***E.O. 12866 Review – Do Not Cite, Quote, or Release During Review***

Regulatory Impact Analysis for the Final Standards of 

Performance for Greenhouse Gas Emissions from New, 

Modified, and Reconstructed Stationary Sources: Electric Utility 

Generating Units
***E.O. 12866 Review – Do Not Cite, Quote, or Release During Review***

ii

EPA-452/R-15-005

August 2015

Regulatory Impact Analysis for the Final Standards of Performance for Greenhouse Gas 

Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility 

Generating Units

U.S. Environmental Protection Agency

Office of Air Quality Planning and Standards

Health and Environmental Impacts Division

Research Triangle Park, NC
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CONTACT INFORMATION

This document has been prepared by staff from the Office of Air Quality Planning and 

Standards, U.S. Environmental Protection Agency. Questions related to this document should 

be addressed to Amanda Curry Brown, U.S. Environmental Protection Agency, Office of Air 

Quality Planning and Standards, Research Triangle Park, North Carolina 27711 (email: 

CurryBrown.Amanda@epa.gov).

ACKNOWLEDGEMENTS

In addition to EPA staff from the Office of Air Quality Planning and Standards, personnel 

from the U.S. EPA Office of Atmospheric Programs and Office of Policy contributed data and 

analysis to this document.
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ACRONYMS

AEO Annual Energy Outlook

ANSI American National Standards Institute

ASTM American Society for Testing and Materials

BPT Benefit-per-Ton

BSER Best System of Emissions Reduction

Btu British Thermal Units

CAA Clean Air Act

CAIR Clean Air Interstate Rule

CCR Coal Combustion Residuals

CCS Carbon Capture and Sequestration or Carbon Capture and Storage

CESA Clean Energy States Alliance

CFR Code of Federal Regulations

CH4 Methane

CO2 Carbon Dioxide

CO2e Carbon Dioxide Equivalent 

CRA Congressional Review Act

CRF Capital Recovery Factor

CSAPR Cross-State Air Pollution Rule

CT Combustion Turbines

CUA Climate Uncertainty Adder

DOE U.S. Department of Energy

EGU Electric Generating Unit

EIA U.S. Energy Information Administration

ELG Effluent Limitation Guidelines

EMM Electricity Market Module

EO Executive Order

EOR Enhanced Oil Recovery

EPA U.S. Environmental Protection Agency

FERC Federal Energy Regulatory Commission

FOM Fixed Operating and Maintenance

FR Federal Register

FRCC Florida Reliability Coordinating Council

GDP Gross Domestic Product

GHG Greenhouse Gas
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GS Geologic Sequestration

GW Gigawatt

GWh Gigawatt-hours

IAM Integrated Assessment Model

ICR Information Collection Request

IGCC Integrated Gasification Combined Cycle

IOU Investor Owned Utility

IPCC Intergovernmental Panel on Climate Change

IPM Integrated Planning Model

IPP Independent Power Producers

IRP Integrated Resource Plan

IWG Interagency Working Group

kWh Kilowatt-hour

lb Pound or Pounds

LCOE Levelized Cost of Electricity

MATS Mercury and Air Toxics Standards

MMBtu Million British Thermal Units

MW Megawatt

MWh Megawatt-hour

N2O Nitrous Oxide

NATCARB National Carbon Sequestration Database and Geographic Information 

System

NCA3 Third National Climate Assessment

NEEDS National Electric Energy Data System

NEMS National Energy Modeling System

NERC North American Electric Reliability Corporation

NETL National Energy Technology Laboratory

NGCC Natural Gas Combined Cycle

NOAK Nth of a Kind

NODA Notice of Data Availability

NOX Nitrogen Oxide

NRC National Research Council

NSPS New Source Performance Standard

NTTAA National Technology Transfer and Advancement Act

OMB Office of Management and Budget

PM2.5 Fine Particulate Matter
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PM NAAQS National Ambient Air Quality Standards for Particulate Matter

PRA Paperwork Reduction Act 

RES Renewable Electricity Standards

RFA Regulatory Flexibility Act

RGGI Regional Greenhouse Gas Initiative

RIA Regulatory Impact Analysis

RPS Renewable Portfolio Standards

SC-CO2 Social Cost of Carbon

SCPC Super Critical Pulverized Coal

SF6 Sulfur Hexafluoride

SIP State Implementation Plan

SO2 Sulfur Dioxide

Tcf Trillion Cubic Feet

TkWh Trillion Kilowatt-Hours

TSD Technical Support Document

TS&M Transportation Storage and Monitoring

UMRA Unfunded Mandates Reform Act

U.S.C. U.S. Code

USGCRP U.S. Global Change Research Program

USGS U.S. Geological Survey

VOM Variable Operating and Maintenance
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Contents

Acronyms ..................................................................................................................................iv

Executive Summary.............................................................................................................. ES-1

ES.1 Background and Context of Final Rule............................................................... ES-1

ES.2 Summary of the Final Rule................................................................................. ES-2

ES.3 Key Findings of Economic Analysis .................................................................... ES-3

Chapter 1 Introduction and Background ............................................................................... 1-1

1.1 Introduction ......................................................................................................... 1-1

1.1.1 Legal Basis for this Rulemaking................................................................ 1-1

1.1.2 Regulatory Analysis.................................................................................. 1-3

1.2 Background for the Final EGU New, Modified, and Reconstructed Source 

GHG Standards..................................................................................................... 1-5

1.2.1 Baseline and Years of Analysis................................................................. 1-5

1.2.2 Definition of Affected EGUs..................................................................... 1-6

1.2.3 Regulated Pollutant ................................................................................. 1-7

1.2.4 Emission Limits......................................................................................... 1-7

1.2.5 Emission Reductions................................................................................ 1-8

1.3 Organization of the Regulatory Impact Analysis ................................................. 1-9

Chapter 2 Electric Power Sector Profile................................................................................. 2-1

2.1 Introduction ......................................................................................................... 2-1

2.2 Power Sector Overview........................................................................................ 2-1

2.2.1 Generation ............................................................................................... 2-1

2.2.2 Transmission ............................................................................................ 2-9

2.2.3 Distribution ............................................................................................ 2-10

2.3 Sales, Expenses, and Prices................................................................................ 2-10

2.3.1 Electricity Prices........................................................................................ 2-11
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2.3.2 Prices of Fossil Fuels Used for Generating Electricity............................... 2-16

2.3.3 Changes in Electricity Intensity of the U.S. Economy Between 2002 

to 2012................................................................................................... 2-17

2.4 Deregulation and Restructuring ........................................................................ 2-19

2.5 Emissions of Greenhouse Gases from Electric Utilities..................................... 2-23

2.6 Carbon Dioxide Control Technologies ............................................................... 2-26

2.6.1 Carbon Capture and Storage ................................................................. 2-28

2.7 Geologic and Geographic Considerations for Geologic Sequestration ............. 2-32

2.7.2 Availability of Geologic Sequestration in Deep Saline Formations ....... 2-36

2.7.3 Availability of CO2 Storage via Enhanced Oil Recovery ......................... 2-36

2.8 State Policies on GHG and Clean Energy Regulation in the Power Sector........ 2-38

2.9 Revenues and Expenses..................................................................................... 2-40

2.10 Natural Gas Market............................................................................................ 2-41

2.11 References ......................................................................................................... 2-45

Chapter 3 Benefits of Reducing Greenhouse Gas Emissions and Other Pollutants.............. 3-1

3.1 Overview of Climate Change Impacts from GHG Emissions................................ 3-1

3.2 Social Cost of Carbon ........................................................................................... 3-2

3.3 Health Co-Benefits of SO2 and NOx Reductions.................................................. 3-8

3.4 References ......................................................................................................... 3-12

Chapter 4 Costs, Economic, and Energy Impacts of the New Source Standards .................. 4-1

4.1 Synopsis................................................................................................................ 4-1

4.2 Requirements of the Final GHG EGU NSPS.......................................................... 4-2

4.3 Power Sector Modeling Framework .................................................................... 4-3

4.3.1 Modeling Overview.................................................................................. 4-3

4.3.2 The Integrated Planning Model ............................................................... 4-4

4.4 Analyses of Future Generating Capacity.............................................................. 4-7
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4.4.1 Base Case Power Sector Modeling Projections....................................... 4-7

4.4.2 Alternative Scenarios from AEO 2014 ................................................... 4-13

4.5 Levelized Cost of Electricity Analysis ................................................................. 4-19

4.5.1 Overview of the Concept of Levelized Cost of Electricity...................... 4-20

4.5.2 Cost and Performance of Technologies................................................. 4-21

4.5.3 Levelized Cost of Electricity of New Generation Technologies............. 4-23

4.5.4 Levelized Cost of Electricity of NGCC and Non-compliant Coal............. 4-25

4.5.5 Levelized Cost of Simple Cycle Combustion Turbine and Natural 

Gas Combined Cycle............................................................................... 4-33

4.6 Macroeconomic and Employment Impacts....................................................... 4-34

4.7 References ......................................................................................................... 4-35

Chapter 5 Analysis of Illustrative Benefit-Cost Scenarios For New Sources.......................... 5-1

5.1 Synopsis................................................................................................................ 5-1

5.2 Comparison of Emissions from Generation Technologies................................... 5-1

5.3 Comparison of Health and Climate Impacts from Generation Technologies...... 5-5

5.4 Illustrative Analysis – Benefits and Costs of New Source Standards across 

a Range of Gas Prices......................................................................................... 5-11

5.4.1 Likely Natural Gas Prices........................................................................ 5-14

5.4.2 Unexpectedly High Natural Gas Prices .................................................. 5-14

5.4.3 Unprecedented Natural Gas Prices........................................................ 5-15

5.5 Illustrative Analysis – Benefits and Costs of Non-Compliant Coal and 

Compliant Coal................................................................................................... 5-16

5.6 Impact of the New Source Standards Considering the Cost of Lost Option

Value .................................................................................................................. 5-23

5.7 References ......................................................................................................... 5-25

Chapter 6 Modified and Reconstructed Source Impacts....................................................... 6-1

6.1 Introduction ......................................................................................................... 6-1

6.2 Reconstructed Sources ........................................................................................ 6-1
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6.3 Modified Sources................................................................................................. 6-1

Chapter 7 Statutory and Executive Order Reviews ............................................................... 6-1

7.1 Executive Order 12866, Regulatory Planning and Review, and Executive 

Order 13563, Improving Regulation and Regulatory Review.............................. 7-1

7.2 Paperwork Reduction Act (PRA) .......................................................................... 7-1

7.2.1 Newly constructed EGUs.......................................................................... 7-2

7.2.2 Modified and Reconstructed EGUs.......................................................... 7-3

7.2.3 Information Collection Burden ................................................................ 7-4

7.3 Regulatory Flexibility Act (RFA)............................................................................ 7-4

7.3.1 Newly constructed EGUs.......................................................................... 7-4

7.3.2 Modified and Reconstructed EGUs.......................................................... 7-5

7.4 Unfunded Mandates Reform Act (UMRA)........................................................... 7-5

7.5 Executive Order 13132, Federalism..................................................................... 7-6

7.6 Executive Order 13175, Consultation and Coordination with Indian Tribal 

Governments ....................................................................................................... 7-6

7.7 Executive Order 13045, Protection of Children from Environmental Health 

Risks and Safety Risks .......................................................................................... 7-8

7.8 Executive Order 13211, Actions Concerning Regulations That Significantly 

Affect Energy Supply, Distribution, or Use .......................................................... 7-9

7.9 National Technology Transfer and Advancement Act......................................... 7-9

7.10 Executive Order 12898: Federal Actions to Address Environmental Justice 

in Minority Populations and Low-Income Populations ....................................... 7-9

7.11 Congressional Review Act (CRA)........................................................................ 7-12
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ES-1

EO 12866_111(b) New-Mods 2060-AQ91 RIA Final_07302015_CLEAN

EXECUTIVE SUMMARY

This Regulatory Impact Analysis (RIA) discusses potential benefits, costs, and economic 

impacts of the Final Standards of Performance for Greenhouse Gas Emissions from New, 

Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units (herein 

referred to as the EGU New, Modified, and Reconstructed Source GHG Standards).

ES.1 Background and Context of Final Rule

The final EGU New, Modified and Reconstructed Source GHG Standards will set emission 

limits for greenhouse gas emissions (GHG) from newly constructed, modified, and 

reconstructed fossil fuel-fired electricity generating units (EGUs). These limits will apply to 

carbon dioxide (CO2) emissions from any affected fossil fuel-fired EGU. The United States 

Environmental Protection Agency (EPA) is finalizing requirements for these sources because 

CO2 is an air pollutant under the Clean Air Act, section 111 (a) and (b) of the Act authorize the 

EPA to establish standards of performance for air pollutants emitted from source categories like 

the one here listed by the EPA because the source category causes, or contributes significantly 

to air pollution which may reasonably be anticipated to endanger public health or welfare. 

Fossil fuel-fired power plants are the country’s largest stationary source emitters of GHGs. As 

stated in the EPA’s Endangerment and Cause or Contribute Findings for Greenhouse Gases 

Under Section 202(a) of the Clean Air Act (CAA) (74 FR 66518), and summarized in Chapter 3 of 

this RIA, the anthropogenic buildup of GHGs in the atmosphere is the cause of most of the 

observed global warming over the last 50 years.

On June 25, 2013, in conjunction with the announcement of his Climate Action Plan, 

President Obama issued a Presidential Memorandum directing the EPA to issue a proposal to 

address carbon pollution from new power plants by September 30, 2013, and to issue 

“standards, regulations, or guidelines, as appropriate, which address carbon pollution from 

modified, reconstructed, and existing power plants.” On September 20, 2013, pursuant to 

authority in CAA section 111(b), EPA Administrator Gina McCarthy signed proposed carbon 

pollution standards for newly constructed fossil fuel-fired power plants (79 FR 1430, January 8, 

2014). 

The EPA subsequently issued a Notice of Data Availability (NODA), soliciting comment 

on its initial interpretation of provisions in the Energy Policy Act of 2005 and the Internal 
***E.O. 12866 Review – Do Not Cite, Quote, or Release During Review***

ES-2

Revenue Code, and also soliciting comment on a Technical Support Document, which addressed 

these provisions’ relationship to the factual record supporting the proposed rule (79 FR 10750, 

February 26, 2014). 

On June 2, 2014, Administrator McCarthy signed proposed standards of performance, 

also pursuant to CAA section 111(b), to limit emissions of CO2 from modified and reconstructed 

fossil fuel-fired electric utility steam generating units and stationary combustion turbines (79 FR 

34959, June 18, 2014).

In this action, the EPA is finalizing standards of performance to limit emissions of CO2

from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam 

generating units and stationary combustion turbines. Consistent with the requirements of CAA 

section 111(a) and (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.

ES.2 Summary of the Final Rule

The EPA has determined that the BSER for newly constructed steam generating units is a 

supercritical pulverized coal (SCPC) unit using post-combustion partial carbon capture and 

storage (CCS) technology to meet an emission limitation of 1,400 lb CO2/MWh-gross. The 

standard for steam generating units that conduct modifications resulting in a potential hourly 

increase in CO2 emissions (mass per hour) of more than 10 percent1is 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. For reconstructed steam generating units, the 

BSER is the most efficient demonstrated generating technology for these types of units (i.e., 

meeting a standard of performance consistent with a reconstructed boiler using most efficient 

steam conditions available, even if the boiler was not originally designed to do so).

The BSER for primarily natural gas-fired stationary combustion turbines expected to 

serve intermediate and base load power demand is the use of well-designed, well-maintained, 

and well-operated natural gas combined cycle (NGCC) technology. These units will be required 

to meet an emission standard of 1,000 lb CO2/MWh-gross output (or 1,030 lb CO2/MWh of net 

energy output). For non-base load and multi-fuel-fired units, BSER is the use of clean fuels.

 

1 More than 10 percent as compared to its highest potential during the previous five years. The EPA is not finalizing 

standards for units that conduct modifications with a potential hourly increase in CO2 of 10 percent of less.
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ES-3

The BSER determination and final standards for each affected EGU are shown in Table 

ES-1. The applicability of these standards based on the capacity and operation of a source are 

described in the preamble for this final rule. The final standards for all source categories will be 

met on a 12-operating month rolling average basis. 

ES.3 Key Findings of Economic Analysis

CAA Section 111(b) requires that the new source performance standards (NSPS) be 

reviewed every eight years. As a result, this rulemaking’s analysis is primarily focused on 

projected impacts within the current eight-year NSPS timeframe.

2 As explained in detail in this 

document, energy market data and projections support the conclusion that, even in the 

absence of this rule, expected economic conditions will lead electricity generators to choose 

new generation technologies that meet the standards without the need for additional controls.

The base case modeling the EPA performed for this rule and for other recent air rules 

projects that, even in the absence of this action, new fossil-fuel fired capacity constructed

through 2022 and the years following will most likely be NGCC capacity that complies with the 

final standards. Analyses performed both by the EPA and the Energy Information 

Administration (EIA) project that new compliant natural gas-fired units and renewable sources 

are likely to be the technologies of choice for new generating capacity due to current and 

projected economic market conditions.

3

 

2

In some cases, conditions in the analysis year of 2022 (eight years from proposal) are represented by results of 

power sector modeling for the year 2020. An analysis year of 2023 (eight years from finalization) would not 

substantively alter the overall conclusions of this RIA.

3

 See the EIA’s 2009 to 2015 Annual Energy Outlooks (AEO).
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ES-4

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

Affected EGU BSER Standard

Newly Constructed Fossil Fuel-Fired 

Steam Generating Units

Efficient new SCPC utility boiler 

implementing partial CCS

1,400 lb CO2/MWh-gross

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-gross for 

sources with heat input > 2,000 

MMBtu/h.

OR

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

sources with heat input ≤ 2,000 

MMBtu/h.

Reconstructed Fossil Fuel-Fired Steam 

Generating Units

Most efficient generating 

technology at the affected EGU.

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

sources with heat input > 2,000 

MMBtu/h.

OR

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

sources with heat input ≤ 2,000 

MMBtu/h.

Newly Constructed and Reconstructed 

Natural Gas-Fired Stationary 

Combustion Turbines

Efficient NGCC technology for 

natural gas-fired base load units 

and clean fuels for non-base load

and multi-fuel-fired units.

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

1,030 lb CO2/MWh-net for 

base load natural gas-fired 

units.

 

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

units.

3. 120 to 160 lb CO2/MMBtu for 

multi-fuel-fired units.

Historically, the EPA has been notified of very few modifications (for criteria pollutants) 

or reconstructions under the NSPS provisions. As such, the EPA anticipates few covered units 

will trigger the reconstruction or modification provisions in the period of analysis. 
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ES-5

Therefore, based on the analysis presented in Chapter 4 of this RIA, the EPA anticipates

that the EGU New, Modified, and Reconstructed Source GHG Standards will result in negligible

CO2 emission changes, energy impacts, quantified benefits, costs, and economic impacts by 

2022. Accordingly, the EPA also does not anticipate this rule will have any significant impacts on 

the price of electricity, employment or labor markets, or the U.S. economy. 

Although the primary conclusion of the analysis presented in this RIA is that the 

standards for newly constructed EGUs will result in negligible costs and benefits, the EPA has 

also performed several illustrative analyses, in Chapter 5, that show the potential impacts of 

the rule if certain key assumptions were to change. This analysis finds that under conditions 

that deviate from current projections about natural gas prices, the monetized benefits of the 

standards to society likely outweigh the costs of the standards. The analysis also presents the 

costs and benefits that would occur in the unlikely case where assumptions about economic 

conditions do not change but an operator chooses to construct new coal-fired capacity. In that 

analysis, monetized benefits outweigh costs under a range of assumptions.

The final standards provide the benefit of regulatory certainty that any new coal-fired 

power plant must limit CO2 emissions to the level of the standard of performance: 1,400 lb 

CO2/MWh. The final standards also reduce regulatory uncertainty by defining the requirements 

to limit emissions of CO2 from new, modified, and reconstructed fossil fuel-fired steam 

generating sources. 

In addition, the EPA intends this rule to send a clear signal about the current and future 

status of CCS technology. Additional CCS applications are expected to lead to improvements in 

this technology’s performance and consequent reductions in its cost. Identifying postcombustion partial CCS technology as the BSER for coal-fired power plants promotes further 

development and encourages continued research of CCS, 4,5 which is important for long-term 

CO2 emission reductions. 

The final standards also provide regulatory certainty for stationary combustion turbines 

that, along with new renewable sources, are expected to be the primary technology options to 

 

4

Statement by Department of Energy Secretary Steven Chu. Statement by Secretary Chu. 

http://energy.gov/articles/building-clean-energy-partnerships-china-and-japan. 

5

Friedman, Dr. Julio S. “A U.S. – China CCS Roadmap.” Lawrence Livermore National Laboratory Carbon 

Management Program. http://www.nrcce.wvu.edu/cleanenergy/docs/Friedmann.pdf. 
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ES-6

provide new generating capacity in the analysis period. Any new stationary combustion 

turbines must be well-designed, well-maintained, and well-operated.
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1-1

CHAPTER 1

INTRODUCTION AND BACKGROUND

1.1 Introduction

In this action, the U.S. Environmental Protection Agency (EPA) is adopting emission 

limits for greenhouse gases (GHGs), specifically carbon dioxide (CO2), emitted from fossil fuelfired EGUs. This document presents the expected economic impacts of the Electricity 

Generating Unit (EGU) New, Modified, and Reconstructed Source GHG Standards rule through

2022, including some projections for years up to 2030. Based on the analysis presented in 

Chapter 4, the current forecast of economic conditions (e.g., price of natural gas) will lead 

electricity generators to choose fuels and technologies that will meet the final standards for 

new sources without the need for additional control, even in the absence of the rule. As a 

result, the final new source standards are expected to have no, or negligible, costs or quantified 

benefits associated with them. However, should forecast economic conditions change or 

operators choose to construct new coal-fired capacity, we project that emission reductions 

associated with the standard may result in monetized benefits exceeding the cost of control, 

and would also provide unquantified benefits. (See Chapter 5.) The EPA has reached a similar 

conclusion for the final reconstruction and modification provisions. Based on historical 

information that has been reported to the EPA, we anticipate few covered units will trigger the 

reconstruction or modification provisions in the period of analysis. As a result, we anticipate 

negligible costs or benefits associated with those standards. This chapter contains background 

information on the rule and an outline of the chapters of the report.

1.1.1 Legal Basis for this Rulemaking

Section 111 of the Clean Air Act (CAA) requires performance standards for air pollutant 

emissions from categories of stationary sources which are listed by the EPA because they may 

reasonably contribute to the endangerment of public health or welfare. In April 2007, the 

Supreme Court ruled in State of Massachusetts v. EPA that GHGs meet the definition of an “air 

pollutant” under the CAA. This ruling clarified that the authorities and requirements of the CAA 

apply to GHGs. As a result, the EPA is authorized to make decisions about whether to regulate 

GHGs under certain provisions of the CAA, based on relevant statutory criteria. Because CO2 is 

an air pollutant emitted from a source category the EPA has listed for purposes of section 111, 

the EPA may establish standards under section 111 (a) and (b) for CO2 for this source category. 

In 2009, the EPA issued a final determination that emissions of certain specified GHGs endanger 

both the public health and the public welfare of current and future generations in the 

Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of 
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1-2

the CAA (74 FR 66,496; Dec. 15, 2009), and has explained in detail how emissions of CO2 from 

this source category cause or contribute significantly to air pollution that endangers health and 

welfare. As described in Chapter 2, this source category contributes more CO2 than any other 

domestic stationary source. 

On June 25, 2013, in conjunction with the announcement of his Climate Action Plan, 

President Obama issued a Presidential Memorandum directing the EPA to issue a proposal to 

address carbon pollution from new power plants by September 30, 2013, and to issue 

“standards, regulations, or guidelines, as appropriate, which address carbon pollution from 

modified, reconstructed, and existing power plants.” On September 20, 2013, pursuant to 

authority in CAA section 111(b), EPA Administrator Gina McCarthy signed proposed carbon 

pollution standards for newly constructed fossil fuel-fired power plants (79 FR 1430, January 8, 

2014). 

The EPA subsequently issued a Notice of Data Availability (NODA), soliciting comment 

on its initial interpretation of provisions in the Energy Policy Act of 2005 and the Internal 

Revenue Code, and also soliciting comment on a Technical Support Document, which addressed 

these provisions’ relationship to the factual record supporting the proposed rule (79 FR 10750, 

February 26, 2014). 

On June 2, 2014, Administrator McCarthy signed proposed standards of performance, 

also pursuant to CAA section 111(b), to limit emissions of CO2 from modified and reconstructed 

fossil fuel-fired electric utility steam generating units and stationary combustion turbines (79 FR 

34959, June 18, 2014).

In this action, the EPA is finalizing standards of performance to limit emissions of CO2

from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam 

generating units and 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.
***E.O. 12866 Review – Do Not Cite, Quote, or Release During Review***

1-3

1.1.2 Regulatory Analysis1

In accordance with Executive Order (EO) 12866, EO 13563, and the EPA’s Guidelines for 

Preparing Economic Analyses, the EPA prepared this Regulatory Impact Analysis (RIA) for this 

“significant regulatory action.” This rule is not anticipated to have an annual effect on the 

economy of $100 million or more or adversely affect in a material way the economy, a sector of 

the economy, productivity, competition, jobs, the environment, public health or safety, or 

state, local, or tribal governments or communities and is therefore not an “economically 

significant rule.” However, under EO 12866 (58 FR 51,735, October 4, 1993), this action is a 

“significant regulatory action” because it “raises novel legal or policy issues arising out of legal 

mandates.” As a matter of policy, the EPA has attempted to provide a thorough analysis of the 

potential impacts of this rule, consistent with requirements of the Executive Orders.

This RIA addresses the potential costs and benefits of the new, modified, and 

reconstructed source emission limits that are the focus of this action. As described in Chapter 4, 

the EPA does not anticipate any costs or quantified benefits will result from the new source 

standards if utilities and project developers make the type of choices related to new generation 

sources that are forecast by the EPA’s and EIA’s models and that many publicly available utility 

integrated resource plans (IRPs) indicate are likely. However, if future economic conditions 

(e.g., natural gas prices) differ from these forecasts and utilities would have constructed new 

coal-fired units in the baseline, there could be some compliance costs. In these cases, the EPA’s 

analysis shows that the rule will result in net benefits under a range of assumptions.

For new sources the EPA and EIA, through their models2, project that new fossil-fired 

electric utility steam generating units and natural gas-fired stationary combustion turbines that

meet the applicability criteria would meet the respective standards under this rule in the 

baseline where no such standards are implemented. Some limited new coal-fired units with 

federally-supported carbon capture and storage (CCS) are included in the modeling, though 

these units are expected to be compliant with the applicable standards under this rule. Because 

this rule does not change these forecasts, it is expected to have no, or negligible, costs,

3

or 

quantified benefits.

 

1

The analysis in this RIA and the draft RIA that accompanied the proposal together constitute the economic 

assessment required by CAA section 317. In the EPA’s judgment, the assessment is as extensive as practicable 

taking into account the EPA’s time, resources, and other duties and authorities.”

2

See the EIA’s 2009 to 2015 Annual Energy Outlooks (AEO).

3

Any additional monitoring or reporting costs from this rule should be negligible because new generators would 

already be required to monitor and report their CO2 emissions under the information collection requirements 
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New non-compliant coal-fired units are not expected to be constructed in the baseline, 

due in part to the low cost of constructing and operating new NGCC units relative to the cost of

new coal-fired units, relatively low forecast growth in electricity demand, and an expectation 

that the growth in end-use energy efficiency and renewable energy resources will continue. The 

expectation that no new non-compliant coal-fired units will be constructed in the baseline, and 

therefore that the promulgated standard of performance would not be a factor in decisions to 

construct, holds under a range of alternative baseline scenarios. 

Natural gas-fired combustion turbine units intended to serve as intermediate and base 

load generators constructed in the baseline are expected to be compliant with the standard, 

due in part to the cost-effectiveness of constructing and operating new combined cycle units 

relative to the cost of new simple cycle units. Absent significantly lower natural gas prices, the 

cost of electricity generated by combined cycle units operating at intermediate and base load 

capacity are lower than simple cycle units operating at the same capacity factor.

Chapter 5 complements and extends the sector level analysis by examining conditions 

(e.g., significantly higher natural gas prices) in which conclusions regarding the future economic 

competitiveness of new non-compliant coal-fired units relative to other new generation 

technologies may differ from those in the sector-wide analysis. The analysis evaluates the cost 

and benefits of adopting different competing generating technologies to serve base load 

demand at an individual facility level. When considering a wide range of natural gas price 

assumptions, along with information on historical and projected gas prices, this illustrative 

facility-level analysis supports the conclusion that these final standards are highly likely to incur 

no costs or quantified benefits. Furthermore, the analysis examines the costs and benefits that 

would occur in the unlikely case where an investor might choose to construct new coal-fired 

capacity, and shows that the result is a net monetized benefit under a range of assumptions. 

As described in Chapter 6, the EPA has reached a similar conclusion for the 

reconstruction and modification provisions for both steam generating units and stationary 

combustion turbines. The EPA has historically been notified of few modifications or 

reconstructions under the NSPS provisions and, as such, anticipates few covered units will 

 

contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98). Costs are only incurred 

if there has been a violation of an emission standard caused by a malfunction and a source chooses to assert an 

affirmative defense. The owner/operator must meet the burden of proving all of the requirements in an 

affirmative defense. See Chapter 7 for more details on monitoring and reporting costs.
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trigger the NSPS reconstruction or modification provisions in the period of analysis. As a result, 

we do not anticipate any significant costs or benefits associated with this rule.

1.2 Background for the Final EGU New, Modified, and Reconstructed Source GHG 

Standards

1.2.1 Baseline and Years of Analysis

The standards on which this analysis is based set GHG emission limits for new, modified,

and reconstructed fossil fuel-fired EGUs. The baseline for this analysis, which uses the 

Integrated Planning Model (IPM), includes state rules that have been finalized and/or approved 

by a state’s legislature or environmental agency as well as final federal rules. Additional legally 

binding and enforceable commitments for GHG reductions considered in the baseline are 

discussed in Chapter 4 of this RIA. 

All analyses are presented for compliance through the year 20224and all estimates are 

presented in 2011 dollars. CAA Section 111(b) requires that the NSPS be reviewed every eight 

years. As a result, this analysis is primarily focused on projected impacts within the current 

eight-year NSPS timeframe. The EPA’s finding of no new non-compliant units (and therefore, 

no projected costs or quantified benefits) is robust beyond the analysis period (past 2030) in 

both the IPM base case and the EIA’s Annual Energy Outlook 2014 Reference Case modeling 

projections. Furthermore, this finding is robust in the analysis period across a wide range of 

alternative potential market, technical, and regulatory scenarios that influence power sector 

investment decisions evaluated by EIA.5 Chapter 5 complements and extends the sector level 

analysis by examining conditions (e.g., significantly high natural gas prices) in which these 

conclusions regarding the future economic competitiveness of new non-compliant coal-fired 

units relative to other new generation technologies may differ. The analysis evaluates the cost 

and benefits of adopting different competing generating technologies to serve base load 

demand at an individual facility level.

Benefits and costs presented in the illustrative analyses in Chapter 5 of this RIA 

represent estimates from emission reductions under the finalized standards in a particular year. 

The latent and/or ongoing damages associated with pollution from these sources in a particular 

 

4

In IPM, conditions in the analysis year of 2022 are represented by a model year of 2020.

5

For example, in the 2014 AEO low gas resource sensitivity case, one of the scenarios most favorable to the 

construction of new coal capacity, the operation of new non-compliant coal capacity in the baseline is not 

forecast by the model until 2027. 
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analysis year are discounted to the analysis year. 6The benefits and costs presented do not 

represent the net present value of a stream of benefits and costs due to emission reductions 

over time.

1.2.2 Definition of Affected EGUs

1.2.2.1 New Sources

The statutory authority for this action is CAA section 111(b), which addresses standards 

of performance for new, modified, and reconstructed sources. The final standards for newly 

constructed fossil fuel-fired EGUs apply to those sources that commenced construction on or 

after January 8, 2014. 

1.2.2.2 Modified Sources

A modification is any physical or operational change to a source that increases the 

amount of any air pollutant emitted by the source or results in the emission of any air pollutant 

not previously emitted. The final standards for modified fossil fuel-fired steam generating units

apply to those sources that make modifications resulting in an increase of hourly CO2 emissions 

of more than 10 percent on or after June 18, 2014. However, projects to install pollution 

controls required under other CAA provisions are specifically exempted from the definition of 

“modifications” under 40 CFR 60.14(e)(5), even if they emit CO2 as a byproduct. 

1.2.2.3 Reconstructed Sources

The EPA’s CAA section 111 regulations provide that reconstructed sources are to be 

treated as new sources and, therefore, subject to new source standards of performance. The 

regulations define reconstructed sources, in general, as existing sources: (i) that replace 

components to such an extent that the capital costs of the new components exceed 50 percent 

of the capital costs of an entirely new facility and (ii) for which compliance with standards of 

performance for new sources is technologically and economically feasible (40 CFR 60.15). The 

final standards for reconstructed fossil fuel-fired EGUs apply to those sources that reconstruct

on or after June 18, 2014.

 

6

The CO2-related benefits, which are estimated using the social cost of carbon, vary depending on the year in 

which the change in CO2 emissions occurs. The social cost of carbon increases over time because future 

emissions are expected to produce larger incremental damages as physical and economic systems become 

more stressed in response to greater climatic change. The EPA relied on a national-average benefit per-ton 

method to estimate PM2.5-related health impacts of SO2 and NOX emissions. Despite our attempts to quantify 

and monetize as many of the co-benefits of reducing emissions from electricity generating sources as possible, 

not all known health and non-health co-benefits are accounted for in this assessment. See Chapter 3 for details.
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1.2.3 Regulated Pollutant

These final standards set limits for emissions of CO2 from affected EGUs. The EPA is

aware that other GHGs such as nitrous oxide (N2O) and to a lesser extent, methane (CH4), may 

be emitted from fossil-fuel-fired EGUs, especially from coal-fired circulating fluidized bed 

combustors and from units with selective catalytic reduction and selective non-catalytic 

reduction systems installed for nitrogen oxide (NOX) control. The EPA is not setting separate 

N2O or CH4 emission limits or an equivalent CO2 emission limit because of a lack of available 

data for these affected EGUs. Additional information on the quantity and significance of 

emissions and on the availability of cost effective controls would be needed before setting

standards for these pollutants.

1.2.4 Emission Limits

The EPA has determined that the BSER for newly constructed steam generating units is a

supercritical pulverized coal (SCPC) unit with post-combustion partial CCS technology. The 

standard of performance achievable using that BSER is 1,400 lb CO2/MWh-gross. The standard 

for modified steam generating units that conduct modifications resulting in a potential hourly 

increase in CO2 emissions (mass per hour) of more than 10 percent7is 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. For reconstructed steam generating units, the 

BSER is the most efficient demonstrated generating technology for these types of units (i.e., 

meeting a standard of performance consistent with a reconstructed boiler using most efficient 

steam conditions available, even if the boiler was not originally designed to do so). 

The BSER for new and reconstructed primarily natural gas-fired combustion turbines 

expected to serve intermediate and base load is the use of well-designed, well-maintained, and 

well-operated natural gas combined cycle (NGCC) technology. The standard of performance 

achievable using that BSER is 1,000 lb/CO2/MWh-gross.

The applicability of these standards is based on the capacity and operation of a source 

and is described in the preamble for this final rule. The final standards will be met on a 12-

operating month rolling average basis. The BSER determination and final standards for each 

affected EGU are shown in Table 1-1.

 

7 More than 10 percent as compared to its highest potential to emit in the past 5 years. The EPA is deferring issuing 

standards for units that conduct modifications with a potential hourly increase in CO2 of 10 percent or less.
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Table 1-1. Summary of BSER and Final Standards for Affected EGUs

Affected EGU BSER Standard

Newly Constructed Fossil Fuel-Fired 

Steam Generating Units

Efficient new SCPC utility boiler 

implementing partial CCS

1,400 lb CO2/MWh-gross

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-gross for 

sources with heat input > 2,000 

MMBtu/h.

OR

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

sources with heat input ≤ 2,000 

MMBtu/h.

Reconstructed Fossil Fuel-Fired Steam 

Generating Units

Most efficient generating 

technology at the affected EGU.

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

sources with heat input > 2,000 

MMBtu/h.

OR

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

sources with heat input ≤ 2,000 

MMBtu/h.

Newly Constructed and Reconstructed 

Natural Gas-Fired Stationary 

Combustion Turbines

Efficient NGCC technology for 

natural gas-fired base load units 

and clean fuels for non-base load

and multi-fuel-fired units.

4. 1,000 lb CO2/MWh-gross or 

1,030 lb CO2/MWh-net for 

base load natural gas-fired 

units. 

5. 120 lb CO2/MMBtu for nonbase load natural gas-fired 

units.

6. 120 to 160 lb CO2/MMBtu for 

multi-fuel-fired units.

1.2.5 Emission Reductions

As will be discussed in more detail in Chapter 4 of this RIA, the EPA anticipates that the 

EGU New, Modified, and Reconstructed Source GHG Standards will result in negligible changes 

in GHGemissions over the analysis period. The EPA expects that owners of new units will 

choose generation technologies that meet these standards in the baseline due to expected 
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economic conditions in the marketplace. Based on historical precedent, the EPA anticipates few 

covered units will trigger the NSPS reconstruction or modification provisions in the period of 

analysis. As a result, we do not anticipate any significant costs or monetized benefits associated 

with this rule.

1.3 Organization of the Regulatory Impact Analysis

This report presents the EPA’s analysis of the potential benefits, costs, and other 

economic effects of the EGU New, Modified, and Reconstructed Source GHG Standards to fulfill 

the requirements of an RIA. This RIA includes the following chapters:

 Chapter 2, Electric Power Sector Profile, describes the industry affected by the rule.

 Chapter 3, Benefits of Reducing GHGs and Other Pollutants, describes the effects of 

emissions on climate and health and provides background information to support 

the benefits analysis.

 Chapter 4, Costs, Economic, and Energy Impacts of the New Source Standards, 

describes impacts of the rule for new sources.

 Chapter 5, Analysis of Illustrative Benefit-Cost Scenarios for New Sources, describes 

additional analyses examining potential impacts under a range of scenarios.

 Chapter 6, Modified and Reconstructed Sources, describes the potential impacts of 

the standards for modified and reconstructed sources.

 Chapter 7, Statutory and Executive Order Impact Analyses, describes the small 

business, unfunded mandates, paperwork reduction act, environmental justice, and 

other analyses conducted for the rule to meet statutory and Executive Order 

requirements.
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CHAPTER 2

ELECTRIC POWER SECTOR PROFILE

2.1 Introduction

This chapter discusses important aspects of the power sector that relate to the EGU 

New, Modified and Reconstructed Source GHG Standards, including the types of electricity 

generating units (EGUs) affected by the regulation, and provides background on the power 

sector and EGUs. In addition, this chapter provides some historical background on trends in the 

past decade in the power sector, as well as about existing U.S. Environmental Protection 

Agency (EPA) regulation of the power sector.

In the past decade there have been significant structural changes in the both the mix of 

generating capacity and in the share of electricity generation supplied by different types of 

generation. These changes are the result of multiple factors in the power sector, including 

normal replacements of older generating units with new units, changes in the electricity 

intensity of the U.S. economy, growth and regional changes in the U.S. population, 

technological improvements in electricity generation from both existing and new units, changes 

in the prices and availability of different fuels, and substantial growth in electricity generation 

by renewable and unconventional methods. Many of these trends will continue to contribute to 

the evolution of the power sector. The evolving economics of the power sector, in particular 

the increased natural gas supply and subsequent relatively low natural gas prices, have resulted 

in more gas being utilized as base load energy in addition to supplying electricity during peak 

load. This chapter presents data on the evolution of the power sector from 2002 through 2012. 

Projections of new capacity and the impact of this rule on these new sources are discussed in 

more detail in Chapter 4 of this Regulatory Impact Assessment (RIA).

2.2 Power Sector Overview

The production and delivery of electricity to customers consists of three distinct 

segments: generation, transmission, and distribution. 

2.2.1 Generation

Electricity generation is the first process in the delivery of electricity to consumers. 

There are two important aspects of electricity generation: capacity and net generation. 

Generating capacity refers to the maximum amount of production from an EGU in a typical 

hour, typically measured in megawatts (MW) or gigawatts (1 GW = 1,000 MW). Electricity 

generation refers to the amount of electricity actually produced by EGUs, measured in kilowatt-
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hours (kWh) or gigawatt-hours (GWh = 1 million kWh). In addition to producing electricity for 

sale to the grid, generators perform other services important to reliable electricity supply, such 

as providing backup generating capacity in the event of unexpected changes in demand or 

unexpected changes in the availability of other generators. Other important services provided 

by generators include facilitating the regulation of the voltage of supplied generation.

Individual EGUs are not used to generate electricity 100 percent of the time. Individual 

EGUs are periodically not needed to meet the regular daily and seasonal fluctuations of 

electricity demand. Furthermore, EGUs relying on renewable resources such as wind, sunlight,

and surface water to generate electricity are routinely constrained by the availability of 

adequate wind, sunlight, or water at different times of the day and season. Units are also 

unavailable during routine and unanticipated outages for maintenance. These factors result in 

the mix of generating capacity types available (i.e., the share of capacity of each type of EGU) 

being substantially different than the mix of the share of total electricity produced by each type 

of EGU in a given season or year. 

Most of the existing capacity generates electricity by creating heat to generate high 

pressure steam that is released to rotate turbines which, in turn, create electricity. Natural gas 

combined cycle (NGCC) units have two generating components operating from a single source 

of heat. The first cycle is a gas-fired turbine, which generates electricity directly from the heat 

of burning natural gas. The second cycle reuses the waste heat from the first cycle to generate 

steam, which is then used to generate electricity from a steam turbine. Other EGUs generate 

electricity by using water or wind to rotate turbine, and a variety of other methods also make 

up a small, but growing, share of the overall electricity supply. The generating capacity includes 

fossil-fuel-fired units, nuclear units, and hydroelectric and other renewable sources (see Table 

2-1). Table 2-1 also shows the comparison between the generating capacity in 2002 and 2012.

In 2012, the power sector consisted of over 19,000 generating units with a total 

capacity1of 1,168 GW, an increase of 188 GW (or 19 percent) from the capacity in 2002 (980

 

1

As with all data presented in this section, this includes generating capacity not only at EGUs primarily operated to 

supply electricity to the grid, but also generating capacity at commercial and industrial facilities that produce 

both electricity used onsite as well as dispatched to the grid. Unless otherwise indicated, capacity data 

presented in this RIA is installed nameplate capacity (also known as nominal capacity), defined by EIA as “The 

maximum rated output of a generator, prime mover, or other electric power production equipment under 

specific conditions designated by the manufacturer.” Nameplate capacity is consistently reported to regulatory 

authorities with a common definition, where alternate measures of capacity (e.g., net summer capacity and net 

winter capacity) can use a variety of definitions and specified conditions.
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GW). The 188 GW increase consisted primarily of natural gas fired EGUs (134 GW) and wind 

generators (55 GW), with substantially smaller net increases and decreases in other types of 

generating units. 
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Table 2-1. Existing Electricity Generating Capacity by Energy Source, 2002 and 2012

2002 2012 Change Between '02 and '12

Energy Source

Generator 

Nameplate 

Capacity 

(MW)

% Total 

Capacity

Generator 

Nameplate 

Capacity 

(MW)

% Total 

Capacity

% 

Increase

Nameplate 

Capacity 

Change 

(MW)

% of Total 

Capacity 

Increase

Coal 338,199 35% 336,341 29% -1% -1,858 -1%

Natural Gas1352,128 36% 485,957 42% 38% 133,829 71%

Nuclear 104,933 11% 107,938 9% 3% 3,005 2%

Hydro 96,344 10% 99,099 8% 3% 2,755 1%

Petroleum 66,219 7% 53,789 5% -19% -12,430 -7%

Wind 4,531 0.5% 59,629 5.1% 1216% 55,098 29%

Other Renewable 14,208 1.5% 20,986 1.8% 47.7% 6,778 3.6%

Misc 3,023 0.3% 4,257 0.4% 40.8% 1,234 0.7%

Total 979,585 100% 1,167,995 100% 19% 188,410 100%

Note: This table presents generation capacity. Actual net generation is presented in Table 2-2.

Source: U.S. EIA Electric Power Annual, 2014. Downloaded from EIA Electricity Data Browser, Electric Power Plants 

Generating Capacity By Source, 2000 – 2013. Available at http://www.eia.gov/electricity/data.cfm#gencapacity. 

1

Natural Gas information in this chapter (unless otherwise stated) reflects data for all generating units using 

natural gas as the primary fossil heat source. This includes Combined Cycle Combustion Turbine (31 percent of 

2012 NG-fired capacity), Gas Turbine (30 percent), Combined Cycle Steam (19 percent), Steam Turbine (17

percent), and miscellaneous (< 1 percent).

The 19 percent increase in generating capacity is the net impact of newly built 

generating units, retirements of generating units, and a variety of increases and decreases to 

the nameplate capacity of individual existing units due to changes in operating equipment,

changes in emission controls, etc. During the period 2002 to 2012, a total of 315,752 MW of 

new generating capacity was built and brought online, and 64,763 MW existing units were 

retired. The net effect of the re-rating of existing units reduced the total capacity by 62,579 

MW. The overall net change in capacity was 188,410 MW, as shown in Table 2-1.

The newly built generating capacity was primarily natural gas (226,605 MW), which was 

partially offset by gas retirements (29,859 MW). Wind capacity was the second largest type of 

new builds (55,583 MW), augmented by 2,807 MW of solar.2 The overall mix of newly built and 

retired capacity, along with the net effect, is shown on Figure 2-1.

 

2

Partially offset by 87 MW retired wind or solar capacity. 
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Figure 2-1. New Build and Retired Capacity (MW) by Fuel Type, 2002-2012

Source: EIA Form 860

Not displayed: wind and solar retirements = 87 MW, net change in coal capacity = -56 MW

In 2012, electric generating sources produced a net 4,048 trillion kWh to meet electricity 

demand, a 5 percent increase from 2002 (3,858 trillion kWh). As presented in Table 2-2, almost

70 percent of electricity in 2012 was produced through the combustion of fossil fuels, primarily 

coal and natural gas, with coal accounting for the largest single share. Although the share of the 

total generation from fossil fuels in 2012 (67 percent) was only modestly smaller than the total 

fossil share in 2002 (71 percent), the mix of fossil fuel generation changed substantially during 

that period. Coal generation declined by 22 percent and petroleum generation by 75 percent, 

while natural gas generation increased by 77 percent. This reflects both the increase in natural 

gas capacity during that period as well as an increase in the utilization of new and existing gas 

EGUs during that period. Wind generation also grew from a very small portion of the overall 

total in 2002 to 3.5 percent of the 2012 total.

Table 2-2. Net Generation in 2002 and 2012 (Trillion kWh = TWh)

2002 2012 Change Between '02 and '12

-50,000

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

New Build Retirement Net Change

Change in Capacity (M

W)

Coal Nat Gas Wind & Solar Oil & Other
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Net 

Generation 

(TWh)

Fuel 

Source 

Share

Net 

Generation 

(TWh)

Fuel Source 

Share

Net 

Generation 

Change 

(TWh)

% Change in 

Net 

Generation

Coal 1,933.1 50% 1,514.0 37% -419.1 -21.7%

Natural Gas 702.5 18% 1,237.8 31% 535.3 76.2%

Nuclear 780.1 20% 769.3 19% -10.7 -1.4%

Hydro 255.6 7% 271.3 7% 15.7 6.1%

Petroleum 94.6 2.5% 23.2 0.6% -71.4 -75.5%

Wind 10.4 0.3% 140.8 3.5% 130.5 1260.0%

Other Renewable 68.8 1.8% 77.5 1.9% 8.8 12.7%

Misc 13.5 0.4% 12.4 0.3% -1.2 -8.7%

Total 3,858 100% 4,046 100% 188 5%

Source: U.S. EIA Monthly Energy Review, July 2014. Table 7.2a Electricity Net Generation: Total (All Sectors). 

Available at http://www.eia.gov/totalenergy/data/monthly/. Accessed 7/29/2015

Coal-fired and nuclear generating units have historically supplied “base load” electricity, 

the portion of electricity loads which are continually present, and typically operate throughout 

all hours of the year. The coal units meet the part of demand that is relatively constant. 

Although much of the coal fleet operates as base load, there can be notable differences across 

various facilities (see Table 2-3). For example, coal-fired units less than 100 megawatts (MW) in 

size compose 37 percent of the total number of coal-fired units, but only 6 percent of total coalfired capacity. Gas-fired generation is better able to vary output and is the primary option used 

to meet the variable portion of the electricity load and has historically supplied “peak” and 

“intermediate” power, when there is increased demand for electricity (for example, when 

businesses operate throughout the day or when people return home from work and run 

appliances and heating/air-conditioning), versus late at night or very early in the morning, when 

demand for electricity is reduced. 

Table 2-3 also shows comparable data for the capacity and age distribution of natural 

gas units. Compared with the fleet of coal EGUs, the natural gas fleet is generally smaller and 

newer. While 55 percent of the coal EGU fleet is over 500 MW per unit, 77 percent of the gas 

fleet is between 50 and 500 MW per unit. Many of the largest gas units are gas-fired steamgenerating EGUs. 
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Table 2-3. Coal and Natural Gas Generating Units, by Size, Age, Capacity, 

and Thermal Efficiency (Heat Rate)

Unit Size 

Grouping 

(MW)

No. 

Units

% of All 

Units

Avg. 

Age

Avg. Net 

Summer 

Capacity 

(MW)

Total Net 

Summer 

Capacity 

(MW)

% Total 

Capacity

Avg. Heat 

Rate 

(Btu/kWh)

COAL

0 – 24 223 18% 40.7 11.4 2,538 1% 11,733

25 – 49 108 9% 44.2 36.7 3,963 1% 11,990

50 – 99 157 12% 49.0 74.1 11,627 4% 11,883

100 - 149 128 10% 50.6 122.7 15,710 5% 10,971

150 - 249 181 14% 48.7 190.4 34,454 11% 10,620

250 - 499 205 16% 38.4 356.2 73,030 23% 10,502

500 - 749 187 15% 35.4 604.6 113,056 36% 10,231

750 - 999 57 5% 31.4 823.9 46,963 15% 9,942

1000 - 1500 11 1% 35.7 1259.1 13,850 4% 9,732

Total Coal 1257 100% 42.6 250.7 315,191 100% 11,013

NATURAL GAS

0 – 24 1992 37% 37.6 7.0 13,863 3% 13,531

25 – 49 410 8% 21.8 125.0 51,247 12% 9,690

50 - 99 962 18% 15.6 174.2 167,536 39% 8,489

100 - 149 802 15% 23.4 39.9 31,982 8% 11,765

150 - 249 167 3% 28.7 342.4 57,179 13% 9,311

250 - 499 982 18% 24.6 71.1 69,788 16% 12,083

500 - 749 37 1% 40.0 588.8 21,785 5% 11,569

750 - 1000 14 0.3% 35.9 820.9 11,492 3% 10,478

Total Gas 5366 100% 27.7 79.2 424,872 100% 11,652

Source: National Electric Energy Data System (NEEDS) v.5.14

Note: The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed to 

a generation-weighted or capacity-weighted average heat rate.) A lower heat rate indicates a higher level of fuel 

efficiency. Table is limited to coal-steam units in operation in 2013 or earlier, and excludes those units in NEEDS 

with planned retirements in 2014 or 2015.

In terms of the age of the generating units, 50 percent of the total coal generating 

capacity has been in service for more than 38 years, while 50 percent of the natural gas 

capacity has been in service less than 15 years. Figure 2-2 presents the cumulative age 

distributions of the coal and gas fleets, highlighting the pronounced differences in the ages of 

the fleets of these two types of fossil-fuel generating capacity. Figure 2-2 also includes the 

distribution of generation.
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Figure 2-2. Cumulative Distribution in 2010 of Coal and Natural Gas Electricity Capacity and 

Generation, by Age

Source: National Electric Energy Data System (NEEDS) v.5.13

Not displayed: coal units (376 MW total, 1 percent of total) and gas units (62 MW, < .01 percent of total)) over 70 

years old for clarity. Figure is limited to coal-steam units in NEEDS v.5.13 in operation in 2013 or earlier (excludes 

~2,100 MW of coal-fired IGCC and fossil waste capacity), and excludes those units in NEEDS with planned 

retirements in 2014 or 2015.

The locations of existing fossil units in the EPA’s National Electric Energy Data System 

(NEEDS) v.5.13 are shown in Figure 2-3.
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Figure 2-3. Fossil Fuel-Fired Electricity Generating Facilities, by Size

Source: National Electric Energy Data System (NEEDS) v.5.13

Note: This map displays fossil capacity at facilities in the NEEDS v.5.13 IPM frame. NEEDS v.5.13 reflects 

generating capacity expected to be online at the end of 2015. This includes planned new builds already under 

construction and planned retirements. In areas with a dense concentration of facilities, some facilities may be 

obscured. 

2.2.2 Transmission

Transmission is the term used to describe the bulk transfer of electricity over a network 

of high voltage lines, from electric generators to substations where power is stepped down for 

local distribution. In the U.S. and Canada, there are three separate interconnected networks of 

high voltage transmission lines,3each operating synchronously. Within each of these 

transmission networks, there are multiple areas where the operation of power plants is 

monitored and controlled to ensure that electricity generation and load are kept in balance. In 

some areas, the operation of the transmission system is under the control of a single regional 

 

3

These three network interconnections are the Western Interconnection, comprising the western parts of both the 

U.S. and Canada (approximately the area to the west of the Rocky Mountains), the Eastern Interconnection, 

comprising the eastern parts of both the U.S. and Canada (except those part of eastern Canada that are in the 

Quebec Interconnection), and the Electric Reliability Council of Texas (ERCOT) Interconnection, comprising 

most of Texas. See map of all NERC interconnections at 

http://www.nerc.com/AboutNERC/keyplayers/Documents/NERC_Interconnections_Color_072512.jpg
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operator. In others, individual utilities coordinate the operation of their generation, 

transmission, and distribution systems to balance their common generation and load needs.

2.2.3 Distribution

Distribution of electricity involves networks of lower voltage lines and substations that 

take the higher voltage power from the transmission system and step it down to lower voltage 

levels to match the needs of customers. The transmission and distribution system is the classic 

example of a natural monopoly, in part because it is not practical to have more than one set of 

lines running from the electricity generating sources to substations or from substations to 

residences and businesses.

Over the last couple of decades, several jurisdictions in the United States began 

restructuring the power industry to separate transmission and distribution from generation, 

ownership, and operation. Historically, the transmission system had been developed by 

vertically integrated utilities, establishing much of the existing transmission infrastructure. 

However, as parts of the country have restructured the industry, transmission infrastructure 

has also been developed by transmission utilities, electric cooperatives, and merchant 

transmission companies, among others. Distribution, also historically developed by vertically 

integrated utilities, is now often managed by a number of utilities that purchase and sell 

electricity, but do not generate it. As discussed below, electricity restructuring has focused 

primarily on efforts to reorganize the industry to encourage competition in the generation 

segment of the industry, including ensuring open access of generation to the transmission and 

distribution services needed to deliver power to consumers. In many states, such efforts have 

also included separating generation assets from transmission and distribution assets to form 

distinct economic entities. Transmission and distribution remain price-regulated throughout the 

country based on the cost of service.

2.3 Sales, Expenses, and Prices

These electric generating sources provide electricity for ultimate commercial, industrial,

and residential customers. Each of the three major categories of ultimate customers consume 

roughly a quarter to a third of the total electricity produced4(see Table 2-4). Some of these uses 

are highly variable, such as heating and air conditioning in residential and commercial buildings, 

 

4

Transportation (primarily urban and regional electrical trains) is a fourth ultimate customer category which 

accounts less than one percent of electricity consumption.
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while others are relatively constant, such as industrial processes that operate 24 hours a day.

The distribution between the end use categories changed very little between 2002 and 2012.

Table 2-4. Total U.S. Electric Power Industry Retail Sales in 2012 (billion kWh)

2002 2012

Sales/Direct 

Use (Billion 

kWh)

Share of Total 

End Use

Sales/Direct 

Use (Billion 

kWh)

Share of Total End 

Use

Sales

Residential 1,265 35% 1,375 35.9%

Commercial 1,104 30% 1,327 34.6%

Industrial 990 27% 986 25.7%

Transportation NA - 7 0.2%

Other 106 3% NA -

Total 3,465 95% 3,695 96%

Direct Use 166 5% 138 4%

Total End Use 3,632 100% 3,832 100%

Source: Table 2.2, EIA Electric Power Annual, 2013

Notes: 

Retail sales are not equal to net generation (Table 2-2) because net generation includes net exported electricity 

and loss of electricity that occurs through transmission and distribution.

Direct Use represents commercial and industrial facility use of onsite net electricity generation; and electricity 

sales or transfers to adjacent or co-located facilities for which revenue information is not available.

2.3.1 Electricity Prices

Electricity prices vary substantially across the United States, differing both between the 

ultimate customer categories and also by state and region of the country. Electricity prices are 

typically highest for residential and commercial customers because of the relatively high costs 

of distributing electricity to individual homes and commercial establishments. The high prices

for residential and commercial customers are the result both of the necessary extensive 

distribution network reaching to virtually every part of the country and every building, and also 

the fact that generating stations are increasingly located relatively far from population centers,

which increases transmission costs. Industrial customers generally pay the lowest average 

prices, reflecting both their proximity to generating stations and the fact that industrial 

customers receive electricity at higher voltages, which makes transmission more efficient and 

less expensive). Industrial customers frequently pay variable prices for electricity by the season 

and time of day, while residential and commercial prices historically have been less variable. 
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Overall industrial customer prices are usually considerably closer to the wholesale marginal cost 

of generating electricity than residential and commercial prices.

On a state-by-state basis, all retail electricity prices vary considerably. In 2011 the 

national average retail electricity price (all sectors) was 9.90 cents/KWh, with a range from 6.44 

cents (Idaho) to 31.59 cents (Hawaii). The Northeast, California, and Alaska have average retail 

prices that can be as much as double those of other states (see Figure 2-4), and Hawaii has the 

most expensive retail price of electricity in the country.

Figure 2-4. Average Retail Electricity Price by State (cents/kWh), 2011

Average national retail electricity prices increased between 2002 and 2012 by 36.7 

percent in nominal (current year $) terms. The amount of increase differed for the three major 

end use categories (residential, commercial and industrial). National average residential prices 

increased the most (40.8 percent), and commercial prices increased the least (27.9 percent). 

The nominal year prices for 2002 through 2012 are shown in Figure 2-5. 
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Figure 2-5. Nominal National Average Electricity Prices for Three Major End-Use Categories

Source: EIA AEO 2012, Table 2.4

Electricity prices for all three end-use categories increased more than overall inflation 

through this period, measured by either the Gross Domestic Product (GDP) implicit price 

deflator (23.5 percent) or the consumer price index (CPI-U, which increased by 27.7 percent)5. 

Most of these electricity price increases occurred between 2002 and 2008. Since 2008 nominal 

electricity prices have been relatively stable while overall inflation continued to increase. The 

increase in nominal electricity prices for the major end use categories, as well as increases in 

the GDP price and CPI-U indices for comparison, are shown in Figure 2-6.

 

5

Source: Federal Reserve Economic Data, FRB St. Louis. Available at http://research.stlouisfed.org/fred2/.

.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Electricity Price (Cent/kWh, nominal $)

Residential Commercial Industrial Total
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Figure 2-6. Relative Increases in Nominal National Average Electricity Prices for Major EndUse Categories, with Inflation Indices

The real (inflation-adjusted) change in average national electricity prices can be 

calculated using the GDP implicit price deflator. Figure 2-7 shows real6(2011$) electricity prices 

for the three major customer categories from 1960 to 2012, and Figure 2-8 shows the relative 

change in real electricity prices relative to the prices in 1960. As can be seen in the figures, the 

price for industrial customers has always been lower than for either residential or commercial 

customers, but the industrial price has been more volatile. While the industrial real price of 

electricity in 2012 was relatively unchanged from 1960, residential and commercial real prices 

are 23 percent and 28 percent lower respectively than in 1960.

 

6

All prices in this section are estimated as real 2011 prices adjusted using the GDP implicit price deflator unless 

otherwise indicated.
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Figure 2-7. Real National Average Electricity Prices (2011$) for Three Major End-Use 

Categories

Source: EIA Monthly Energy Review, April 2015, Table 9.8

0

2

4

6

8

10

12

14

16

18

1960 1970 1980 1990 2000 2010

Real Electricity Prices (2011$, ¢ /kWh)

Real Electricity Prices, 1960-2014 (including taxes)

Residential Commercial Industrial Total
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Figure 2-8. Relative Change in Real National Average Electricity Prices (2011$) for Three 

Major End-Use Categories

Source: EIA Monthly Energy Review, April 2015, Table 9.8

2.3.2 Prices of Fossil Fuels Used for Generating Electricity

Another important factor in the changes in electricity prices are the changes in fuel 

prices for the three major fossil fuels used in electricity generation: coal, natural gas and oil. 

Relative to real prices in 2002, the national average real price (in 2011$) of coal delivered to 

EGUs in 2012 had increased by 54 percent, while the real price of natural gas decreased by 22 

percent. The real price of oil increased by 203 percent, but with oil declining as an EGU fuel (in 

2012 oil generated only 1 percent of electricity) the doubling of oil prices had little overall 

impact in the electricity market. The combined real delivered price of all fossil fuels in 2012 

increased by 23 percent over 2002 prices. Figure 2-9 shows the relative changes in real price of 

all three fossil fuels between 2002 and 2012.

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

40%

50%

60%

1960 1970 1980 1990 2000 2010

Change in Real Electricity Prices

Relative Change in Electricity Prices,

1960-2014 (including taxes)

Residential Commercial Industrial Total
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Figure 2-9. Relative Real Prices of Fossil Fuels for Electricity Generation and Change in 

National Average Real Price per MBtu Delivered to EGU

Source: EIA AEO 2012, Table 9.9

2.3.3 Changes in Electricity Intensity of the U.S. Economy Between 2002 to 2012

An important aspect of the changes in electricity generation (i.e., electricity demand) 

between 2002 and 2012 is that while total net generation increased by 4.9 percent over that 

period, the demand growth for generation has been low, and in fact was lower than both the 

population growth (9.2 percent) and real GDP growth (19.8 percent). Figure 2-10 shows the 

growth of electricity generation, population and real GDP during this period.
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Figure 2-10. Relative Growth of Electricity Generation, Population, and Real GDP Since 2002

Sources: U.S. EIA Monthly Energy Review, December 2014. Table 7.2a Electricity Net Generation: Total (All 

Sectors). U.S. Census. 

Because demand for electricity generation grew more slowly than both the population 

and GDP, the relative electric intensity of the U.S. economy improved (i.e., less electricity used 

per person and per real dollar of output) during 2002 to 2012. On a per capita basis, real GDP 

per capita grew by 10.9 percent, increasing from $44,900 (in 2011$) per person in 2002 to 

$49,800 per person in 2012. At the same time electricity generation per capita decreased by 3.9 

percent, declining from 13.4 MWh per person in 2002 to 12.8 MWh per person in 2012. The 

combined effect of these two changes improved the overall electricity efficiency of the U.S. 

economy. Electricity generation per dollar of real GDP decreased 12.5 percent, declining from 

299 MWh per $1 million of GDP to 261 MWh per $1 million GDP. These relative changes are 

shown in Figure 2-11. Figures 2-10 and 2-11 clearly show the effects of the 2007 – 2009 

recession on both GDP and electricity generation, as well as the effects of the subsequent 

economic recovery.
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Figure 2-11. Relative Change of Real GDP, Population, and Electricity Generation Intensity 

Since 2002

Sources: U.S. EIA Monthly Energy Review, December 2014. Table 7.2a Electricity Net Generation: Total (All 

Sectors). U.S. Census

2.4 Deregulation and Restructuring

The process of restructuring and deregulation of wholesale and retail electric markets 

has changed the structure of the electric power industry. In addition to reorganizing asset 

management between companies, restructuring sought a functional unbundling of the 

generation, transmission, distribution, and ancillary services the power sector has historically 

provided, with the aim of enhancing competition in the generation segment of the industry.

Beginning in the 1970s, government policy shifted against traditional regulatory 

approaches and in favor of deregulation for many important industries, including 

transportation (notably commercial airlines), communications, and energy, which were all 

thought to be natural monopolies (prior to 1970) that warranted governmental control of 

pricing. However, deregulation efforts in the power sector were most active during the 1990s. 

Some of the primary drivers for deregulation of electric power included the desire for more 

efficient investment choices, the economic incentive to provide least-cost electric rates through 

market competition, reduced costs of combustion turbine technology that opened the door for 

more companies to sell power with smaller investments, and complexity of monitoring utilities’ 

cost of service and establishing cost-based rates for various customer classes. Deregulation and 

market restructuring in the power sector involved the divestiture of generation from utilities, 

the formation of organized wholesale spot energy markets with economic mechanisms for the 
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rationing of scarce transmission resources during periods of peak demand, the introduction of 

retail choice programs, and the establishment of new forms of market oversight and 

coordination.

The pace of restructuring in the electric power industry slowed significantly in response 

to market volatility in California and financial turmoil associated with bankruptcy filings of key 

energy companies. By the end of 2001, restructuring had either been delayed or suspended in 

eight states that previously enacted legislation or issued regulatory orders for its 

implementation (shown as “Suspended” in Figure 2-12). Eighteen other states that had 

seriously explored the possibility of deregulation in 2000 reported no legislative or regulatory 

activity in 2001 (EIA, 2003) (“Not Active” in Figure 2-12). Currently, there are 15 states plus the 

District of Columbia where price deregulation of generation (restructuring) has occurred 

(“Active” in Figure 2-12). Power sector restructuring is more or less at a standstill; by 2010 there 

were no active proposals under review by the Federal Energy Regulatory Commission (FERC) for 

actions aimed at wider restructuring, and no additional states have begun retail deregulation 

activity since that time.

Figure 2-12. Status of State Electricity Industry Restructuring Activities

Source: EIA 2010. “Status of Electricity Restructuring by State.” Available online at: 

http://www.eia.gov/cneaf/electricity/page/restructuring/restructure_elect.html.

One major effect of the restructuring and deregulation of the power sector was a 

significant change in type of ownership of electricity generating units in the states that 

deregulated prices. Throughout most of the 20th century, electricity was supplied by vertically
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integrated regulated utilities. The traditional integrated utilities controlled generation, 

transmission, and distribution in their designated areas, and prices were set by cost of service 

regulations set by state government agencies (e.g., Public Utility Commissions). Deregulation 

and restructuring resulted in unbundling of the vertical integration structure. Transmission and 

distribution continued to operate as monopolies with cost of service regulation, while 

generation shifted to a mix of ownership affiliates of traditional utility ownership and some 

generation owned and operated by competitive companies known as Independent Power 

Producers (IPP). The resulting generating sector differed by state or region, as the power sector 

adapted to the restructuring and deregulation requirements in each state. 

By 2002, the major impacts of adapting to changes brought about by deregulation and 

restructuring during the 1990s were largely in place. The resulting ownership mix of generating 

capacity (MW) in 2002 was 62 percent of the generating capacity owned by traditional utilities, 

35 percent owned by IPPs,

7

and 3 percent owned by commercial and industrial producers. The 

mix of electricity generated (MWh) was more heavily weighted towards the utilities, with a 

distribution in 2002 of 66 percent, 30 percent, and 4 percent for utilities, IPPs and 

commercial/industrial, respectively.

Since 2002 IPPs have expanded faster than traditional utilities, substantially increasing 

their share by 2012 of both capacity (58 percent utility, 39 percent IPPs, and 3 percent 

commercial/industrial) and generation (58 percent, 38 percent, and 4 percent). 

The mix of capacity and generation in 2002 and 2012 for each of the ownership types is 

shown in Figures 2-13 (capacity) and 2-14 (generation). The capacity and generation data for 

commercial and industrial owners are not shown on these figures due to the small magnitude 

of those ownership types. A portion of the shift of capacity and generation is due to sales and 

transfers of generation assets from traditional utilities to IPPs, rather than strictly the result of 

newly built units.

 

7

IPP data presented in this section include both combined and non-combined heat and power plants.
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Figures 2-13 & 2-14. Capacity and Generation Mix by Ownership Type, 2002 & 2012

Figures 2-15 and 2-16. Generation Capacity Built and Retired between 2002 and 2012 by 

Ownership Type

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

Utility IPP

Retired Capacity (M

W) Capacity Retirements 2002-2012

by Ownership Type

Coal Gas Wind & Solar Other

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

Capacity (M

W)

Capacity Mix, 2002 & 2012

Nuclear Coal Gas Hydro Wind All Other

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

Utility IPP

New

Capacity (M

W)

Capacity Built 2002-2012

by Ownership Type

Coal Gas Wind & Solar Other

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

Generation (G

Wh)

Generation Mix, 2002 & 2012

Nuclear Coal Gas Hydro Wind All Other
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The mix of capacity by fuel types that have been built and retired between 2002 and 

2012 also varies significantly by type of ownership. Figure 2-15 presents the new capacity built 

during that period, showing that IPPs built the majority of both new wind and solar generating 

capacity, as well as somewhat more natural gas capacity than the traditional utilities built. 

Figure 2-16 presents comparable data for the retired capacity, showing that utilities retired 

more coal and “other” capacity (mostly oil-fired) than IPPs retired, while the IPPs retired more 

natural gas capacity than the utilities retired. The retired gas capacity was primarily (60

percent) steam and combustion turbines.

2.5 Emissions of Greenhouse Gases from Electric Utilities

The burning of fossil fuels, which generates about 69 percent of our electricity 

nationwide, results in emissions of greenhouse gases. The power sector is a major contributor 

of CO2 in particular, but also contributes to emissions of sulfur hexafluoride (SF6), methane 

(CH4), and nitrous oxide (N2O). In 2013, the electricity generation accounted for 38 percent of 

national CO2 emissions. Including both generation and transmission (a source of SF6), the power 

sector accounted for 31 percent of total nationwide greenhouse gas emissions, measured in 

CO2 equivalent. Table 2-5 and Figure 2-17 show the GHG emissions8 from the power sector 

relative to other major economic sectors. Table 2-6 shows the contributions of CO2 and other 

GHGs from the power sector and other major emitting economic sectors. 

 

8

CO2 equivalent data in this section are calculated with the IPCC SAR (Second Assessment Report) GWP potential 

factors.
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Table 2-5. Domestic Emissions of Greenhouse Gases, by Economic Sector (million tons of 

CO2 equivalent)

2002 2013 Change Between '02 and '13

Sector/Source

GHG 

Emissions

% Total 

GHG 

Emissions

GHG 

Emissions

% Total 

GHG 

Emissions

Change in 

Emissions

% Change 

in 

Emissions

% of Total 

Change in 

Emissions

Electric Power Industry 2,550 33% 2,289 31% -260 -10% 64%

Transportation 2,158 28% 1,991 27% -167 -8% 41%

Industry 1,564 20% 1,535 21% -29 -2% 7%

Agriculture 618 8% 647 9% 29 5% -7%

Commercial 402 5% 442 6% 40 10% -10%

Residential 412 5% 413 6% 1 0% 0%

U.S. Territories 58 <1% 38 <1% -19 -33% 5%

Total GHG Emissions 7,762 100% 7,356 100% -406 -5% 100%

Sinks and Reductions -976 -972 4 0%

Net GHG Emissions 6,786 6,384 -402 -6%

Source: EPA, 2015 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013”, Table 2-12. Includes CO2, 

CH4, N2O and SF6 emissions.

Figure 2-17. Domestic Emissions of Greenhouse Gases from Major Sectors, 2002 and 2013

(million tons of CO2 equivalent)

Source: EPA, 2015 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013”, Table 2-12

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2002 2013

G

H

G Emissions (Million Tons C

O2e)

Electric Power Industry Transportation Industry

Agriculture Commercial Residential
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Not Shown: CO2e emissions from U.S. Territories. The amount of CO2 emitted during the 

combustion of fossil fuels varies according to the carbon content and heating value of the fuel 

used. The CO2 emission factors used in IPM v5.14 (same as used in v5.13) are shown in Table 2-

7. Coal has higher carbon content than oil or natural gas, and thus releases more CO2 during 

combustion. Coal emits about 1.7 times as much carbon per unit of energy when burned as 

natural gas does (EPA 2013).

Table 2-6. Greenhouse Gas Emissions from the Electricity Sector (Generation, Transmission 

and Distribution), 2002 and 2013 (million tons of CO2 equivalent)

2002 2013

Change Between '02 and 

'13

Gas/Fuel Type or Source GHG 

Emissions

% of Total 

GHG 

Emissions 

from Power 

Sector

GHG 

Emissions

% of Total 

GHG 

Emissions 

from Power 

Sector

Change in 

GHG 

Emissions

% Change 

in 

Emissions

CO2 2,521 98.9% 2,262 98.8% -259 -10%

Fossil Fuel Combustion 2,505 98.2% 2,248 98.2% -257 -10%

Coal 2,083 81.7% 1,736 75.8% -347 -17%

Natural Gas 337 13.22% 487 21.28% 150 45%

Petroleum 84.7 3.32% 24.7 1.08% -60.0 -71%

Geothermal 0.4 0.02% 0.4 0.02% 0.0 0%

Incineration of Waste 13.0 0.51% 11.1 0.49% -1.9 -14%

Other Process Uses of 

Carbonates

2.9 0.11% 2.4 0.11% -0.4 -15%

CH4 0.4 0.02% 0.4 0.02% 0.0 0%

Stationary 

Combustion*

0.4 0.02% 0.4 0.02% 0.0 0%

Incineration of Waste + + 

N2O 13.7 0.54% 21.4 0.93% 7.7 56%

Stationary 

Combustion*

13.2 0.52% 21.1 0.92% 7.8 59%

Incineration of Waste 0.4 0.02% 0.3 0.01% -0.1 -25%

SF6 14.7 0.57% 5.6 0.25% -9.0 -62%

Electrical Transmission 

and Distribution

14.7 0.57% 5.6 0.25% -9.0 -62%

Total GHG Emissions 2,550 2,289 -260

Source: EPA, 2015 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013”, Table 2-11

* Includes only stationary combustion emissions related to the generation of electricity.

** SF6 is not covered by this rule, which specifically regulates CO2 emissions from combustion.

+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.
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Table 2-7. Fossil Fuel Emission Factors in the EPA Base Case 5.14 IPM Power Sector 

Modeling Application

Fuel Type Carbon Dioxide (lb/MMBtu)

Coal 

Bituminous 202.8 – 209.6

Subbituminous 209.2 – 215.8

Lignite 212.6 – 219.

Natural Gas 117.1

Fuel Oil 

Distillate 161.4

Residual 161.4 – 173.9

Biomass 195

Waste Fuels 

Waste Coal 204.7

Petroleum Coke 225.1

Fossil Waste 321.1

Non-Fossil Waste 0

Tires 189.5

Municipal Solid Waste 91.9

Source: Documentation for IPM Base Case v.5.13, Table 11-5. The emission factors used in Base Case 5.14 are 

identical to the emission factors in IPM Base Case 5.13.

Note: CO2 emissions presented here for biomass account for combustion only and do not reflect emissions from 

initial photosynthesis (carbon sink) or harvesting activities and transportation (carbon source).

2.6 Carbon Dioxide Control Technologies

In the power sector, current approaches available for significantly reducing the CO2

emissions of new fossil fuel combustion sources to meet a 1,400 lb CO2/MWh emission rate 

include the use of: (1) highly efficient coal-fired generation (e.g., modern supercritical or ultrasupercritical steam units) with partial carbon capture and storage (CCS), (2) highly efficient coalfired designs (e.g., modern supercritical or ultra-supercritical steam units) with up to 40 percent

natural gas co-firing, (3), integrated coal gasification combined cycle (IGCC) co-firing with up to 

10 percent natural gas, and/or (4) natural gas combined cycle (NGCC) combustion

turbine/steam-turbine units.

Investment decisions for the optimal choice of the type of new generating capacity 

capable of meeting the 1,400 lb CO2/MWh standard of performance depend in part on the 

intended primary use of new generating capacity. Daily peak electricity demands, involving 

operation for relatively few hours per year, are often most economically met by simple-cycle 
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combustion turbines (CT). Stationary CTs used for power generation can be installed quickly, at 

relatively low capital cost. They can be remotely started and loaded quickly, and can follow 

rapid demand changes. Full-load efficiencies of large current technology CTs are typically 30-33

percent but can be has high as 40 percent or more (high heating value basis), as compared to 

efficiencies of 50 percent or more for new combined-cycle units that recover and use the 

exhaust heat otherwise wasted from a CT. A simple-cycle CT’s lower efficiency causes it to burn 

much more fuel to produce a MWh of electricity than a combined-cycle unit. Thus, when 

burning natural gas its CO2 emission rate per MWh could be 40-60 percent higher than a more 

efficient NGCC unit. 

Base load electricity demand can be met with NGCC generation, coal and other fossilfired steam generation, and IGCC technology, as well as generation from sources that do not 

emit CO2, such as nuclear and hydro. IGCC employs the use of a gasifier to transform fossil fuels 

into synthesis gas (“syngas”) and heat. The syngas is used to fuel a combined cycle generator, 

and the heat from the syngas conversion can produce steam for the steam turbine portion of 

the combined cycle generator. Electricity can be generated through this IGCC process 

somewhat more efficiently than through conventional boiler-steam generators. Additionally, 

with gasification, some of the syngas can be converted into other marketable products such as 

fertilizers and chemical feedstocks for processes to manufacture liquid hydrocarbons (e.g., fuels 

and lubricants), and CO2 can be captured for use in EOR. Figure 2-18 shows the array of 

products (including electricity) and by-products that can be produced in a syngas process.
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Figure 2-18. Marketable products from Syngas Generation

Source: National Energy Technology Lab. Gasifipedia. Available at http://www.netl.doe.gov/research/coal/energysystems/gasification/gasifipedia/co-generation

2.6.1 Carbon Capture and Storage

CCS can be achieved through either pre-combustion or post-combustion capture of CO2

from a gas stream associated with the fuel combusted. Furthermore, CCS can be designed and 

operated for full capture of the CO2 in the gas stream (i.e., above 90 percent) or for partial 

capture (below 90 percent). Post-combustion capture processes remove CO2 from the exhaust 

gas of a combustion system – such as a utility boiler. It is referred to as “post-combustion 

capture” because the CO2 is the product of the combustion of the primary fuel and the capture 

takes place after the combustion of that fuel. This process is illustrated for a pulverized coal 

power plant in Figure 2-19 and described in more detail in the preamble. (See preamble section 

V.D.) For post-combustion, a station's net generating output will be lower due to the energy 

needs of the capture process.
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Figure 2-19. Post-Combustion CO2 Capture for a Pulverized Coal Power Plant

Source: Interagency Task Force on Carbon Capture and Storage 2010

Pre-combustion capture is mainly applicable to IGCC facilities, where the fuel is 

converted into syngas under heat and pressure and some percentage of the carbon contained 

in the syngas is captured before combustion.9For pre-combustion technology, a significant 

amount of energy is needed to gasify the fuel(s). This process is illustrated in Figure 2-20. 

Application of post-combustion CCS with IGCC can be designed to use no water-gas shift, or 

single- or two-stage shift processes, to obtain varying percentages of CO2 removal – from a 

“partial capture” percentage to 90 percent “full capture.” Pre-combustion CCS typically has a 

lesser impact on net energy output than does post-combustion CCS. For more detail on CCS 

technology, see the “Report of the Interagency Task Force on Carbon Capture and Storage” 

(2010).10

 

9

Note that pre-combustion CCS is not considered the best system of emission reduction for this standard. This 

information is provided for background purposes.

10 For more information on the cost and performance of CCS, see http://www.netl.doe.gov/energyanalyses/baseline_studies.html.
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Figure 2-20. Pre-Combustion CO2 Capture for an IGCC Power Plant

Source: Interagency Task Force on Carbon Capture and Storage 2010

Carbon capture technology has been successfully applied since 1930 on several smaller 

scale industrial facilities and more recently in a number of demonstration phase projects 

worldwide for power sector applications. In October 2014, the first commercial-scale coal-fired

capture and storage project for electricity generation began operation at the Boundary Dam 

Power Station in Saskatchewan, Canada. The Boundary Dam Station is owned by the Province 

of Saskatchewan, and operated by SaskPower, a provincially owned corporation that is the 

primary electric utility in the Province. The commercial-scale demonstration project retrofit 

Unit 3 (a 130 MW, coal fired built in 1970, and rebuilt in 2013) at a total cost of approximately 

$1.5 billion (Canadian, or about $1.2 billion U.S.), including a partial subsidy of $240 million 

(Canadian) by the Canadian federal government. The carbon capture system is a postcombustion process designed to capture 90 percent of the CO2 emitted by Unit #3. Retrofitting 

the carbon capture system reduced the capacity of the unit to 110 MW. The majority of the 

captured CO2 is used for an enhanced oil recovery (EOR) project in southern Saskatchewan. The 

portion of the CO2 is being stored in a nearby research and monitoring geological storage 

facility, where the captured CO2 will be injected 3.4 kilometers underground into a sandstone 
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formation located below the major coal field supplying lignite to Unit # 3. The remaining 

captured CO2 will be injected into deep saline formations.

In the United States there are two commercial-scale CCS facilities nearing completion:

1) the Kemper County Carbon Dioxide Capture and Storage Project in Mississippi, and 

2) The W.A. Parish Petra Nova CCA Project near Houston, Texas.

Construction began on the Kemper project in 2010, and the startup is currently 

scheduled for May 2016. The Kemper project is constructing a new 524 MW lignite unit as well 

as a 58 MW natural gas unit. Mississippi Power (a division of Southern Power) is building and 

will operate the Kemper project. The control system is designed to capture 65 percent of the 

CO2 generated by the plant, and is projected to capture 3.5 million tons of CO2 per year. The 

resulting CO2 emission rate is expected to be approximately 800 pounds per MWh produced. 

The current total cost estimate is $5.6 billion, a substantial increase from the original $2.4 

billion estimate.11 The construction has received a $270 million grant from the U.S. Department 

of Energy, and $133 million in investment tax credits from the Internal Revenue Service. The 

captured CO2 will be transported via a 60 mile pipeline and used for EOR projects in mature 

Mississippi oil fields.12

The only other commercial-scale electricity power sector CCS project currently under 

construction in the United States is the W.A. Parish Petra Nova CCS Project near Houston, 

Texas. The Parish Petra project is a 50/50 partnership between NRG Energy (an integrated 

electricity company generating and supplying electricity to 1.6 million customers in Texas) and 

the Nippon Oil and Gas Exploration Company. The Parish project will retrofit a post-combustion 

CCS system on a portion of the flue gas from the existing 610 MW coal fired Unit # 8. The CCS 

system will treat a 240 MW slipstream of the flue gas, and is designed to capture 90 percent of 

the CO2 in the treated flue gas. The capacity rating of Unit # 8 will not be reduced due to the 

CCS project because an 85 MW custom-built natural gas fired combustion turbine cogeneration unit is being built on-site to provide both electricity and steam to the CCS unit. The 

 

11 The Mississippi Public Utilities Staff authorized an independent monitor to conduct a review of the project. The 

findings of the review are provided in a summary report available at: 

http://www.psc.state.ms.us/InsiteConnect/InSiteView.aspx?model=INSITE_CONNECT&queue=CTS_ARCHIVEQ

&docid=328417

12 Carbon Capture and Sequestration Technologies Program at MIT. Accessed 1/23/2015. 

https://sequestration.mit.edu/tools/projects/kemper.html
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total cost of the CCS project is estimated to be $1 billion (including a $167 million grant from 

the U.S. Department of Energy), and the project is expected to extract 1.4 – 1.6 million tons of 

CO2 per year. The construction contract was awarded in July, 2014, and operation is expected 

to begin in early 2016. The CO2 will be piped 85 miles to a reservoir for EOR in the West Ranch 

Oil Field.13

2.7 Geologic and Geographic Considerations for Geologic Sequestration

Geologic sequestration (GS) (i.e., long-term containment of a CO2 stream in subsurface 

geologic formations) is technically feasible and available throughout most of the United States. 

(See generally preamble to final rule at sections V.M and N.) 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 EOR. 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 

GS. The geographic availability of deep saline formations, EOR, and unmineable coal seams is 

shown in Figure 2-21. Estimates of CO2 storage resources by state compiled by the Department 

of Energy’s (DOE) National Carbon Sequestration Database and Geographic Information System 

(NATCARB) and published in DOE’s 2012 United States Carbon Utilization and Storage Atlas 

(discussed below) are provided in Table 2-8.

 

13 U.S. DOE (2010) “Recovery Act: W.A. Parish Post-Combustion CO2 Capture and Sequestration Project”. 

http://www.netl.doe.gov/research/proj?k=FE0003311 Accessed 1/23/2015
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Figure 2-21 Geologic Sequestration in the Continental United States

Sources: EPA Greenhouse Gas Reporting Program; Department of Energy, NATCARB; Department of 

Transportation, National Pipeline Management System.
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Table 2-8. Total CO2 Storage Resource (U.S. Department of Energy (DOE) National Energy 

Technology Laboratory (NETL))

14

Million Tons

State Low Estimate High Estimate

ALABAMA 135,022 765,422 

ALASKA 9,524 21,771 

ARIZONA 143 1,290 

ARKANSAS 6,812 70,184 

CALIFORNIA 37,357 463,665 

COLORADO 41,458 393,734 

CONNECTICUT not assessed by DOE-NETL not assessed by DOE-NETL 

DELAWARE 44 44 

DISTRICT OF COLUMBIA not assessed by DOE-NETL not assessed by DOE-NETL 

FLORIDA 113,251 611,793 

GEORGIA 160,210 175,322 

HAWAII not assessed by DOE-NETL not assessed by DOE-NETL 

IDAHO 44 430 

ILLINOIS 11,045 128,772 

INDIANA 35,296 75,189 

IOWA 11 55 

KANSAS 11,993 95,173 

KENTUCKY 3,219 8,433 

LOUISIANA 186,842 2,319,238 

MAINE not assessed by DOE-NETL not assessed by DOE-NETL 

MARYLAND 2,050 2,127 

MASSACHUSETTS not assessed by DOE-NETL not assessed by DOE-NETL 

(Continued on next page)

 

14 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of 

Fossil Energy, National Energy Technology Laboratory (NETL).
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Table 2-8. Total CO2 Storage Resource (DOE-NETL), cont.

Million Tons*

State Low Estimate High Estimate

MICHIGAN 20,999 52,040 

MINNESOTA not assessed by DOE-NETL not assessed by DOE-NETL 

MISSISSIPPI 159,846 1,306,270 

MISSOURI 11 187 

MONTANA 93,233 1,006,100 

NEBRASKA 26,202 124,826 

NEVADA not assessed by DOE-NETL not assessed by DOE-NETL 

NEW HAMPSHIRE not assessed by DOE-NETL not assessed by DOE-NETL 

NEW JERSEY 0 0 

NEW MEXICO 47,135 395,828 

NEW YORK 5,115 5,115 

NORTH CAROLINA 1,477 20,271 

NORTH DAKOTA 73,954 162,569 

Offshore Federal Only 539,956 7,098,976 

OHIO 14,837 14,837 

OKLAHOMA 62,777 269,570 

OREGON 7,507 103,286 

PENNSYLVANIA 24,361 24,361 

RHODE ISLAND not assessed by DOE-NETL not assessed by DOE-NETL 

SOUTH CAROLINA 33,180 37,677 

SOUTH DAKOTA 9,656 26,489 

TENNESSEE 474 4,255 

TEXAS 489,205 4,772,925 

UTAH 28,076 265,558 

VERMONT not assessed by DOE-NETL not assessed by DOE-NETL 

VIRGINIA 485 3,208 

WASHINGTON 40,367 547,550 

WEST VIRGINIA 18,353 18,353 

WISCONSIN not assessed by DOE-NETL not assessed by DOE-NETL

WYOMING 80,127 754,917 

U.S. Total 2,531,653 22,147,811 

* States with a “zero” value represent estimates of minimal CO2 storage resource. States that have not yet been 

assessed by DOE-NETL have been identified.
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2.7.2 Availability of Geologic Sequestration in Deep Saline Formations

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 NATCARB system

using volumetric models and published in a Carbon Utilization and Storage Atlas.

15 DOE 

estimates that areas of the United States with appropriate geology have a sequestration 

potential of at least 2,200 billion tons of CO2 in deep saline formations. According to DOE, 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.16 The USGS estimates a mean of 3,300 billion tons of subsurface CO2 sequestration 

potential, including saline and oil and gas reservoirs, across the basins studied in the United 

States. As shown in Figure 2-21, there are 39 states for which onshore and offshore deep saline 

formation storage capacity has been identified.

17

 

2.7.3 Availability of CO2 Storage via Enhanced Oil Recovery 

Although 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 

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.18 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 that can be used for 

deployment of CCS across geographically diverse areas.

 

15 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S. Department of Energy, Office 

of Fossil Energy, National Energy Technology Laboratory (NETL).

16 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment 

of geologic carbon dioxide storage resources—Results: U.S. Geological Survey Circular 1386, p. 41, 

http://pubs.usgs.gov/circ/1386/. 

17 Alaska is not shown in the figure; it has deep saline formation storage capacity, geology amenable to EOR 

operations, and potential GS capacity in unmineable coal.

18 Koottungal, Leena, 2014, 2014 Worldwide EOR Survey, Oil & Gas Journal, Volume 112, Issue 4, April 7, 2014 

(corrected tables appear in Volume 112, Issue 5, May 5, 2014).
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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 2-21).

19

 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 

currently used include Alabama, Colorado, Louisiana, Michigan, Mississippi, New Mexico, 

Oklahoma, Texas, Utah, and Wyoming. 

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.20 

According to data reported to the EPA’s Greenhouse Gas Reporting Program (GHGRP), 

approximately 66 million tons of CO2 were supplied to EOR in the United States in 2013.21

Approximately 70 percent of this total CO2 supplied was produced from natural (geologic) CO2

sources, and approximately 30 percent was captured from anthropogenic sources.22

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.23 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 20 billion tons of anthropogenic CO2 and increase total oil production 

by 67 billion barrels. The availability of anthropogenic CO2 in areas outside of current sources 

could drive new EOR projects by making more CO2 locally available.

 

19 The distance of 100 kilometers reflects the assumptions in the DOE-NETL cost estimates. 

20 Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F P. “Evaluation of CO2 trapping mechanisms at the 

SACROC northern platform, Permian basin, Texas, site of 35 years of CO2 injection.” American Journal of 

Science 310. (2010): 282-324.

21 Greenhouse Gas Reporting Program, data reported as of August 18, 2014.

22Ibid.

23 “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.
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2.8 State Policies on GHG and Clean Energy Regulation in the Power Sector

Several states have also established emission performance standards or other measures 

to limit emissions of GHGs from new EGUs that are comparable to or more stringent than this 

rulemaking. 

In 2003, then-Governor George Pataki sent a letter to his counterparts in the Northeast 

and Mid-Atlantic inviting them to participate in the development of a regional cap-and-trade 

program addressing power plant CO2 emissions. This program, known as the Regional 

Greenhouse Gas Initiative (RGGI), began in 2009 and sets a regional CO2 cap for participating 

states. The currently participating states include: Connecticut, Delaware, Maine, Maryland, 

Massachusetts, New Hampshire, New York, Rhode Island, and Vermont. The cap covers CO2

emissions from all fossil-fired EGUs greater than 25 MW in participating states, and limits total 

emissions to 91 million tons in 2014. The 2014 emissions cap is a 51 percent reduction below 

the initial cap in 2009 to 2011 of 188 million tons. This emissions budget is reduced 2.5 percent

annually from 2015 to 2020. RGGI CO2 allowances are sold in a quarterly auction. RGGI

conducted their 27th quarterly allowance auction in March, 2015 the market clearing price was 

$5.41 per ton of CO2 for current allowances, which was a record high price (the February ’15 

price of $5.21 was the previous record). A total of allowances for 15.3 million tons were sold in 

the March 2015 auction, well below the record of 38.7 million tons sold in June 2013 for $3.21

per ton.

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 -net.

In 2006, Governor Schwarzenegger also signed into law Assembly Bill 32, the Global 

Warming Solutions Act of 2006. This act includes a multi-sector GHG cap-and-trade program 

which covers approximately 85 percent of the state GHG emissions. EGUs are included in phase 

I of the program, which began in 2013. Phase II begins in 2020 and includes upstream sources. 

The cap is based on a 2 percent reduction from total 2012 expected emissions, and declines 2 

percent annually through 2014, then 3 percent each year until 2020. The AB32 cap and trade 

program began functioning in 2011, and functioning market is now operating on the NYMEX 

futures commodity market. The final 2014 market price for carbon allowances was $11.23/ton 
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of carbon. On April 17, 2015 the 2015 allowance futures price was $11.48/ton, and the spot 

price was $11.30/ton.

In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, “Base

load Electric Generation Performance” 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-net. In 2013 the State of Washington 

revised24 the emission limit to 970 lb CO2/MWh-net based on a survey of available NGCC 

generation units commercially available in the United States.

In 1997, Oregon required a new base load gas fired power plants to meet a CO2

emission standard that was 17 percent below the most efficient NGCC unit operating in the 

United States. In 2000 Oregon established that the effective 17 percent below most efficient 

was 675 lb CO2/MWh-net 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-net regardless of fuel type, 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. Natural gas- and petroleum 

distillate-fired facilities that are primarily used to serve peak demand or to integrate energy 

from renewable resources are specifically exempted from the performance standard.

In August 2011, New York Governor Cuomo signed the Power NY Act of 2011. 

Implementing regulations established CO2 emission standards for new and modified electric 

generators greater than 25 MW. The standards vary based on the type of facility: base load 

facilities must meet a CO2 standard of 925 lb/MWh-net or 120 lb/MMBtu, and peaking facilities 

must meet a CO2 standard of 1,450 lb/MWh-net or 160 lb/MMBtu.

Several other states have enacted CO2 regulations affecting EGUs that do not set 

emission limits, but set other regulatory requirements limiting CO2 emissions from EGUs. For 

example, Montana enacted a law in 2007 requiring the Public Service Commission to limit 

approvals of new equity interests in or leases of a facility used to generate coal-based electricity 

 

24 Washington Department of Commerce, 2013. “Greenhouse Gas Emission Performance Standard for Baseload 

Electric Generation.” Available at http://www.commerce.wa.gov/Documents/Concise-Expl-Stmt-WSR-13-06-

074.pdf.
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to facilities that capture and sequester at least half of their CO2 emissions. Minnesota enacted 

the Next Generation Energy Act in 2007 requiring increases in power sector greenhouse gas 

emissions from any new large coal energy facilities built in Minnesota or the import of 

electricity from such a facility located out of state to be offset by equivalent emission 

reductions. New Mexico enacted legislation in 2007 authorizing tax credits and cost recovery 

incentives for qualifying coal-fired facilities. To qualify, plants must capture and store emissions 

so that they emit less than 1,100 lb CO2/MWh, among other requirements.

Additionally, most states have implemented Renewable Portfolio Standards (RPS), or 

Renewable Electricity Standards (RES). These programs are designed to increase the renewable 

share of a state’s total electricity generation. Currently 29 states, the District of Columbia and 

Guam have enforceable RPS or other mandatory renewable capacity policies, and 8 states, 

Puerto Rico and Guam have voluntary goals.25 These programs vary widely in structure, 

enforcement, and scope. 

2.9 Revenues and Expenses

Due to lower retail electricity sales, total utility operating revenues declined in 2012 to 

$271 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008 

levels in 2012, operating expenses were appreciably lower and as a result, net income also rose 

in comparison to 2008 (see Table 2-9). Recent economic events have put downward pressure 

on electricity demand, thus dampening electricity prices and consumption (utility revenues), 

but have also reduced the price and cost of fossil fuels and other expenses. In 2012 electricity 

generation was 1.28 percent below the generation in 2011, and has declined in four of the past 

five years.

Table 2-9 shows that investor-owned utilities (IOUs) earned income of about 13.0 

percent compared to total revenues in 2012. The 2012 return on revenue was the third highest 

year for the period 2002 to 2012 (average: 11.9 percent, range: 10.6 percent to 13.32 percent).

Table 2-9. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities 

for 2002, 2008 and 2012 (nominal $millions) 

2002 2008 2012

Utility Operating Revenues 219,609 298,962 270,912

Electric Utility 200,360 266,124 249,166

 

25 Clean Energy States Alliance 2013
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Other Utility 19,250 32,838 21,745

Utility Operating Expenses 189,062 267,263 235,694

Electric Utility 171,604 236,572 220,722

Operation 116,660 175,887 152,379

Production 90,715 140,974 111,714

Cost of Fuel 24,149 47,337 38,998

Purchased Power 58,810 84,724 54,570

Other 7,776 8,937 18,146

Transmission 3,560 6,950 7,183

Distribution 3,117 3,997 4,181

Customer Accounts 4,168 5,286 5,086

Customer Service 1,820 3,567 5,640

Sales 264 225 221

Admin. and 

General

13,018 14,718 18,353

Maintenance 10,861 14,192 15,489

Depreciation 16,199 19,049 23,677

Taxes and Other 26,716 26,202 29,177

 Other Utility 17,457 30,692 14,972

Net Utility Operating Income 30,548 31,699 35,218

Source: Table 8.3, EIA Electric Power Annual, 2012

Note: These data do not include information for public utilities, nor for IPPs.

2.10 Natural Gas Market

The natural gas market in the United States has historically experienced significant price 

volatility from year to year and between seasons, can undergo major price swings during shortlived weather events (such as cold snaps leading to short-run spikes in heating demand), and 

has seen a dramatic shift since 2008 due to increased production from shale formations. Over 

the last decade, the annual average nominal price of gas delivered to the power sector peaked 

in 2008 at $9.02/MMBtu and has since fallen dramatically to a low of $3.42/MMBtu in 2012. 

During that time, the daily price26 of natural gas reached as high as $18.48/MMBtu and as low 

as $2.03/MMBtu. Adjusting for inflation using the GDP implicit price deflator, in 2011 dollars

the annual average price of natural gas delivered to the power sector peaked at $9.38/MMBtu 

in 2008 and has fallen to a low of $3.36/MMBtu in 2012. The annual natural gas prices in both 

 

26 Henry Hub daily prices. Henry Hub is a major gas distribution hub in Louisiana; Henry Hub prices are generally 

seen as the primary metric for national gas prices for all end uses. The price of natural gas delivered to 

electricity generation differs substantially in different regions of the country, and can be higher or lower than 

the Henry Hub national benchmark price.
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nominal and real (2011$) terms are shown in Figure 2-22. A comparison of the trends in the real 

price of natural gas with the real prices of delivered coal and oil is shown in Figure 2-23. Figure 

2-23 shows that while the real price of coal and oil increased from 2002 to 2012 (+54 percent

and +203 percent respectively), the real price of natural gas declined by 22 percent in the same 

period. Most of the decline in real natural gas prices occurred between 2008 (the peak price 

year) and 2012, during which real gas prices declined by 64 percent while coal and oil prices 

both increased by 9 percent in the same period. The sharp decline in natural gas prices from 

2008 to 2012 was primarily caused by the rapid increase in natural gas production from shale 

formations.

Figure 2-22. Nominal and Real (2011$) Prices of Natural Gas Delivered to the Power Sector 

($/MMBtu)

Source: http://www.eia.gov/totalenergy/data/monthly/#prices. Downloaded 2/15/2015.

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

2002 2004 2006 2008 2010 2012

Natural Gas Prices ($/m

mBT

U)

Nominal Price Real Price
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Figure 2-23. Relative Change in Real (2011$) Prices of Fossil Fuels Delivered to the Power 

Sector ($/MMBtu)

Source: http://www.eia.gov/totalenergy/data/monthly/#prices. Downloaded 2/15/2015.

Current and projected natural gas prices are considerably lower than the prices 

observed over the past decade, largely due to advances in hydraulic fracturing and horizontal 

drilling techniques that have opened up new shale gas resources and substantially increased 

the supply of economically recoverable natural gas. According to the U.S. Energy Information 

Administration’s Annual Energy Outlook 2012 (AEO 2012) (EIA 2012):

Shale gas refers to natural gas that is trapped within shale formations. Shales are finegrained sedimentary rocks that can be rich sources of petroleum and natural gas. Over 

the past decade, the combination of horizontal drilling and hydraulic fracturing has 

allowed access to large volumes of shale gas that were previously uneconomical to 

produce. The production of natural gas from shale formations has rejuvenated the 

natural gas industry in the United States.

The EIA’s AEO 2014 estimates that the United States possessed 2,266 trillion cubic feet 

(Tcf) of technically recoverable dry natural gas resources as of January 1, 2012. Proven reserves 

make up 15 percent of the technically recoverable total estimate, with the remaining 85 

percent from unproven reserves. Natural gas from proven and unproven shale resources 

accounts for 611 Tcf of this resource estimate. 

-50%

0%

50%

100%

150%

200%

250%

2002 2004 2006 2008 2010 2012

Coal Oil Gas Average
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Many shale formations, especially the Marcellus27, are so large that only small portions 

of the entire formations have been intensively production-tested. Furthermore, estimates from 

the Marcellus and other emerging fields with few wells already drilled are likely to shift 

significantly over time as new geological and production information becomes available. 

Consequently, there is some uncertainty in estimate of technically recoverable resources, and it 

is regularly updated as more information is gained through drilling and production. 

At the 2012 rate of U.S. consumption (about 25.6 Tcf per year), 2,266 Tcf of natural gas 

is enough to supply nearly 90 years of use. The AEO 2014 estimate of the shale gas resource 

base is modestly higher than the AEO 2012 estimate (2,214 Tcf) of shale gas production, driven 

by lower drilling costs and continued drilling in shale plays with high concentrations of natural 

gas liquids and crude oil, which have a higher value in energy equivalent terms than dry natural 

gas.28

EIA’s projections of natural gas conditions did not change substantially in AEO 2014 

from either the AEO 2012 or 2013, and EIA is continues to forecast abundant reserves 

consistent with the above findings. Recent historical data reported to EIA is also consistent 

with these trends, with 2014 being the highest year on record29 for domestic natural gas 

production.30

 

27 The Marcellus formation, underlying most of Pennsylvania and West Virginia, along with portions of New York 

and Ohio, in 2014 produced 36 percent of the U.S. total natural gas extracted from shale formations.

28 For more information, see: http://www.eia.gov/forecasts/archive/aeo11/IF_all.cfm#prospectshale; 

http://www.eia.gov/energy_in_brief/about_shale_gas.cfm

29 The total dry gas production in 2012 from the lower 48 states, including both onshore and offshore production, 

was 23.97 Tcf, a 1.5 percent increase from 2013 and a 7.9 percent total increase from 2011

30 http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2014&subject=8-AEO2014&table=72-

AEO2014®ion=0-0&cases=ref2014-d102413a
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2.11 References

Advanced Resources International. Improving Domestic Energy Security and Lowering CO2

Emissions with “Next Generation” CO2-Enhanced Oil Recovery (CO2-EOR). 2011. Available 

online at: http://www.netl.doe.gov/research/energyanalysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-04a505a19185.

Clean Energy States Alliance (CESA). The State of State Renewable Portfolio Standards. June 

2013. Available online at http://www.cesa.org/assets/2013-Files/RPS/State-of-StateRPSs-Report-Final-June-2013.pdf

Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F P. Evaluation of CO2 trapping 

mechanisms at the SACROC northern platform, Permian basin, Texas, site of 35 years of 

CO2 injection. American Journal of Science 310. (2010): 282-324.

Independent Monitor’s Prudency Evaluation Report for the Kemper County IGCC Project. April 

15, 2014. Available online at: 

http://www.psc.state.ms.us/InsiteConnect/InSiteView.aspx?model=INSITE_CONNECT&q

ueue=CTS_ARCHIVEQ&docid=328417.

Interagency Task Force on Carbon Capture and Storage. Report of the Interagency Task Force on 

Carbon Capture and Storage. August 2010. Available online at: 

http://www.epa.gov/climatechange/downloads/CCS-Task-Force-Report-2010.pdf. 

Intergovernmental Panel on Climate Change. Climate Change 2001: The Scientific Basis. 2001. 

Available online at: 

http://www.grida.no/publications/other/ipcc_tar/?src=/climate/ipcc_tar/wg1/218.htm. 

International Energy Agency (IEA). Tracking Clean Energy Progress 2013. Input to the Clean 

Energy Ministerial. 2013. Available online at: http://www.iea.org/etp/tracking/.

Koottungal, Leena. 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).

National Energy Technology Laboratory (NETL). Reducing CO2 Emissions by Improving the 

Efficiency of Existing Coal-fired Power Plant Fleet. July 2008. Available online at: 

http://www.netl.doe.gov/energy-analyses/pubs/CFPP%20Efficiency-FINAL.pdf.

National Energy Technology Laboratory (NETL). The United States 2012 Carbon Utilization and 

Storage Atlas, Fourth Edition. 2012. Available online at: 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlasIV/.

National Energy Technology Laboratory (NETL). Energy Analyses: Cost and Performance 

Baselines for Fossil Energy Plants. 2013. Available online at: 

http://www.netl.doe.gov/energy-analyses/baseline_studies.html.
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Pacific Northwest National Laboratory (PNNL). An Assessment of the Commercial Availability of 

Carbon Dioxide Capture and Storage Technologies as of June 2009. June 2009. Available 

online at: http://www.pnl.gov/science/pdf/PNNL-18520_Status_of_CCS_062009.pdf.

U.S. Energy Information Administration (U.S. EIA). Carbon Dioxide Emissions from the 

Generation of Electric Power in the United States. July 2000. Available online at: 

ftp://ftp.eia.doe.gov/environment/co2emiss00.pdf.

U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2003. 2003. Available 

online at: http://www.eia.gov/electricity/annual/archive/03482003.pdf. 

U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2009. 2009. Available 

online at: http://www.eia.gov/electricity/annual/archive/03482009.pdf. 

U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2011. 2013. Available 

online at: http://www.eia.gov/electricity/annual/.

U.S. Energy Information Administration (U.S. EIA). “Status of Electricity Restructuring by State.” 

2010a. Available online at: 

http://www.eia.gov/cneaf/electricity/page/restructuring/restructure_elect.html.

U.S. Energy Information Administration (U.S. EIA). AEO 2010 Retrospective Review. 2010b. 

Available online at: http://www.eia.gov/forecasts/aeo/retrospective/.

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010c. 

Available online at: http://www.eia.gov/oiaf/archive/aeo10/index.html. 

U.S. Energy Information Administration (U.S. EIA). Annual Energy Review 2010. 2010d. Available 

online at: http://www.eia.gov/totalenergy/data/annual/pdf/aer.pdf.

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2011. 2011. Available 

online at: http://www.eia.gov/forecasts/archive/aeo11/. 

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2012 (Early Release). 

2012. Available online at: http://www.eia.gov/forecasts/aeo/.

U.S. Energy Information Administration (U.S. EIA). Today in Energy: Most states have 

Renewable Portfolio Standards. 2012a. Available online at: 

http://www.eia.gov/todayinenergy/detail.cfm?id=4850.

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available 

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

U.S. Energy Information Administration (U.S. EIA). Monthly Energy Review, April 2015. 2015. 

Available online at: http://www.eia.gov/totalenergy/data/monthly/.
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U.S. Environmental Protection Agency (U.S. EPA). Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990–2011. April 2013. Available online at: 

http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-

Main-Text.pdf.

U.S. Geological Survey (USGS) Carbon Dioxide Storage Resources Assessment Team. National 

assessment of geologic carbon dioxide storage resources – Results: U.S. Geological 

Survey Circular 1386. Available online at: http://pubs.usgs.gov/circ/1386/. 
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CHAPTER 3

BENEFITS OF REDUCING GREENHOUSE GAS EMISSIONS AND OTHER POLLUTANTS

This rule is designed to set emission limits for carbon dioxide (CO2),thereby limiting 

potential increases in future emissions and atmospheric CO2 concentrations. This will reduce 

the risk of adverse effects of climate change. As discussed in Chapter 4, the U.S. Environmental 

Protection Agency (EPA) anticipates negligible CO2 emission changes resulting from the rule

relative to baseline conditions, due to market baseline market conditions. The final standards 

provide the benefit of regulatory certainty that any new coal-fired power plant must limit its 

CO2 emissions to a level reflecting the performance of a highly efficient super critical pulverized

coal (SCPC) unit utilizing post-combustion partial carbon capture and storage (CCS). As 

explained in preamble section V.P.1.b, there are documented instances of project developers 

abandoning projects using CCS due to this lack of regulatory certainty. In addition, the history 

of regulatory actions has shown that emission standards that are based on the performance of 

advanced control equipment lead to increased use of that control equipment, and that the 

absence of a requirement stifles technology development. (See preamble section V.P.1.b.)

This chapter summarizes the adverse effects on public health and public welfare from 

the emissions of CO2, which is a well-mixed greenhouse gas. This form of air pollution was 

determined by the EPA in the 2009 Endangerment Finding to endanger public health and

welfare.1The major assessments by the U.S. Global Change Research Program (USGCRP), the 

Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) 

served as the primary scientific bases for the Endangerment Finding. A discussion of climate 

science findings from newer assessments can be found in the Preamble. This chapter also 

provides a general discussion about how the climate-related and human health benefits of 

emissions reductions are estimated. These valuation approaches are used in Chapter 5 to 

quantify and monetize the relative differences in emissions between electric generating 

technologies that may be constructed in the future.

3.1 Overview of Climate Change Impacts from GHG Emissions

Through the implementation of CAA regulations, the EPA addresses the negative 

externalities caused by air pollution. The preamble to the final rule summarizes the public 

 

1

Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, 

74 Fed. Reg. 66,496 (Dec. 15, 2009). See also Coalition for Responsible Regulation v. EPA, 684 F. 3d at 119-126, 

upholding the Endangerment Finding in all respects, and noting that “[t]he body of scientific evidence 

marshaled by EPA in support of the Endangerment Finding is substantial” (id. at 120).
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health and public welfare impacts that were detailed in the 2009 Endangerment Finding. For 

health, these include the increased likelihood of heat waves, negative impacts on air quality, 

more intense hurricanes, more frequent and intense storms and heavy precipitation, and 

impacts on infectious and waterborne diseases. For welfare, these include reduced water 

supplies in some regions, increased water pollution, increased occurrences of floods and 

droughts, rising sea levels and damage to coastal infrastructure, increased peak electricity 

demand, changes in ecosystems, and impacts on indigenous communities. 

The preamble also summarizes new scientific assessments and recent climatic 

observations. Major scientific assessments released since the 2009 Endangerment Finding have 

further improved scientific understanding of climate change, and provide even more evidence 

that GHG emissions endanger public health and welfare for current and future generations. The 

Third National Climate Assessment (NCA3), in particular, assessed the impacts of climate 

change on human health in the United States, finding that, Americans 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 IPCC reported similar conclusions in its Fifth Assessment Report, finding that it is likely that 

adverse health impacts related to heat exposure are already being exacerbated by climate 

change and that, if unabated, climate change will lead to a greater risk of morbidity and 

mortality due to more intense heat waves, undernutrition, and increased prevalence of foodand water-borne illnesses. These assessments also detail the risks to vulnerable groups such as 

children, the elderly and low income households. Furthermore, the assessments present an 

improved understanding of the impacts of climate change on public welfare, improved 

projections of future warming over the next century, higher projections of future sea level rise 

than had been previously estimated due in part to improved understanding of the Antarctic and 

Greenland ice sheets, more detailed description of U.S. impacts based on the National Climate 

Assessment, improved understanding of changes in rainfall and droughts, and new assessments 

of the impacts of climate change on permafrost and ocean acidification. The impacts of GHG 

emissions will be realized worldwide, independent upon their location of origin, and impacts 

outside of the United States will produce consequences relevant to the United States. 

3.2 Social Cost of Carbon

The social cost of carbon (SC-CO2) is a metric that estimates the monetary value of 

impacts associated with marginal changes in CO2 emissions in a given year. It includes a wide 

range of anticipated climate impacts, such as net changes in agricultural productivity and 

human health, property damage from increased flood risk, and changes in energy system costs,
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such as reduced costs for heating and increased costs for air conditioning. It is typically used to 

assess the avoided damages as a result of regulatory actions (i.e., benefits of rulemakings that 

lead to an incremental reduction in cumulative global CO2 emissions). This section discusses the 

development of the SC-CO2 estimates and the analyses in Chapter 5 apply the SC-CO2 estimates 

to illustrate the value to society of the difference in CO2 emissions among different generation 

technologies. 

The SC-CO2 estimates used in these analyses were developed over many years, using the 

best science available, and with multiple opportunities for input from the public, which is 

discussed further below.

2

 Specifically, an interagency working group (IWG) that included the 

EPA and other executive branch agencies and offices used three integrated assessment models 

(IAMs) to develop the SC-CO2 estimates and recommended four global values for use in 

regulatory analyses. As noted in the Government Accountability Office’s 2014 review, this 

interagency working group (1) used consensus-based decision-making, (2) relied on existing 

academic literature and modeling, and (3) took steps to disclose limitations and incorporate 

new information by considering public comments and revising the estimates as updated 

research became available. 

The SC-CO2 estimates were first released in February 2010 and updated in 2013 using 

new versions of each IAM. As discussed further below, the IWG published two minor 

corrections to the SC-CO2 estimates in July 2015. These estimates are published in the Technical 

Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact 

Analysis Under Executive Order 12866 (“current SC-CO2 TSD”) and henceforth we refer to them 

as the “SC-CO2 estimates.” 

The SC-CO2 estimates were developed using an ensemble of the three most widely cited 

integrated assessment models in the economics literature with the ability to estimate the SCCO2. A key objective of the IWG was to draw from the insights of the three models while 

respecting the different approaches to linking GHG emissions and monetized damages taken by 

modelers in the published literature. After conducting an extensive literature review, the 

interagency group selected three sets of input parameters (climate sensitivity, socioeconomic 

and emissions trajectories, and discount rates) to use consistently in each model. All other 

model features were left unchanged, relying on the model developers’ best estimates and 

 

2

Ample opportunity for public comment on all aspects of the SC-CO2 estimates has been provided, including the 

estimates selected by the IWG in 2009 and in the numerous proposed rules issued by the EPA and other federal 

agencies between February 2010 and May 2013 that made use of the estimates.
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judgments, as informed by the literature. Specifically, a common probability distribution for the 

equilibrium climate sensitivity parameter, which informs the strength of climate’s response to 

atmospheric GHG concentrations, was used across all three models. In addition, a common 

range of scenarios for the socioeconomic parameters and emissions forecasts were used in all 

three models. Finally, the marginal damage estimates from the three models were estimated 

using a consistent range of discount rates, 2.5, 3.0, and 5.0 percent. See the 2010 SC-CO2 TSD 

for a complete discussion of the methods used to develop the estimates and the key 

uncertainties, and the current SC-CO2 TSD for the latest estimates. 

The SC-CO2 estimates represent global measures because of the distinctive nature of the 

climate change, which is highly unusual in at least three respects. First, emissions of most GHGs 

contribute to damages around the world independent of the country in which they are emitted. 

The SC-CO2 must therefore incorporate the full (global) damages caused by GHG emissions to 

address the global nature of the problem. Second, the U.S. operates in a global and highly 

interconnected economy, such that impacts on the other side of the world can affect our 

economy. This means that the true costs of climate change to the U.S. are larger than the 

direct impacts that simply occur within the U.S. Third, climate change represents a classic public 

goods problem because each country’s reductions benefit everyone else and no country can be 

excluded from enjoying the benefits of other countries’ reductions, even if it provides no 

reductions itself. In this situation, the only way to achieve an economically efficient level of 

emissions reductions is for countries to cooperate in providing mutually beneficial reductions 

beyond the level that would be justified only by their own domestic benefits. In reference to 

the public good nature of mitigation and its role in foreign relations, thirteen prominent 

academics noted that these “are compelling reasons to focus on a global [SC-CO2]” in a recent 

article on the SC-CO2 (Pizer et al., 2014). In addition, as noted in OMB’s Response to Comments 

on the SC-CO2, there is no bright line between domestic and global damages. Adverse impacts 

on other countries can have spillover effects on the United States, particularly in the areas of 

national security, international trade, public health and humanitarian concerns.3

The 2010 SC-CO2 TSD noted a number of limitations to the SC-CO2 analysis, including the 

incomplete way in which the integrated assessment models capture catastrophic and non-

 

3

See: (1) Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean 

Air Act, 74 Fed. Reg. 66,496, 66,535 (Dec. 15, 2009) and (2) National Research Council: Climate and Social 

Stress: Implications for Security Analysis. Washington, DC: The National Academies Press, 2013. 
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catastrophic impacts, their incomplete treatment of adaptation and technological change, 

uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding 

risk aversion. Current integrated assessment models do not assign value to all of the important 

physical, ecological, and economic impacts of climate change recognized in the climate change 

literature due to a lack of precise information on the nature of damages and because the 

science incorporated into these models understandably lags behind the most recent research.4

The limited amount of research linking climate impacts to economic damages makes the 

modeling exercise even more difficult. These individual limitations do not all work in the same 

direction in terms of their influence on the SC-CO2 estimates, though taken together they 

suggest that the SC-CO2 estimates are likely conservative. In particular, the IPCC Fourth 

Assessment Report (2007), which was the most current IPCC assessment available at the time 

of the IWG’s 2009-2010 review, concluded that “It is very likely that [SC-CO2 estimates] 

underestimate the damage costs because they cannot include many non-quantifiable impacts.” 

Since then, the peer-reviewed literature has continued to support this conclusion. For example, 

the IPCC Fifth Assessment report observed that SC-CO2 estimates continue to omit various 

impacts that would likely increase damages. The 95th percentile estimate was included in the 

recommended range for regulatory impact analysis to address these concerns.

The EPA and other agencies have continued to consider feedback on the SC-CO2

estimates from stakeholders through a range of channels, including public comments on this 

rulemaking and others that use the SC-CO2 in supporting analyses and through regular 

interactions with stakeholders and research analysts implementing the SC-CO2 methodology 

used by the interagency working group. The SC-CO2 comments received on this rulemaking 

covered a wide range of topics including the technical details of the modeling conducted to 

develop the SC-CO2 estimates, the aggregation and presentation of the SC-CO2 estimates, and 

the process by which the SC-CO2 estimates were derived. The EPA Response to Comments 

document provides a summary and response to the SC-CO2 comments submitted to this 

rulemaking.

Many of the comments the EPA received in this proceeding mirrored those that OMB 

received in response to a separate request for public comment on the approach used to 

 

4

Climate change impacts and SCC modeling is an area of active research. For example, see: (1) Howard, Peter, 

“Omitted Damages: What’s Missing from the Social Cost of Carbon.” March 13, 2014, 

http://costofcarbon.org/files/Omitted_Damages_Whats_Missing_From_the_Social_Cost_of_Carbon.pdf; and 

(2) Electric Power Research Institute, “Understanding the Social Cost of carbon: A Technical Assessment,” 

October 2014, www.epri.com.
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develop the estimates and the EPA has carefully considered those comments and responses 

here. After careful evaluation of the full range of comments submitted to OMB, the IWG 

continued to recommend the use of these SC-CO2 estimates in regulatory impact analysis. The 

IWG remains committed to ensuring that the SC-CO2 estimates continue to reflect the best 

available scientific and economic information on climate change. In light of this commitment, 

the IWG announced plans to obtain expert independent advice from the National Academies of 

Sciences, Engineering, and Medicine.

5

The Academies process will be informed by the public 

comments received and focus on the technical merits and challenges of potential approaches to 

improving the SC-CO2 estimates in future updates.

OMB also has published a revised TSD that informed our analysis here. The revision to 

the TSD is limited to two minor technical corrections to the current estimates. One technical 

correction addressed an inadvertent omission of climate change damages in the last year of 

analysis (2300) in one model and the second addressed a minor indexing error in another 

model. On average the revised recommended SC-CO2 estimates are one dollar less than the 

mean SC-CO2 estimates reported in the November 2013 revision to the May 2013 TSD. The 

change in the estimates associated with the 95th percentile estimates when using a 3 percent

discount rate is slightly larger, as those estimates are heavily influenced by the results from the 

model that was affected by the indexing error.6

The EPA has examined the minor technical corrections in the revised TSD and the public 

comments—including those submitted to OMB’s separate SC-CO2 comment process—here as 

part of its consideration of whether and how to use SC-CO2 estimates in this proceeding. Based 

on this examination, the EPA concurs with the consensus-based interagency working group, of 

which it is an active member, and finds that it is reasonable, and scientifically appropriate, to 

use the current SC-CO2 estimates for purposes of analysis here. 

The four SC-CO2 estimates the EPA is selecting to use in its analysis here are as follows: 

$13, $41, $62, and $120 per short ton of CO2 emissions in the year 2022 (2011$).7 The first 

 

5

See https://www.whitehouse.gov/blog/2015/07/02/estimating-benefits-carbon-dioxide-emissions-reductions6

The TSDs report SC-CO2 estimates in dollars per metric ton. The impact of the correction does not change with 

the conversion to short tons.

6

The TSDs report SC-CO2 estimates in dollars per metric ton. The impact of the correction does not change with 

the conversion to short tons.

7

The current version of the TSD is available at http://www.whitehouse.gov/sites/default/files/omb/inforeg/scctsd-final-july-2015.pdf. The 2010 and 2013 TSDs present SC-CO2 in 2007$ per metric ton. The unrounded estimates 

from the current TSD were adjusted to (1) short tons for using conversion factor 0.90718474 and (2) 2011$ using 

the GDP Implicit Price Deflator (1.0613744) from the National Income and Product Accounts Tables; the 
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three values are based on the average SC-CO2 from the three IAMs, at discount rates of 5, 3, 

and 2.5 percent, respectively. SC-CO2 estimates for several discount rates are included because 

the literature shows that the SC-CO2 is quite sensitive to assumptions about the discount rate, 

and because no consensus exists on the appropriate rate to use in an intergenerational context 

(where costs and benefits are incurred by different generations). The fourth value is the 95th 

percentile of the SC-CO2 from all three models at a 3 percent discount rate. It is included to 

represent higher-than-expected impacts from temperature change further out in the tails of the

SC-CO2 distribution (representing less likely, but potentially catastrophic, outcomes).

Table 3-1 presents the global SC-CO2 estimates for the years 2015 to 2050. In order to 

calculate the dollar value for emission reductions, the SC-CO2 estimate for each emissions year 

would be applied to changes in CO2 emissions for that year, and then discounted back to the 

analysis year using the same discount rate used to estimate the SC-CO2. The SC-CO2 increases 

over time because future emissions are expected to produce larger incremental damages as 

physical and economic systems become more stressed in response to greater climate change. 

Note that the interagency group estimated the growth rate of the SC-CO2 directly using the 

three integrated assessment models rather than assuming a constant annual growth rate. This 

helps to ensure that the estimates are internally consistent with other modeling assumptions. 

 

unrounded 2011$ estimates are used in the Chapter 5 illustrative analysis. The RIA presents SC-CO2 estimates 

rounded to two significant digits. 
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Table 3-1. Social Cost of CO2, 2015-2050a(in 2011$)

Year

Discount Rate and Statistic

5% Average 3% Average 2.5% Average 3%

95th percentile

2015 $11 $35 $54 $100

2020 $12 $41 $60 $120

2022 $13 $41 $62 $120

2025 $13 $44 $65 $130

2030 $15 $48 $70 $150

2035 $17 $53 $75 $160

2040 $20 $58 $81 $180

2045 $22 $62 $86 $190

2050 $25 $66 $90 $200

a

These SC-CO2 values are stated in $/short ton and rounded to two significant figures. Unrounded estimates from 

the current TSD have been converted from $/metric ton to $/short ton using conversion factor 0.90718474 for 

consistency with this rulemaking and adjusted to 2011$ using the GDP Implicit Price Deflator (1.0613744). This 

calculation does not change the underlying methodology nor does it change the meaning of the SC-CO2

estimates. For both metric and imperial denominated SC-CO2 estimates, the values vary depending on the year 

of CO2 emissions and are defined in real terms. The unrounded 2011$ estimates are used in the Chapter 5 

illustrative analysis. The SC-CO2 estimates shown in this table have been rounded to two significant digits.

3.3 Health Co-Benefits of SO2 and NOx Reductions 

The EPA anticipates that this rule will result in negligible emission changes over the 

baseline by 2022. However, if CO2 emissions are reduced from new EGUs under this rule, then

emissions of other pollutants from the power sector would also likely be reduced. For example, 

reducing CO2 emissions through the adoption of CCS by coal-fired boilers may also yield sulfur 

dioxide (SO2) and emission reductions, which in turn would yield health benefits. We refer to 

these additional benefits as “co-benefits”. 

SO2 is a precursor for fine particulate matter formation, which is particulate matter 2.5 

micrometers in diameter and smaller (PM2.5), while NOX is a precursor for PM2.5 and groundlevel ozone formation. As such, reductions of SO2 and NOX would in turn lower overall ambient 

concentrations of PM2.5 and ozone. Reducing exposure to PM2.5 and ozone is associated with 

human health benefits including avoided mortality and morbidity. Researchers have associated 

PM2.5 and ozone exposure with adverse health effects in numerous toxicological, clinical, and 

epidemiological studies (U.S. EPA, 2009; U.S. EPA, 2013a). Health effects associated with 

exposure to PM2.5 include premature mortality for adults and infants, cardiovascular morbidity 

such as heart attacks and hospital admissions, and respiratory morbidity such as asthma 
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attacks, bronchitis, hospital and emergency room visits, work loss days, restricted activity days, 

and respiratory symptoms. Health effects associated with exposure to ozone include premature 

mortality and respiratory morbidity such as hospital admissions, emergency room visits, and 

school loss days. In addition to human health co-benefits associated with PM2.5 and ozone 

exposure, reducing SO2 and NOX emissions under this rule would result in reduced health 

impacts from direct exposure to these pollutants. For example, ambient concentrations of SO2

are associated with respiratory symptoms in children, emergency department visits, and 

hospitalizations for respiratory conditions. 

Reducing SO2 and NOX emissions would also result in other human welfare (non-health) 

improvements including improvements in ecosystem services. SO2 and NOX emissions can 

adversely impact vegetation and ecosystems through acidic deposition and nutrient 

enrichment, and can affect certain manmade materials, visibility, and climate (U.S. EPA, 2009; 

U.S. EPA, 2008). 

The avoided incidences of health effects and monetized value of health or non-health 

improvements that result from SO2 and NOx emissions reductions depend on the location of 

those reductions. For a full discussion of the human health, ecosystem and other benefits of 

reducing SO2 and NOX emissions from power sector sources, please refer to the Regulatory 

Impact Analysis for the Final Carbon Pollution Guidelines for Existing Power Plants (U.S. EPA, 

2015).

As described in Chapter 4, the EPA anticipates that this rule will result in no emission 

changes by 2022. As a result we did not need to perform a full health co-benefit impact 

assessment for a specific modeled compliance scenario. In Chapter 5, the EPA presents results 

for several illustrative plant-level analyses that show the potential impacts of the rule if certain 

key assumptions were to change substantially. When assessing the co-benefits of differences in 

emissions from different generation technologies in Chapter 5, the EPA does not assume a 

specific location for the illustrative new unit.8Instead, the EPA relied on a national-average 

benefit per-ton (BPT) method to estimate PM2.5-related health impacts of SO2 and NOX

emissions. The BPT approach provides an estimate of the total monetized human health 

benefits (the sum of premature mortality and morbidity) of reducing one ton of PM2.5 precursor 

(i.e., NOX and SO2) from the sector. To develop the BPT estimates used in this analysis the EPA 

 

8

If the EPA assumed a location for a particular new unit it may be possible to perform a full health impact 

assessment of different technology options for generating electricity at that location. Doing so for a number of 

locations is beyond the scope of this analysis and would be better captured in sector-wide modeling. 
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utilized detailed air quality modeling of the entire power sector SO2 and NOX emissions along 

with the BenMAP model9to estimate the benefits of air quality improvements using projected 

2020 population, baseline incidence rates, and economic factors.

The SO2- and NOX-related BPT estimates utilized in this analysis are derived from the 

TSD on estimating the BPT of reducing PM2.5 and its precursors (U.S. EPA, 2013b). These BPT 

values are estimated in a methodologically consistent manner with those reported in Fann et al. 

(2012). They differ from those reported in Fann et al. (2012) as they reflect the health impact 

studies and population data updated in the benefits analysis of the final PM NAAQS RIA (U.S. 

EPA, 2012). The recalculation of the Fann et al. (2012) BPT values based on the updated data 

from the PM NAAQS RIA (U.S. EPA, 2012) is described in the TSD (U.S. EPA, 2013b). The BPT 

values are for the entire electricity sector and are not differentiated by fuel or generator type. 

The methods used for this analysis are consistent with those used to estimate the health 

co-benefits from secondary PM2.5 formation for the Regulatory Impact Analysis for the Final

Carbon Pollution Guidelines for Existing Power Plants (U.S. EPA, 2015). One notable difference 

between the BPT values used in the two analyses is that this analysis utilizes national-average 

BPT estimates because the EPA does not assert a specific location for the illustrative new unit, 

whereas the BPT estimates used in the RIA for the final existing source guidelines differ by 

region.10

Despite our attempts to quantify and monetize as many of the co-benefits of reducing 

emissions from electricity generating sources as possible, not all known health and non-health

co-benefits from reducing SO2 and NOx are accounted for in this assessment. For more 

information about unquantified health and non-health co-benefits of SO2 and NOx please refer 

to tables 5-2 and 6-2 of the PM NAAQS RIA (U.S. EPA, 2012), respectively. Furthermore, the 

analysis that follows does not account for known differences in other air and water pollutants 

between the different generating technologies, including, for example, ozone or directlyemitted PM. The implications for limiting our consideration of co-benefits to pollutants that 

cause secondary PM2.5 is discussed in Chapter 5. 

As we do not assume a specific location for the new units being compared, this RIA is 

unable to include the type of detailed uncertainty assessment found in the RIA for the National 

 

9

Available at http://www.epa.gov/air/benmap. 

10 Separate BPT values are generated for California, the Eastern U.S., and the Western U.S. excluding California. For 

further information, see EPA 2015. 
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Ambient Air Quality Standards for Particulate Matter (PM NAAQS RIA) (U.S. EPA, 2012). 

However, the results of the uncertainty analyses presented in the PM NAAQS RIA can provide 

some information regarding the uncertainty inherent in the benefits results presented in this 

analysis. In addition to the uncertainties described in the PM NAAQS RIA, the use of BPT

estimates come with additional uncertainty. Specifically, these national-average BPT estimates

reflect a specific geographic distribution of SO2 and NOX reductions resulting in a specific 

reduction in PM2.5 exposure and may not fully reflect local or regional variability in population 

density, meteorology, exposure, baseline health incidence rates, timing of emissions, or other 

factors that might lead to an over-estimate or under-estimate of the actual benefits associated 

with PM2.5 precursors in a specific location. These estimates are illustrative as the EPA does not 

assume a specific location for the illustrative electricity generation technologies and is 

therefore unable to specifically determine the population that would be affected by their 

emissions. Therefore, the benefits for any specific unit can be different than the estimates 

shown here.

Notwithstanding these limitations, reducing one thousand tons of annual SO2 from U.S. 

power sector sources has been estimated to yield between four and nine incidences of 

premature mortality avoided and monetized PM2.5-related health benefits (including these 

incidences of premature mortality avoided) between $38 million and $85 million in 2020 

(2011$) using a 3 percent discount rate or between $34 million and $76 million (2011$) using a 

7 percent discount rate. Additionally, reducing one thousand tons of annual NOX from U.S. 

EGUs has been estimated to yield up to one incidence of premature mortality avoided and 

monetized PM2.5-related health benefits (including these incidences of premature mortality 

avoided) of between $5.5 million and $12 million in 2020 (2011$) using a 3 percent discount 

rate or between $5.0 million and $11 million (2011$) using a 7 percent discount rate. For each 

pollutant, the range of estimated benefits for each discount rate is due to the EPA’s use of two 

alternative primary estimates of PM2.5-related mortality impacts: a lower primary estimate 

based on Krewski et al. (2009) and a higher primary estimate based on Lepeule et al. (2012). 

The benefit per ton values are reported in Table 3-2. 
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Table 3-2. Monetized Health Benefits Per Ton of PM2.5 Precursor Reductions in 2020a(in 

2011$)

PM2.5 Precursor

SO2 NOX

3% Discount Rate

Krewski et al. (2009) $38,000 $5,500

Lepeule et al. (2012) $85,000 $12,000

7% Discount Rate

Krewski et al. (2009) $34,000 $5,000

Lepeule et al. (2012) $76,000 $11,000

a

These estimates are from U.S. EPA, 2013a (electricity generating units) and are adjusted to 2011$ using the Gross 

Domestic Product implicit price deflator reported by the Department of Commerce.

3.4 References

40 CFR Chapter I [EPA–HQ–OAR–2009–0171; FRL–9091–8] RIN 2060–ZA14, “Endangerment and 

Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean 

Air Act,” Federal Register / Vol. 74, No. 239 / Tuesday, December 15, 2009 / Rules and 

Regulations.

Fann, N., K.R. Baker, C.M. Fulcher. 2012. Characterizing the PM2.5-related health benefits of 

emission reductions for 17 industrial, area and mobile emission sectors across the U.S. 

Environment International, Volume 49, 15 November 2012, Pages 141-151, ISSN 0160-

4120, http://dx.doi.org/10.1016/j.envint.2012.08.017.

Interagency Working Group (IWG) on Social Cost of Carbon (SC-CO2). 2010. Technical Support 

Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866. Docket ID EPA-HQ-OAR-2009-0472-114577. Participation by Council of Economic 

Advisers, Council on Environmental Quality, Department of Agriculture, Department of 

Commerce, Department of Energy, Department of Transportation, Environmental 

Protection Agency, National Economic Council, Office of Energy and Climate Change, 

Office of Management and Budget, Office of Science and Technology Policy, and 

Department of Treasury. 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Costof-Carbon-for-RIA.pdf Accessed March 31, 2015.
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3-13

Interagency Working Group (IWG) on Social Cost of Carbon (SC-CO2). 2013, Revised July 2015. 

Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866. Docket ID EPA-HQ-OAR-2013-0495. Participation by 

Council of Economic Advisers, Council on Environmental Quality, Department of 

Agriculture, Department of Commerce, Department of Energy, Department of 

Transportation, Domestic Policy Council, Environmental Protection Agency, National 

Economic Council, Office of Management and Budget, Office of Science and Technology 

Policy, and Department of Treasury. 

<http://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf > 

Accessed July 2, 2015.

Intergovernmental Panel on Climate Change (IPCC). 2007. Climate Change 2007: Synthesis 

Report. Contribution of Working Groups I, II and III to the Fourth Assessment Report of 

the Intergovernmental Panel on Climate Change (AR4) [Core Writing Team, Pachauri, 

R.K and Reisinger, A. (eds.)]. IPCC, Geneva, Switzerland, 104 pp. 

<http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_rep

ort_synthesis_report.htm>. Accessed March 30, 2015.

Intergovernmental Panel on Climate Change (IPCC). 2014. Climate Change 2014: Impacts, 

Adaptation, and Vulnerability. Contribution of Working Group II to the Fifth Assessment 

Report of the Intergovernmental Panel on Climate Change. Cambridge University Press, 

Cambridge, United Kingdom and New York, NY, USA. 

Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz, 

and W.H. White. 2009. “Reanalysis of the Harvard Six Cities Study and the American 

Cancer Society Study of Particulate Air Pollution and Mortality.” Special Report to the 

Health Effects Institute. Cambridge, MA. July.

Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. “Chronic Exposure to Fine Particles and 

Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.

Medina-Ramon, M. and J. Schwartz, 2007: Temperature, temperature extremes, and mortality: 

a study of acclimatization and effect modification in 50 U.S. cities. Occupational and 

Environmental Medicine, 64(12), 827-833.

National Research Council (NRC). 2009. Hidden Cost of Energy: Unpriced Consequences of 

Energy Production and Use. National Academies Press. Washington, DC.

National Research Council (NRC). 2013. Climate and Social Stress: Implications for Security 

Analysis. The National Academies Press. Washington, DC.

Pizer, W., M. Adler, J. Aldy, D. Anthoff, M. Cropper, K. Gillingham, M. Greenstone, B. Murray, R. 

Newell, R. Richels, A. Rowell, S. Waldhoff, J. Wiener. 2014. “Using and improving the 

social cost of carbon.” Science, Vol. 346, No. 6214, 12/05/14, pp 1189-1190.
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U.S. Environmental Protection Agency (U.S. EPA). 2008. Integrated Science Assessment for 

Oxides of Nitrogen and Sulfur –Ecological Criteria National (Final Report). National 

Center for Environmental Assessment, Research Triangle Park, NC. EPA/600/R-08/139. 

December. Available on the Internet at 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485.

U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for 

Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for 

Environmental Assessment – RTP Division. December. Available on the Internet at 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.

U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis for the Final 

Mercury and Air Toxics Standards. Office of Air Quality Planning and Standards, 

Research Triangle Park, NC. December. Available on the Internet at 

http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the 

Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. 

Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. 

Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2013a. Integrated Science Assessment for 

Ozone and Related Photochemical Oxidants. EPA/600/R-10/076F. Research Triangle 

Park, NC: U.S. EPA. February. Available on the Internet at 

http://oaspub.epa.gov/eims/eimscomm.getfile?p_download_id=511347.

U.S. Environmental Protection Agency (U.S. EPA). 2013b. Technical Support Document 

Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of 

Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on 

the Internet at http://www2.epa.gov/sites/production/files/2014-

10/documents/sourceapportionmentbpttsd.pdf

U.S. Environmental Protection Agency (U.S. EPA). 2015. Regulatory Impact Analysis for the Final

Carbon Pollution Guidelines for Existing Power Plants. 

U.S. Global Change Research Program (USGCRP). Global Climate Change Impacts in the United 

States. Thomas R. Karl, Jerry M. Melillo, and Thomas C. Peterson, (eds.). Cambridge 

University Press, 2009.
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CHAPTER 4

COSTS, ECONOMIC, AND ENERGY IMPACTS OF THE NEW SOURCE STANDARDS

4.1 Synopsis

This chapter reports the compliance cost, economic, and energy impact analyses

performed for the final EGU New Source GHG Standards.

1

The U.S. Environmental Protection 

Agency (EPA) analyzed and assessed a wide range of potential scenarios and outcomes, using a 

detailed power sector model, other government projections for the power sector, and 

additional economic assessments and analyses to determine the potential impacts of this 

action. 

The primary finding of this assessment is that in the baseline, all projected unplanned2

capacity additions affected by these standards during the analysis period 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 carbon 

capture and storage (CCS) supported by federal and state funding). The analysis period is 

defined as through 20223to reflect that CAA Section 111(b) requires that the NSPS be reviewed 

every eight years. The EPA’s conclusion was based on:

 EIA power sector modeling projections,

 EPA power sector modeling projections,

 Electric utility integrated resource planning (IRP) documents, and

 Projected new EGUs reported by industry to the U.S. Energy Information 

Administration (EIA).

The EPA’s forecast of no new non-compliant coal-fired capacity remains robust beyond 

the analysis period (past 2030 in both EIA and EPA baseline modeling projections) and across a 

wide range of alternative potential market, technical, and regulatory scenarios that influence 

 

1

Chapter 6 reports the compliance cost, economic, and energy impact analyses performed for the final EGU 

Modified and Reconstructed Source Standards.

2

Unplanned capacity represents projected capacity additions that are not under construction.

3

In some cases, conditions in the analysis year of 2022 are represented by results of power sector modeling for the 

year 2020. An analysis year of 2023 (8 years from finalization) would not substantively alter the overall 

conclusions of this RIA. Integrated Planning Model (IPM) output for subsequent years has been made available 

in the docket and is discussed where appropriate throughout the document.
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power sector investment decisions. As a result, the EGU New Source GHG Standards are not 

expected to change GHG emissions for newly constructed EGUs, and are anticipated to yield no 

monetized benefits and impose negligible costs, economic impacts, or energy impacts on the 

electricity sector or society. While the EPA does not project any new coal-fired EGUs without 

CCS to be built in the absence of this rule, this chapter presents an analysis of the project-level 

costs of building new coal-fired capacity with and without CCS to demonstrate that a 

requirement of partial CCS would not preclude new coal construction due to economic 

conditions. An additional illustrative analysis, presented in Chapter 5, shows that even in the 

unlikely event that new, non-compliant EGU capacity would be built, the final EGU New Source 

GHG Standards would provide net benefits under a range of assumptions.

4.2 Requirements of the Final GHG EGU NSPS

In this action, the EPA is finalizing standards of performance for two basic categories of 

new units that have not commenced construction by January 8, 2014: (i) fossil fuel-fired electric 

utility steam generating units (boilers and IGCC units) and (ii) natural gas-fired stationary 

combustion turbines that generate electricity for sale and meet certain applicability criteria.

The EPA is finalizing standards of performance for affected EGUs within the following

two categories: (1) all fossil fuel-fired steam generating units (steam generating units, boilers 

and integrated gasification combined cycle (IGCC) units), and (2) all natural gas-fired stationary 

combustion turbines, regardless of the size of the stationary turbine unit. All affected new fossil 

fuel-fired EGUs would be required to meet an output-based emission rate of a specific mass of 

carbon dioxide (CO2) per megawatt-hour (MWh) of electricity generated energy output on a 

gross basis.

New fossil fuel-fired steam generating units (boilers and IGCC units) would be required 

to meet an emission standard of 1,400 lb CO2/MWh of gross energy output. 

Newly constructed natural gas-fired stationary combustion turbines will be required to 

meet a standard of 1,000 lb CO2/MWh of gross energy output (or 1,030 lb CO2/MWh of net 

energy output). This emission limit applies to all affected natural gas-fired stationary 

combustion units regardless of size. The natural gas combustion turbine standard, however, will 

only apply to units that will exceed a sales threshold on the amount of electricity generated 

that is sold to the electric grid. The purpose of the sales threshold criterion is to permit gasfired combustion turbines that only sell a small portion of the gross electricity generated to the 

grid (“non-base load units”) to not have to meet the same emission standard as a combustion 
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turbine unit designed primarily to generate base and intermediate electricity to be sold to the 

grid.

Please refer to the preamble for additional detail concerning affected EGUs and 

standards of performance.

4.3 Power Sector Modeling Framework

4.3.1 Modeling Overview

Over the last decade, the EPA has conducted extensive analyses of regulatory actions 

impacting the power sector. These efforts support the Agency’s understanding of key policy 

variables and provide the framework for how the Agency estimates the costs and benefits 

associated with its actions that impact the power sector. Current forecasts for the utilization of

new and existing generating capacity are a key input into evaluating the impact of this rule. 

Given excess capacity within the existing fleet and relatively low forecasts of electricity demand 

growth, there is limited new capacity of any type expected to be constructed over the next 

decade. A small number of new coal-fired power plants have been completed and brought 

online in recent years. However, the EPA does not expect the construction of any new noncompliant coal-fired capacity through the analysis period. The EPA also does not expect any 

new non-compliant natural gas-fired stationary combustion turbines meeting the applicability 

criteria to be built. This conclusion is based in part on the Agency’s own power sector modeling 

utilizing the Integrated Planning Model (IPM) as well as EIA’s Annual Energy Outlook 2014 (AEO 

2014) projections.

IPM, developed by ICF International, Inc, is a state-of-the-art, peer reviewed, dynamic 

linear programming model that can be used to project power sector behavior under future 

business as usual conditions and examine prospective air pollution control policies throughout 

the United States for the entire electric power system. The EPA used IPM to project likely future 

electricity market conditions with and without this rule. 

In addition to using IPM, the EPA has closely examined modeling results from a number 

of alternative baseline scenarios in the AEO 2014 from the EIA. To produce the AEO, EIA 

employs the National Energy Modeling System (NEMS), an energy-economy modeling system of 

the United States. According to EIA:4

 

4

http://www.eia.gov/oiaf/aeo/overview/
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NEMS projects the production, imports, conversion, consumption, and prices of energy, 

subject to assumptions on macroeconomic and financial factors, world energy markets, 

resource availability and costs, behavioral and technological choice criteria, cost and 

performance characteristics of energy technologies, and demographics.

The Electricity Market Module of NEMS produces projections of power sector behavior 

that minimize the cost of meeting electricity demand subject to the sector’s inherent 

constraints, including the availability of existing generation capacity, transmission capacity and 

cost, cost of utility and nonutility technologies, expected load shapes, fuel markets, regulations, 

and other factors. EIA’s AEO projections independently corroborate the EPA’s conclusions in 

that the forecast no new generation capacity being constructed through the analysis period 

that would not already meet the final new source standards. Both the IPM and AEO 2014

NEMS modeling results are presented in Section 4.4.

4.3.2 The Integrated Planning Model

IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. 

electric power sector. It provides forecasts of least cost capacity expansion, electricity dispatch, 

and emission control strategies while meeting energy demand and environmental, 

transmission, dispatch, and reliability constraints. The EPA has used IPM for over two decades

to better understand power sector behavior under future business as usual conditions and 

evaluate the economic and emission impacts of prospective environmental policies. The model 

is designed to reflect electricity markets as accurately as possible. 5 The EPA uses the best 

available information from utilities, industry experts, gas and coal market experts, financial 

institutions, and government statistics as the basis for the detailed power sector modeling in 

IPM. The model documentation provides additional information on the assumptions discussed 

here as well as all other model assumptions and inputs.6,7

Although the Agency typically focuses on broad system effects when assessing the 

economic impacts of a particular policy, the EPA’s application of IPM includes a detailed and 

sophisticated regional representation of key power sector variables and its organization. When 

considering which new units are most cost effective to build and operate, the model considers 

the relative economics of various technologies based on a wide spectrum of current and future 

considerations, including capital costs, operation and maintenance costs, fuel costs, utility 

 

5

http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html

6

http://www.epa.gov/airmarkets/programs/ipm/psmodel.html

7

http://www.epa.gov/airmarkets/documents/ipm/EPA_Base_Case_v514_Incremental_Documentation.pdf
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sector regulations, and emission profiles. The capital costs for new units account for regional 

differences in labor, material, and construction costs. These regional cost differentiation factors 

were developed based on data and assumptions used in the EIA’s AEO 2013.

As part of IPM’s assessment of the relative economic value of building a new power 

plant, the model incorporates a detailed representation of the fossil-fuel supply system that is 

used to forecast equilibrium fuel prices, a key component of new power plant economics. The 

model includes an endogenous representation of the North American natural gas supply system 

through a natural gas module that reflects full supply/demand equilibrium of the North 

American gas market. This module consists of 118 supply, demand, and storage nodes, 15

liquefied natural gas regasification facility locations and three LNG export facility locations that 

are tied together by a series of linkages (i.e., pipelines) that represent the North American 

natural gas transmission and distribution network.

IPM also endogenously models the coal supply and demand system throughout the 

continental U.S., and reflects non-power sector demand and imports/exports. IPM reflects 36 

coal supply regions, 465 coal supply curves for each of nine years, 14 coal sulfur grades, and the 

coal transport network, which consists of 4,947 linkages representing the costs of transporting 

coal via rail, barge, and truck and conveyer linkages connecting 41 regions with 575 individual 

coal-fired generating stations. The coal supply curves and the transport network costs used in 

IPM are publicly available,

8

and were developed during a thorough bottom-up, mine-by-mine 

approach that depicts the coal choices and associated supply costs that power plants will face 

over the modeling time horizon. The IPM documentation outlines the methods and data used 

to quantify the economically recoverable coal reserves, characterize their cost, and build the 84 

coal supply curves. These curves have been independently reviewed by industry experts and 

have been made available for public review on several occasions over the past two years during 

other rulemaking processes. 

The EPA has used IPM extensively over the past two decades to analyze options for 

reducing power sector emissions. The model has been used to forecast the costs, emission 

changes, and power sector impacts for the Clean Air Interstate Rule (CAIR), Cross-State Air 

Pollution Rule (CSAPR), the Mercury and Air Toxics Standards (MATS), and the proposed GHG 

 

8

The IPM coal supply curves are presented in detail in Appendix 9-24 of the IPM Base Case documentation, which 

is available at http://www.epa.gov/airmarkets/programs/ipm/psmodel.html. The coal transport network costs 

are in Appendix 9-23, available at that same link.
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emission guidelines for existing source EGUs.

9

 Recently IPM has also been used to estimate the 

air pollution reductions and power sector impacts of water and waste regulations affecting 

EGUs, including Cooling Water Intakes (316(b)) Rule, Disposal of Coal Combustion Residuals 

from Electric Utilities (CCR) and Steam Electric Effluent Limitation Guidelines (ELG).

The model undergoes periodic formal peer review, which includes separate expert 

panels for both the model itself and the EPA’s key modeling input assumptions.10 The 

rulemaking process also provides opportunity for expert review and comment by stakeholders, 

including owners and operators of the electricity sector that is represented by the model, public 

interest groups, and other developers of U.S. electricity sector models. The EPA is required to 

respond to significant comments submitted regarding the inputs used in IPM, its structure, and 

application. The feedback that the Agency receives provides a detailed check for key input 

assumptions, model representation, and modeling results. IPM has received extensive review 

by energy and environmental modeling experts in a variety of contexts. For example, from the 

mid-1990s through 2011 the Science Advisory Board reviewed IPM as part of the Clean Air Act 

(CAA) Amendments Section 812 studies of the CAA costs and benefits that are periodically 

conducted.11 The model has also undergone considerable interagency scrutiny when it has 

been used to conduct over one dozen legislative analyses performed at Congress’ request over 

the past decade. In addition, Regional Planning Organizations throughout the U.S. have 

extensively examined IPM as a key element in the state implementation plan (SIP) process for 

achieving the National Ambient Air Quality Standards. The Agency has also used the model in a 

number of comparative modeling exercises sponsored by Stanford University’s Energy 

Modeling Forum over the past 15 years.

IPM has also been employed by state partnerships (e.g., the Regional Greenhouse Gas 

Initiative (RGGI), the Western Regional Air Partnership, Ozone Transport Assessment Group), 

other federal and state agencies, environmental groups, and industry, all of whom subject the 

model to their own review procedures. States have also used the model extensively to inform 

issues related to ozone in the northeastern U.S. This groundbreaking work set the stage for the 

NOx SIP call, which has helped reduce summer nitrogen oxide (NOx) emissions and the 

formation of ozone in densely populated areas in the northeast. 

 

9

The IPM projection conducted for this rulemaking is available at the EPA’s website and in the public docket.

10 http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html

11 http://www.epa.gov/air/sect812/index.html
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4.4 Analyses of Future Generating Capacity

4.4.1 Base Case Power Sector Modeling Projections

The “base case” for this analysis is a business-as-usual scenario that would be expected 

under market and regulatory conditions in the absence of this rule. As such, the IPM base case 

represents the baseline for this regulatory impact analysis. The EPA frequently updates the IPM 

base case to reflect the latest available electricity demand forecasts, as well as expected costs 

and availability of new and existing generating resources, fuels, and emissions control 

technologies.

The EPA conducted analysis and modeling in support of the April 2012 EGU GHG New 

Source Standards proposal, and concluded that new unplanned non-compliant base load power 

plants are not expected to be built through the analysis period (2020 for the original proposal) 

and beyond (77 FR 22392, April 13, 2012). The EPA conducted an analysis of the economic 

impacts by modeling a base case scenario of future electricity market conditions. The EPA’s IPM 

modeling for the 2012 proposal utilized the IPM v. 4.10 base case, and relied on the AEO 2010 

for the electric demand forecast for the U.S. and employed a set of the EPA’s assumptions 

regarding fuel supplies, the performance and cost of electric generation technologies, pollution 

controls, and numerous other parameters. For the 2012 proposal, the EPA also conducted three 

additional base case sensitivity analyses using IPM.12

After considering public comments received on the 2012 proposal, the EPA issued a new 

proposal for carbon emissions from new power plants (79 FR 1430, January 8, 2014). The EPA’s 

IPM modeling of the 2013 proposal relied on the AEO 2013 electric demand forecast, and was 

analyzed using the IPM v. 5.13 base case. The EPA also conducted three additional base case 

sensitivity analyses using IPM.13

For the analysis of the final rule, the EPA used the IPM v. 5.14 base case, which relied on 

the electric demand forecast in AEO 2014. The v. 5.14 base case updated v. 5.13 unit level 

specifications (including control configurations) based on comments received and EGU 

compliance plans in response to environmental regulations. The base case accounts for the 

effects of the finalized MATS and CSAPR rules, New Source Review settlements and state rules 

through 2014 impacting sulfur dioxide (SO2), NOx, directly emitted particulate matter and CO2, 

 

12 http://www2.epa.gov/sites/production/files/2013-09/documents/20120327proposalria.pdf

13 http://www2.epa.gov/sites/production/files/2013-09/documents/20130920proposalria.pdf and 

http://www.epa.gov/airmarkets/programs/ipm/proposedEGU_GHG_NSPS.html
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and final actions the EPA has taken to implement the Regional Haze Rule. The EPA’s IPM base 

case also includes two federal non-air rules effecting EGUs: the Cooling Water Intakes (316(b)) 

Rule and the Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR). 

Table 4-1 reports the unplanned capacity additions forecast by the IPM base case. 

Unplanned capacity additions are those that the model forecasts to be built in response to 

forecast economic conditions, such as fuel prices and demand growth. The EPA’s IPM base case 

forecast finds that EGUs are projected to adopt technology for new steam and combustion 

turbine generation capacity that would be compliant with the standards, even in the absence of 

this rule. Only some new coal-fired units with carbon capture and storage (CCS) technology,

which are receiving partial federal financial support, are included in the baseline modeling. 

Furthermore, new simple-cycle combustion turbines (CTs) constructed in the EPA’s IPM base 

case are assumed to operate at an emissions rate above the standard. However, mirroring real 

world behavior, relatively low levels of CT generation are projected in the base case. In the base 

case new CTs are forecast to operate, on average in each domestic model region, at capacity 

factors well below the applicability requirements of this rule. In the base case the maximum 

average capacity factor for individual new CTs is 14 percent or less across all domestic regions 

and all simulation years. The emissions rate of new natural gas combined cycle (NGCC) units in 

the EPA’s IPM base case is below the emissions rate standard of this final rule, although this is

by assumption. However, assuming an emissions rate for new NGCC units that is below the 

emissions rate standard is consistent with the detailed emissions rate analysis described in the 

preamble for this rule. That analysis carefully considered emissions rate data on newly 

constructed NGCC units and GHG limitations in recently issued construction permits for NGCC 

facilities and found that these facilities operated below the standard or were permitted to 

operate below the standard. 

The EIA projections that are reflected in AEO 2014 reference case are summarized in the 

following tables alongside the EPA base case projections. According to the EIA, the AEO 2014 

reference case “projection is a business-as-usual trend estimate, given known technology and 

technological and demographic trends.”14 It represents existing policies and regulations 

influencing the power sector.

15

 As shown in Table 4-1, new coal-fired capacity through 2030 is 

projected to be entirely CCS-equipped and would be in compliance with these standards (300 

MW) in the AEO 2014 reference case. The projected CCS-equipped capacity is assumed to 

 

14 http://www.eia.gov/forecasts/archive/aeo14/pdf/0383(2014).pdf

15 Reference case assumptions are described in Assumptions to the Annual Energy Outlook 2014 (U.S. EIA 2014b).
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occur in response to existing federal, state, and local incentives for the technology.16 The AEO 

2014 reference case forecasts that the vast majority of new, unplanned generating capacity will 

be either natural gas-fired or renewable.17 The reference case projects a capacity factor for 

simple cycle combustion turbines of less than 20 percent in all regions and in all years, and 

therefore these units are projected to operate below the applicability limit for this final rule. As 

in the IPM-based analysis, the emission rate for new NGCC units in the AEO 2014 reference case 

is assumed to be below the applicable standard in this final rule. 

As described in detail in 4.4.2, the economics favoring new natural gas combined cycle 

(NGCC) additions instead of coal-fired additions are robust under a range of sensitivity cases 

examined in the AEO 2014. Sensitivity cases that EIA conducted in the AEO 2014, as well as the 

AEO 2013, separately examine higher economic growth, lower coal prices, no risk premium for 

greenhouse gas emissions liability from conventional coal, and lower oil and natural gas 

resources. None of these sensitivity cases forecast unplanned additions of coal-fired capacity 

without CCS in the analysis period. This has been a consistent finding in the AEO, which led the 

Department of Energy (DOE) to conclude that “the low capital expense, technical maturity, and 

dispatchability of natural gas generation are likely to dominate investment decisions under 

current policies and projected prices."18 

Table 4-1. Unplanned Cumulative Capacity Additions (GW)

EPA Base Case AEO 2014 Reference Case

Capacity Type 2020 2020 2025 2030

Conventional Coal 0 0 0 0

Coal with CCS 0.3 0.3 0.3 0.3

Natural Gas CC 6.9 9.8 28.8 95.7

Natural Gas CT 2.6 14.1 34.5 49.2

Nuclear 0 0 0 0

 

16 These programs include the Emergency Economic Stabilization Act of 2008, the American Reinvestment and 

Recovery Act of 2009 (which assisted in funding for such programs as the Clean Coal Power Initiative through 

DOE and tax credits for Clean Energy Manufactures through DOE and the Treasury Department), as well as 

loans provided by USDA for CO2 capture projects. See also preamble section 3.H.3.g discussing the EPAct 2005.

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

18 Department of Energy (2011). Report on the First Quadrennial Technology Review. Available at 

http://energy.gov/sites/prod/files/QTR_report.pdf. 
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Renewables19 15.9 17.4 19.3 22.5

Distributed Generation20- 1.6 3.3 4.6

Total 25.8 43.2 86.3 141.4

Notes: The sum of the table values in each column may not match the total figure due to rounding. EPA capacity data is net 

nameplate capacity, AEO capacity data is net summer generating capacity.

Source: EPA 2020 projection from IPM v. 5.14 base case; EIA 2020-2030 projection from EIA Annual Energy Outlook 2014, Table 

A9.

The capacity projections of EIA and the EPA represent a continuation of current trends, 

where natural gas-fired capacity has been the technology of choice for base load and 

intermediate load power generation over the last few years (see Figure 4-1), due in large part 

to its significant levelized cost of electricity21 (LCOE) advantage over coal-fired generating 

technologies. A greater discussion of the relative LCOE of different generating technologies is 

provided beginning in Section 4.4.

 

19 Renewable projections in 2020 are larger in the AEO 2014 reference case than in the EPA’s IPM v 5.14 base case 

primarily due to differences in modeling assumptions regarding the amount of ‘planned’ renewable capacity 

additions and ‘unplanned’ additions in the AEO forecast. The overall amount of total renewable capacity in use 

by 2020 is largely similar in the two forecasts. The EPA planned cumulative renewable capacity additions 

include utility-scale onshore wind, solar PV, geothermal and biomass built between 2015 and 2020. The AEO 

2014 unplanned renewable capacity additions includes conventional hydroelectric, geothermal, wood, wood 

waste, all municipal waste, landfill gas, biomass (not co-fired with coal), PV and thermal solar, and wind power 

built between 2012 and 2020.

20 The term “Distributed Generation” refers to two different concepts. AEO defines the term distributed generation 

as “primarily peak-load capacity fueled by natural gas.” The EPA forecasts using the IPM model do not model 

new construction of distributed generation or capacity, which in the IPM model refers to small scale generation 

such as roof top PV, household geothermal, etc. Such small scale generation does not generate net electricity 

that can be sold to the grid, although it can reduce peak load demands on the grid system.

21The levelized cost of electricity is an economic assessment of the cost of electricity from a new generating unit or 

plant, including all the costs over its lifetime: initial investment, operations and maintenance, cost of fuel, and 

cost of capital.
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Figure 4-1. Historical U.S. Power Plant Capacity Additions, by Technology, 1891-2013

Source: Form EIA-860 (2013)

Notes: Figure reflects all capacity brought online from 1891 – 2013, including 77 GW subsequently retired. Total 

capacity shown: 1,126 GW, including 12 GW built pre-1940. Other Renewables include: hydro, biomass, solar, 

landfill gases, solid waste combustion and geothermal. Other includes: petroleum & distillates, petroleum coke, 

propane, other gases and waste heat not otherwise included. 

In addition to new builds, increased electricity demand is expected to be partially 

fulfilled by increased utilization of existing generating capacity. Generation projections are the 

result of least-cost economic modeling both in IPM and AEO 2014, and reflect the most costeffective dispatch and investment decisions modeled, given a variety of variables and 

constraints. Even without the deployment of new conventional coal-fired capacity, U.S. 

electricity demand will continue to be met by a diverse mix of electricity generation sources 

with coal projected to continue to provide the largest share of electricity (36 percent of total 

2020 generation in AEO 2014 and 37 percent in the EPA’s projections), as displayed in Table 4-

2. 

0

10,000

20,000

30,000

40,000

50,000

60,000

Pre 194

0

1942194519481951195419571960196319661969197219751978198119841987199019931996199920

02

20

05

20

08

2011

C

a

p

acity (G

W)

First Year of Operation (range: 1891-1913) 
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Table 4-2. 2012 U.S. Electricity Net Generation and Projections for 2020, 2025, and 2030

(Billion kWh)

Historical EPA Base 

Case AEO 2014 Reference Case

2012 2020 2020 2025 2030

Coal 1,512 1,534 1,646 1,689 1,692

Oil 23 47 18 19 19

Natural Gas 1,228 1,156 1,286 1,410 1,552

Nuclear 769 815 779 711 782

Hydroelectric 274 282 288 291 294

Wind 142 251 218 218 219

Other Renewables 48 121 102 133 154

Other 71 -7 65 151 103

Total 4,067 4,199 4,402 4,622 4,815

Source: Historical data from Form EIA-860, 2012. EPA 2020 projection from IPM 5.14 base case; EIA 2020-2030 projection from 

EIA Annual Energy Outlook 2014, Tables A8 and A16

Notes: The sum of the table values in each column may not match the total figure due to rounding. “Other Renewables” 

include biomass, geothermal, waste and solar electric generation capacity. “Other” includes pumped storage (net loss, nonbiogenic waste, batteries, hydrogen, and other miscellaneous generation and storage technologies. Negative value reflects net 

energy loss from pumped storage.

It has been previously noted that the current projections for key market variables, such 

as natural gas prices, and state and regional regulations are now even less favorable to the 

development of non-compliant coal-fired capacity than at the time of the 2012 proposal. State 

and regional regulations have changed since the 2012 proposal, as noted in Section 2.8, most 

notably regulations of GHG emissions from the power sector and state renewable portfolio 

standards (RPS):

 State regulations addressing CO2 emissions – Several states have adopted 

measures to address emissions of CO2 from the power sector. These approaches 

include flexible market-based programs like California’s Assembly Bill 32 and 

RGGI in the Northeast, and specific GHG performance standards for new power 

plants in California, Oregon, New York, and Washington.

 State Renewable Portfolio Standards (RPS) – There are now 29 states, the District 

of Columbia and Puerto Rico that have an enforceable RPS, or similar laws.22 

Eight other States, the Virgin Islands and Guam have voluntary goals. These 

 

22http://www.cesa.org/assets/2013-Files/RPS/State-of-State-RPSs-Report-Final-June-2013.pdf
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measures, in conjunction with federal financial incentives, are key drivers of the 

significant growth in new renewable energy seen over the past few years and 

expected over the next decade. Only 12 states do not currently have an 

enforceable RPS.23

 State and Utility IRPs – IRPs, which are usually adopted by utilities in response to 

state requirements, allow regulators and utilities to consider a broader array of 

measures to meet future electric demand most cost effectively. IRPs also help 

electric planners to consider key strategic and policy goals like electric reliability, 

environmental impacts, and the economic efficiency of power sector 

investments.24 In general, these plans confirm the expectation that utilities 

anticipate any new sources of generation will be from sources that meet the 

standards set in this regulation. Furthermore, these plans reflect an expectation 

of relatively low demand growth due, in part, to policies and regulations to 

reduce the electricity consumption such as energy efficiency regulations and

policies, evolution of the Smart Grid, and demand response measures. 

4.4.2 Alternative Scenarios from AEO 2014

As described in the previous section, in addition to the EPA’s own analysis, the EPA 

reviewed EIA’s recent forecasts of new capacity in the electricity sector for the AEO 2014. The 

AEO 2014 reference case forecasts no new non-compliant capacity would be built. Power sector 

modeling by EIA also projects that their conclusion of there being no new coal-fired capacity 

built in the analysis period is robust under a range of alternative assumptions that influence the 

industry’s decisions to build new power plants. For example, EIA typically supplements the AEO 

with scenarios that explore key market, technical, and regulatory issues. Of the 31 scenarios 

contained in the AEO 2014, none project new coal-fired capacity in the analysis period used by 

the EPA for this RIA, including the four scenarios that may be considered most favorable to the 

development of coal-fired capacity displayed in Table 4-3. 

Table 4-3. AEO 2014 Reference Case and Alternative Scenario Forecasts of Unplanned 

Cumulative Capacity Additions by 2020, GW 

 

23 In January 2015 West Virginia repealed the West Virginia Alternative Renewable Energy Portfolio Act, which was 

enacted in 2009. E.g, http://www.governor.wv.gov/media/pressreleases/2015/Pages/GOVERNOR-TOMBLINAPPROVES-REPEAL-OF-ALTERNATIVE-RENEWABLE-ENERGY-PORTFOLIO-ACT.aspx

24 See Integrated Resource Plan Technical Support Document for more information.
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Capacity Type Reference

High 

Growth

Low Coal 

Cost

Low Gas 

& Oil 

Resource

No GHG 

Concern

Conventional Coal 0 0 0 0 0

Coal with CCS 0.3 0.3 0.3 0.3 0.3

Natural Gas 23.9 34.4 19.8 16.3 22.7

Nuclear 0 0 0.0 2.5 0.0

Non-Hydro Renewables 17.4 19.7 17.6 23.7 17.5

Other 1.6 2.0 1.5 0.8 1.6

Total 43.2 56.5 39.3 43.6 42.1

Note: The AEO 2014 scenario definitions are: High Economic Growth increases annual real GDP growth by 2.8

percent per year through 2040 (reference case GDP growth is 2.4 percent per year); Low Coal Cost assumes 2.4

percent greater regional coal mining productivity growth than in the reference case, and lower wages, 

equipment, and declining transportation costs for the coal industry than in the reference case, falling to 25

percent below the reference case by 2040; Low Oil and Gas Resource reduces the ultimate estimated recovery 

of shale gas, tight gas, and tight oil by 50 percent; No GHG Concern removes the perceived risk of incurring costs 

under a future GHG policy from market investment decisions.

4.4.3 Power Sector Fuel Price Dynamics and Trends

Expectations about what new fossil-fired generation would serve future demand have 

changed over the past decade from generating sources that use coal to those, primarily 

combined cycle systems, which use natural gas. As mature technologies, the cost and 

performance characteristics of conventional coal-fired capacity and NGCC are projected by the 

EPA to be relatively stable over time.25 Therefore, expectations of future fuel prices play a key 

role in determining the overall cost competitiveness of conventional coal-fired units versus 

NGCC units.

Current and projected natural gas prices are considerably lower than observed 

prices over the past decade. This is largely due to advances in hydraulic fracturing and 

horizontal drilling techniques that have opened up new shale gas resources and 

substantially increased the supply of economically recoverable natural gas. According to 

EIA:

Shale gas refers to natural gas that is trapped within shale formations. Shales are 

fine-grained sedimentary rocks that can be rich sources of petroleum and natural 

gas. Over the past decade, the combination of horizontal drilling and hydraulic 

fracturing has allowed access to large volumes of shale gas that were previously 

 

25 http://www.epa.gov/airmarkets/documents/ipm/Chapter_4.pdf
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uneconomical to produce. The production of natural gas from shale formations 

has rejuvenated the natural gas industry in the United States.

Of the natural gas consumed in the United States in 2011, about 95 percent was 

produced domestically; thus, the supply of natural gas is not as dependent on foreign 

producers as is the supply of crude oil, and the delivery system is less subject to 

interruption. The availability of large quantities of shale gas should enable the United 

States to consume a predominantly domestic supply of gas for many years and produce 

more natural gas than it consumes.26

The AEO 2014 projects U.S. natural gas production will increase by 13.3 trillion cubic 

feet (Tcf), a 55 percent increase (from 24.3 Tcf in 2014 to 37.5 Tcf in 2040). Over 75 percent of 

this forecast increase in domestic natural gas production is due the projected doubling of shale 

gas production, which is forecast to increase by 10.2 TCF (from 9.6 TCF in 2014 to 19.8 TCF in 

2040).

27

Recent historical data reported to EIA is also consistent with these trends, with 2014 

being the highest year on record for domestic natural gas production.28 Gas production in 2014 

was 6.3 percent above production in 2013, which is the largest annual growth rate since 1984. 

The average real (2011$) natural gas price delivered to the power sector was $4.39/MMBtu in 

2014, an increase from $4.25/MMBtu in 2013.29,30

Increases in the natural gas resource base have led to fundamental changes in the 

outlook for natural gas. While sources may disagree on the absolute level of increases from 

shale resources, there is general agreement that recoverable natural gas resources will be 

substantially higher for the foreseeable future than previously anticipated, exerting downward 

pressure on natural gas prices.31,32 Modeling by the EPA and EIA incorporates the impact of 

 

26 For more information, see: http://www.eia.gov/forecasts/archive/aeo11/IF_all.cfm#prospectshale;

http://www.eia.gov/energy_in_brief/about_shale_gas.cfm

27 AEO 2014, Appendix A, Table A14. Oil and Gas Supply

28 http://www.eia.gov/dnav/ng/hist/n9010us2a.htm

29 http://www.eia.gov/dnav/ng/hist/n3045us3A.htm; Assumes that 1 TCF = 1.023 MMBtu natural gas 

(http://www.eia.gov/tools/faqs/faq.cfm?id=45&t=8) 

30 The relative prices of natural gas and coal rather than the price of any single fuel drive power sector investment 

decisions. The projections for relative fuel prices are discussed in Section 4.4.4.

31

 National Petroleum Council. 2011. Prudent Development: Realizing the Potential of North America's Abundant 

Natural Gas and Oil Resources. http://www.npc.org/reports/rd.html (see Figure 1.2 on p. 47).

32 EIA. 2014. U.S. Crude Oil and Natural Gas Proved Reserves, 2013. 

http://www.eia.gov/naturalgas/crudeoilreserves/pdf/usreserves.pdf
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these additional resources on the forecasts of the price of natural gas used by electric 

generating units. The increases in the natural gas resource base are reflected not only in 

current natural gas prices and projections (e.g., AEO 2014), but also in current capacity planning 

by utilities and electricity producers across the country. The North American Electric Reliability 

Corporation’s (NERC) Long Term Reliability Assessment, which is based on utility plans for new 

capacity over a 10-year period, reinforces this consensus by stating that “gas-fired generation 

[is] the primary choice for new capacity.”

33

The EPA’s and EIA’s modeling frameworks are designed to reflect the longer term, 

fundamentals-based perspective that electric utilities and developers employ in evaluating 

capital investments, while analyzing alternative scenarios to account for broader fuel market 

uncertainties. Short-term fuel price volatility is not the most relevant factor in this context 

because new power plants have asset lives measured in decades, not in months or years, and 

new capacity investment decisions are based on long-run expected prices, not month-tomonth, or even year-to year, variations in fuel prices. Shorter-term prices will affect how units 

are dispatched, but these potential dispatch impacts are considered with other factors over a 

longer time horizon and factored into the choice of which type of plant to build. In contrast, 

the uncertainty surrounding long-term fuel prices will exert significantly greater influence on 

the technology selected for new capacity additions. In a modeling context with perfect 

foresight, this longer term uncertainty may be evaluated by the comparisons of alternative 

scenarios presented throughout this chapter.

In addition to major changes in the gas supply outlook, there have been notable changes

in the coal supply outlook. Coal costs have generally increased over the past few years due

primarily to increased production costs. These costs have increased as the most accessible and 

economically viable mines are depleted, requiring movement into coal reserves that are more 

costly to mine. The basic trends in coal supply are not expected to change for the foreseeable 

future.34

 

33 NERC, Long-Term Reliability Assessments for 2012. New capacity includes both planned and conceptual 

resources as defined by NERC.

34 http://www.eia.gov/forecasts/aeo/assumptions/pdf/coal.pdf
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Taken together, current and expected natural gas and coal market trends are 

contributing to a recent fundamental shift in the economic conditions for new power plant 

development that utilities and developers have recognized and responded to in planning.35

4.4.4 Power Sector Fuel Projections

To examine the potential impacts of uncertainty inherent in natural gas and coal 

markets, the EIA used scenario analysis to generate the 2020 fuel price projections in Table 4-4.

The relative prices of available fuels partially drive power sector investment decisions. Even 

under scenarios where the spread between the unit price of gas and coal is highest, no 

construction of new non-compliant generating capacity is projected in 2020, as shown in Table 

4-3.

Table 4-4. National Delivered 2020 Fuel Prices by AEO 2014 Scenario (2011$/MMBtu)

Scenario Natural Gas Coal

Reference 4.99 2.57

High Growth 5.28 2.59

Low Growth 4.97 2.55

High Coal Cost 5.13 2.90

Low Coal Cost 4.88 2.27

High Gas/Oil Resource 4.30 2.45

Low Gas/Oil Resource 5.63 2.63

 

35 For example: "We don’t have any plans to build new coal plants. So the rules won’t have much of an impact. 

Any additional generation plants we’d build for the next generation will be natural gas." American Electric 

Power, 3/26/2012, National Journal; “As we look out over the next two decades, we do not plan to build 

another coal plant. ... As the evidence is coming in, [shale gas] is proving to be the real deal. If we have no 

plans, as one of the largest utilities and largest users of coal in this country, no plans to build a new coal plant 

for two decades, the regulations are not relevant.” Jim Rogers (Duke), 3/27/2012, NPR All Things Considered.; 

“If you actually look at the economics today, you would be burning gas, not coal,” Jack Fusco, Calpine, 

12/1/2010, Marketplace; “Coal’s most ardent defenders are in no hurry to build new ones in this environment.” 

John Rowe, Exelon, 9/2011, EnergyBiz; “With low gas prices, gas-fired generation kind of snowplows everything 

else” Lew Hay, NextEra, 11/1/2010, Dow Jones. “The Demise of Coal-Fired Power Plants” , Washington Post, 

Nov 23, 2012 (new EGU construction is natural-gas fired, even in Kentucky coal country).
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Note: AEO 2014 scenario definitions: High Economic Growth assumes real GDP growth is 2.8 percent peryear 

from 2012 to 2040 (base case assumes 2.4 percent); Low Economic Growth assumes real GDP growth is 1.9

percent per year High Coal Cost assumes lower regional productivity growth rates and higher wages, equipment, 

and transportation costs for the coal industry; Low Coal Cost assumes greater regional productivity growth rates 

and lower wages, equipment, and transportation costs for the coal industry; High Oil and Gas Resource expands 

the ultimate estimated recovery of shale gas, tight gas, and tight oil by 100 percent; Low Oil and Gas Resource 

reduces the ultimate estimated recovery of shale gas, tight gas, and tight oil by 50 percent.

However, given that power plants are long-lived assets, capacity planning decisions are 

necessarily undertaken with a forward view of expected market and regulatory conditions. In 

producing the AEO 2014, EIA capacity expansion projections are informed by a lifecycle cost 

analysis over a 30-year period in which the expectations of future prices are consistent with the 

projections realized in the model (i.e. the model executes decisions with perfect foresight of 

future market, technical, and regulatory conditions). Therefore, the fuel prices that inform 

capacity expansion decisions in 2020 are not only the prices that year, but the entire future fuel 

price stream. For example, Figure 4-2 displays EIA’s natural gas price projections for the 

Reference Case and several key scenarios through 2050.

$4

$5

$6

$7

$8

$9

$10

$11

Delivered Gas Price (2011$/M

MBtu)

Reference

High growth

Low growth

High coal cost

Low coal cost

High resource

Low resource
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Figure 4-2. National Real Price of Natural Gas Delivered to EGUs for Select AEO 2014 

Scenarios (2011$/MMBtu)

Note: The AEO gas price forecasts go through 2040. The AEO forecasted prices are interpolated to 2050 by 

applying the average annual rate of price increase from 2035 to 2040 in each AEO scenario to all 

subsequent years from 2041 through 2049.

Natural gas prices are expected to increase after 2020 in all scenarios.

36 However, rising 

natural gas prices through 2040 – including in EIA’s low gas/oil resource scenario - are still not 

sufficient to support new, non-compliant coal-fired generation through 2022 in these scenarios. 

This demonstrates that natural gas prices do not have to continue at currently low levels for 

NGCC to maintain its economic advantage over coal-fired technologies.

While the uniformity of EIA scenarios in projecting no new, non-compliant coal-fired 

capacity through the analysis period is compelling, the scenario projections cannot fully 

illustrate the extent of the economic advantage that NGCC maintains over conventional coal,

only that the advantage remains intact across a broad range of market and technical scenarios. 

To identify potential market conditions that could fully erode the cost advantages of NGCC over 

coal-fired technologies during the analysis period, the unit-level engineering cost analysis in 

section 5.4 compares these technologies. That analysis builds on the unit-level cost 

comparisons presented in the following sections of this chapter. 

4.5 Levelized Cost of Electricity Analysis 

New capacity projections from the EPA and EIA reviewed in the previous section

indicate that the NSPS is not projected to require changes in the design or construction of new 

EGUs from what would be expected in the absence of the rule. Thus, under both the baseline 

projections and alternative scenarios analyzed in AEO 2014, the final EGU New Source GHG 

Standards are projected to result in negligible emission reductions, quantified benefits, or costs.

To further examine the robustness of these conclusions the EPA conducted additional 

analysis using the levelized cost of electricity (LCOE) for different types of new generation 

technologies. The LCOE is a widely used metric that represents the cost, in dollars per output, 

of building and operating a generating facility over the entirety of its economic life. Evaluating 

competitiveness on the basis of the LCOE is particularly useful in establishing cost comparisons 

between generation types with similar operating characteristics but with different cost and 

financial characteristics. The typical cost components associated with the LCOE include capital, 

 

36 Coal prices are also expected to rise in all scenarios.
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fixed operating and maintenance (FOM), variable operating and maintenance (VOM), 

transportation, storage and monitoring (TS&M) and fuel. (See preamble section V. H. 5.)

4.5.1 Overview of the Concept of Levelized Cost of Electricity

The levelized capital and FOM costs may be calculated by taking the annualized capital 

and FOM (expressed in $/kW-yr) costs and spreading the expense over the annual generation 

of the facility using the expected average annual capacity factor (the percent of full load at 

which a unit would produce its actual annual generation if it operated for 8,760 hours). The 

annualized capital cost (expressed in $/kW-yr) is the product of the $/kW capital cost and the 

capital recovery factor (CRF). A CRF may be calculated using the project’s interest rate and 

book life.37

The VOM cost, which is already expressed in terms of cost per unit output, may be 

presented with or without the fuel expense. The fuel expense is typically the largest 

component of VOM costs (non-fuel components to VOM include start-up fuel, consumables, 

inspections, etc.) and for certain capacity types – such as NGCC – fuel expense may represent 

the majority of the LCOE. 

Because levelized costs consider the entire lifecycle of the facility, fuel expenses are 

represented by the levelized fuel price which captures the forecast of annual delivered fuel 

prices over the economic life of the facility at a given discount rate.38 Levelizing fuel prices 

recognizes the necessity to consider the trajectory of fuel costs over the facility’s entire 

economic life.

 

37 The interest rate assumed for NGCC and CT projects is 9.06 percent; the interest rate assumed for coal-fired 

projects is 9.57 percent. All three types of projects are assumed to have a 30-year book life, resulting in a 

capital recovery factor of 9.78 percent for NGCC and CT projects and 10.23 percent for coal-fired projects.

38 As an illustration of applying a discount rate to a stream of future fuel prices, the levelized fuel price will be less 

than the mean fuel price if prices are increasing, equal to the mean if fuel prices are constant, and greater than 

the mean if fuel prices are declining. The weighting of nearer-term prices through the application of a discount 

rate is consistent with modeling economic behavior of investors. The EPA used a 5 percent discount rate to 

calculate levelized fuel prices, a value consistent with the discount rate embedded in IPM. The model applies a 

discount rate of 4.77 percent for optimizing the sector’s decision-making over time. IPM’s discount rate, 

designed to represent a broad range of private-sector decisions for power generation, rates differs from 

discount rates used in other analyses in this RIA, such as the benefits analysis which each assume alternative 

social discount rates of 3 percent and 7 percent. These discount rates represent social rates of time preference, 

whereas the discount rate in IPM represents an empirically-informed price of raising capital for the power 

sector. Like all other assumed price inputs in IPM, the EPA uses the best available information from utilities, 

financial institutions, debt rating agencies, and government statistics as the basis for the capital charge rates 

and the discount rate used for power sector modeling in IPM.
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It should be noted that there are other important considerations beyond the LCOE that 

impact power plant investment decisions. New power plant developers must consider the 

particular demand characteristics in any particular region, the existing mix of generators, 

operational flexibility of different types of generation, prevailing and expected electricity prices, 

other potential revenue opportunities (e.g., the capacity value of a particular unit, where 

certain power markets have mechanisms to compensate units for availability to maintain 

reliability, sale of co-products, etc.), and the varying financial risks associated with different 

generation technologies. Broader system-wide power sector modeling – such as the analyses 

conducted by the EPA and EIA – is able to more effectively capture some of these 

considerations.

4.5.2 Cost and Performance of Technologies 

This section reports the LCOE of individual technologies that are affected EGUs of this 

final rule. These are compared in the following sections. The NGCC and coal-fired generation 

technology cost and performance assumptions that form the basis for the LCOE analysis in this 

RIA are from the DOE’s National Energy Technology Laboratory (NETL).39 NETL cost and 

performance characteristics were selected for coal-fired technologies because the NETL 

estimates were unique in the detail of their cost and performance estimates for a range of CO2

capture levels for both new super critical pulverized coal (SCPC) and integrated gasification 

combined cycle (IGCC) facilities.

40,41 In particular, the NETL costs released in 2015 include vendor 

quotes for new technology deployed. The use of NETL cost and performance characteristics also 

allows for comparisons to be made across generating technologies using a single, internally 

 

40 All potential build types are compliant with all current environmental regulations, including the EPA’s MATS.

40 All potential build types are compliant with all current environmental regulations, including the EPA’s MATS.

41 The NETL cost data intend 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). The cost 

estimates for plant designs that only contain fully mature technologies which have been widely deployed at 

commercial scale (e.g., pulverized coal power plants without CO2 capture) reflect nth-of-a-kind (NOAK) on the 

technology commercialization maturity spectrum. The costs of such plants have dropped over time due to 

“learning by doing” and risk reduction benefits that result from serial deployments as well as from continuing 

research and development. The cost estimates for plant designs that include technologies that are not yet fully 

mature (e.g., IGCC and any plant with CO2 capture) use the same cost estimating methodology as for the 

mature plant designs, which does not fully account for the unique cost premiums associated with the initial, 

complex integrations of emerging technologies in a commercial application. Thus, it is anticipated that initial 

deployments of the IGCC and capture plants may incur costs higher than those reflected within this report. 

Actual reported project costs for all of the plant types are also expected to deviate from the cost estimates in 

this report due to project- and site-specific considerations (e.g. contracting strategy, local labor costs, seismic 

conditions, water quality, financing parameters, local environmental concerns, weather delays, etc.) that may 

make construction more costly. Such variations are not captured by the reported cost uncertainty.
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consistent framework. The CO2 capture sensitivity analysis included an evaluation of the cost, 

performance, and environmental profile of these facilities under different configurations that 

were tailored to achieve a specific level of carbon capture. For simple cycle CTs, NETL cost and 

performance estimates were not available or sufficiently recent so the EPA adopted EIA’s AEO 

2014 estimates of the LCOE.

To represent a new SCPC facility, NETL assumed a new boiler with a combination of lowNOx burners with overfire air and a selective catalytic reduction system for NOx control. The 

plant was assumed to have a fabric filter and a wet limestone flue gas desulfurization scrubber 

for particulate matter and SO2 control, respectively. For configurations including CCS, the plant 

was assumed to have a sodium hydroxide polishing scrubber to ensure that the flue gas 

entering the CO2 capture system has a SO2 concentration of 10 parts per million or less. The 

SCPC unit treating a slip stream with partial post-combustion CCS were assumed to be 

equipped with the CO2 removal system designed by Shell Cansolv, the system currently in fullscale commercial use at the Boundary Dam facility.42

 Estimated costs for the system reflect the 

latest vendor quotations. 

Specific to the partial capture configurations for SCPC, the NETL study identified two 

options. The first option identified was to process the entire flue gas stream through the 

capture system, but at reduced solvent circulation rates. The second option was to maintain the 

same high solvent circulation rate and stripping steam requirement as would be used for full 

capture, but only treat a portion of the total flue gas stream. The NETL report determined that 

this “slip stream” approach was the most economical because a reduction in flue gas flow rate 

would: (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce the size of 

the CO2 absorption columns; and (3) trim the cooling water requirement of the direct contact 

cooling system.

43 The “slip stream” approach – which leads to lower capital and operating costs

– was therefore adopted by the EPA for cost and performance estimates under partial capture.

44The technology cost and performance characteristics utilized by the EPA in developing the 

LCOE estimates discussed in this chapter and Chapter 5 are listed below in Table 4-5.

Table 4-5. Technology Cost and Performance Specifications (2011$) 

 

42 NETL 2015 at 59, 137.

43 NETL based this determination primarily upon a review of the literature. See page 2 of 

http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf

44 For additional detail and discussion on the specific technology configurations selected for this analysis, please 

refer to the preamble.
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Capacity 

Type

Capital Cost 

($/MWh)

Fixed 

Operations & 

Maintenance 

($/MWh)

Variable 

Operations & 

Maintenance 

($/MWh)

TS&M

($/MWh)

Levelized 

Fuel Cost 

($/MWh)

Net Plant 

HHV 

Efficiency (%)

NGCC 13 4 1.8 - 42 50.2

SCPC 39 10 9 - 25 40.7

SCPC w/ 

Partial CCS 

(1,400 

lb/MWh 

gross)

51 11 10 1 26 39.2

SCPC CoFiring 

Natural Gas 

(1,400 

lb/MWh 

gross)

39 10 9 - 34 40.3

IGCC 54 14 9 - 26 39.0

IGCC CoFiring 

Natural Gas 

(1,400 

lb/MWh)

54 14 9 - 28 39.0

Notes: Cost from NETL 2015. The coal assumed is a bituminous coal with a sulfur content of 2.8 percent (dry) at a real (2011$) 

price of $2.94/MMBtu, consistent with NETL 2015. The analysis uses a natural gas price of $6.19. NETL uses a high-risk financial 

structure resulting in a capital charge factor (CCF) of 0.124 to evaluate the costs of all cases with CO2 capture (non-capture case 

uses a conventional financial structure with a CCF of 0.116).

NETL (2015) explains that there are a range of future potential costs that are up to 15 percent below, or 30 percent above their

central estimate, consistent with a “feasibility study” level of design engineering applied to the various cases in this study. The 

value of the studies lie 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.

4.5.3 Levelized Cost of Electricity of New Generation Technologies

To support and provide context for the sectoral modeling results presented above, this section 

presents two LCOE comparisons:

45

 

45 As the sectoral modeling may not capture all considerations, particularly local ones, under which a noncompliant coal unit may be built, Section 5.5 provides a comparison of the cost of a non-compliant coal unit to 

a compliant coal unit, either with partial CCS or natural gas co-firing. The analysis demonstrates that the 

standard could be accommodated and would not, based on the cost increment of constructing and operating a
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1. NGCC to non-compliant Coal – to demonstrate the cost advantages of NGCC across a 

range of natural gas prices and regional market conditions.

2. NGCC to CT – to demonstrate the low likelihood of a new combustion turbine being 

built with the expectation of meeting the applicability criteria based on utilization

and thus being covered by these standards.

The illustrative unit cost and performance characteristics used in this section assume 

representative costs associated with spatially dependent components, such as connecting to

existing fuel delivery infrastructure and the transmission grid. In practice units may experience 

higher or lower costs for these components depending on where they are located. It should be 

noted that the LCOE comparisons presented in this section only represent the cost to the 

generator and do not reflect the additional social costs that are associated with emissions of 

greenhouse gases or other air pollutants. A broader consideration of the health and welfare

(i.e., non-health benefits) impacts of emissions from these technologies is considered in 

Chapter 5.

It is also important to note that both the EIA and the EPA apply a climate uncertainty 

adder (CUA) - represented by a three percent increase to the weighted average cost of capital –

to new, conventional coal-fired capacity types.46 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. While baseline power sector 

modeling scenarios may not specify potential future GHG regulatory requirements, investors in 

the industry typically incorporate some expectation of a future cost to limit CO2 emissions in 

resource planning evaluations that influence investment decisions. Therefore, the CUA reflects 

the additional planning cost typically assigned by project developers and utilities to GHGintensive projects in a context of climate uncertainty. The EPA believes the inclusion of the CUA 

in LCOE estimates is consistent with the industry’s current planning and evaluation framework

for future projects (demonstrable through IRPs and public utility commission orders) and is 

 

CCS, preclude new coal construction. The section also demonstrates how the cost to a non-compliant coal unit 

of complying with the final standard is mitigated by the emission reduction benefits of controlling its emissions. 

46 While this statement is true in the AEO Reference Case, EIA evaluates No GHG Concern where the CUA is 

removed. Results from this scenario on investment in new technology are reported in Table 4-3.
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therefore pertinent when evaluating the cost competitiveness of alternative generating 

technologies.

47

 

In defining the CUA, EIA states that “the adjustment should not be seen as an increase in 

the actual cost of financing, but rather as representing the implicit hurdle being added to GHGintensive projects to account for the possibility they may eventually have to purchase 

allowances or invest in other GHG emission-reducing projects that offset their emissions.”48

Therefore, the EPA recognizes the application of the CUA is context dependent. As a part of the

planning process, it is appropriately applied to evaluating prospective projects, and then 

removed once a project transitions from planning to execution. While omitting the CUA is 

inconsistent with an analysis considering how project characteristics and market conditions 

would lead a developer or utility to select a certain project, as is the purpose of this section, for 

transparency the cost estimates based on the 2015 NETL analysis for non-compliant coal-fired 

projects are presented in the following analysis both with and without the CUA. All LCOE 

estimates of coal-fired facilities with CCS are presented without the CUA, to represent the 

reduced CO2 liability associated with such technologies.

4.5.4 Levelized Cost of Electricity of NGCC and Non-compliant Coal

The EPA’s base LCOE estimates for NGCC, SCPC, and IGCC are shown in Figure 4-3 by 

cost component (capital, FOM, VOM, TS&M, and fuel) and assume a construction date of 2020

and an 85 percent capacity factor. Although the EPA believes that this cost data is broadly 

representative of the economics between new coal and new natural gas facilities, this analysis 

assumes representative new units and does not reflect the full array of new generating sources 

that could potentially be built. To the extent that other types of new EGUs that would be 

affected by this rule are built, they may exhibit different costs than those presented here. For 

example, new conventional coal facilities of a size smaller than what is assumed in the base 

estimate would tend to exhibit a relatively higher LCOE, while some technologies could 

potentially display a lower LCOE if, all else equal, fuel could be obtained at a lower price than 

that assumed in this analysis (such as may be the case for petroleum coke or waste coal 

 

47 For example, a 2011 Synapse Report lists 15 utilities that adopted a value for estimating CO2 emissions liability in 

their integrated resource planning. http://www.synapse-energy.com/Downloads/SynapsePaper.2011-

02.0.2011-Carbon-Paper.A0029.pdf. In addition to utilities, several state commissions have mandated the 

inclusion of potential financial liabilities associated with CO2 emissions in long-term planning (e.g., Minnesota 

utilities must adopt a price beginning in 2017).

48 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
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facilities). These potential differences do not fundamentally change the analysis presented in 

this RIA.

On a levelized cost basis, NGCC is significantly cheaper than all of the non-compliant

coal-fired options. For technologies that are included in the IPM Base Case and the AEO, their 

LCOE values are comparable to the LCOE values calculated from the NETL study. The difference 

in the LCOE of NGCC and non-compliant coal technologies explains the finding in the sectoral 

modeling described above that natural gas generation is forecast to be the source of new fossilfired generation. 

In addition to the disparity in total LCOE, there are fundamental differences in the cost 

composition between natural gas- and coal-fired facilities. NGCC costs are dominated by fuel 

expense while the levelized cost of coal-fired technologies driven by capital expense. 

Consequently, this section will explore the impact of changes in natural gas price and the 

capital costs of coal-fired facilities to better quantify the magnitude of the relative cost 

advantage NGCC exhibits over coal-fired alternatives.

Figure 4-3. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation 

Technologies by Cost Component

Notes: 
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(1) The coal assumed is a bituminous coal with a sulfur content of 2.8 percent (dry) and a real delivered price of 

$2.94/MMBtu consistent with NETL 2015. 

(2) The levelized delivered price of natural gas is $6.19/MMBtu (2011$).

(3) SCPC and IGCC without CCS are shown first without any CUA and then with a 3 percent CUA.

(4) The cost of CO2transport, storage and monitoring (TS&M) is included as part of LCOE for SCPC with 18 percent

CCS, which captures and sells CO2. 

(5) A capacity factor of 85 percent is assumed across all technologies.

(6) NETL uses a high-risk financial structure resulting in a capital charge factor (CCF) of 0.124 to evaluate the costs of 

all cases with CO2 capture (non-capture case uses a conventional financial structure with a CCF of 0.116).

(7) For comparison, EIA estimates of levelized costs in 2019 under AEO 2014 Reference Case assumptions for SCPC 

and IGCC are $94.4/MWh and $114.7/MWh ( both in 2012$), respectively, including a 3 percent CUA and 

excluding transmission investment costs.49 The levelized costs presented above are based on NETL assumptions 

and will necessarily differ from AEO 2014 levelized costs for a variety of reasons, including cost and performance 

characteristics, financial assumptions, and fuel input prices. 

Figure 4-4 presents the LCOE of an NGCC facility at four alternative levelized natural gas 

price levels. For comparison, the LCOE estimates for SCPC and IGCC (with no CO2 control) 

including the CUA are provided as well.50

 

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

50 Some new units could be designed to combust waste coal or petroleum coke (pet coke), which may be affected

by this rule. These technologies could exhibit different local economics, particularly in the delivered price of 

fuel. From a capital and operating perspective, the EPA believes the cost and performance of these units are 

broadly similar and therefore well represented by new, conventional coal-fired facilities (e.g. SCPC).
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Figure 4-4. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation 

Technologies Across Alternative Natural Gas Prices

It is only when natural gas prices exceed $11/MMBtu on a levelized basis (in 2011$) that new 

coal-fired generation without CCS approaches parity with NGCC in terms of the LCOE. None of 

the AEO 2014 scenarios described in this chapter project national average natural gas prices 

near that level.

51

 To achieve an $11/MMBtu levelized price in 2020 would require a 

significantly more pessimistic natural gas outlook than what is contained in AEO’s low natural 

gas resource scenario. To illustrate, Table 4-6 report the levelized natural gas prices (initial year 

of 2020) for both a 20-year period (to accommodate the end of EIA’s modeling projections in 

2040) and 30-year period (calculated by continuing the projected level of price increases 

through 2050).

 

51 As noted earlier in this chapter, investment decisions require consideration of fuel price projections over long 

periods of time; similarly, the power sector modeling cited here make fuel price projections over long periods 

of time. Neither these modeling projections nor these LCOE calculations are meant to suggest that the gas 

price could not reach as high as $10/MMBtu at any given point in time, but these analyses do not expect such a 

price level to be sustained over a period of time that would influence an economic assessment of which type of 

new capacity offers a better investment.

$60

$86

$93

$113

$94

$118

$0

$20

$40

$60

$80

$100

$120

$140

NGCC

($6.19/MMBtu)

NGCC

($10/MMBtu)

NGCC

($11/MMBtu)

NGCC

($14/MMBtu)

SCPC (w. CUA) IGCC (w. CUA)

LC

OE, $/M

Wh (2011$)
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4-29

Table 4-6. Levelized Natural Gas Prices by Select AEO 2014 Scenario (2011$/MMBtu)

Scenario

20-Year AEO 

Projection

(2020-2039)

30-Year AEO-Based 

Projection

(2020-2049)

Reference 6.07 6.53

High Growth 6.32 6.96

Low Growth 5.78 6.20

High Coal Cost 6.19 6.69

Low Coal Cost 6.03 6.47

High Gas/Oil Resource 4.80 4.85

Low Gas/Oil Resource 7.70 8.45

Note: Discount rate of 5 percent, consistent with IPM assumptions. The 30-year natural 

gas price is calculated by applying the average annual rate of price increase from 2035 to 

2040 in all subsequent years from 2041 through 2049. The scenarios are described in 

Table 4-4. 

As an illustration, one potential price path that would achieve a $10/MMBtu on a 20-

year levelized basis in 2020 is a natural gas price path 30 percent higher than EIA’s low resource 

scenario in all years (see Figure 4-5). This illustrative price path to achieve a $10/MMBtu 

levelized price would result in an $11.02/MMBtu annual real price in 2030 and a 

$13.81/MMBtu real price in 2040. Even on this significantly higher price path, a representative 

NGCC unit would have a lower LCOE than a non-compliant coal unit. What this information 

indicates is that natural gas price forecasts need to be notably higher than the highest forecast 

in the AEO 2014 scenarios before we would expect that general market dynamics would favor 

new non-compliant coal generation over new compliant natural gas generation as the fossilfuel technology of choice to satisfy demand. Chapter 5 discusses this finding further by bringing 

in the consideration of the emissions damages associated with these technologies. 
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Figure 4-5. Projected Real National Delivered Natural Gas Price for Select AEO 2014 

Scenarios and Illustrative Path for > $10/MMBtu Levelized Price

It is important to note that the LCOE calculations are based on assumptions regarding 

the representative national cost of generation at new facilities.52 It is known that there is 

significant spatial variation in the costs of new generation due to design differences, labor 

productivity and wage differences, and delivered fuel prices, among other potential factors. 

For example, EIA utilizes capital cost scalars to capture regional differences in labor, material 

 

52 Actual reported project costs for all of the plant types are also expected to deviate from the cost estimates in 

this report due to project- and site-specific considerations (e.g. contracting strategy, local labor costs, seismic 

conditions, water quality, financing parameters, local environmental concerns, weather delays, etc.) that may 

make construction more costly. Such variations are not captured by the reported cost uncertainty

$6.07

$4.80

$7.70

$10.00

$0

$2

$4

$6

$8

$10

$12

$14

2015 2020 2025 2030 2035 2040

Gas Price Delivered to EG

Us (2011$/M

MBtu)

Reference Low Gas & Oil Resources

High Gas & Oil Resources Illustrative Path to $10 Gas

Levelized Price
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4-31

and construction costs. 53 The minimum and maximum capital cost scalars across all regions in 

AEO 2014 for SCPC, IGCC, and NGCC build options are presented in Table 4-7.

54

Table 4-7. AEO 2014 Regional Capital Cost Scalars by Capacity Type

Capacity Type Minimum Capital 

Cost Scalar

Maximum Capital Cost 

Scalar

SCPC 0.885 1.152

IGCC 0.908 1.136

NGCC 0.893 1.205

Applying the regional capital cost scalars displayed above to the base LCOE estimates

from NETL developed earlier in this section produces only a small change in the relative 

competitiveness of the technologies as seen in Table 4-8.

Table 4-8. LCOE Estimates with Minimum and Maximum AEO 2014 Regional Capital Cost 

Scalars (2011$/MWh)

Capacity Type

Reference 

LCOE

($/MWh)

LCOE Using 

Minimum Capital 

Cost Scalar

($/MWh)

LCOE Using

Maximum Capital 

Cost Scalar

($/MWh)

SCPC (no CCS, without CUA) 82 73 95

SCPC (no CCS, with CUA) 94 83 108

IGCC (no CCS, without CUA) 103 93 117

IGCC (no CCS, with CUA) 118 108 135

NGCC 60 54 72

The LCOE of SCPC in the lowest capital cost region still results in an LCOE that is 1

percent higher than an NGCC located in the most expensive capital cost region, even without

the CUA. (The difference is 15 percent when the CUA is included.) The IGCC LCOE is 29 percent

above NGCC in the most expensive region, even without considering the CUA. 

The other primary driver in determining the regional impact on competitiveness of new 

build options is delivered fuel prices. As part of the AEO, EIA releases electric power 

projections – including fuel prices – for each of the 22 Electricity Market Module (EMM) 

regions. The two regions with the highest projected 2020 natural gas prices in the AEO 2014 

are the Western Electricity Coordinating Council/Southwest (Southwest) and the Florida 

 

53 http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf

54 Excluding the New York City and Long Island areas, as well as those areas of the country that prohibit the 

development of new, non-compliant coal-fired facilities.
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4-32

Reliability Coordinating Council (FRCC). The 20-year levelized natural gas and coal price 

forecasts (2020-2039) in the AEO 2014 reference case are displayed in Figure 4-6 for both 

regions.

Figure 4-6. Levelized Regional Fuel Price from AEO 2014 Reference Case, 2020-2039 

(2011$/MMBtu)55 

The FRCC region experiences the highest overall natural gas prices as well as a greater 

unit price differential between coal and natural gas prices under the AEO projections. The 

impact on the LCOE of the SCPC, IGCC, and NGCC technologies without CCS is reported in Table 

4-9 for both sets of fuel prices, as well as the national average for comparison. 

Table 4-9. LCOE Estimates For Minimum and Maximum AEO 2014 Regional Fuel Prices

(2011$/MWh)

Capacity Type

LCOE Using 

National 

Average Fuel 

Prices

($/MWh)

LCOE Using FRCC 

Fuel Prices

($/MWh)

LCOE Using 

Southwest Fuel 

Prices

($/MWh)

SCPC (no CCS, without CUA) 82 94 82

SCPC (no CCS, with 3% CUA) 94 105 93

IGCC (no CCS, without CUA) 103 114 102

IGCC (no CCS, with 3% CUA) 118 130 118

NGCC 60 87 70

 

55 Assuming 5 percent discount rate.

$10.12 

$7.61 

$3.67 

$2.46 

$0

$2

$4

$6

$8

$10

$12

FRCC WECC-Southwest

Levelized Cost of Delivered Fuels

(2011$/M

MBtu)

Gas Coal
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4-33

Due to the greater fuel price differential, the more favorable region for the 

development of coal-fired facilities from an LCOE perspective is the FRCC, where the regional 

fuel prices reduce the LCOE advantage of NGCC to $7/MWh over SCPC (compared with a 

$22/MWh advantage with national fuel prices) and $27/MWh over IGCC (compared with a 

$43/MWh advantage with national fuel prices.

In conclusion, even the most favorable combination of regional variability in capital 

costs and delivered fuel prices represented by EIA are insufficient to support new, unplanned, 

conventional coal-fired capacity in the analysis period.

4.5.5 Levelized Cost of Simple Cycle Combustion Turbine and Natural Gas Combined Cycle

Simple cycle combustion turbines (CTs) fulfill a fundamentally different function in 

power sector operations than that of NGCC and fossil-fired steam facilities. CTs are designed to 

start quickly in order to meet demand for electricity during peak operating periods and are 

generally less expensive to build on a capital cost basis, but are also less fuel efficient than 

combined cycle technology, which employs heat recovery systems. Due to lower fuel 

efficiencies, CTs produce a significantly higher cost of electricity (cost per kWh) at higher 

capacity factors and consequently are typically utilized at levels below the applicability 

requirements for EGUs affected by the EGU New Source GHG Standards. New CTs are expected 

to most often be built to ensure reserve margins are met during peak periods (typically in the 

summer), and in some instances be able to generate additional revenues by selling capacity into 

power markets. The EPA expects that any CT unit built in the period of analysis would be 

classified as a non-base load unit and would not incur any costs to meet the relevant standard. 

To illustrate the economic incentives of utilizing combustion turbines in an intermediate 

and base load mode of operation, Figure 4-7 presents the LCOE estimates for a new 

conventional CT, Advanced CT and NGCC at increasing capacity factors. The estimates utilize 

the AEO 2014 Reference Case levelized natural gas price for 2020.
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4-34

Figure 4-7. Levelized Cost of Electricity Across a Range of Capacity Factors, CT and NGCC 

(2011$/MWh at $6.07/MMBtu Levelized Natural Gas Price)

In the LCOE figure above, utilizing a CT for generation is less expensive than an NGCC 

unit only at capacity factors of less than 20 percent.

56

 If expected utilization is greater than 20

percent, it can reasonably be expected that a utility or developer would seek to deploy NGCC 

over CT for a host of economic, environmental, and technical reasons. Furthermore, the design 

net efficiencies for currently available potentially impacted aeroderivative simple cycle 

combustion turbines range from approximately 32 percent for smaller designs to 39 percent for 

the largest intercooled designs. The efficiencies of industrial frame units range from 30 percent 

for smaller designs to 36 percent for the largest units.57 The EPA therefore expects any CT unit 

built in the period of analysis to be classified as a non-base load unit.

4.6 Macroeconomic and Employment Impacts58

These final EGU New Source GHG Standards are anticipated to result in negligible 

emission changes in the electricity sector in the analysis period, and therefore are anticipated 

to impose negligible costs or quantified benefits. The EPA typically analyzes impacts on

 

56 CT cost, performance, and financial assumptions from AEO 2014.

57 These efficiency values follow the methodology the EPA has historically used and are based on the higher 

heating value (HHV) of the fuel. Low heating value efficiency values would be somewhat higher.

58 The employment analysis in this 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).

$0

$50

$100

$150

$200

$250

$300

$350

0% 20% 40% 60% 80% 100%

LC

OE (2011$/M

Wh)

Capacity Factor

NGCC Conventional CT Advanced CT
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4-35

employment or labor markets associated with rules based on the estimated compliance costs 

and other energy impacts (e.g., changes in electricity prices), which serve as an input to such 

analyses. However, since the EPA does not forecast a change in behavior relative to the 

baseline in response to this rule, there are no notable macroeconomic or employment impacts 

expected as a result of this rule. 

4.7 References

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emission reductions for 17 industrial, area and mobile emission sectors across the U.S.

Environment International, Volume 49, 15 November 2012, Pages 141-151, ISSN 0160-

4120, http://dx.doi.org/10.1016/j.envint.2012.08.017.

Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz, 

and W.H. White. 2009. “Reanalysis of the Harvard Six Cities Study and the American 

Cancer Society Study of Particulate Air Pollution and Mortality.” Special Report to the 

Health Effects Institute. Cambridge, MA. July.

Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. “Chronic Exposure to Fine Particles and 

Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.

Malik, N.S. 2010, November 1. NextEra CEO sees clean energy standards replacing recent 

climate proposals [Radio transcript]. Dow Jones News [Online]. Available: Dow Jones 

Interactive Directory: Publications Library.

Mufson, S. January 2, 2011. “Coal’s Burnout.’ The Washington Post. Retrieved from: 

http://www.washingtonpost.com/newssearch.National Energy Technology Laboratory

(NETL). Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide

Capture. Revised Sept. 16, 2013. Available online at: http://www.netl.doe.gov/energyanalyses/pubs/Gerdes-08022011.pdf.

National Energy Technology Laboratory (NETL). Cost and Performance Baseline for Fossil Energy 

Plants Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants. June 22, 

2015. Available online at: http://www.netl.doe.gov/research/energy-analysis/energybaseline-studies.

Rosenberg, M. 2011, September/October. “The Reign of Cheap Gas.” EnergyBiz Magazine. 

Retrieved from http://www.energybiz.com/magazine/article/234577/reign-cheap-gas.

Tong, S. 2010, November 1. Placing Bets on Clean Energy. [Radio transcript]. American Public 

Media: Marketplace [Online]. Available: Marketplace Programs on Demand.
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National Petroleum Council. 2011. Prudent Development: Realizing the Potential of North 

America's Abundant Natural Gas and Oil Resources. Available online at: 

http://www.npc.org/reports/rd.html.

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010. Available 

online at: http://www.eia.gov/oiaf/archive/aeo10/index.html. 

U.S. Energy Information Administration (U.S. EIAa). Annual Energy Outlook 2014. 2014. 

Available online at: http://www.eia.gov/forecasts/aeo/.

U.S. Energy Information Administration (U.S. EIA). U.S. Crude Oil and Natural Gas Proved 

Reserves, 2013Available online at:

http://www.eia.gov/naturalgas/crudeoilreserves/pdf/usreserves.pdf

U.S. Energy Information Administration (U.S. EIAb). Assumptions to the Annual Energy Outlook 

2014. 2014. Available online at: 

http://www.eia.gov/forecasts/aeo/assumptions/pdf/0554(2014).pdfU.S. Environmental 

Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis for the Final Mercury 

and Air Toxics Standards. Office of Air Quality Planning and Standards, Research Triangle 

Park, NC. December. Available on the Internet at 

http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the 

Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. 

Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. 

Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2013a. Technical Support Document 

Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of 

Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on 

the Internet at: 

http://www.epa.gov/airquality/benmap/models/Source_Apportionment_BPT_TSD_1_3

1_13.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2013b. Integrated Science Assessment for 

Ozone and Related Photochemical Oxidants. EPA/600/R-10/076F. Research Triangle 

Park, NC: U.S. EPA. February. Available on the Internet at 

http://oaspub.epa.gov/eims/eimscomm.getfile?p_download_id=511347.
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CHAPTER 5

ANALYSIS OF ILLUSTRATIVE BENEFIT-COST SCENARIOS FOR NEW SOURCES

5.1 Synopsis

The previous chapter of this regulatory impact analysis (RIA) presents the U.S. 

Environmental Protection Agency’s (EPA) analysis and projections from the U.S. Energy 

Information Administration (EIA) that support the conclusion that the EGU New Source 

Standards1 will result in negligible costs and benefits in the period of analysis. The EPA 

recognizes that this conclusion is based on underlying expected economic conditions (e.g., fuel 

prices) and assumptions about considerations investors would weigh in deciding whether to 

build new non-compliant coal-fired power plants. Extending the analysis in the previous chapter 

that considers those factors in evaluating the robustness of the findings from the sectoral 

perspective, this chapter presents the results of several illustrative analyses that show, under a 

range of alternative conditions, the potential costs and benefits of these standards for 

individual investments that provide base load dispatchable generation. We evaluate conditions 

under which different generator types are constructed in lieu of a non-compliant supercritical 

coal unit and estimate the benefit of adopting the investment that is compliant with the 

standards. This also allows us to consider the costs and benefits of a situation where an 

operator chooses to build a new coal-fired unit that is compliant with the standard. 

While the analysis in Chapter 4 focuses on national level conditions, the analysis in this 

chapter explores the potential impacts to individual investments. The analysis in this chapter 

finds that under unlikely conditions in which the EPA’s conclusions regarding the future 

economic competitiveness of new non-compliant coal-fired units relative to other new 

generation technologies no longer apply, or in specific situations where an operator chooses to 

build a coal-fired unit, that the quantifiable benefits of the standards outweigh the costs under 

a range of assumptions.

5.2 Comparison of Emissions from Generation Technologies

As discussed in Chapter 4, natural gas combined cycle (NGCC) units are on average 

expected to be more economical to build and operate than new coal units (see section 4.5).

Therefore, as our point of departure for comparing the costs and benefits of an individual 

investment decision, we evaluate the private cost of a new NGCC unit that is compliant with the 

finalized standards with the private cost of a new, non-compliant conventional supercritical 

 

1

The standards for modified and reconstructed sources are addressed in Chapter 6.
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pulverized coal (SCPC) coal-fired unit.2 When evaluating the costs and benefits associated with 

these standards, it is also important to understand the difference in emissions associated with 

these units. In addition to being more economical, new NGCC units have lower emission

profiles for CO2 and criteria air pollutants than new coal units. For example, a typical new SCPC 

facility that burns bituminous coal in compliance with current utility regulations (e.g., the 

Mercury and Air Toxics Standards (MATS)) would have considerably greater CO2, sulfur dioxide 

(SO2), nitrogen dioxide (NOx), toxic metals, acid gases, and particulate emissions than a 

comparable NGCC facility. 

Table 5-1 shows that emissions of these pollutants from a typical new NGCC unit are 

significantly lower than those from a new coal-fired unit.3 The emission characteristics are 

based on, and thus consistent with, the cost and performance assumptions of the illustrative 

units described in the levelized cost of electricity (LCOE) analysis in section 4.5. That is, these 

are base load units of the same net capacity operating at an 85 percent capacity factor, the coal 

unit is assumed to be using bituminous coal with a sulfur content of 2.8 percent dry, they are in 

compliance with current utility regulations (e.g., the MATS), etc. The typical new NGCC unit 

would emit about 1.9 fewer million tons of CO2 per year than the typical new SCPC unit, as well 

as roughly 1,700 fewer tons of SO2 and about 1,300 fewer tons of NOx per year than the SCPC 

unit. Table 5-1 also provides comparable information for a representative integrated 

gasification combined cycle (IGCC) unit providing the same amount of electricity and using the 

same coal. The new IGCC unit would emit less CO2, SO2 and NOx than a typical coal-fired SCPC 

unit, but has higher emissions of each of these pollutants than a new NGCC unit. Reductions in 

SO2 emissions are a particularly significant driver for monetized health benefits, as SO2 is a 

precursor to the formation of particulates in the atmosphere, and particulates are associated 

with premature death and other serious health effects. NOX is both an ozone precursor, and is

associated with formation of secondary fine nitrate PM2.5. Both ozone and fine nitrate PM2.5

are associated with significant adverse health effects, including premature mortality. Further 

information on these pollutants’ health and welfare effects is described in Chapter 3. 

Table 5-1 also shows the representative coal units’ emissions of these same pollutants 

when meeting the promulgated standard of performance of 1,400 lb CO2/MWh. Two compliant 

 

2

As discussed in section 4.4.1 and in the preamble, we expect new NGCC capacity built in the period of analysis 

will be compliant with the standard even in the absence of the standard. As a result, there are no compliance 

costs anticipated for new NGCC units.

3

Estimated emissions of CO2, SO2, and NOX for the illustrative new coal and NGCC units could vary depending on a 

variety of assumptions including heat rate, fuel type, and emission controls, amongst others.
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SCPC units are presented: one uses carbon capture and storage (CCS) and another that co-fires 

natural gas. The compliant IGCC unit is assumed to co-fire natural gas. For the compliant SCPC 

unit using CCS, in addition to reductions of CO2, SO2 emissions would also decrease due to the 

need to scrub acid gases to very low levels prior to carbon capture in order to prevent 

degradation of the solvent involved in the capture process.4The NOX emission rate, measured 

on a net-basis, is slightly lower for non-compliant units than both compliant SCPC units. This is 

because there is a fuel efficiency loss associated with both compliance technologies and 

because NOX emission rate standards for new sources are on a gross-basis. While we account 

for these increases in the NOX emission rate in the analysis below, in some cases, NOX emissions

from fossil-fired sources are also subject to mass limits on the total NOX emissions across EGUs 

(e.g. in states subject to the Cross-State Air Pollution Rule annual NOX program), so these 

emissions may be offset by NOX reductions from other generating units.

 

4

See NETL 2015 at 161.
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Table 5-1. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired 

Generating Units

Natural Gas CC SCPC SCPC+Partial CCS 

(1,400 lb/MWh 

Gross)

SCPC+Co-Fire Nat 

Gas

IGCC IGCC+Co-Fire Nat 

Gas

Emissions 

Emission 

Rate Emissions 

Emission 

Rate Emissions 

Emission 

Rate Emissions 

Emission 

Rate Emissions 

Emission 

Rate Emissions 

Emission 

Rate 

SO2 84 0.0041 1,500 0.71 1,200 0.61 1,500 0.71 18 0.0087 18 0.0087

NOx 130 0.061 1,500 0.74 1,500 0.75 1,500 0.74 1,100 0.52 1,100 0.52

CO2 1.6

million 800

3.5

million 1,700

3.1

million 1,500

3.0

million 1,500

3.5

million 1,700

3.4

million 1,700

Notes: Emissions from NETL 2015. Emissions are in short tons/year and Emission Rates are in net lb/MWh. Values rounded to two significant digits. Emission 

characteristics are based on, and thus consistent with the cost and performance assumptions of, the illustrative units described in LCOE analysis in section 4.5

(i.e., these are base load units running at 85 percent capacity factor, all coal units are assumed to be using bituminous coal with a sulfur content of 2.8 percent

dry, etc.). The tons of emissions are estimated for a coal-fired facility that achieves the gross-output standard of 1,400 lb/MWh and presented in this table on a 

net output basis. For the post-combustion CCS system assumed in the SCPC case, acidic gases (e.g., SO2, HCl) need to be scrubbed to very low levels prior to 

going to the CCS system to avoid degradation of the solvent. Therefore, SO2 emissions are lower in the case of the SCPC unit with partial CCS. See preamble for 

discussion about the format of the standard. Here we further assume all units are of the same capacity (600 MW net).
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5.3 Comparison of Health and Climate Impacts from Generation Technologies

As discussed in the previous section, the emissions of GHGs and other pollutants 

associated with new sources of electricity generation are greater for coal-fired units than for 

NGCC units. Reducing the emissions associated with electricity generation results in climate, 

human health, and non-health benefits. 

To consider the health and climate benefits associated with the adoption of lower 

emitting new generation technologies, we apply the 2022 benefit values discussed in Chapter 3 

to the differences in illustrative emission profiles between the technologies in Table 5-1.

1

Specifically, we multiply the difference in CO2 emissions between two technologies by the 

estimates of the social cost of carbon dioxide (SC-CO2) (Table 3-1), multiply the difference in 

SO2 and NOX emissions by the PM2.5-related SO2 and NOX benefit per ton (BPT) estimates (Table 

3-2), and add those values to get a measure of the 2022 benefits attributable to differences in 

emissions of adopting the lower emitting new generation technology. We subsequently divide

by the amount of generation (in MWh) underlying the annual emissions estimates to derive the 

benefits attributable to the differences in emissions per unit of generation. 

Only the direct emissions of CO2, SO2, and NOX are considered in this illustrative 

exercise. Other air and water pollutants emitted by these technologies and emissions from the 

extraction and transport of the fuels used by these technologies are not considered. For 

example, coal has higher mercury emissions than natural gas, but the relative benefits from the 

difference in mercury emissions are not considered. A similar example of emissions not 

considered are those of directly emitted PM2.5. Furthermore, there may be differences in 

upstream greenhouse gas emissions (in particular, methane) from different technologies which

were not quantified for this assessment.

Table 5-2 reports the 2022 incremental climate and health benefits associated with a 

new NGCC unit relative to a new coal-fired SCPC and IGCC units, given different mortality risk 

studies and assumptions about the discount rate. These benefits are based on the emissions 

presented in Table 5-1. The benefits presented in Table 5-2 are estimated on an output basis to 

enable easier comparisons to the potential costs of investing in a new non-compliant coal-fired 

 

1

Due to data limitations, we are not able to estimate annualized benefits from the stream of emissions over the 

lifetime of the generating technologies. Because the benefit per-ton of emission reductions increases over time, 

due in part to population growth, the single year estimate results in a conservative comparison of benefits to 

costs where LCOE represents annualized lifetime costs of generating technologies.
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unit relative to a new NGCC unit. These incremental benefits should be relatively invariant 

across natural gas prices and other economic factors. Depending on the discount rate and 

mortality risk study used, 2022 incremental benefits associated with generation from a 

representative new NGCC unit relative to a new coal-fired SCPC or IGCC unit are $7.0 to $91 per 

MWh (2011$).2

The health and non-health benefits associated with reduced emissions can depend on a 

number of factors, including the specific fuels combusted and the location of the emissions. 

While the benefits of reduced CO2 emissions do not depend on the location of generation

because the location of CO2 emissions does not influence their impact on the evolution of 

global climate conditions, the precise incremental health co-benefits will be location specific

and depend on the specific fuels used. However, these factors will not change the qualitative 

conclusion. There will be incremental climate and human health benefits associated with a new 

NGCC unit relative to a new coal-fired unit, independent of the location. 

 

2

Different discount rates are applied to SC-CO2 than to the other benefit estimates because CO2 emissions are 

long-lived and subsequent damages occur over many years. Moreover, several rates are applied to SC-CO2

because the literature shows that it is sensitive to assumptions about discount rate and because no consensus 

exists on the appropriate rate to use in an intergenerational context. The SC-CO2 interagency working group 

centered its attention on the 3 percent discount rate but emphasized the importance of considering all four SCCO2 estimates. See the 2010 SC-CO2 TSD. Docket ID EPA-HQ-OAR-2009-0472-114577 or 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf for 

details.
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Table 5-2. Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Illustrative New 

Natural Gas Combined Cycle Generation Relative to New Non-Compliant SCPC or IGCC 

Coal Generation in 20221

SCPC IGCC

CO2-Related Benefits using SC-CO2

5% Discount Rate $5.7 $5.8

3% Discount Rate $19 $19

2.5% Discount Rate $28 $28

3% Discount Rate (95th percentile) $56 $57

Total PM2.5-Related Co-Benefits from SO2 and NOX Changes

3% discount rate

Krewski et al. (2009) $15 $1.3

Lepeule et al. (2012) $34 $3.0

7% discount rate

Krewski et al. (2009) $14 $1.2

Lepeule et al. (2012) $31 $2.7

Combined CO2-Related and PM2.5-Related Benefits 

Discount Rate Applied to PM2.5-Related Benefits 

(range based on adult mortality function)

SC-CO2 Discount Rate 3% 7% 3% 7%

5% Discount Rate $21 to $40 $19 to $37 $7.1 to $8.8 $7.0 to $8.5

3% Discount Rate $34 to $53 $33 to $50 $20 to $22 $20 to $22

2.5% Discount Rate $43 to $62 $42 to $59 $30 to $31 $30 to $31

3% Discount Rate (95th percentile) $72 to $91 $70 to $87 $59 to $60 $58 to $60

Notes: The emission rates and operating characteristics of the units being compared in this table are reported in Table 5.1. Benefits are 

estimated for a 2022 analysis year. The range of benefits within each SC-CO2 value and discount rate for PM2.5-related benefits pairing 

reflects the use of two core estimates of PM2.5-related premature mortality.2The EPA has evaluated the range of potential impacts per 

MWh by combining all SC-CO2 values with health benefits values at the 3 percent and 7 percent discount rates. Combining the 3 percent 

SC-CO2 values with the 3 percent health benefit values assumes that there is no difference in discount rates between intragenerational 

and intergenerational impacts. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor 

reductions (Table 3-2), which are representative of 2022.

 

1

This analysis assumes representative new units and does not reflect the full array of new generating sources that could 

potentially be built (e.g., a comparison of a small new conventional coal-fired unit with a small natural gas-fired unit, or 

a comparison of a waste coal or petroleum coke-fired unit to a natural gas-fired unit of a comparable size and capacity 

factor). However, the damages associated with other units that could be built, and which would be subject to this rule, 

would not change noticeably (i.e., these new facilities would be subject to emissions standards for other pollutants and 

would emit similar levels of SO2, NOX, and CO2, on an output basis) except for differences in location, as discussed 

previously.

2

The range of estimated benefits for each discount rate is due to the EPA’s use of two alternative primary estimates of 

PM2.5-related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a higher primary estimate 

based on Lepeule et al. (2012).
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The conclusion from this analysis is that there are significant environmental and health 

benefits associated with electricity generation from a representative new NGCC unit relative to 

a new non-compliant coal-fired unit. Other studies of the social costs of coal and natural gasfired generation provide similar findings (Muller et. al., 2011; NRC, 2009).1

As explained previously, the power sector has moved away from the construction of 

coal-fired power plants in favor of other generation (e.g., natural gas-fired power plants) due, in 

part, to the significant cost differential. Even so, it is possible that a limited number of currently 

unplanned coal-fired power plants would be constructed through 2022. In these circumstances, 

the construction of compliant coal-fired units in place of non-compliant coal-fired units would 

result in relative climate and human health and non-health benefits. Table 5-3 reports the 2022 

incremental benefits associated with a new SCPC coal-fired unit with CCS relative to a new SCPC 

coal-fired unit, given different mortality risk studies and assumptions about the discount rate. 

The values are calculated based on the emissions presented in Table 5-1. Depending on the 

discount rate used and mortality risk study used, 2022 incremental benefits associated with 

generation from a representative new SCPC coal-fired unit with CCS relative to a new SCPC unit 

without CCS are $3.1 to $18 per MWh (2011$), factoring in the disbenefit from a small increase 

in NOx emissions.

2

These incremental benefits will be referenced in the analyses presented in 

subsequent sections. 

 

1 Muller et al. 2011 conclude that, “coal-fired power plants have air pollution damages larger than their value 

added”, while the same is not true for natural gas plants (see Table 5 in Muller et al.). However, these 

comparisons are based on typical existing coal and natural gas units, including natural gas boilers, and are not 

sensitive to location (although the underlying analysis in the study does account for differences in the location 

of existing units when estimating damages). The NRC 2009 study shows that only the most polluting natural gas 

units may cause greater damages than even the least polluting existing coal plants (compare Tables 2-9 and 2-

15 in NRC 2009). However, the NRC comparison does not compare new units located in the same place, and so 

some of the natural gas units with the greatest damages may be attributable to their location, and includes 

natural gas steam boilers, which have a higher emission rates per unit of generation than NGCC units. Despite 

these caveats, the finding of these two studies are consistent with the findings in this section. 

2

Different discount rates are applied to SC-CO2 than to the other benefit estimates because CO2 emissions are 

long-lived and subsequent damages occur over many years. Moreover, several rates are applied to SC-CO2

because the literature shows that it is sensitive to assumptions about discount rate and because no consensus 

exists on the appropriate rate to use in an intergenerational context. The SC-CO2 interagency group centered its 

attention on the 3 percent discount rate but emphasized the importance of considering all four SC-CO2

estimates. See the 2010 SC-CO2 TSD for details. Docket ID EPA-HQ-OAR-2009-0472-114577 or 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf.
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Table 5-3. Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Compliant 

Coal-Fired Generation with CCS meeting 1,400 lb/MWh Standard Relative to New

Non-Compliant Coal-Fired Generation in 2022

SCPC 

CO2-Related Benefits using SC-CO2

5% Discount Rate $1.3

3% Discount Rate $4.4

2.5% Discount Rate $6.6

3% Discount Rate (95th percentile) $13

Total PM2.5-Related Benefits from SO2 and NOX Changes

3% discount rate

Krewski et al. (2009) $1.9

Lepeule et al. (2012) $4.3

7% discount rate

Krewski et al. (2009) $1.7

Lepeule et al. (2012) $3.9

Combined CO2-Related and PM2.5-Related Benefits 

Discount Rate Applied to 

PM2.5-Related Benefits 

(range based on adult 

mortality function)

SC-CO2 Discount Rate 3% 7%

5% Discount Rate $3.2 to $5.6 $3.1 to $5.2

3% Discount Rate $6.3 to $8.7 $6.1 to $8.3

2.5% Discount Rate $8.5 to $11 $8.3 to $10

3% Discount Rate (95th percentile) $15 to $18 $15 to $17
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Notes: Benefits are estimated for a 2022 analysis year. The range of benefits within each SC-CO2 value and discount rate for 

PM2.5-related benefits pairing reflects the use of two core estimates of PM2.5-related premature mortality.3The EPA has 

evaluated the range of potential impacts per MWh by combining all SC-CO2 values with health benefits values at the 3 percent 

and 7 percent discount rates. Combining the 3 percent SC-CO2 values with the 3 percent health benefit values assumes that 

there is no difference in discount rates between intragenerational and intergenerational impacts. PM2.5-related co-benefits are 

estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 

2022.

Table 5-4 reports the 2022 incremental benefits associated with a new compliant coalfired unit co-firing natural gas relative to a new non-compliant coal-fired unit, given different 

mortality risk studies and assumptions about the discount rate. The values are calculated based 

on the emissions presented in Table 5-1. Depending on whether the unit is SCPC or IGCC, the 

discount rate used, and mortality risk study used, 2022 incremental benefits associated with 

generation from a representative new coal-fired unit co-firing natural gas relative to a new coalfired unit that does not co-fire natural gas are 0.25 to $14 per MWh (2011$).4

These 

incremental benefits will be used in the analyses presented in subsequent sections.

Table 5-4. Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Compliant 

Coal-Fired Generation with Co-Firing Natural Gas Relative to New Non-Compliant 

Coal-Fired Generation in 2022

SCPC Co-Firing Natural Gas IGCC Co-Firing Natural Gas

CO2-Related Benefits using SC-CO2

5% Discount Rate $1.5 $0.25

3% Discount Rate $4.8 $0.82

2.5% Discount Rate $7.2 $1.2

3% Discount Rate (95th percentile) $14 $2.5

Total PM2.5-Related Benefits from SO2 and NOX Changes

3% discount rate

Krewski et al. (2009) - -

Lepeule et al. (2012) - -

 

3

The range of estimated benefits for each discount rate is due to the EPA’s use of two alternative primary 

estimates of PM2.5-related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a 

higher primary estimate based on Lepeule et al. (2012).

4

Different discount rates are applied to SC-CO2 than to the other benefit estimates because CO2 emissions are 

long-lived and subsequent damages occur over many years. Moreover, several rates are applied to SC-CO2

because the literature shows that it is sensitive to assumptions about discount rate and because no consensus 

exists on the appropriate rate to use in an intergenerational context. The SC-CO2 interagency group centered its 

attention on the 3 percent discount rate but emphasized the importance of considering all four SC-CO2

estimates. See the 2010 SC-CO2 TSD for details. Docket ID EPA-HQ-OAR-2009-0472-114577 or 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf.
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7% discount rate

Krewski et al. (2009) - -

Lepeule et al. (2012) - -

Combined CO2-Related and PM2.5-Related Benefits 

Discount Rate Applied to PM2.5-Related Benefits 

(range based on adult mortality function)

SC-CO2 Discount Rate 3% 7% 3% 7%

5% Discount Rate $1.5 $1.5 $0.25 $0.25

3% Discount Rate $4.8 $4.8 $0.82 $0.82

2.5% Discount Rate $7.2 $7.2 $1.2 $1.2

3% Discount Rate (95th percentile) $14 $14 $2.5 $2.5

Notes: Benefits are estimated for a 2022 analysis year. The range of benefits within each SC-CO2 value and discount rate for 

PM2.5-related benefits pairing reflects the use of two core estimates of PM2.5-related premature mortality.5The EPA has 

evaluated the range of potential impacts per MWh by combining all SC-CO2 values with health benefits values at the 3 percent 

and 7 percent discount rates. Combining the 3 percent SC-CO2 values with the 3 percent health benefit values assumes that 

there is no difference in discount rates between intragenerational and intergenerational impacts. PM2.5-related co-benefits are 

estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 

2022.

5.4 Illustrative Analysis – Benefits and Costs of New Source Standards across a Range of 

Gas Prices

As the analysis in Chapter 4 demonstrated, under a wide range of likely electricity 

market conditions – including the EPA base case and EIA reference case scenarios as well as 

multiple alternative scenarios – it is expected that the industry will choose to construct new 

units that already meet the standards of this rulemaking in the baseline. Section 4.5.4 further 

explored how much higher natural gas prices would need to be to favor new non-compliant 

coal generation over new NGCC generation. In this section, we continue that analysis by 

considering the potential impacts of the regulation on benefits if key assumptions regarding 

natural gas prices were to change during the analysis period. The analysis in this section 

indicates that in this scenario, the standards for new sources would result in increased private 

costs, but would also lead to climate and human health benefits, and is highly likely to result in 

net benefits to society as a whole. 6

 

5

The range of estimated benefits for each discount rate is due to the EPA’s use of two alternative primary 

estimates of PM2.5-related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a 

higher primary estimate based on Lepeule et al. (2012).

6

EO 13563 states that each agency must “propose or adopt a regulation only upon a reasoned determination that 

its benefits justify its costs (recognizing that some benefits are hard to quantify).” While the presence of net 

social benefits for a given regulatory option is not the only condition necessary for optimal regulatory design, it 

does signify that the regulatory option is welfare improving for society.
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5-12

Furthermore, this section, as in section 4.5.4, demonstrates that local fuel prices must 

be significantly different than regional differences already captured in IPM and EIA’s modeling 

of private investment costs to favor the construction of a new non-compliant coal-fired unit 

over a new NGCC unit to serve a particular load. Section 4.5.4 describes how regional 

conditions and other factors may influence the LCOE comparison, and how these regional 

differences are already captured in the electricity sector modeling in support of this rule. The 64

different regions in IPM reflect the administrative structure of regional transmission 

organizations (RTOs) and independent system operators (ISOs).7 However, there may be local 

conditions within those regions which differ meaningfully from the broader regional conditions. 

The analysis in this section evaluates how substantially divergent those local conditions must be 

from representative conditions for non-compliant coal generation to be the fossil fuel-fired 

technology of choice to serve demand. 

The starting point for this analysis is the illustrative comparison (presented in Section 

4.5) of the relative LCOE of representative new coal-fired SCPC and IGCC EGUs and

representative NGCC units.

8

That comparison demonstrated a significant difference in the LCOE 

between the coal-fired and natural gas-fired generating technologies. The estimated LCOE for a 

representative NGCC unit is roughly $34 and $43 per MWh less than for a representative new 

coal-fired SCPC or IGCC unit, respectively (see Figure 4-3).9This is consistent with the EPA’s 

expectation that the new source standards for steam units are not projected to impose any 

appreciable costs or quantified benefits under current and likely future market conditions, as 

discussed in Chapter 4. The emissions associated with these technologies, and the benefits in 

terms of reduced damages of operating the new NGCC unit in lieu of the new non-compliant 

coal unit, are reported in the previous section.

 

7

Further disaggregation of the NERC assessment regions and RTOs allows a more accurate characterization of the 

operation of the U.S. power markets by providing the ability to represent transmission bottlenecks across RTOs 

and ISOs, as well as key transmission limits within them.

8

By fixing generation in this comparison, we are assuming that both technologies generate the same benefits in 

the form of electricity generating services. We assume in the discussion that the benefit of electricity 

production to consumers outweighs the private and social investment cost. However, a caveat of our 

comparison is that at particularly high fuel prices this might not be the case (that is, at high costs for both 

technologies, it may not be worthwhile to construct either technology). For a discussion of when comparing the 

levelized costs of different generating technologies provides informative results and when it does not see, for 

example, Joskow 2010 and 2011. 

9

The reported decrease in the LCOE from adopting NGCC are relative to the SCPC with 3 percent carbon 

uncertainty adder (CUA) and IGCC without 3 percent CUA. The CUA is described in Chapter 4. 
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5-13

To supplement this conclusion, this section identifies three relevant ranges within the 

distribution of future natural gas prices that can be classified as likely gas prices, unexpectedly 

high natural gas prices, and unprecedented natural gas prices. Because the cost of natural gas is 

a significant share of the LCOE for NGCC units, we evaluate how changes in natural gas prices 

affect differences in the relative private costs of new technologies. We identify the natural gas 

price when the private costs, which are inclusive of the CUA for the SCPC, suggest that a new 

non-compliant coal unit may be adopted by an investor in lieu of a new NGCC unit. We then 

compare the social costs of these technologies, which is inclusive of both the private costs of 

these technologies and the damages from these technologies but exclusive of the CUA, at this 

natural gas price.10 We then identify the natural gas price when the social cost of investing in 

the new non-compliant coal unit is plausibly less than the social cost of the new NGCC unit. 

In general, this analysis shows that there would likely be a net social benefit, even under 

scenarios with higher than expected gas prices, if new compliant NGCC units were built in place 

of new non-compliant coal-fired units as a result of this rule.11 Under some conditions, higher

natural gas prices may result in a net social cost of constructing and operating new natural gas 

in lieu of non-compliant coal, holding all other parameters constant and disregarding social 

benefits that we are unable to monetize.

12 However, even under these unlikely conditions these 

 

10 When forecasting the behavior of private actors in choosing between different technologies based on expected 

future costs, we account for a CUA, but when comparing the difference in costs of illustrative new units after 

construction, such as in the analysis of the social costs of these technologies (i.e., the private cost plus the cost 

associated with their emissions), the CUA is not included. The CUA is described in section 4.5.3. The private cost 

of these technologies may differ from the social cost of these technologies for reasons other than their 

associated emissions, as described at the end of Section 5.5. 

11 As previously noted, the benefits estimated in this section are based on a single year (2022) of emissions from 

different generating technologies. Due to data limitations, we are not able to estimate annualized benefits from 

the stream of emissions over the lifetime of the generating technologies. This results in a conservative 

comparison of benefits to costs where LCOE represents annualized lifetime costs of generating technologies.

12 As described below, an outcome where there are net social costs is unlikely to occur over our analysis period and 

for a significant period beyond. However, even a situation where natural gas prices are significantly higher, 

such as very high economic growth, would increase both natural gas and coal prices at the same time - making 

it harder to alter the underlying cost advantage of NGCC generation. Furthermore, even in the situation where 

we report net social costs, it is important to recall that the analysis is limited in the types of benefits and costs 

considered, given that it does not account for the emissions associated with the production and delivery of 

natural gas and coal, the limitations of current SC-CO2 estimates, and the limited accounting of non-CO2

emissions benefits. As previously discussed, the current SC-CO2 estimates do not capture all important all of the 

physical, ecological, and economic impacts of climate change recognized in the climate change literature. 

Despite our attempts to quantify and monetize as many of the co-benefits as possible, the health and welfare 

co-benefits are not fully quantified or monetized in this assessment. For more information about unquantified 

health and welfare co-benefits please refer to tables 5-2 and 6-2 of the PM NAAQS RIA (U.S. EPA, 2012), 

respectively.
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finalized standards may yield social net benefits as there may be other technologies to serve 

demand that would have a lower social cost than a new non-compliant coal unit. 

5.4.1 Likely Natural Gas Prices 

As shown in Chapter 4, it is only when natural gas prices exceed $11/MMBtu on a 

levelized basis (in 2011 dollars) that the representative new non-compliant SCPC unit likely

becomes competitive with new NGCC in terms of its cost of electricity produced. As discussed in 

Chapter 4, none of the AEO2014 scenarios approach this natural gas price level on either a 

forward looking 20-year levelized price basis or on an average annual price basis at any point 

during the analysis period.

13

5.4.2 Unexpectedly High Natural Gas Prices

At natural gas prices above $11/MMBtu, the private LCOE for a new SCPC unit may fall 

below that of a new NGCC unit.14 Therefore, in the event of such unexpectedly high levelized 

fuel prices, some new SCPC units might be constructed in the absence of this final rulemaking,

provided that coal price do not rise at the same time, there is sufficient demand for electricity,

and new non-compliant SCPC units are competitive with other new and existing generating 

technologies other than NGCC units. In this scenario, we expect some compliance costs if a new 

NGCC unit (or a compliant coal-fired unit) were to be built in lieu of the non-compliant coal 

unit. However, generation from a new NGCC unit would also have incremental environmental 

and health benefits as it emits less CO2 SO2, and NOx than generation from a new noncompliant SCPC unit (as may a compliant coal-fired unit; see Section 5.5).

For levelized natural gas prices of $11/MMBtu and somewhat higher, the resulting 

emission reduction benefits of building an NGCC unit, rather than a non-compliant SCPC unit, 

will outweigh the increase in costs of an NGCC unit over a non-compliant SCPC unit. This 

observation indicates that the standard for new fossil steam sources would yield net benefits in

the analysis year. For example, at a levelized gas price of $12/MMBtu, the NGCC unit would 

generate electricity for approximately $17/MWh more than the non-complaint SCPC unit on a 

levelized basis,15 and result in incremental benefits from emissions reductions of $19 to 

 

13 As reported in Table 4-6, The projected delivered electricity sector natural gas price for 2020 assuming a 5 

percent discount rate in the AEO 2014 reference scenario is $6.53/MMBtu (2011$). In the “Low oil and gas 

resource” it is $8.45/MMBtu (2011$).

14 As noted above, the private LCOE of the non-compliant SCPC unit is inclusive of the CUA. Also as noted above, 

the CUA is removed for comparisons of the social costs of generating technology. 

15 The LCOE of the representative NGCC unit increases by $6.80/MWh for every $1/MMBtu increase in natural gas 

prices. 
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$91/MWh (see analysis of 2022 relative benefits of NGCC: Table 5-2). The net benefit of this 

scenario would be $2.2 to $73/MWh.

For context, even a natural gas price of $10/MMBtu (in 2011 dollars) is higher than any 

national average annual natural gas price faced by the electric power sector since at least 1996, 

when the EIA historic data series begins.

16 The continued development of unconventional 

natural gas resources in the U.S. suggests that annual gas prices may actually tend to be 

towards the lower end of the historical range. In addition, the highest projected average 

levelized natural gas price for 2020 of any of the AEO 2014 scenarios cited in Chapter 4 is 

$8.45/MMBtu (2011$), which occurs in the Low Oil and Gas Resource scenario (see Table 4-6). 

As discussed in Chapter 4, none of the EIA sensitivity cases (which account for future fuel prices

for both gas and coal) show scenarios where non-compliant coal-fired units become more 

economic than NGCC units in the period of analysis.

5.4.3 Unprecedented Natural Gas Prices

At extremely high natural gas prices, the LCOE for a non-compliant SCPC unit could be 

sufficiently lower than the cost of a new NGCC unit, such that the net benefit of the new fossil 

steam standard in a given year could be negative (i.e., a net cost), at least under some ranges of 

benefit estimates. For example, at a very high17 levelized gas price of $14/MMBtu, the NGCC

unit would generate electricity for roughly $31/MWh more than the illustrative non-compliant

SCPC, but result in social benefits from lower emissions of $19 to $91/MWh relative to the noncompliant SCPC unit (see analysis of 2022 relative benefits of NGCC: Table 5-2). If the NGCC unit 

were built in lieu of the SCPC unit as a result of the new fossil steam standard, the impact would 

range from a net social cost of $11/MWh to a net social benefit of $60/MWh relative to the 

SCPC unit.

18

Depending on which discount rates are used to estimate benefits, it is possible that the 

standard would result in a net cost (i.e., costs exceed benefits). However, as noted in the 

previous subsection, natural gas prices at these levels would be unprecedented. As a result, the 

EPA believes that the probability of levelized natural gas prices reaching levels at which this 

standard would generate net social costs is extremely small. 

 

16 See: http://www.eia.gov/dnav/ng/hist/n3045us3A.htm. EIA reports average annual delivered natural gas prices 

to the electricity sector for the past 16 years (since 1997).

17 For context, between 2009 and 2014 the national annual average nominal price of natural gas delivered for 

electricity generation ranged from $3.58/MMBtu to $5.30/MMBtu. The 6 year average was $4.76/MMBtu, 

roughly 1/3 the illustrative high price of $14/MMBtu.

18 As noted above, the CUA is removed for comparisons of the social costs of generating technology.
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We emphasize that differences in generating costs, plant design, local factors, and the 

relative differences between fuels costs can all affect the precise circumstances under which 

the new steam fossil standard would be projected to have no costs, net social benefits or net 

social costs. However, based on historical and expected gas prices, we project that the new 

fossil steam standard is most likely to have negligible costs because firms will invest in 

technology that will comply with the standard in the baseline, and, if it does result in costs, it is 

also likely to produce positive, although modest, net social benefits. Furthermore, these results, 

complemented by the analysis in Chapter 4 on regional differences in levelized costs of these 

technologies, indicate that local differences in the cost of these technologies must be 

significantly different from representative conditions for non-compliant coal generation to be 

the technology of choice to serve demand. Therefore the probability that this finalized standard 

would result in net social costs is exceedingly low.

5.5 Illustrative Analysis – Benefits and Costs of Non-Compliant Coal and Compliant Coal 

As discussed in detail in the previous section and in Chapter 4, it is unlikely that a new 

non-compliant coal-fired unit would be constructed in the analysis period. The power sector 

continues to move away from the construction of coal-fired power plants in favor of natural 

gas-fired power plants due, in part, to the significant LCOE differential explored in the previous 

section. Even so, an operator may have reasons to choose to construct a conventional coal-fired 

power plant. (For example, some comments received on the 2012 and 2014 proposed 

regulations suggested that an operator may find it desirable to construct a new coal-fired EGU 

for the purpose of diversifying its generation fleet across fuels to hedge against uncertainty in 

fuel markets.) In these circumstances, the EPA believes that any need for CCS could be 

accommodated and would not, based on the incremental cost of the CCS portion of the new 

unit, preclude the construction of the new coal-fired facility. One factor in determining that 

needing CCS would not preclude the construction of the new facility is the availability of 

Enhanced Oil Recovery (EOR) opportunities for new coal-fired facilities.19

This section evaluates the impacts that might occur if an investor, which otherwise 

wanted to construct a new non-compliant coal unit, chose to instead construct a new compliant 

coal-fired unit in response to the new fossil steam standard. In this scenario, this decision 

would result in some costs in order to build a unit with partial CCS or co-fire with natural gas. 20

 

19 The potential availability of EOR was not used in the EPA’s evaluating the reasonableness of cost in determining 

the best system of emissions reduction (BSER). 

20 In this section we do not include a CUA for the illustrative new non-compliant SCPC and IGCC units as we are 

assuming that the investor will install construct and operate a new coal fired plant regardless. Furthermore, as 
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However, there would also be climate and other benefits resulting from changes in CO2 and

SO2. 

For each coal-fired generation type, SCPC and IGCC, the EPA analyzed the cost of 

constructing these units and emission impacts of meeting the new source standards in 2022. 

While partial CCS is considered the best system of emission reductions (BSER) for these SCPC 

units, it would also be possible to meet the standard without CCS through co-firing natural gas, 

which is also analyzed. 

The cost of CCS used to support this rule assumes that the geologic sequestration of CO2

will be in deep saline formations and accounts for the cost of doing so, but the EPA also 

recognizes the potential for sequestering CO2 for EOR. For non-EOR applications, 

transportation, storage, and monitoring (TS&M) costs of $5-$15 dollars per ton of CO2 are 

applied based on the level of capture. This range is consistent with estimates provided by NETL 

and the Global CCS Institute.21

EOR refers to the injection of gases and/or fluids into a reservoir to increase oil 

production efficiency. CO2-EOR has been successfully used at many production fields 

throughout the United States. The oil and natural gas industry in the United States has over 40 

years of experience in injection and monitoring of CO2. This experience provides a strong 

foundation for the technologies used in the deployment of CCS on coal-fired electric generating 

units. Although deep saline formations provide the most CO2 storage opportunity (at least 

2,243 billion tons), oil and gas reservoirs are estimated to have 228 billion tons of CO2 storage 

resource.22

The use of CO2 for EOR can significantly lower the cost of implementing CCS. The 

opportunity to sell the captured CO2 rather than paying directly for its long-term storage, 

greatly improves the economics of the new generating unit. According to the International 

 

in the previous section, when comparing the difference in costs of illustrative new units after construction, such 

as in the analysis of the social costs of these technologies (i.e., the private cost plus the cost associated with 

their emissions), the CUA is not included.

21 http://www.netl.doe.gov/energy-analyses/pubs/QGESS_CO2T%26S_Rev2_20130408.pdf

 http://www.globalccsinstitute.com/publications/economic-assessment-carbon-capture-and-storagetechnologies-2011-update. 

Note that NETL assumes 100 kilometers (62 miles) of pipeline, but points out that, of the 500 largest existing CO2

point sources, 95 percent are located within 100 kilometers (62 miles) miles of a potential geologic storage 

reservoir. Therefore it is reasonable to assume that a new source can be similarly located.

22 U.S. Department of Energy National Energy Technology Laboratory (2012). United States Carbon Utilization and 

Storage Atlas, Fourth Edition.
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Energy Agency, of the CCS projects in operation (e.g., Boundary Dam Energy Project, 

Saskatchewan, Canada) or under construction or at an advanced stage of planning, 70 percent

intend to use captured CO2 to improve recovery of oil in mature fields, including Mississippi 

Power’s Kemper County Energy Facility, NRG Energy’s W.A. Parish Petra Nova CCS Project, 

Summit Power’s Texas Clean Energy Project, and the Hydrogen Energy California Project. The 

Texas Clean Energy project is planning to capture 90 percent of the CO2 and sell it for EOR.23

Therefore, in the near term, new coal-fired EGUs with CCS may be located in areas 

amenable to using the captured CO2 in EOR operations 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 

increasing oil well productivity. Furthermore, the EPA believes the opportunity to engage in 

EOR opportunities is not significantly limited by the location of those opportunities or the 

current CO2 pipeline infrastructure (12 states currently have active EOR operations). Provision 

of electric power does not require coal-fired facilities to be co-located with the demand it is 

intended to serve. Please refer to Chapter 2 for a more detailed discussion of EOR, including its 

geographic availability, expected future growth, and overall impact on the economics of CCS.

There are two EOR opportunities evaluated in this section – ‘High’ and ‘Low.’ The high 

EOR opportunity assumes a CO2 sale price of $36 per ton; the low EOR opportunity assumes a 

CO2 sale price of $18 per ton based on assumptions used by NETL in evaluating potential EOR 

opportunities. 24 For either opportunity, it is assumed that the facility is only responsible for the 

costs of transmitting the captured CO2 to the fence line, as is currently the practice.25 Costs for 

TS&M of CO2, however, are real costs that must be borne by someone. Whether the facility, the 

pipeline owner or the eventual user (i.e., oil field producer) of the CO2 bear the TS&M cost 

could be negotiated, with the outcome varying in different situations. We expect that when CO2

is sold for EOR applications, the buyer rather than the EGU operator will likely bear those costs. 

However, for the purposes of this analysis, the TS&M costs are included for both EOR and non-

 

23 http://www.texascleanenergyproject.com/

24 The High and Low CO2 sale prices utilized by the EPA are consistent with NETL’s Base Case and Low Case sale 

prices, respectively (http://www.netl.doe.gov/energy-analyses/pubs/storing%20co2%20w%20eor_final.pdf). 

In addition, this range is broadly consistent with the CO2 sale price data collected by the Department of Interior 

for projects located on federal lands (http://statistics.onrr.gov/ReportTool.aspx). Prices are expressed in 2011$ 

and the price is expected to be static over time. Prices were converted from metric to short tons using a factor 

of 0.90718474.

25 For EOR applications the point of sale is typically the facility fence line, in which case the coal facility operator 

will avoid the TS&M cost. Consequently, the economic benefit of EOR to the investor in the coal plant may be 

greater than simply the price paid for CO2. 
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EOR applications, recognizing that this likely slightly overstates the cost to the operator in 

circumstances where CO2 is sold for EOR.

Figure 5-1 compares the LCOE for a non-compliant coal to a compliant coal unit with 

partial CCS both with and without EOR. With the exception of the LCOE costs accounting for 

EOR, these costs were provided in Table 4-5. We see in Figure 5-1 that if a limited number of 

non-compliant coal-fired power plants would have been constructed in the analysis period the 

adoption of CCS could be accommodated and would not, based on the incremental cost of the 

CCS portion of the new unit, preclude the construction of the new coal-fired facility.

Furthermore, Figure 5-1 shows the LCOE analysis estimate that a non-compliant coal unit could 

achieve a 1,400 lb/MWh emission rate by co-firing with 34 percent natural gas (at a levelized 

cost of $34.40/MWh) at an SCPC unit, or with 6 percent natural gas at an IGCC unit.
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Figure 5-1. Levelized Cost of Electricity, Uncontrolled Coal and Coal with Partial 

CCS (1,400 lb/MWh gross). 2011$ 

Notes: 

(1) Cost data from NETL 2015, adjusted for EOR revenue and co-firing where applicable. 

(2) NETL uses a high-risk financial structure resulting in a capital charge factor (CCF) of 0.124 to evaluate 

the costs of all cases with CO2 capture (non-capture case uses a conventional financial structure with 

a CCF of 0.116).

(3) A non-compliant 550 MW (net capacity) unit SCPC requires NG co-firing at 34% to achieve a 1,400 

lb/MWh CO2 emission rate. A non-compliant 620 MW (net) IGCC unit requires 6 percent NG co-firing.

LCOE costs for co-firing were estimated assuming a levelized $6.19/MMBtu price of delivered gas.

(4) The partial control alternatives that achieve 1,400 lb/MWh using CCS without EOR include the cost of 

TS&M.

Tables 5-5 and 5-6 show the costs and 2022 net benefits (benefits minus private 

compliance costs) per MWh of adopting compliant coal in lieu of non-compliant coal. The EPA 

estimates of the benefits or disbenefits associated with changes in CO2, SO2, and NOX emissions 

using the methods described in Table 5-3. The cost estimates used are reported in Figure 5-1. 

As before, it is important to note that these comparisons omit additional benefits that may be 

associated with the abatement of greenhouse gas emissions and other benefits associated with 

reducing criteria pollutant emissions.

$0

$20

$40

$60

$80

$100

$120

$140

SCPC IGCC

LC

OE ($/M

Wh, 2011$)

Uncontrolled (w/o CUA) Uncontrolled (w CUA)

No CCS, 1400 lbs/MWh via NG Cofiring Partial CCS (1400 lbs/MWh) no EOR

Partial CCS (1400 lbs/MWh) $18 EOR Partial CCS (1400 lbs/MWh) $36 EOR
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Table 5-5. Illustrative 2022 Costs and Benefits for Compliant SCPC with Partial Capture or 

with Co-Firing Natural Gas Relative to Non-Compliant SCPC (per MWh 2011$)

SCPC with 

Partial CCS

SCPC 

Co-Firing

Natural Gas

Additional LCOE a$17 $9.8

Revenue from EOR (Low - High EOR) $4.2 to $7.1 *

Additional LCOE, net of EOR $9.6 to $13 *

Value of Monetized Benefits for 2022 Emissions

SC-CO2 5% with Krewski 3% to SC-CO2 3% (95th) with 

Lepeule 3%b$3.2 to $18 $1.5 to $14

Net Monetized Benefits

Without EOR Revenue -$13 to $0.84 -$8.3 to $4.7

With EOR Revenue -$9.3 to $7.9 *

a

For this comparison the LCOE of the representative SCPC without CCS or co-firing natural gas does not include 3

percent CUA. 

b Benefits are estimated for a 2022 analysis year. Values shown are calculated using different discount rates. Four 

estimates (average SC-CO2 at discount rates of 5, 3, and 2.5 percent, respectively, and 95th percentile SC-CO2 at 3 

percent) of the SC-CO2 in the year 2022 were used. See Table 3-1 for the SC-CO2 estimates. =The average SC-CO2 at 

5 percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest 

estimate. See section 3.2 for complete discussion of these estimates. PM2.5-related co-benefits are estimated using 

2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022.
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Table 5-6. Illustrative 2022 Costs and Benefits for Compliant IGCC with Co-Firing Natural 

Gas Relative to Non-Compliant IGCC (per MWh 2011$)

IGCC Co-Firing 

Natural Gas

Additional LCOEa$2.0

Revenue from EOR (Low - High EOR) *

Additional LCOE, net of EOR *

Value of Monetized Benefits for 2022 Emissions

SC-CO2 5% with Krewski 3% to SC-CO2 3% (95th) with Lepeule 

3%b$0.25 to $2.5

Net Monetized Benefits 

Without EOR Revenue $-1.8 to $0.45

With EOR Revenue *

a

For this comparison the LCOE of the representative IGCC co-firing natural gas does not include 3 percent CUA.

b

Benefits are estimated for a 2022 analysis year. Values shown are calculated using different discount rates. Four 

estimates (average SC-CO2 at discount rates of 5, 3, and 2.5 percent, respectively, and 95th percentile SC-CO2 at 3 percent) 

of the SC-CO2 in the year 2022 were used. See Table 3-1 for the SC-CO2 estimates. =The average SC-CO2 at 5 percent 

produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate. See Section

3.2 for complete discussion of these estimates. PM2.5-related co-benefits are estimated using 2020 monetized health 

benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022.

As shown in Chapter 4, current market conditions indicate that a unit compliant with the 

standards is currently the most economical investment, even in the baseline. The costs 

reported in Tables 5-5 and 5-6 represent the compliance costs to a hypothetical investor who, 

in the baseline, would choose to build a non-compliant fossil-fired steam power plant and, in 

compliance with the standard, still constructs the plant but now in such a way that reduces the 

plant’s emissions. In short, the compliance costs are the expenditures that the investor would 

make in order to comply with the standard. The underlying premise of this example is that the 

profit from the plant exceeds the additional cost of compliance to the investor; otherwise the 

investor would not be expected to make the investment. If the profit were less than the 

compliance costs then the investor’s lost profits would be the private costs. For this reason, if 

the investor makes a different compliance decision other than those assumed in Table 5-5 and 

5-6 the private costs will be lower, and therefore, the compliance costs presented in Table 5-5 

and 5-6 would be an upper bound to the private costs borne by the hypothetical investor. 

As explained in OMB’s Circular A4 and the EPA’s Guidelines for Economic Analysis, social 

costs, and not private costs, are the appropriate metric for the benefit-cost analysis in this RIA.

Social costs represents the total burden that a regulation or action will impose on the economy. 
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It is defined as the sum of all opportunity costs incurred as a result of a regulation or action 

where an opportunity cost is the value lost to society of any goods and services that will not be 

produced and consumed as a result of a regulation. The opportunity cost of a regulation or

activity is measured by the prices of the goods and services used in response to the regulation 

or required for that activity. Therefore, when a resource is used in response to a regulation or 

for an activity, it has a social cost associated with it.

The costs in Tables 5-5 and 5-6 could be taken to approximate the social cost of an 

individual investor complying with the standard, assuming that investor would chose to 

construct a compliant fossil-fired steam power plant rather than making an alternative 

investment. However, detailed behavioral models of the electricity sector (such as IPM) that 

take into many of the important criteria for investment decisions over time show that this 

investment decision does not hold across the economy. Therefore, these estimates are unlikely 

to be representative of the social costs of this rule. The conclusions presented in Chapter 4 –

that costs of the rule are likely to be negligible – represent the best approximation of the 

overall cost to society. 

5.6 Impact of the New Source Standards Considering the Cost of Lost Option Value

Consistent with the EPA’s practice in evaluating the benefits and costs of significant 

rules, Chapter 4 uses detailed electricity sector modeling of expected market conditions to 

demonstrate that new EGUs expected to be built in the period of analysis would be in 

compliance with this final rule, even in the absence of this rule. As a result in the analysis 

period, as measured in those deterministic settings, the cost are expected to be negligible and 

there are no quantified benefits. That analysis is extended in this chapter to consider

unexpected conditions in which the construction of a new non-compliant coal-fired unit would 

be desirable from the perspective of an individual investor and evaluates the costs and benefits 

of constructing a generating technology that complies with the final rule instead. This section 

further extends, and draws on, those analyses to discuss, qualitatively, the potential benefits 

and costs of the standards from the perspective of an uncertain future. 

Firms operating in the power sector have a set of options available to address increases 

in electricity demand, such as increasing the utilization of existing generating capacity, 

implementing energy efficiency programs to mitigate demand growth, or investing in new 

generating capacity. Within the category of investing in new generating capacity they are able 

to select amongst a set of generating technologies and energy sources. Uncertainty about 

future conditions that could impact the profitability of these different investment options 
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means that retaining flexibility to react to future conditions and choose the most profitable 

investments has value to firms. The value associated with retaining flexibility and being able to 

select the most profitable investments in the future is referred to as “option value.”26 This rule 

does not impose a direct cost on firms by requiring them to take a specific action, instead the 

cost of this rule for firms is the lost option value associated with losing the ability to build a new 

fossil steam or combustion turbine EGU with an emissions rate above their respective 

standards. 

This option value is determined, in part, by the likelihood that the restricted choices 

would have been exercised in the future absent the policy and the cost of available substitutes. 

Since the analysis in Chapter 4 estimates that new combustion turbines forecast in the baseline

that meet the applicability criteria will already meet the standards this discussion focuses on 

new fossil steam EGUs. As discussed in Chapter 4, it is highly unlikely that over the analysis 

period there will be enough expansion in relative fuel prices (e.g., natural gas prices relative to 

coal) to make a typical new fossil steam EGU cost competitive with available substitutes (e.g., 

NGCC, investing in energy efficiency program). Even in the unlikely event that this occurs, the 

incremental cost of constructing a compliant fossil steam EGU with partial CCS or an alternative 

compliance pathway will represent an upper bound on the costs to the firm due to the 

availability of substitute generation sources which might be able to provide a similar service at 

a lower cost. Given both of these reasons, the low likelihood of the restricted options being 

exercised in the baseline and availability of cost effective substitutes, on average the lost option 

value for firms is likely to be small.

Furthermore, as shown in the preceding sections, even in situations where an investor 

would find it desirable to invest in a new, non-compliant EGU over available alternatives in the 

baseline, the health and environmental benefits of restricting the choice set may be higher than

the costs to the firm. Therefore it will also be the case that expected benefits from preventing 

new EGUs with an emissions rate above the respective standards, will likely be higher than the 

lost option value. 

A similar perspective may be applied to assessing the costs of this rule. There are at 

least two notable differences when assessing the lost option value from society’s perspective

relative to the firm’s perspective. First, from society’s perspective the cost is lower because the 

available substitution possibilities may be greater for society than for a single firm as they are 

 

26 We refer the interested reader to Dixit and Pindyck (1994) and Trigeorgis (1996) for more information on the 

concept of option value in the context of firms’ investment choices.
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not bound by the conditions of a single firm but activities that may be pursued by all electricity 

producers and consumers at large. Second, the value of adding a single new EGU for the 

purpose of diversifying the generation fleet across fuels to hedge against uncertainty in fuel 

markets, will likely be lower for society at large than for a single firm with a generating fleet

that is relatively less coal-intensive than the entirety of the generating fleet.

27 Both of these 

differences suggest that the cost of lost option value from society’s perspective is lower than 

what is already likely to a minimal cost of lost option value for a particular firm. 

It is difficult to precisely estimate the lost option value associated with this final rule 

given the numerous sources of uncertainty that influence investment decisions in the electricity 

sector and the existing modeling tools. However, the analysis reported in this chapter and the 

previous chapter has considered important variables that influence investment decisions in the 

electricity sector and found that across a wide range of potential outcomes this rule would have 

negligible costs. Furthermore, considering the additional analysis in this chapter and the 

discussion above, the cost of the lost option value of the rule is concluded to be small. 

Additionally, if conditions arise that would have led to the construction of non-compliant EGUs 

absent the final rule, the quantifiable benefits of limiting the construction of those units likely 

exceeds the cost (even though not all benefits are captured). However, as discussed throughout 

this RIA, when considering the most likely outcomes, the new source standards are anticipated 

to yield no quantified benefits and impose negligible costs over the analysis period. 

5.7 References

Dixit, Avinash and Pindyck, Robert. Investment Under Uncertainty. 1994. Princeton University 

Press.

Joskow, P.L. 2010. Comparing the Cost of Intermittent and Dispatchable Electricity Generating 

Technologies. MIT Center for Energy and Environmental Policy Research Working Paper 

10-013.

Joskow, P.L. 2011. Comparing the Costs of Intermittent and Dispatchable Electricity Generating 

Technologies. American Economic Review. vol. 101:238-41.

 

27

 The option value associated with constructing a new EGU associated with a specific fuel source as part of a 

portfolio to hedge against uncertainty in future relative fuel prices will be conditional upon the current 

composition of the firm’s generation portfolio. If the current stock was constructed in expectation of relative 

fuel prices that more strongly favored higher emitting fuels, then the composition of the generating fleet may

already be too heavily weighted toward the ability to use those fuels, given the current expected distribution of 

relative fuel prices. Furthermore, the possibility to hedge against changes in fuel prices may be pursued by 

other means, such as risk contracts, and thus is not limited to the construction of generation sources with 

particular fuel sources. 
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Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz, 

and W.H. White. 2009. “Reanalysis of the Harvard Six Cities Study and the American 

Cancer Society Study of Particulate Air Pollution and Mortality.” Special Report to the 

Health Effects Institute. Cambridge, MA. July.

Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. “Chronic Exposure to Fine Particles and 

Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.

Muller, N.Z., R. Mendelsohn, and W. Nordhaus. 2011. Environmental Accounting for Pollution in 

the United States Economy. American Economic Review. 101:1649-1675.

National Energy Technology Laboratory (NETL). Cost and Performance of PC and IGCC Plants for

a Range of Carbon Dioxide Capture. Revised Sept. 16, 2013. Available online at:

http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf. 

National Energy Technology Laboratory (NETL). Cost and Performance Baseline for Fossil Energy 

Plants Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants. June 22, 

2015. Available online at: http://www.netl.doe.gov/research/energy-analysis/energybaseline-studies.

National Research of Council (NRC). 2009. Hidden Costs of Energy: Unpriced Consequences of

Energy Production and Use. National Academies Press: Washington, D.C.

Trigeorgis, Lenos. Real Options: Managerial Flexibility and Strategy in Resource Allocation.

1996. The MIT Press.

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010. Available 

online at: http://www.eia.gov/oiaf/archive/aeo10/index.html. 

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available 

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

U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the 

Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. 

Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. 

Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.
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CHAPTER 6

MODIFIED AND RECONSTRUCTED SOURCE IMPACTS

6.1 Introduction

In addition to the standards for new sources analyzed in Chapter 4 and Chapter 5, this 

action also sets standards under Clean Air Act Section 111(b) for units that modify or 

reconstruct. For the reasons discussed in this chapter, the EPA also believes that the standards 

for modified and reconstructed fossil fuel-fired EGUs will result in minimal compliance costs, 

because we expect few 111(b) modified or reconstructed EGUs in the period of analysis 

(through 2022).

6.2 Reconstructed Sources

The new source performance standard (NSPS) provisions (40 CFR part 60, subpart A) 

define a “reconstruction” as 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. Historically, we are 

only aware of one EGU that has notified the EPA that it has reconstructed under the 

reconstruction provision of section 111(b). As a result, we anticipate that few EGUs will 

undertake reconstruction in the period of analysis. For this reason, the standards will not result 

in any significant emission reductions, costs, or quantified benefits in the period of analysis. 

Likewise, the EPA does not anticipate any impacts on the price of electricity or energy supply.

The rule is not expected to raise any resource adequacy concerns, since reserve margins will 

not be impacted and the rule does not impose any additional requirements on existing facilities

not triggering the reconstruction provision. There are no notable macroeconomic or

employment impacts expected as a result of these standards.

Due to the extremely limited data available on reconstructions, it is not possible to 

conduct a representative illustrative analysis of what costs and benefits might result from this 

rule in the unlikely case that a unit were to reconstruct.

6.3 Modified Sources

Historically, few EGUs have notified the EPA that they have modified under the 

modification provision of section 111(b). The EPA’s current regulations define an NSPS

“modification” as a physical or operational change that increases the source’s maximum 
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achievable hourly rate of emissions, but specifically exempt from that definition projects that 

entail the installation of pollution control equipment or systems. 

The EPA expects that most of the actions EGUs are likely to take in the foreseeable 

future that could be classified as NSPS “modifications” would qualify as pollution control 

projects. In many cases, those projects are likely to involve the installation of add-on control 

equipment needed to meet Clean Air Act (CAA) requirements for criteria and air toxics air 

pollutants. Any associated carbon dioxide (CO2) emissions increases would likely be small and 

would occur as a chemical byproduct of the operation of the control equipment. In other cases, 

those projects would involve equipment changes to improve fuel efficiency to meet state 

requirements for implementation of the CAA section 111(d) rulemaking for existing sources and 

would have the effect of increasing a source’s maximum achievable hourly emission rate (lb 

CO2/hr), even while decreasing its actual output based emission rate (lb CO2/MWh). Because all 

of these actions would be treated as pollution control projects under the EPA’s current NSPS 

regulations, they would be specifically exempted from the definition of modification.

Given the limited information that we have about past modifications, the EPA 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 large-scale modifications

of steam generating units, such as major facility upgrades involving the reconstruction or 

replacement of steam turbines and other equipment upgrades that result in substantial 

increases in a unit’s potential hourly CO2 emissions rate. The EPA does not have sufficient 

information at this time to predict the full array of actions that existing steam generating units 

may undertake, including those in response to applicable requirements under an approved CAA 

section 111(d) plan. Additionally, it is not possible to predict which, if any, of these actions may 

result in increases in potential CO2 hourly emissions. Nevertheless, the EPA expects that, to the 

extent actions are undertaken by existing steam generating units, the magnitude of the 

increases in potential hourly CO2 emissions associated with the vast majority of such changes

would generally be small and therefore would generally not be subject to the standards of 

performance for modified steam generating units finalized in this action.

Based on this information, we anticipate that few EGUs will take actions that would be 

considered NSPS modifications and subject to the standards of performance finalized in this 

action during the period of analysis. For this reason, the standards will result in minimal 
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emission reductions, costs, or quantified benefits in the period of analysis. Likewise, the Agency 

does not anticipate any impacts on the price of electricity or energy supplies. This rule is not 

expected to raise any resource adequacy concerns, since reserve margins will not be impacted 

and the rule does not impose any additional requirements on existing facilities not triggering 

the NSPS modification provision. There are no notable macroeconomic or employment impacts 

expected as a result of these standards.

Due to the limited data available on past modifications and the diversity of existing units 

that could potentially modify, it is not possible to conduct a representative illustrative analysis 

of what costs and benefits might result from this rule in the unlikely case that a unit were to 

take an action that would be classified as a modification.
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CHAPTER 7

STATUTORY AND EXECUTIVE ORDER REVIEWS

7.1 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). This RIA includes an economic analysis of 

the potential costs and benefits associated with this action. 

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 Chapter 5 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 fuelfired 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. As noted previously, the monetized 

benefits exceed the compliance costs under a range of assumptions.

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, we discuss factors that limit our ability to quantify the costs and 

benefits of the standards for modified and reconstructed sources.

7.2 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 
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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 2506.03). Because the CO2 standards for newly constructed, modified, and 

reconstructed EGUs will be included in the same new subpart (40 CFR part 60, subpart TTTT) 

and are being finalized in the same action, the ICR document for this action includes estimates 

of the information collection burden on owners and operators of newly constructed, modified, 

and reconstructed EGUs. Estimated cost burden is based on 2013 Bureau of Labor Statistics 

(BLS) labor cost data. Thus, all burden estimates are in 2013 dollars. Burden is defined at 5 CFR 

1320.3(b). You can find a copy of the ICR in the dockets for this action (Docket ID Numbers EPAHQ-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.

7.2.1 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.
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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 natural 

gas combined cycle 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.

7.2.2 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 

fuel-fired 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 NSPS 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 
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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.

7.2.3 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 $60,997 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.

7.3 Regulatory Flexibility Act (RFA)

EPA certifies 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.

7.3.1 Newly constructed EGUs

The EPA believes that electric power companies will choose to build new fossil fuel-fired 

electric utility steam generating units or natural gas-fired stationary combustion turbines that 

comply with the regulatory requirements of the final rule because of existing and expected 

market conditions. The EPA does not project any new coal-fired steam generating units without 

CCS to be built. We expect that any newly constructed natural gas-fired stationary combustion 

turbines will meet the standards. We do not include an analysis of the illustrative impacts on 

small entities that may result from implementation of the final rule because we anticipate 

negligible compliance costs over a range of likely sensitivity conditions as a result of the 

standards for newly constructed EGUs. Thus the cost-to-sales ratios for any affected small 

entity would be zero costs as compared to annual sales revenue for the entity. Accordingly, 

there are no anticipated economic impacts as a result of the standards for newly constructed 

EGUs. We have therefore concluded that this final action will have no net regulatory burden for 

all directly regulated small entities.
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7.3.2 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, 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.

7.4 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 gas-fired 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.

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 

modification or reconstruction provisions in the period of analysis. In Chapter 6, 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 
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significant costs on those sources.

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 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.

7.5 Executive Order 13132, Federalism

This final action does not have federalism implications. It will not have substantial direct 

effects on the states, on the relationship between the national government and the states, or 

on the distribution of power and responsibilities among the various levels of government. The 

EPA believes that electric power companies will choose to build new fossil fuel-fired electric 

utility steam generating units or natural gas-fired stationary combustion turbines that comply 

with the regulatory requirements of the final rule because of existing and expected market 

conditions. In addition, as previously stated, the EPA expects few modified or reconstructed 

fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion 

turbines 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.

7.6 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 
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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 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 tribeonly 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 
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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).

7.7 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 greenhouse gas 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, Chapter 5 of this 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. 

Under these scenarios, the rule would result in substantial reductions of both CO2, and also fine 

particulate matter such that net quantifiable benefits exceed regulatory costs under a range of 

scenarios. 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 
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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 the preamble.

7.8 Executive Order 13211, Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use

This final action is not a “significant energy action” because it is not likely to have a 

significant adverse effect on the supply, distribution, or use of energy. The EPA believes that 

electric power companies will choose to build new fossil fuel-fired electric utility steam 

generating units or natural gas-fired stationary combustion turbines that comply with the 

regulatory requirements of the final rule because of existing and expected market conditions. In 

addition, as previously stated, the EPA expects few fossil fuel-fired electric utility steam 

generating units or natural gas-fired stationary combustion turbines to trigger the NSPS 

modification or reconstruction provisions in the period of analysis. Thus, this action is not 

anticipated to have notable impacts on emissions, costs or energy supply decisions for the 

affected electric utility industry.

7.9 National Technology Transfer and Advancement Act

This final action involves technical standards. The following voluntary consensus 

standards are used in the final rule: American Society for Testing and Materials (ASTM) 

Methods D388-12 (Standard Classification of Coals by Rank), D396-13c (Standard Specification 

for Fuel Oils), D975-14 (Standard Specification for Diesel Fuel Oils), D3699-13b (Standard 

Specification for Kerosene), D6751-12 (Standard Specification for Biodiesel Fuel Blend Stock 

(B100) for Middle Distillate Fuels), D7467-13 (Standard Specification for Diesel Fuel Oil, 

Biodiesel Blend (B6 to B20)), and American National Standards Institute (ANSI) Standard C12.20 

(American National Standard for Electricity Meters - 0.2 and 0.5 Accuracy Classes). The rule also 

requires use of Appendices A, B, D, F and G to 40 CFR part 75; these Appendices contain 

standards that have already been reviewed under the NTTAA.

7.10 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 
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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 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 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 climate-related health 

effects.

The record for the 2009 Endangerment Finding summarizes the strong scientific 

evidence that the potential impacts of climate change raise environmental justice issues is 

found in the major assessment reports by the U.S. Global Change Research Program (USGCRP), 

the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council 

(NRC) of the National Academies 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 resource 

within established reservation boundaries and threats to traditional subsistence lifestyles. 

Tribal communities whose health, economic well-being, and cultural traditions depend upon 
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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 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.1The new assessment reports provides more 

detailed findings regarding these populations’ vulnerabilities and projected impacts they may 

experience. In addition, the most recent assessment reports provide 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, the 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.

 

1 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United 

States: The Third National Climate Assessment. U.S. Global Change Research Program, 841 pp.

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects.

Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate 

Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. 

Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, 1132 pp.

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects. 

Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate 

Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. 

Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, 688 pp.
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The EPA believes the human health or environmental risk addressed by this final action 

will not have potential disproportionately high and adverse human health or environmental 

effects on minority, low-income or indigenous populations. The final rule limits GHG emissions 

from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam 

generating units and natural gas-fired stationary combustion turbines by establishing national 

emission standards for CO2.

The EPA has determined that the final rule will not result in disproportionately high and 

adverse human health or environmental effects on minority, low-income or indigenous 

populations because the rule is not anticipated to notably affect the level of protection 

provided to human health or the environment. The EPA believes that electric power companies 

will choose to build new fossil fuel-fired electric utility steam generating units and natural gasfired stationary combustion turbines that comply with the regulatory requirements of the final 

rule because of existing and expected market conditions. The EPA does not project any new 

coal-fired steam generating units without CCS to be built and expects that any newly built 

natural gas-fired stationary combustion turbines will meet the standards. In addition, as 

previously stated, the EPA expects few fossil fuel-fired electric utility steam generating units or 

natural gas-fired stationary combustion turbines to trigger the NSPS modification or 

reconstruction provisions in the period of analysis. This final rule will ensure that, to whatever 

extent there are newly constructed, modified, and reconstructed EGUs, they will use the best 

performing technologies to limit emissions of CO2.

7.11 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).
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United States

Environmental Protection

Agency

Office of Air Quality Planning and Standards

Health and Environmental Impacts Division

Research Triangle Park, NC

Publication No. EPA-452/R-15-005

August 2015