature 

and flow). This standard is available at 

http://www.iso.org/iso/home.htm or by 

mail at International Organization for 

Standardization (ISO), 1, ch. de la VoieCreuse, Case postale 56, CH–1211 

Geneva 20, Switzerland. 

Since no EPA Methods were used, 

there was no need for a NTTAA search. 

The rule also requires use of appendices 

A, B, D, F and G to 40 CFR part 75 and 

the procedures under 40 CFR 98.33; 

these appendices contain standards that 

have already been reviewed under the 

NTTAA. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629; 

February 16, 1994) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the U.S. The EPA defines 

environmental justice as the fair 

treatment and meaningful involvement 

of all people regardless of race, color, 

national origin, or income with respect 

to the development, implementation, 

and enforcement of environmental laws, 

regulations, and policies. The EPA has 

this goal for all communities and 

persons across this Nation. It will be 

achieved when everyone enjoys the 

same degree of protection from 

environmental and health hazards and 

equal access to the decision-making 

process to have a healthy environment 

in which to live, learn, and work. 

Leading up to this rulemaking the 

EPA summarized the public health and 

welfare effects of GHG emissions in its 

2009 Endangerment Finding. As part of 

the Endangerment Finding, the 

Administrator considered climate 

change risks to minority or low-income 

populations, finding that certain parts of 

the population may be especially 

vulnerable based on their 

circumstances. Populations that were 

found to be particularly vulnerable to 

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581Melillo, 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. 

climate change risks include the poor, 

the elderly, the very young, those 

already in poor health, the disabled, 

those living alone, and/or indigenous 

populations dependent on one or a few 

resources. See Sections XIV.F and G, 

above, where the EPA discusses 

Consultation and Coordination with 

Tribal Governments and Protection of 

Children. The Administrator placed 

weight on the fact that certain groups, 

including children, the elderly, and the 

poor, are most vulnerable to climaterelated health effects. 

The record for the 2009 

Endangerment Finding summarizes the 

strong scientific evidence in the major 

assessment reports by the U.S. Global 

Change Research Program (USGCRP), 

the Intergovernmental Panel on Climate 

Change (IPCC), and the National 

Research Council (NRC) of the National 

Academies that the potential impacts of 

climate change raise environmental 

justice issues. These reports concluded 

that poor communities can be especially 

vulnerable to climate change impacts 

because they tend to have more limited 

adaptive capacities and are more 

dependent on climate-sensitive 

resources such as local water and food 

supplies. In addition, Native American 

tribal communities possess unique 

vulnerabilities to climate change, 

particularly those impacted by 

degradation of natural and cultural 

resources within established reservation 

boundaries and threats to traditional 

subsistence lifestyles. Tribal 

communities whose health, economic 

well-being, and cultural traditions 

depend upon the natural environment 

will likely be affected by the 

degradation of ecosystem goods and 

services associated with climate change. 

The 2009 Endangerment Finding record 

also specifically noted that Southwest 

native cultures are especially vulnerable 

to water quality and availability 

impacts. Native Alaskan communities 

are already experiencing disruptive 

impacts, including coastal erosion and 

shifts in the range or abundance of wild 

species crucial to their livelihoods and 

well-being. 

The most recent assessments continue 

to strengthen scientific understanding of 

climate change risks to minority and 

low-income populations in the United 

States.581 The new assessment literature 

provides more detailed findings 

regarding these populations’ 

vulnerabilities and projected impacts 

they may experience. In addition, the 

most recent assessment reports provides 

new information on how some 

communities of color may be uniquely 

vulnerable to climate change health 

impacts in the United States. These 

reports find that certain climate change 

related impacts—including heat waves, 

degraded air quality, and extreme 

weather events—have disproportionate 

effects on low-income and some 

communities of color, raising 

environmental justice concerns. Existing 

health disparities and other inequities 

in these communities increase their 

vulnerability to the health effects of 

climate change. In addition, assessment 

reports also find that climate change 

poses particular threats to health, 

wellbeing, and ways of life of 

indigenous peoples in the United States. 

As the scientific literature presented 

above and in the Endangerment Finding 

illustrates, low income communities 

and some communities of color are 

especially vulnerable to the health and 

other adverse impacts of climate change. 

The EPA believes the human health or 

environmental risk addressed by this 

final action will not have potential 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income or indigenous 

populations. The final rule limits GHG 

emissions from newly constructed, 

modified, and reconstructed fossil fuelfired electric utility steam generating 

units and newly constructed and 

modified stationary combustion 

turbines by establishing national 

emission standards for CO2. 

The EPA has determined that the final 

rule will not result in disproportionately 

high and adverse human health or 

environmental effects on minority, lowincome 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 gasfired stationary combustion turbines 

will meet the standards. In addition, as 

previously stated, the EPA expects few 

fossil fuel-fired electric utility steam 

generating units or natural gas-fired 

stationary combustion turbines to trigger 

the NSPS modification or reconstruction 

provisions in the period of analysis. 

This final rule will ensure that, to 

whatever extent there are newly 

constructed, modified, and 

reconstructed EGUs, they will use the 

best performing technologies to limit 

emissions of CO2. 

K. Congressional Review Act (CRA) 

This final action is subject to the CRA, 

and the EPA will submit a rule report 

to each House of the Congress and to the 

Comptroller General of the United 

States. This action is not a ‘‘major rule’’ 

as defined by 5 U.S.C. 804(2). 

XV. Withdrawal of Proposed Standards 

for Certain Modified Sources 

In this action, as discussed above in 

Sections IV and VI, the EPA is issuing 

final standards of performance for 

affected fossil fuel-fired steam 

generating EGUs that implement 

modifications resulting in an increase of 

CO2 emissions (in lb/hr) of more than 10 

percent. In addition, the EPA is 

withdrawing the proposed standards of 

performance for emissions of carbon 

dioxide (CO2) from modified fossil fuelfired EGUs not covered by those final 

standards. Specifically, the EPA is 

withdrawing the proposed standards for 

fossil fuel-fired steam generating EGUs 

that implement modifications resulting 

in an increase of CO2 emissions (in lb/ 

hr) of less than or equal to 10 percent. 

A detailed rationale for the withdrawal 

of these proposed standards is provided 

in Section VI above. 

The EPA is also, in this action, 

withdrawing proposed standards for 

modified stationary combustion 

turbines. A detailed rationale for the 

withdrawal of these proposed standards 

is provided in Section IX above. 

The proposed standards for modified 

fossil fuel-fired EGUs that the EPA is 

withdrawing in this action were 

published in the Federal Register on 

June 18, 2014 (79 FR 34960). 

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64648 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

XVI. Statutory Authority 

The statutory authority for this action 

is provided by sections 111, 301, 302, 

and 307(d)(1)(C) of the CAA as amended 

(42 U.S.C. 7411, 7601, 7602, 

7607(d)(1)(C)). This action is also 

subject to section 307(d) of the CAA (42 

U.S.C. 7607(d)). 

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: August 3, 2015. 

Gina McCarthy, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, parts 60, 

70, 71, and 98 of the Code of the Federal 

Regulations are amended as follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

■ 2. Section 60.17 is amended by: 

■ a. Redesignating paragraphs (d) 

through (t) as paragraphs (e) through (u) 

and adding paragraph (d); 

■ b. In newly redesignated paragraph 

(g), further redesignating paragraph 

(g)(15) as paragraph (g)(17) and adding 

paragraphs (g)(15) and (16); 

■ c. In newly redesignated paragraph 

(h), revising paragraphs (h)(37), (42), 

(46), (138), (187), and (190); and 

■ c. In newly redesignated paragraph 

(m), further redesignating paragraph 

(m)(1) as paragraph (m)(2) and adding 

paragraph (m)(1). 

The revisions and additions read as 

follows: 

§ 60.17 Incorporations by reference. 

* * * * * 

(d) The following material is available 

for purchase from the American 

National Standards Institute (ANSI), 25 

W. 43rd Street, 4th Floor, New York, NY 

10036, Telephone (212) 642–4980, and 

is also available at the following Web 

site: http://www.ansi.org. 

(1) ANSI No. C12.20–2010 American 

National Standard for Electricity 

Meters—0.2 and 0.5 Accuracy Classes 

(Approved August 31, 2010), IBR 

approved for § 60.5535(d). 

(2) [Reserved] 

* * * * * 

(g) * * * 

(15) ASME PTC 22–2014, Gas 

Turbines: Performance Test Codes, 

(Issued December 31, 2014), IBR 

approved for § 60.5580. 

(16) ASME PTC 46–1996, 

Performance Test Code on Overall Plant 

Performance, (Issued October 15, 1997), 

IBR approved for § 60.5580. 

* * * * * 

(h) * * * 

(37) ASTM D388–99 (Reapproved 

2004) ε1 Standard Classification of Coals 

by Rank, IBR approved for §§ 60.41, 

60.45(f), 60.41Da, 60.41b, 60.41c, 

60.251, and 60.5580. 

* * * * * 

(42) ASTM D396–98, Standard 

Specification for Fuel Oils, IBR 

approved for §§ 60.41b, 60.41c, 

60.111(b), 60.111a(b), and 60.5580. 

* * * * * 

(46) ASTM D975–08a, Standard 

Specification for Diesel Fuel Oils, IBR 

approved for §§ 60.41b 60.41c, and 

60.5580. 

* * * * * 

(138) ASTM D3699–08, Standard 

Specification for Kerosine, including 

Appendix X1, (Approved September 1, 

2008), IBR approved for §§ 60.41b, 

60.41c, and 60.5580. 

* * * * * 

(187) ASTM D6751–11b, Standard 

Specification for Biodiesel Fuel Blend 

Stock (B100) for Middle Distillate Fuels, 

including Appendices X1 through X3, 

(Approved July 15, 2011), IBR approved 

for §§ 60.41b, 60.41c, and 60.5580. 

* * * * * 

(190) ASTM D7467–10, Standard 

Specification for Diesel Fuel Oil, 

Biodiesel Blend (B6 to B20), including 

Appendices X1 through X3, (Approved 

August 1, 2010), IBR approved for 

§§ 60.41b, 60.41c, and 60.5580. 

* * * * * 

(m) * * * 

(1) ISO 2314:2009(E), Gas turbines– 

Acceptance tests, Third edition 

(December 15, 2009), IBR approved for 

§ 60.5580. 

* * * * * 

■ 3. Part 60 is amended by adding 

subpart TTTT to read as follows: 

Subpart TTTT—Standards of Performance 

for Greenhouse Gas Emissions for Electric 

Generating Units 

Applicability 

Sec. 

60.5508 What is the purpose of this 

subpart? 

60.5509 Am I subject to this subpart? 

Emission Standards 

60.5515 Which pollutants are regulated by 

this subpart? 

60.5520 What CO2 emissions standard must 

I meet? 

General Compliance Requirements 

60.5525 What are my general requirements 

for complying with this subpart? 

Monitoring and Compliance Determination 

Procedures 

60.5535 How do I monitor and collect data 

to demonstrate compliance? 

60.5540 How do I demonstrate compliance 

with my CO2 emissions standard and 

determine excess emissions? 

Notifications, Reports, and Records 

60.5550 What notifications must I submit 

and when? 

60.5555 What reports must I submit and 

when? 

60.5560 What records must I maintain? 

60.5565 In what form and how long must I 

keep my records? 

Other Requirements and Information 

60.5570 What parts of the general 

provisions apply to my affected EGU? 

60.5575 Who implements and enforces this 

subpart? 

60.5580 What definitions apply to this 

subpart? 

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 

Table 2 of Subpart TTTT of Part 60—CO2

Emission Standards for Affected Stationary 

Combustion Turbines that Commenced 

Construction after January 8, 2014 and 

Reconstruction after June 18, 2014 (Net 

Energy Output-based Standards Applicable 

as Approved by the Administrator) 

Table 3 to Subpart TTTT of Part 60— 

Applicability of Subpart A of Part 60 

(General Provisions) to Subpart TTTT 

Applicability 

§ 60.5508 What is the purpose of this 

subpart? 

This subpart establishes emission 

standards and compliance schedules for 

the control of greenhouse gas (GHG) 

emissions from a steam generating unit, 

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IGCC, or a stationary combustion 

turbine that commences construction 

after January 8, 2014 or commences 

modification or reconstruction after 

June 18, 2014. An affected steam 

generating unit, IGCC, or stationary 

combustion turbine shall, for the 

purposes of this subpart, be referred to 

as an affected EGU. 

§ 60.5509 Am I subject to this subpart? 

(a) Except as provided for in 

paragraph (b) of this section, the GHG 

standards included in this subpart apply 

to any steam generating unit, IGCC, or 

stationary combustion turbine that 

commenced construction after January 

8, 2014 or commenced reconstruction 

after June 18, 2014 that meets the 

relevant applicability conditions in 

paragraphs (a)(1) and (2) of this section. 

The GHG standards included in this 

subpart also apply to any steam 

generating unit or IGCC that 

commenced modification after June 18, 

2014 that meets the relevant 

applicability conditions in paragraphs 

(a)(1) and (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 or generators 

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 (10) of this section. 

(1) Your EGU is a steam generating 

unit or IGCC that is currently and 

always has been subject to a federally 

enforceable permit condition limiting 

annual net-electric sales to no more than 

one-third of its potential electric output 

or 219,000 MWh, whichever is greater. 

(2) Your EGU is capable of 

combusting 50 percent or more nonfossil fuel and is also subject to a 

federally enforceable permit condition 

limiting the annual capacity factor for 

all fossil fuels combined of 10 percent 

(0.10) or less. 

(3) Your EGU is a combined heat and 

power unit that is subject to a federally 

enforceable permit condition limiting 

annual net-electric sales to no more than 

either 219,000 MWh or the product of 

the design efficiency and the potential 

electric output, whichever is greater. 

(4) Your EGU serves a generator along 

with other steam generating unit(s), 

IGCC, or stationary combustion 

turbine(s) where the effective generation 

capacity (determined based on a 

prorated output of the base load rating 

of each steam generating unit, IGCC, or 

stationary combustion turbine) is 25 

MW or less. 

(5) Your EGU is a municipal waste 

combustor that is subject to subpart Eb 

of this part. 

(6) Your EGU is a commercial or 

industrial solid waste incineration unit 

that is subject to subpart CCCC of this 

part. 

(7) Your EGU is a steam generating 

unit or IGCC that undergoes a 

modification resulting in an hourly 

increase in CO2 emissions (mass per 

hour) of 10 percent or less (2 significant 

figures). Modified units that are not 

subject to the requirements of this 

subpart pursuant to this subsection 

continue to be existing units under 

section 111 with respect to CO2

emissions standards. 

(8) Your EGU is a stationary 

combustion turbine that is not capable 

of combusting natural gas (e.g., not 

connected to a natural gas pipeline). 

(9) The proposed Washington County 

EGU project described in Air Quality 

Permit No. 4911–303–0051–P–01–0 

issued by the Georgia Department of 

Natural Resources, Environmental 

Protection Division, Air Protection 

Branch, effective April 8, 2010, 

provided that construction had not 

commenced for NSPS purposes as of 

January 8, 2014. 

(10) The proposed Holcomb EGU 

project described in Air Emission 

Source Construction Permit 0550023 

issued by the Kansas Department of 

Health and Environment, Division of 

Environment, effective December 16, 

2010, provided that construction had 

not commenced for NSPS purposes as of 

January 8, 2014. 

Emission Standards 

§ 60.5515 Which pollutants are regulated 

by this subpart? 

(a) The pollutants regulated by this 

subpart are greenhouse gases. The 

greenhouse gas standard in this subpart 

is in the form of a limitation on 

emission of carbon dioxide. 

(b) PSD and title V thresholds for 

greenhouse gases. (1) For the purposes 

of 40 CFR 51.166(b)(49)(ii), with respect 

to GHG emissions from affected 

facilities, the ‘‘pollutant that is subject 

to the standard promulgated under 

section 111 of the Act’’ shall be 

considered to be the pollutant that 

otherwise is subject to regulation under 

the Act as defined in § 51.166(b)(48) of 

this chapter and in any SIP approved by 

the EPA that is interpreted to 

incorporate, or specifically incorporates, 

§ 51.166(b)(48). 

(2) For the purposes of 40 CFR 

52.21(b)(50)(ii), with respect to GHG 

emissions from affected facilities, the 

‘‘pollutant that is subject to the standard 

promulgated under section 111 of the 

Act’’ shall be considered to be the 

pollutant that otherwise is subject to 

regulation under the Act as defined in 

§ 52.21(b)(49) of this chapter. 

(3) For the purposes of 40 CFR 70.2, 

with respect to greenhouse gas 

emissions from affected facilities, the 

‘‘pollutant that is subject to any 

standard promulgated under section 111 

of the Act’’ shall be considered to be the 

pollutant that otherwise is ‘‘subject to 

regulation’’ as defined in 40 CFR 70.2. 

(4) For the purposes of 40 CFR 71.2, 

with respect to greenhouse gas 

emissions from affected facilities, the 

‘‘pollutant that is subject to any 

standard promulgated under section 111 

of the Act’’ shall be considered to be the 

pollutant that otherwise is ‘‘subject to 

regulation’’ as defined in 40 CFR 71.2. 

§ 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 2 of this subpart, consistent 

with paragraphs (b), (c), and (d) of this 

section, as applicable. 

(b) Except as specified in paragraphs 

(c) and (d) of this section, you must 

comply with the applicable gross energy 

output standard, and your operating 

permit must include monitoring, 

recordkeeping, and reporting 

methodologies based on the applicable 

gross energy output standard. For the 

remainder of this subpart (for sources 

that do not qualify under paragraphs (c) 

and (d) of this section), where the term 

‘‘gross or net energy output’’ is used, the 

term that applies to you is ‘‘gross energy 

output.’’ 

(c) As an alternate to meeting the 

requirements in paragraph (b) of this 

section, an owner or operator of a 

stationary combustion turbine may 

petition the Administrator in writing to 

comply with the alternate applicable net 

energy output standard. If the 

Administrator grants the petition, 

beginning on the date the Administrator 

grants the petition, the affected EGU 

must comply with the applicable net 

energy output-based standard included 

in this subpart. Your operating permit 

must include monitoring, 

recordkeeping, and reporting 

methodologies based on the applicable 

net energy output standard. For the 

remainder of this subpart, where the 

term ‘‘gross or net energy output’’ is 

used, the term that applies to you is 

‘‘net energy output.’’ Owners or 

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64650 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

operators complying with the net 

output-based standard must petition the 

Administrator to switch back to 

complying with the gross energy outputbased standard. 

(d) Stationary combustion turbines 

subject to a heat input-based standard in 

Table 2 of this subpart that are only 

permitted to burn one or more uniform 

fuels, as described in paragraph (d)(1) of 

this section, are only subject to the 

monitoring requirements in paragraph 

(d)(1). All other stationary combustion 

turbines subject to a heat input based 

standard in Table 2 are subject to the 

requirements in paragraph (d)(2) of this 

section. 

(1) Stationary combustion turbines 

that are only permitted to burn fuels 

with a consistent chemical composition 

(i.e., uniform fuels) that result in a 

consistent emission rate of 160 lb CO2/ 

MMBtu or less are not subject to any 

monitoring or reporting requirements 

under this subpart. These fuels include, 

but are not limited to, natural gas, 

methane, butane, butylene, ethane, 

ethylene, propane, naphtha, propylene, 

jet fuel kerosene, No. 1 fuel oil, No. 2 

fuel oil, and biodiesel. Stationary 

combustion turbines qualifying under 

this paragraph are only required to 

maintain purchase records for permitted 

fuels. 

(2) Stationary combustion turbines 

permitted to burn fuels that do not have 

a consistent chemical composition or 

that do not have an emission rate of 160 

lb CO2/MMBtu or less (e.g., non-uniform 

fuels such as residual oil and non-jet 

fuel kerosene) must follow the 

monitoring, recordkeeping, and 

reporting requirements necessary to 

complete the heat input-based 

calculations under this subpart. 

General Compliance Requirements 

§ 60.5525 What are my general 

requirements for complying with this 

subpart? 

Combustion turbines qualifying under 

§ 60.5520(d)(1) are not subject to any 

requirements in this section other than 

the requirement to maintain fuel 

purchase records for permitted fuel(s). 

For all other affected sources, 

compliance with the applicable CO2

emission standard of this subpart shall 

be determined on a 12-operating-month 

rolling average basis. See Table 1 or 2 

of this subpart for the applicable CO2

emission standards. 

(a) You must be in compliance with 

the emission standards in this subpart 

that apply to your affected EGU at all 

times. However, you must determine 

compliance with the emission standards 

only at the end of the applicable 

operating month, as provided in 

paragraph (a)(1) of this section. 

(1) For each affected EGU subject to 

a CO2 emissions standard based on a 12- 

operating-month rolling average, you 

must determine compliance monthly by 

calculating the average CO2 emissions 

rate for the affected EGU at the end of 

the initial and each subsequent 12- 

operating-month period. 

(2) Consistent with § 60.5520(d)(2), if 

your affected stationary combustion 

turbine is subject to an input-based CO2

emissions standard, you must determine 

the total heat input in million Btus 

(MMBtu) from natural gas (HTIPng) and 

the total heat input from all other fuels 

combined (HTIPo) using one of the 

methods under § 60.5535(d)(2). You 

must then use the following equation to 

determine the applicable emissions 

standard during the compliance period: 

Where: 

CO2 emission standard = the emission 

standard during the compliance period 

in units of lb/MMBtu. 

HTIPng = the heat input in MMBtu from 

natural gas. 

HTIPo = the heat input in MMBtu from all 

fuels other than natural gas. 

120 = allowable emission rate in lb of CO2/ 

MMBtu for heat input derived from 

natural gas. 

160 = allowable emission rate in lb of CO2/ 

MMBtu for heat input derived from all 

fuels other than natural gas. 

(b) At all times you must operate and 

maintain each affected EGU, including 

associated equipment and monitors, in 

a manner consistent with safety and 

good air pollution control practice. The 

Administrator will determine if you are 

using consistent operation and 

maintenance procedures based on 

information available to the 

Administrator that may include, but is 

not limited to, fuel use records, 

monitoring results, review of operation 

and maintenance procedures and 

records, review of reports required by 

this subpart, and inspection of the EGU. 

(c) Within 30 days after the end of the 

initial compliance period (i.e., no more 

than 30 days after the first 12-operatingmonth compliance period), you must 

make an initial compliance 

determination for your affected EGU(s) 

with respect to the applicable emissions 

standard in Table 1 or 2 of this subpart, 

in accordance with the requirements in 

this subpart. The first operating month 

included in the initial 12-operatingmonth compliance period shall be 

determined as follows: 

(1) For an affected EGU that 

commences commercial operation (as 

defined in § 72.2 of this chapter) on or 

after October 23, 2015, 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) Section 63.5555(c)(3)(i), for units 

subject to the Acid Rain Program; or 

(ii) Section 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 October 23, 2015: 

(i) If the date on which emissions 

reporting is required to begin under 

§ 75.64(a) of this chapter has passed 

prior to October 23, 2015, 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 October 23, 2015, then the first 

month of the initial compliance period 

shall be the first operating month (as 

defined in § 60.5580) after the calendar 

month in which emissions reporting is 

required to begin under 

§ 63.5555(c)(3)(ii)(A). 

(3) For a modified or reconstructed 

EGU that becomes subject to this 

subpart, the first month of the initial 

compliance period shall be the first 

operating month (as defined in 

§ 60.5580) after the calendar month in 

which emissions reporting is required to 

begin under § 63.5555(c)(3)(iii). 


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Monitoring and Compliance 

Determination Procedures 

§ 60.5535 How do I monitor and collect 

data to demonstrate compliance? 

(a) Combustion turbines qualifying 

under § 60.5520(d)(1) are not subject to 

any requirements in this section other 

than the requirement to maintain fuel 

purchase records for permitted fuel(s). If 

your combustion turbine uses nonuniform fuels as specified under 

§ 60.5520(d)(2), you must monitor heat 

input in accordance with paragraph 

(c)(1) of this section, and you must 

monitor CO2 emissions in accordance 

with either paragraph (b), (c)(2), or (c)(5) 

of this section. For all other affected 

sources, you must prepare a monitoring 

plan to quantify the hourly CO2 mass 

emission rate (tons/h), in accordance 

with the applicable provisions in 

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

electronic portion of the monitoring 

plan must be submitted using the 

ECMPS Client Tool and must be in 

place prior to reporting emissions data 

and/or the results of monitoring system 

certification tests under this subpart. 

The monitoring plan must be updated as 

necessary. Monitoring plan submittals 

must be made by the Designated 

Representative (DR), the Alternate DR, 

or a delegated agent of the DR (see 

§ 60.5555(c)). 

(b) You must determine the hourly 

CO2 mass emissions in kilograms (kg) 

from your affected EGU(s) according to 

paragraphs (b)(1) through (5) of this 

section, or, if applicable, as provided in 

paragraph (c) of this section. 

(1) For an affected coal-fired EGU or 

for an IGCC unit you must, and for all 

other affected EGUs you may, install, 

certify, operate, maintain, and calibrate 

a CO2 continuous emission monitoring 

system (CEMS) to directly measure and 

record hourly average CO2

concentrations in the affected EGU 

exhaust gases emitted to the 

atmosphere, and a flow monitoring 

system to measure hourly average stack 

gas flow rates, according to 

§ 75.10(a)(3)(i) of this chapter. As an 

alternative to direct measurement of 

CO2 concentration, provided that your 

EGU does not use carbon separation 

(e.g., carbon capture and storage), you 

may use data from a certified oxygen 

(O2) monitor to calculate hourly average 

CO2 concentrations, in accordance with 

§ 75.10(a)(3)(iii) of this chapter. If you 

measure CO2 concentration on a dry 

basis, you must also install, certify, 

operate, maintain, and calibrate a 

continuous moisture monitoring system, 

according to § 75.11(b) of this chapter. 

Alternatively, you may either use an 

appropriate fuel-specific default 

moisture value from § 75.11(b) or submit 

a petition to the Administrator under 

§ 75.66 of this chapter for a site-specific 

default moisture value. 

(2) For each continuous monitoring 

system that you use to determine the 

CO2 mass emissions, you must meet the 

applicable certification and quality 

assurance procedures in § 75.20 of this 

chapter and appendices A and B to part 

75 of this chapter. 

(3) You must use only unadjusted 

exhaust gas volumetric flow rates to 

determine the hourly CO2 mass 

emissions rate from the affected EGU; 

you must not apply the bias adjustment 

factors described in Section 7.6.5 of 

appendix A to part 75 of this chapter to 

the exhaust gas flow rate data. 

(4) You must select an appropriate 

reference method to setup (characterize) 

the flow monitor and to perform the ongoing RATAs, in accordance with part 

75 of this chapter. If you use a Type-S 

pitot tube or a pitot tube assembly for 

the flow RATAs, you must calibrate the 

pitot tube or pitot tube assembly; you 

may not use the 0.84 default Type-S 

pitot tube coefficient specified in 

Method 2. 

(5) Calculate the hourly CO2 mass 

emissions (kg) as described in 

paragraphs (b)(5)(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/h), obtained either 

from Equation F–11 in Appendix F to 

part 75 of this chapter (if CO2

concentration is measured on a wet 

basis), or by following the procedure in 

section 4.2 of appendix F to part 75 of 

this chapter (if CO2 concentration is 

measured on a dry basis). 

(ii) Next, multiply each hourly CO2

mass emission rate by the EGU or stack 

operating time in hours (as defined in 

§ 72.2 of this chapter), to convert it to 

tons of CO2.

(iii) Finally, multiply the result from 

paragraph (b)(5)(ii) of this section by 

909.1 to convert it from tons of CO2 to 

kg. Round off to the nearest kg. 

(iv) The hourly CO2 tons/h values and 

EGU (or stack) operating times used to 

calculate CO2 mass emissions are 

required to be recorded under § 75.57(e) 

of this chapter and must be reported 

electronically under § 75.64(a)(6) of this 

chapter. You must use these data to 

calculate the hourly CO2 mass 

emissions. 

(c) If your affected EGU exclusively 

combusts liquid fuel and/or gaseous 

fuel, as an alternative to complying with 

paragraph (b) of this section, you may 

determine the hourly CO2 mass 

emissions according to paragraphs (c)(1) 

through (4) of this section. If you use 

non-uniform fuels as specified in 

§ 60.5520(d)(2), you may determine CO2

mass emissions during the compliance 

period according to paragraph (c)(5) of 

this section. 

(1) If you are subject to an outputbased standard and you do not install 

CEMS in accordance with paragraph (b) 

of this section, you must implement the 

applicable procedures in appendix D to 

part 75 of this chapter to determine 

hourly EGU heat input rates (MMBtu/h), 

based on hourly measurements of fuel 

flow rate and periodic determinations of 

the gross calorific value (GCV) of each 

fuel combusted. 

(2) For each measured hourly heat 

input rate, use Equation G–4 in 

appendix G to part 75 of this chapter to 

calculate the hourly CO2 mass emission 

rate (tons/h). You may determine sitespecific carbon-based F-factors (Fc) 

using Equation F–7b in section 3.3.6 of 

appendix F to part 75 of this chapter, 

and you may use these Fc values in the 

emissions calculations instead of using 

the default Fc values in the Equation G– 

4 nomenclature. 

(3) For each ‘‘valid operating hour’’ 

(as defined in § 60.5540(a)(1), multiply 

the hourly tons/h CO2 mass emission 

rate from paragraph (c)(2) of this section 

by the EGU or stack operating time in 

hours (as defined in § 72.2 of this 

chapter), to convert it to tons of CO2. 

Then, multiply the result by 909.1 to 

convert from tons of CO2 to kg. Round 

off to the nearest two significant figures. 

(4) The hourly CO2 tons/h values and 

EGU (or stack) 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) of this 

chapter. You must use these data to 

calculate the hourly CO2 mass 

emissions. 

(5) If you operate a combustion 

turbine firing non-uniform fuels, as an 

alternative to following paragraphs 

(c)(1) through (4) of this section, you 

may determine CO2 emissions during 

the compliance period using one of the 

following methods: 

(i) Units firing fuel gas may determine 

the heat input during the compliance 

period following the procedure under 

§ 60.107a(d) and convert this heat input 

to CO2 emissions using Equation G–4 in 

appendix G to part 75 of this chapter. 

(ii) You may use the procedure for 

determining CO2 emissions during the 

compliance period based on the use of 

the Tier 3 methodology under 

§ 98.33(a)(3) of this chapter. 

(d) Consistent with § 60.5520, you 

must determine the basis of the 

emissions standard that applies to your 

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affected source in accordance with 

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

section, as applicable: 

(1) If you operate a source subject to 

an emissions standard established on an 

output basis (e.g., lb of CO2 per gross or 

net MWh of energy output), you must 

install, calibrate, maintain, and operate 

a sufficient number of watt meters to 

continuously measure and record the 

hourly gross electric output or net 

electric output, as applicable, from the 

affected EGU(s). These measurements 

must be performed using 0.2 class 

electricity metering instrumentation and 

calibration procedures as specified 

under ANSI Standards No. C12.20 

(incorporated by reference, see § 60.17). 

For a combined heat and power (CHP) 

EGU, as defined in § 60.5580, you must 

also install, calibrate, maintain, and 

operate meters to continuously (i.e., 

hour-by-hour) determine and record the 

total useful thermal output. For process 

steam applications, you will need to 

install, calibrate, maintain, and operate 

meters to continuously determine and 

record the hourly steam flow rate, 

temperature, and pressure. Your plan 

shall ensure that you install, calibrate, 

maintain, and operate meters to record 

each component of the determination, 

hour-by-hour. 

(2) If you operate a source subject to 

an emissions standard established on a 

heat-input basis (e.g., lb CO2/MMBtu) 

and your affected source uses nonuniform heating value fuels as 

delineated under § 60.5520(d), you must 

determine the total heat input for each 

fuel fired during the compliance period 

in accordance with one of the following 

procedures: 

(i) Appendix D to part 75 of this 

chapter; 

(ii) The procedures for monitoring 

heat input under § 60.107a(d); 

(iii) If you monitor CO2 emissions in 

accordance with the Tier 3 methodology 

under § 98.33(a)(3) of this chapter, you 

may convert your CO2 emissions to heat 

input using the appropriate emission 

factor in Table C–1 of part 98 of this 

chapter. If your fuel is not listed in 

Table C–1, you must determine a fuelspecific carbon-based F-factor (Fc) in 

accordance with section 12.3.2 of EPA 

Method 19 of appendix A–7 to this part, 

and you must convert your CO2

emissions to heat input using Equation 

G–4 in appendix G to part 75 of this 

chapter. 

(e) Consistent with § 60.5520, if two 

or more affected EGUs serve a common 

electric generator, you must apportion 

the combined hourly gross or net energy 

output to the individual affected EGUs 

according to the fraction of the total 

steam load contributed by each EGU. 

Alternatively, if the EGUs are identical, 

you may apportion the combined hourly 

gross or net electrical load to the 

individual EGUs according to the 

fraction of the total heat input 

contributed by each EGU. 

(f) In accordance with §§ 60.13(g) and 

60.5520, if two or more affected EGUs 

that implement the continuous emission 

monitoring provisions in paragraph (b) 

of this section share a common exhaust 

gas stack and are subject to the same 

emissions standard in Table 1 or 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 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 and determine excess emissions? 

(a) In accordance with § 60.5520, if 

you are subject to an output-based 

emission standard or you burn nonuniform fuels as specified in 

§ 60.5520(d)(2), you must demonstrate 

compliance with the applicable CO2

emission standard in Table 1 or 2 of this 

subpart as required in this section. For 

the initial and each subsequent 12- 

operating-month rolling average 

compliance period, you must follow the 

procedures in paragraphs (a)(1) through 

(7) of this section to calculate the CO2

mass emissions rate for your affected 

EGU(s) in units of the applicable 

emissions standard (i.e., either kg/MWh 

or lb/MMBtu). You must use the hourly 

CO2 mass emissions calculated under 

§ 60.5535(b) or (c), as applicable, and 

either the generating load data from 

§ 60.5535(d)(1) for output-based 

calculations or the heat input data from 

§ 60.5535(d)(2) for heat-input-based 

calculations. Combustion turbines firing 

non-uniform fuels that contain CO2

prior to combustion (e.g., blast furnace 

gas or landfill gas) may sample the fuel 

stream to determine the quantity of CO2

present in the fuel prior to combustion 

and exclude this portion of the CO2

mass emissions from compliance 

determinations. 

(1) Each compliance period shall 

include only ‘‘valid operating hours’’ in 

the compliance period, i.e., operating 

hours for which: 

(i) ‘‘Valid data’’ (as defined in 

§ 60.5580) are obtained for all of the 

parameters used to determine the hourly 

CO2 mass emissions (kg) and, if a heat 

input-based standard applies, all the 

parameters used to determine total heat 

input for the hour are also obtained; and 

(ii) The corresponding hourly gross or 

net energy output value is also valid 

data (Note: For hours with no useful 

output, zero is considered to be a valid 

value). 

(2) You must exclude operating hours 

in which: 

(i) The substitute data provisions of 

part 75 of this chapter are applied for 

any of the parameters used to determine 

the hourly CO2 mass emissions or, if a 

heat input-based standard applies, for 

any parameters used to determine the 

hourly heat input; or 

(ii) An exceedance of the full-scale 

range of a continuous emission 

monitoring system occurs for any of the 

parameters used to determine the hourly 

CO2 mass emissions or, if applicable, to 

determine the hourly heat input; or 

(iii) The total gross or net energy 

output (Pgross/net) or, if applicable, the 

total heat input is unavailable. 

(3) For each compliance period, at 

least 95 percent of the operating hours 

in the compliance period must be valid 

operating hours, as defined in paragraph 

(a)(1) of this section. 

(4) You must calculate the total CO2

mass emissions by summing the valid 

hourly CO2 mass emissions values from 

§ 60.5535 for all of the valid operating 

hours in the compliance period. 

(5) Sources subject to output based 

standards. For each valid operating 

hour of the compliance period that was 

used in paragraph (a)(4) of this section 

to calculate the total CO2 mass 

emissions, you must determine Pgross/net

(the corresponding hourly gross or net 

energy output in MWh) according to the 

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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. 

Where: 

Pgross/net = In accordance with § 60.5520, gross 

or net energy output of your affected 

EGU for each valid operating hour (as 

defined in § 60.5540(a)(1)) in MWh. 

(Pe)ST = Electric energy output plus 

mechanical energy output (if any) of 

steam turbines in MWh. 

(Pe)CT = Electric energy output plus 

mechanical energy output (if any) of 

stationary combustion turbine(s) in 

MWh. 

(Pe)IE = Electric energy output plus 

mechanical energy output (if any) of 

your affected EGU’s integrated 

equipment that provides electricity or 

mechanical energy to the affected EGU or 

auxiliary equipment in MWh. 

(Pe)FW = Electric energy used to power boiler 

feedwater pumps at steam generating 

units in MWh. Not applicable to 

stationary combustion turbines, IGCC 

EGUs, or EGUs complying with a net 

energy output based standard. 

(Pe)A = Electric energy used for any auxiliary 

loads in MWh. Not applicable for 

determining Pgross. 

(Pt)PS = Useful thermal output of steam 

(measured relative to SATP conditions, 

as applicable) that is used for 

applications that do not generate 

additional electricity, produce 

mechanical energy output, or enhance 

the performance of the affected EGU. 

This is calculated using the equation 

specified in paragraph (a)(5)(ii) of this 

section in MWh. 

(Pt)HR = Non steam useful thermal output 

(measured relative to SATP conditions, 

as applicable) from heat recovery that is 

used for applications other than steam 

generation or performance enhancement 

of the affected EGU in MWh. 

(Pt)IE = Useful thermal output (relative to 

SATP conditions, as applicable) from 

any integrated equipment is used for 

applications that do not generate 

additional steam, electricity, produce 

mechanical energy output, or enhance 

the performance of the affected EGU in 

MWh. 

TDF = Electric Transmission and Distribution 

Factor of 0.95 for a combined heat and 

power affected EGU where at least on an 

annual basis 20.0 percent of the total 

gross or net energy output consists of 

electric or direct mechanical output and 

20.0 percent of the total gross or net 

energy output consists of useful thermal 

output on a 12-operating-month rolling 

average basis, or 1.0 for all other affected 

EGUs. 

(ii) If applicable to your affected EGU 

(for example, for combined heat and 

power), you must calculate (Pt)PS using 

the following equation: 

Where: 

Qm = Measured steam flow in kilograms (kg) 

(or pounds (lb)) for the operating hour. 

H = Enthalpy of the steam at measured 

temperature and pressure (relative to 

SATP conditions or the energy in the 

condensate return line, as applicable) in 

Joules per kilogram (J/kg) (or Btu/lb). 

CF = Conversion factor of 3.6 × 109 J/MWh 

or 3.413 × 106 Btu/MWh. 

(6) Calculation of annual basis for 

standard. Sources complying with 

energy output-based standards must 

calculate the basis (i.e., denominator) of 

their actual annual emission rate in 

accordance with paragraph (a)(6)(i) of 

this section. Sources complying with 

heat input based standards must 

calculate the basis of their actual annual 

emission rate in accordance with 

paragraph (a)(6)(ii) of this section. 

(i) In accordance with § 60.5520 if you 

are subject to an output-based standard, 

you must calculate the total gross or net 

energy output for the affected EGU’s 

compliance period by summing the 

hourly gross or net energy output values 

for the affected EGU that you 

determined under paragraph (a)(5) of 

this section for all of the valid operating 

hours in the applicable compliance 

period. 

(ii) If you are subject to a heat inputbased standard, you must calculate the 

total heat input for each fuel fired 

during the compliance period. The 

calculation of total heat input for each 

individual fuel must include all valid 

operating hours and must also be 

consistent with any fuel-specific 

procedures specified within your 

selected monitoring option under 

§ 60.5535(d)(2). 

(7) If you are subject to an outputbased standard, you must calculate the 

CO2 mass emissions rate for the affected 

EGU(s) (kg/MWh) by dividing the total 

CO2 mass emissions value calculated 

according to the procedures in 

paragraph (a)(4) of this section by the 

total gross or net energy output value 

calculated according to the procedures 

in paragraph (a)(6)(i) of this section. 

Round off the result to two significant 

figures if the calculated value is less 

than 1,000; round the result to three 

significant figures if the calculated value 

is greater than 1,000. If you are subject 

to a heat input-based standard, you 

must calculate the CO2 mass emissions 

rate for the affected EGU(s) (lb/MMBtu) 

by dividing the total CO2 mass 

emissions value calculated according to 

the procedures in paragraph (a)(4) of 

this section by the total heat input 

calculated according to the procedures 

in paragraph (a)(6)(ii) of this section. 

Round off the result to two significant 

figures. 

(b) In accordance with § 60.5520, to 

demonstrate compliance with the 

applicable CO2 emission standard, for 

the initial and each subsequent 12- 

operating-month compliance period, the 

CO2 mass emissions rate for your 

affected EGU must be determined 

according to the procedures specified in 

paragraph (a)(1) through (7) of this 

section and must be less than or equal 

to the applicable CO2 emissions 

standard in Table 1 or 2 of this part, or 

the emissions standard calculated in 

accordance with § 60.5525(a)(2). 

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 (3) and 60.19, as applicable to your 

affected EGU(s) (see Table 3 of this 

subpart). 


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(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 ongoing compliance determinations on a 

12-operating-month rolling average 

basis, you must submit electronic 

quarterly reports as follows. After you 

have accumulated the first 12-operating 

months for the affected EGU, you must 

submit a report for the calendar quarter 

that includes the twelfth operating 

month no later than 30 days after the 

end of that quarter. Thereafter, you must 

submit a report for each subsequent 

calendar quarter, no later than 30 days 

after the end of the quarter. 

(2) In each quarterly report you must 

include the following information, as 

applicable: 

(i) Each rolling average CO2 mass 

emissions rate for which the last 

(twelfth) operating month in a 12- 

operating-month compliance period 

falls within the calendar quarter. You 

must calculate each average CO2 mass 

emissions rate for the compliance 

period according to the procedures in 

§ 60.5540. You must report the dates 

(month and year) of the first and twelfth 

operating months in each compliance 

period for which you performed a CO2

mass emissions rate calculation. If there 

are no compliance periods that end in 

the quarter, you must include a 

statement to that effect; 

(ii) If one or more compliance periods 

end in the quarter, you must identify 

each operating month in the calendar 

quarter where your EGU violated the 

applicable CO2 emission standard; 

(iii) If one or more compliance 

periods end in the quarter and there are 

no violations for the affected EGU, you 

must include a statement indicating this 

in the report; 

(iv) The percentage of valid operating 

hours in each 12-operating-month 

compliance period described in 

paragraph (a)(1)(i) of this section (i.e., 

the total number of valid operating 

hours (as defined in § 60.5540(a)(1)) in 

that period divided by the total number 

of operating hours in that period, 

multiplied by 100 percent); 

(v) Consistent with § 60.5520, the CO2

emissions standard (as identified in 

Table 1 or 2 of this part) 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, as applicable to the 

units of your emission standard, over 

the four quarters of the calendar year; 

and 

(ii) The potential electric output of the 

EGU. 

(b) You must submit all electronic 

reports required under paragraph (a) of 

this section using the Emissions 

Collection and Monitoring Plan System 

(ECMPS) Client Tool provided by the 

Clean Air Markets Division in the Office 

of Atmospheric Programs of EPA. 

(c)(1) For affected EGUs under this 

subpart that are also subject to the Acid 

Rain Program, you must meet all 

applicable reporting requirements and 

submit reports as required under 

subpart G of part 75 of this chapter. 

(2) For affected EGUs under this 

subpart that are not in the Acid Rain 

Program, you must also meet the 

reporting requirements and submit 

reports as required under subpart G of 

part 75 of this chapter, to the extent that 

those requirements and reports provide 

applicable data for the compliance 

demonstrations required under this 

subpart. 

(3)(i) For all newly-constructed 

affected EGUs under this subpart that 

are also subject to the Acid Rain 

Program, you must begin submitting the 

quarterly electronic emissions reports 

described in paragraph (c)(1) of this 

section in accordance with § 75.64(a) of 

this chapter, 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) of this 

chapter, if that date occurs on or after 

October 23, 2015; or 

(B) October 23, 2015, if the date on 

which reporting would ordinarily be 

required to begin under § 75.64(a) of this 

chapter has passed prior to October 23, 

2015. 

(iii) For reconstructed or modified 

units, reporting of emissions data shall 

begin at the date on which the EGU 

becomes an affected unit under this 

subpart, provided that the ECMPS 

Client Tool is able to receive and 

process net energy output data on that 

date. Otherwise, emissions data 

reporting shall be on a gross energy 

output basis until the date that the 

Client Tool is first able to receive and 

process net energy output data. 

(4) If any required monitoring system 

has not been provisionally certified by 

the applicable date on which emissions 

data reporting is required to begin under 

paragraph (c)(3) of this section, the 

maximum (or in some cases, minimum) 

potential value for the parameter 

measured by the monitoring system 

shall be reported until the required 

certification testing is successfully 

completed, in accordance with § 75.4(j) 

of this chapter, § 75.37(b) of this 

chapter, or section 2.4 of appendix D to 

part 75 of this chapter (as applicable). 

Operating hours in which CO2 mass 

emission rates are calculated using 

maximum potential values are not 

‘‘valid operating hours’’ (as defined in 

§ 60.5540(a)(1)), and shall not be used in 

the compliance determinations under 

§ 60.5540. 

(d) For affected EGUs subject to the 

Acid Rain Program, the reports required 

under paragraphs (a) and (c)(1) of this 

section shall be submitted by: 

(1) The person appointed as the 

Designated Representative (DR) under 

§ 72.20 of this chapter; or 

(2) The person appointed as the 

Alternate Designated Representative 

(ADR) under § 72.22 of this chapter; or 

(3) A person (or persons) authorized 

by the DR or ADR under § 72.26 of this 

chapter to make the required 

submissions. 

(e) For affected EGUs that are not 

subject to the Acid Rain Program, the 

owner or operator shall appoint a DR 

and (optionally) an ADR to submit the 

reports required under paragraphs (a) 

and (c)(2) of this section. The DR and 

ADR must register with the Clean Air 

Markets Division (CAMD) Business 

System. The DR may delegate the 

authority to make the required 

submissions to one or more persons. 

(f) If your affected EGU captures CO2

to meet the applicable emission limit, 

you must report in accordance with the 

requirements of 40 CFR part 98, subpart 

PP and either: 

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(1) Report in accordance with the 

requirements of 40 CFR part 98, subpart 

RR, if injection occurs on-site, or 

(2) Transfer the captured CO2 to an 

EGU or facility that reports in 

accordance with the requirements of 40 

CFR part 98, subpart RR, if injection 

occurs off-site. 

(3) Transfer the captured CO2 to a 

facility that has received an innovative 

technology waiver from EPA pursuant 

to paragraph (g) of this section. 

(g) Any person may request the 

Administrator to issue a waiver of the 

requirement that captured CO2 from an 

affected EGU be transferred to a facility 

reporting under 40 CFR part 98, subpart 

RR. To receive a waiver, the applicant 

must demonstrate to the Administrator 

that its technology will store captured 

CO2 as effectively as geologic 

sequestration, and that the proposed 

technology will not cause or contribute 

to an unreasonable risk to public health, 

welfare, or safety. In making this 

determination, the Administrator shall 

consider (among other factors) operating 

history of the technology, whether the 

technology will increase emissions or 

other releases of any pollutant other 

than CO2, and permanence of the CO2

storage. The Administrator may test the 

system itself, or require the applicant to 

perform any tests considered by the 

Administrator to be necessary to show 

the technology’s effectiveness, safety, 

and ability to store captured CO2

without release. The Administrator may 

grant conditional approval of a 

technology, with the approval 

conditioned on monitoring and 

reporting of operations. The 

Administrator may also withdraw 

approval of the waiver on evidence of 

releases of CO2 or other pollutants. The 

Administrator will provide notice to the 

public of any application under this 

provision and provide public notice of 

any proposed action on a petition before 

the Administrator takes final action. 

§ 60.5560 What records must I maintain? 

(a) You must maintain records of the 

information you used to demonstrate 

compliance with this subpart as 

specified in § 60.7(b) and (f). 

(b)(1) For affected EGUs subject to the 

Acid Rain Program, you must follow the 

applicable recordkeeping requirements 

and maintain records as required under 

subpart F of part 75 of this chapter. 

(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 (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) of 

this chapter for continuous moisture 

monitoring systems; 

(v) The records under § 75.57(e)(1) of 

this chapter, except for paragraph 

(e)(1)(x), for CO2 concentration 

monitoring systems or O2 monitors used 

to calculate CO2 concentration; 

(vi) The records under § 75.58(c)(1) of 

this chapter, specifically paragraphs 

(c)(1)(i), (ii), and (viii) through (xiv), for 

oil flow meters; 

(vii) The records under § 75.58(c)(4) of 

this chapter, specifically paragraphs 

(c)(4)(i), (ii), (iv), (v), and (vii) through 

(xi), for gas flow meters; 

(viii) The quality-assurance records 

under § 75.59(a) of this chapter, 

specifically paragraphs (a)(1) through 

(12) and (15), for CEMS; 

(ix) The quality-assurance records 

under § 75.59(a) of this chapter, 

specifically paragraphs (b)(1) through 

(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); and 

(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. 

(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 carbonbased F-factors you used in the 

emissions calculations (if applicable). 

§ 60.5565 In what form and how long must 

I keep my records? 

(a) Your records must be in a form 

suitable and readily available for 

expeditious review. 

(b) You must maintain each record for 

3 years after the date of conclusion of 

each compliance period. 

(c) You must maintain each record on 

site for at least 2 years after the date of 

each occurrence, measurement, 

maintenance, corrective action, report, 

or record, according to § 60.7. Records 

that are accessible from a central 

location by a computer or other means 

that instantly provide access at the site 

meet this requirement. You may 

maintain the records off site for the 

remaining year(s) as required by this 

subpart. 

Other Requirements and Information 

§ 60.5570 What parts of the general 

provisions apply to my affected EGU? 

Notwithstanding any other provision 

of this chapter, certain parts of the 

general provisions in §§ 60.1 through 

60.19, listed in Table 3 to this subpart, 

do not apply to your affected EGU. 

§ 60.5575 Who implements and enforces 

this subpart? 

(a) This subpart can be implemented 

and enforced by the EPA, or a delegated 

authority such as your state, local, or 

tribal agency. If the Administrator has 

delegated authority to your state, local, 

or tribal agency, then that agency (as 

well as the EPA) has the authority to 

implement and enforce this subpart. 

You should contact your EPA Regional 

Office to find out if this subpart is 

delegated to your state, local, or tribal 

agency. 

(b) In delegating implementation and 

enforcement authority of this subpart to 

a state, local, or tribal agency, the 

Administrator retains the authorities 

listed in paragraphs (b)(1) through (5) of 

this section and does not transfer them 

to the state, local, or tribal agency. In 

addition, the EPA retains oversight of 

this subpart and can take enforcement 

actions, as appropriate. 

(1) Approval of alternatives to the 

emission standards. 

(2) Approval of major alternatives to 

test methods. 

(3) Approval of major alternatives to 

monitoring. 

(4) Approval of major alternatives to 

recordkeeping and reporting. 

(5) Performance test and data 

reduction waivers under § 60.8(b). 

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64656 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

§ 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, base load rating includes the 

heat input from duct burners. 

Coal means all solid fuels classified as 

anthracite, bituminous, subbituminous, 

or lignite by ASTM International in 

ASTM D388–99 (Reapproved 2004) e1

(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. 

Combined cycle unit means an 

electric generating unit that uses a 

stationary combustion turbine from 

which the heat from the turbine exhaust 

gases is recovered by a heat recovery 

steam generating unit (HRSG) to 

generate additional electricity. 

Combined heat and power unit or 

CHP unit, (also known as 

‘‘cogeneration’’) means an electric 

generating unit that that use a steam 

generating unit or stationary combustion 

turbine to simultaneously produce both 

electric (or mechanical) and useful 

thermal output from the same primary 

energy source. 

Design efficiency means the rated 

overall net efficiency (e.g., electric plus 

useful thermal output) on a lower 

heating value basis at the base load 

rating, at ISO conditions, and at the 

maximum useful thermal output (e.g., 

CHP unit with condensing steam 

turbines would determine the design 

efficiency at the maximum level of 

extraction and/or bypass). Design 

efficiency shall be determined using one 

of the following methods: ASME PTC 22 

Gas Turbines (incorporated by 

reference, see § 60.17), ASME PTC 46 

Overall Plant Performance (incorporated 

by reference, see § 60.17) or ISO 2314 

Gas turbines—acceptance tests 

(incorporated by reference, see § 60.17). 

Distillate oil means fuel oils that 

comply with the specifications for fuel 

oil numbers 1 and 2, as defined by 

ASTM International in ASTM D396–98 

(incorporated by reference, see § 60.17); 

diesel fuel oil numbers 1 and 2, as 

defined by ASTM International in 

ASTM D975–08a (incorporated by 

reference, see § 60.17); kerosene, as 

defined by ASTM International in 

ASTM D3699 (incorporated by 

reference, see § 60.17); biodiesel as 

defined by ASTM International in 

ASTM D6751 (incorporated by 

reference, see § 60.17); or biodiesel 

blends as defined by ASTM 

International in ASTM D7467 

(incorporated by reference, see § 60.17). 

Electric Generating units or EGU 

means any steam generating unit, IGCC 

unit, or stationary combustion turbine 

that is subject to this rule (i.e., meets the 

applicability criteria) 

Fossil fuel means natural gas, 

petroleum, coal, and any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Gaseous fuel means any fuel that is 

present as a gas at ISO conditions and 

includes, but is not limited to, natural 

gas, refinery fuel gas, process gas, cokeoven 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 steam generating units, the 

gross electric or mechanical output from 

the affected EGU(s) (including, but not 

limited to, output from steam turbine(s), 

combustion turbine(s), and gas 

expander(s)) minus any electricity used 

to power the feedwater pumps plus 100 

percent of the useful thermal output; 

(3) For combined heat and power 

facilities where at least 20.0 percent of 

the total gross energy output consists of 

electric or direct mechanical output and 

20.0 percent of the total gross energy 

output consists of useful thermal output 

on a 12-operating-month rolling average 

basis, the gross electric or mechanical 

output from the affected EGU 

(including, but not limited to, output 

from steam turbine(s), combustion 

turbine(s), and gas expander(s)) minus 

any electricity used to power the 

feedwater pumps (the electric auxiliary 

load of boiler feedwater pumps is not 

applicable to IGCC facilities), that 

difference divided by 0.95, plus 100 

percent of the useful thermal output. 

Heat recovery steam generating unit 

(HRSG) means an EGU in which hot 

exhaust gases from the combustion 

turbine engine are routed in order to 

extract heat from the gases and generate 

useful output. Heat recovery steam 

generating units can be used with or 

without duct burners. 

Integrated gasification combined 

cycle facility or IGCC means a combined 

cycle facility that is designed to burn 

fuels containing 50 percent (by heat 

input) or more solid-derived fuel not 

meeting the definition of natural gas, 

plus any integrated equipment that 

provides electricity or useful thermal 

output to the affected EGU or auxiliary 

equipment. The Administrator may 

waive the 50 percent solid-derived fuel 

requirement during periods of the 

gasification system construction, startup 

and commissioning, shutdown, or 

repair. No solid fuel is directly burned 

in the EGU during operation. 

ISO conditions means 288 Kelvin 

(15°C), 60 percent relative humidity and 

101.3 kilopascals pressure. 

Liquid fuel means any fuel that is 

present as a liquid at ISO conditions 

and includes, but is not limited to, 

distillate oil and residual oil. 

Mechanical output means the useful 

mechanical energy that is not used to 

operate the affected EGU(s), generate 

electricity and/or thermal energy, or to 

enhance the performance of the affected 

EGU. Mechanical energy measured in 

horsepower hour should be converted 

into MWh by multiplying it by 745.7 

then dividing by 1,000,000. 

Natural gas means a fluid mixture of 

hydrocarbons (e.g., methane, ethane, or 

propane), composed of at least 70 

percent methane by volume or that has 

a gross calorific value between 35 and 

41 megajoules (MJ) per dry standard 

cubic meter (950 and 1,100 Btu per dry 

standard cubic foot), that maintains a 

gaseous state under ISO conditions. 

Finally, natural gas does not include the 

following gaseous fuels: Landfill gas, 

digester gas, refinery gas, sour gas, blast 

furnace gas, coal-derived gas, producer 

gas, coke oven gas, or any gaseous fuel 

produced in a process which might 

result in highly variable CO2 content or 

heating value. 

Net-electric sales means: 

(1) The gross electric sales to the 

utility power distribution system minus 

purchased power; or 

(2) For combined heat and power 

facilities where at least 20.0 percent of 

the total gross energy output consists of 

electric or direct mechanical output and 

at least 20.0 percent of the total gross 

energy output consists of useful thermal 

output on an annual basis, the gross 

electric sales to the utility power 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64657 

distribution system minus purchased 

power of the thermal host facility or 

facilities. 

(3) Electricity supplied to other 

facilities that produce electricity to 

offset auxiliary loads are included when 

calculating net-electric sales. 

(4) Electric sales that that result from 

a system emergency are not included 

when calculating net-electric sales. 

Net-electric output means the amount 

of gross generation the generator(s) 

produces (including, but not limited to, 

output from steam turbine(s), 

combustion turbine(s), and gas 

expander(s)), as measured at the 

generator terminals, less the 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: 

(1) The net electric or mechanical 

output from the affected EGU plus 100 

percent of the useful thermal output; or 

(2) 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. 

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. 

Potential electric output means 33 

percent or the base load rating design 

efficiency at the maximum electric 

production rate (e.g., CHP units with 

condensing steam turbines will operate 

at maximum electric production), 

whichever is greater, multiplied by the 

base load rating (expressed in MMBtu/ 

h) of the EGU, multiplied by 106 Btu/ 

MMBtu, divided by 3,413 Btu/KWh, 

divided by 1,000 kWh/MWh, and 

multiplied by 8,760 h/yr (e.g., a 35 

percent efficient affected EGU with a 

100 MW (341 MMBtu/h) fossil fuel heat 

input capacity would have a 306,000 

MWh 12-month potential electric output 

capacity). 

Standard ambient temperature and 

pressure (SATP) conditions means 

298.15 Kelvin (25 °C, 77 °F) and 100.0 

kilopascals (14.504 psi, 0.987 atm) 

pressure. The enthalpy of water at SATP 

conditions is 50 Btu/lb. 

Solid fuel means any fuel that has a 

definite shape and volume, has no 

tendency to flow or disperse under 

moderate stress, and is not liquid or 

gaseous at ISO conditions. This 

includes, but is not limited to, coal, 

biomass, and pulverized solid fuels. 

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. A stationary 

combustion turbine that burns any solid 

fuel directly is considered a steam 

generating unit. 

Steam generating unit means any 

furnace, boiler, or other device used for 

combusting fuel and producing steam 

(nuclear steam generators are not 

included) plus any integrated 

equipment that provides electricity or 

useful thermal output to the affected 

EGU(s) or auxiliary equipment. 

System emergency means any 

abnormal system condition that the 

Regional Transmission Organizations 

(RTO), Independent System Operators 

(ISO) or control area Administrator 

determines requires immediate 

automatic or manual action to prevent 

or limit loss of transmission facilities or 

generators that could adversely affect 

the reliability of the power system and 

therefore call for maximum generation 

resources to operate in the affected area, 

or for the specific affected EGU to 

operate to avert loss of load. 

Useful thermal output means the 

thermal energy made available for use in 

any heating application (e.g., steam 

delivered to an industrial process for a 

heating application, including thermal 

cooling applications) that is not used for 

electric generation, mechanical output 

at the affected EGU, to directly enhance 

the performance of the affected EGU 

(e.g., economizer output is not useful 

thermal output, but thermal energy used 

to reduce fuel moisture is considered 

useful thermal output), or to supply 

energy to a pollution control device at 

the affected EGU. Useful thermal output 

for affected EGU(s) with no condensate 

return (or other thermal energy input to 

the affected EGU(s)) or where measuring 

the energy in the condensate (or other 

thermal energy input to the affected 

EGU(s)) would not meaningfully impact 

the emission rate calculation is 

measured against the energy in the 

thermal output at SATP conditions. 

Affected EGU(s) with meaningful energy 

in the condensate return (or other 

thermal energy input to the affected 

EGU) must measure 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 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 qualityassured data are reported under this 

subpart (except for qualifying 

commercial billing meters under section 

2.1.4.2 of appendix D to part 75), and for 

on-going quality assurance, the 

provisions in section 2.1.6 of appendix 

D to part 75 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 

2 of this subpart. 

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64658 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

TABLE 1 OF SUBPART TTTT OF PART 60—CO2 EMISSION STANDARDS FOR AFFECTED STEAM GENERATING UNITS AND

INTEGRATED GASIFICATION COMBINED CYCLE FACILITIES THAT COMMENCED CONSTRUCTION AFTER JANUARY 8, 

2014 AND RECONSTRUCTION OR MODIFICATION AFTER JUNE 18, 2014 

[Note: Numerical values of 1,000 or greater have a minimum of 3 significant figures and numerical values of less than 1,000 have a minimum of 

2 significant figures] 

Affected EGU CO2 Emission standard 

Newly constructed steam generating unit or integrated gasification 

combined cycle (IGCC).

640 kg CO2/MWh of gross energy output (1,400 lb CO2/MWh). 

Reconstructed steam generating unit or IGCC that has base load rating 

of 2,100 GJ/h (2,000 MMBtu/h) or less.

910 kg of CO2 per MWh of gross energy output (2,000 lb CO2/MWh). 

Reconstructed steam generating unit or IGCC that has a base load rating greater than 2,100 GJ/h (2,000 MMBtu/h).820 kg of CO2 per MWh of gross energy output (1,800 lb CO2/MWh). 

Modified steam generating unit or IGCC ................................................. A unit-specific emission limit determined by the unit’s best historical annual CO2 emission rate (from 2002 to the date of the modification); 

the emission limit will be no lower than: 

1. 1,800 lb CO2/MWh-gross for units with a base load rating greater than 2,000 MMBtu/h; or 

2. 2,000 lb CO2/MWh-gross for units with a base load rating of 

2,000 MMBtu/h or less. 

TABLE 2 OF SUBPART TTTT OF PART 60—CO2 EMISSION STANDARDS FOR AFFECTED STATIONARY COMBUSTION TURBINES THAT COMMENCED CONSTRUCTION AFTER JANUARY 8, 2014 AND RECONSTRUCTION AFTER JUNE 18, 2014 

(NET ENERGY OUTPUT-BASED STANDARDS APPLICABLE AS APPROVED BY THE ADMINISTRATOR) 

[Note: Numerical values of 1,000 or greater have a minimum of 3 significant figures and numerical values of less than 1,000 have a minimum of 

2 significant figures] 

Affected EGU CO2 Emission standard 

Newly constructed or reconstructed stationary combustion turbine that 

supplies more than its design efficiency or 50 percent, whichever is 

less, times its potential electric output as net-electric sales on both a 

12-operating month and a 3-year rolling average basis and combusts 

more than 90% natural gas on a heat input basis on a 12-operatingmonth rolling average basis.

450 kg of CO2 per MWh of gross energy output (1,000 lb CO2/MWh); 

or 

470 kilograms (kg) of CO2 per megawatt-hour (MWh) of net energy 

output (1,030 lb/MWh). 

Newly constructed or reconstructed stationary combustion turbine that 

supplies its design efficiency or 50 percent, whichever is less, times 

its potential electric output or less as net-electric sales on either a 

12-operating month or a 3-year rolling average basis and combusts 

more than 90% natural gas on a heat input basis on a 12-operatingmonth rolling average basis.

50 kg CO2 per gigajoule (GJ) of heat input (120 lb CO2/MMBtu). 

Newly constructed and reconstructed stationary combustion turbine that 

combusts 90% or less natural gas on a heat input basis on a 12-operating-month rolling average basis.

50 kg CO2/GJ of heat input (120 lb/MMBtu) to 69 kg CO2/GJ of heat 

input (160 lb/MMBtu) as determined by the procedures in § 60.5525. 

TABLE 3 TO SUBPART TTTT OF PART 60—APPLICABILITY OF SUBPART A OF PART 60 (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 (3) and to keep records of malfunctions in § 60.7(b), if applicable. 

§ 60.8 ............ Performance tests ...................................................... No.

§ 60.9 ............ Availability of Information ........................................... Yes.

§ 60.10 .......... State authority ............................................................ Yes.

§ 60.11 .......... Compliance with standards and maintenance requirements.No.

§ 60.12 .......... Circumvention ............................................................ Yes.

§ 60.13 .......... Monitoring requirements ............................................ No ........................ All monitoring is done according to part 75. 

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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64659 

TABLE 3 TO SUBPART TTTT OF PART 60—APPLICABILITY OF SUBPART A OF PART 60 (GENERAL PROVISIONS) TO

SUBPART TTTT—Continued 

General 

provisions 

citation 

Subject of citation Applies to subpart 

TTTT Explanation 

§ 60.14 .......... Modification ................................................................ Yes (steam generating units and 

IGCC facilities).

No (stationary 

combustion turbines.

§ 60.15 .......... Reconstruction ........................................................... Yes.

§ 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. 

PART 70—STATE OPERATING PERMIT 

PROGRAMS 

■ 4. The authority citation for part 70 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

■ 5. In § 70.2, the definition of 

‘‘Regulated pollutant (for presumptive 

fee calculation)’’ is amended by: 

■ a. Revising the introductory text; 

■ b. Removing ‘‘or’’ from the end of 

paragraph (2); 

■ c. Removing the period at the end of 

paragraph (3) and adding ‘‘; or’’ in its 

place; and 

■ d. Adding paragraph (4). 

The revision and additions read as 

follows: 

§ 70.2 Definitions. 

* * * * * 

Regulated pollutant (for presumptive 

fee calculation), which is used only for 

purposes of § 70.9(b)(2), means any 

regulated air pollutant except the 

following: 

* * * * * 

(4) Greenhouse gases. 

* * * * * 

■ 6. Section 70.9 is amended by revising 

paragraph (b)(2)(i), and adding 

paragraph (b)(2)(v) to read as follows: 

§ 70.9 Fee determination and certification. 

* * * * * 

(b) * * * 

(2)(i) The Administrator will presume 

that the fee schedule 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 

GHG evaluation for a permit 

modification or related permit 

action ....................................... 7 

GHG evaluation at permit renewal ....................................... 10 

* * * * * 

PART 71—FEDERAL OPERATING 

PERMIT PROGRAMS 

■ 7. The authority citation for part 71 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

■ 8. In § 71.2, the definition of 

‘‘Regulated pollutant (for fee 

calculation)’’ is amended by: 

■ a. Removing ‘‘or’’ from the end of 

paragraph (2); 

■ b. Removing the period at the end of 

paragraph (3) and adding ‘‘; or’’ in its 

place; and 

■ b. Adding paragraph (4). 

The revisions and additions read as 

follows: 

§ 71.2 Definitions. 

* * * * * 

Regulated pollutant (for fee 

calculation), which is used only for 

purposes of § 71.9(c), means any 

‘‘regulated air pollutant’’ except the 

following: 

* * * * * 

(4) Greenhouse gases. 

* * * * * 

■ 9. Section 71.9 is amended by: 

■ a. Revising paragraphs (c)(1), (c)(2)(i), 

(c)(3), and (c)(4); and 

■ b. Adding paragraph (c)(8). 

The revisions and addition 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 calculation) emitted 

from the source, including fugitive 

emissions; and 

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64660 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

(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 

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: 

Activity Set fee 

GHG completeness determination (for initial permit or updated application) .................... $2,236 

GHG evaluation for a permit 

modification or related permit 

action ....................................... 364 

GHG evaluation at permit renewal ....................................... 520 

* * * * * 

PART 98—MANDATORY 

GREENHOUSE GAS REPORTING 

■ 10. The authority citation for part 98 

is revised to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

■ 11. Section 98.426 is amended by 

adding paragraph (h) to read as follows: 

§ 98.426 Data reporting requirements. 

* * * * * 

(h) If you capture a CO2 stream from 

an electricity generating unit that is 

subject to subpart D of this part and 

transfer CO2 to any facilities that are 

subject to subpart RR of this part, you 

must: 

(1) Report the facility identification 

number associated with the annual GHG 

report for the subpart D facility; 

(2) Report each facility identification 

number associated with the annual GHG 

reports for each subpart RR facility to 

which CO2 is transferred; and 

(3) Report the annual quantity of CO2

in metric tons that is transferred to each 

subpart RR facility. 

■ 12. 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. 

[FR Doc. 2015–22837 Filed 10–22–15; 8:45 am] 

BILLING CODE 6560–50–P 

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