Regulatory Impact Analysis for the Proposed Standards of 

Performance for Greenhouse Gas Emissions for New Stationary 

Sources: Electric Utility Generating Units
ii

EPA-452/R-13-003

September 2013

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

Emissions for New 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
iii

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, C439-02, 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.
iv

ACRONYMS

AEO Annual Energy Outlook

BACT Best Available Control Technology

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

CFR Code of Federal Regulations

CH4 Methane

CO2 Carbon Dioxide

CRF Capital Recovery Factor

CSAPR Cross State Air Pollution Rule

CT Combustion Turbines

CUA Climate Uncertainty Adder

DICE Dynamic Integrated Climate and Economy Model

DOE U.S. Department of Energy

EAB Environmental Appeals Board

EGR Enhanced Gas Recovery

EGU Electric Generating Unit

EIA U.S. Energy Information Administration

EMM Electricity Market Module

EO Executive Order

EOR Enhanced Oil Recovery

EPA U.S. Environmental Protection Agency

ER Enhanced Recovery

FERC Federal Energy Regulatory Commission

FGD Flue Gas Desulfurization

FOAK First of a Kind

FOM Fixed Operating and Maintenance

FR Federal Register

FRCC Florida Reliability Coordinating Council

FUND Framework for Uncertainty, Negotiation, and Distribution Model
v

GDP Gross Domestic Product

GHG Greenhouse Gas

GS Geologic Sequestration

Gt Gigaton

H2S Hydrogen Sulfide

HFC Hydrofluorocarbons

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

IRP Integrated Resource Plan

kWh Kilowatt-hour

lbs Pounds

LCOE Levelized Cost of Electricity

LNB Low NOX Burners

MATS Mercury and Air Toxics Standards

MEA Monoethanolamine

MGD Millions of Gallons per Day

mg/L Milligrams per Liter

mmBtu Million British Thermal Units

MW Megawatt

MWh Megawatt-hour

N2O Nitrous Oxide

NaOH Sodium Hydroxide

NATCARB National Carbon Sequestration Database and Geographic Information 

System

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 Next of a Kind or Nth of a Kind

NOX Nitrogen Oxide

NRC National Research Council
vi

NSPS New Source Performance Standard

NSR New Source Review

NTTAA National Technology Transfer and Advancement Act

OFA Overfire Air

OMB Office of Management and Budget

PAGE Policy Analysis of the Greenhouse Gas Effect Model

PFC Perfluorocarbons

PM2.5 Fine Particulate Matter

ppm Parts per Million

PRA Paperwork Reduction Act 

PSD Prevention of Significant Deterioration

RCSP Regional Carbon Sequestration Partnerships

RES Renewable Electricity Standards

RFA Regulatory Flexibility Act

RGGI Regional Greenhouse Gas Initiative

RIA Regulatory Impact Analysis

RPS Renewable Portfolio Standards

SBREFA Small Business Regulatory Enforcement Fairness Act

SCC Social Cost of Carbon

SCPC Super Critical Pulverized Coal

SCR Selective Catalytic Reduction

SF6 Sulfur Hexafluoride

SIP State Implementation Plan

SO2 Sulfur Dioxide

Tcf Trillion Cubic Feet

TDS Total Dissolved Solids

TSD Technical Support Document

TSM 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

U.S. NRC U.S. Nuclear Regulatory Commission

VCS Voluntary Consensus Standards

VOM Variable Operating and Maintenance
vii

TABLE OF CONTENTS

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

1.1 Background and Context of Proposed Rule......................................................... 1-1

1.2 Summary of the Proposed Rule........................................................................... 1-2

1.3 Key Findings of Economic Analysis ...................................................................... 1-3

Chapter 2 Introduction and Background ............................................................................... 2-1

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

2.2 Background for the Proposed EGU New Source GHG Standards........................ 2-3

2.3 Organization of the Regulatory Impact Analysis ................................................. 2-7

Chapter 3 Defining the Climate Change Problem and Rationale for Rulemaking................. 3-1

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

3.2 References ........................................................................................................... 3-8

Chapter 4 Electric Power Sector Profile................................................................................. 4-1

4.1 Introduction ......................................................................................................... 4-1

4.2 Power Sector Overview........................................................................................ 4-1

4.3 Deregulation and Restructuring .......................................................................... 4-6

4.4 Emissions of Greenhouse Gases from Electric Utilities....................................... 4-7

4.5 Carbon Dioxide Control Technologies ............................................................... 4-11

4.6 Geologic Sequestration...................................................................................... 4-14

4.7 GHG and Clean Energy Regulation in the Power Sector.................................... 4-22

4.8 Revenues, Expenses, and Prices ........................................................................ 4-27

4.9 Natural Gas Market............................................................................................ 4-31
viii

4.10 Electricity Demand and Demand Response....................................................... 4-33

4.11 References ......................................................................................................... 4-35

Chapter 5 Costs, Benefits, Economic, and Energy Impacts ................................................... 5-1

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

5.2 Requirements of the Proposed GHG EGU NSPS .................................................. 5-2

5.3 Power Sector Modeling Framework .................................................................... 5-3

5.4 Analyses of Future Generating Capacity.............................................................. 5-6

5.5 Levelized Cost of Electricity Analysis ................................................................. 5-17

5.6 Comparison of Emissions from Generation Technologies................................. 5-34

5.7 Benefits of Reducing GHGs and Other Pollutants ............................................. 5-35

5.8 Comparison of Health and Welfare Impacts from Generation 

Technologies...................................................................................................... 5-42

5.9 Illustrative Analysis – Benefits and Costs across a Range of Gas Prices............ 5-46

5.10 Illustrative Analysis – Benefits and Costs of CCS Compared with 

Conventional Coal.............................................................................................. 5-50

5.11 Impact of the Proposed Rule on Option Costs .................................................. 5-52

5.12 Summary of Costs, Benefits, and Energy Impacts............................................. 5-54

5.13 Macroeconomic and Employment Impacts....................................................... 5-54

5.14 References ......................................................................................................... 5-54

Chapter 6 Statutory and Executive Order Analyses............................................................... 6-1

6.1 Synopsis................................................................................................................ 6-1

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

Order 13563, Improving Regulation and Regulatory Review.............................. 6-1

6.3 Paperwork Reduction Act.................................................................................... 6-2

6.4 Regulatory Flexibility Act ..................................................................................... 6-4
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6.5 Unfunded Mandates Reform Act (UMRA)........................................................... 6-7

6.6 Executive Order 13132, Federalism..................................................................... 6-8

6.8 Executive Order 13045, Protection of Children from Environmental Health 

Risks and Safety Risks ........................................................................................ 6-10

6.9 Executive Order 13211, Actions Concerning Regulations That Significantly 

Affect Energy Supply, Distribution, or Use ........................................................ 6-10

6.10 National Technology Transfer and Advancement Act....................................... 6-10

6.11 Executive Order 12898: Federal Actions to Address Environmental Justice 

in Minority Populations and Low-Income Populations ..................................... 6-11
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LIST OF TABLES

Table 1-1. Proposed Emission Limits ..................................................................................... 1-3

Table 2-1. Proposed Emission Limits ..................................................................................... 2-6

Table 4-1. Existing Electricity Generating Capacity by Energy Source, 2011......................... 4-3

Table 4-2. Total U.S. Electric Power Industry Retail Sales in 2011 (Billion kWh)................... 4-3

Table 4-3. Electricity Net Generation in 2011 (Billion kWh).................................................. 4-4

Table 4-4. Coal Steam Electricity Generating Units, by Size, Age, Capacity, and 

Thermal Efficiency (Heat Rate) ..................................................................................... 4-5

Table 4-5. Domestic Emissions of Greenhouse Gases, by Economic Sector (million 

metric tonnes of CO2 equivalent)................................................................................. 4-9

Table 4-6. Greenhouse Gas Emissions from the Electricity Sector (Generation, 

Transmission and Distribution), 2011 (million metric tonnes of CO2 equivalent)..... 4-10

Table 4-7. Fossil Fuel Emission Factors in EPA Modeling Applications ............................... 4-12

Table 4-8. Total CO2 Storage Resource................................................................................ 4-17

Table 4-9. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric 

Utilities for 2010 ($millions) ....................................................................................... 4-30

Table 4-10. Projected Revenues by Service Category in 2015 for Public Power and 

Investor- Owned Utilities (billions)............................................................................. 4-31

Table 5-1.Reference Case Unplanned Cumulative Capacity Additions (GW)........................ 5-9

Table 5-2. 2011 U.S. Electricity Net Generation and Projections for 2020, 2025, and 

2030 (Billion kWh)....................................................................................................... 5-11

Table 5-3. AEO 2013 Unplanned Cumulative Capacity Additions, GW (2020).................... 5-13

Table 5-4. National Delivered 2020 Fuel Prices by AEO 2013 Scenario 

(2011$/MMBtu).......................................................................................................... 5-16

Table 5-5. Technology Cost and Performance (2011$) ....................................................... 5-21

Table 5-6. Levelized Natural Gas Prices by Select AEO 2013 Scenario (2011$/MMBtu)..... 5-26

Table 5-7. AEO 2013 Regional Capital Cost Scalars by Capacity Type ................................. 5-27

Table 5-8. LCOE Estimates with Minimum and Maximum AEO 2013 Regional Capital 

Cost Scalars (2011$/MWh)......................................................................................... 5-28

Table 5-9. LCOE Estimates For Minimum and Maximum AEO 2013 Regional Capital 

Cost Scalars (2011$/MWh) ...................................................................................... 5-29

Table 5-10. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired

Generating Units......................................................................................................... 5-36

Table 5-11. Social Cost of CO2, 2015-2050a (in 2011$) ....................................................... 5-40

Table 5-12. Monetized Health Co-Benefits Per Ton of PM2.5 Precursor Reductions in 

2020 (in 2011$)........................................................................................................... 5-43
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Table 5-13. 2020 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from 

Illustrative New Natural Gas Combined Cycle Generation Relative to New SCPC 

or IGCC Coal Generation without CCS ........................................................................ 5-45

Table 5-14. 2020 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from 

Coal- Fired Generation with CCS meeting 1,100 lbs/MWh Relative to New CoalFired Generation Without CCS................................................................................... 5-47

Table 5-15. Illustrative Costs and 2020 Social Benefits for SCPC with Partial Capture 

and Full Capture CCS Relative to SCPC without CCS (per MWh 2011$)..................... 5-52

Table 5-16. Illustrative Costs and 2020 Social Benefits for IGCC with Partial Capture 

and Full Capture CCS Relative to IGCC without CCS (per MWh 2011$) ..................... 5-52

Table 6-1. Potentially Regulated Categories and Entities...................................................... 6-5
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LIST OF FIGURES

Figure 4-1. Fossil Fuel-Fired Electricity Generating Facilities, by Size ................................... 4-6

Figure 4-2. Status of State Electricity Industry Restructuring Activities................................ 4-8

Figure 4-3. Domestic Emissions of Greenhouse Gases, 2011 (million metric tonnes of 

CO2 equivalent)............................................................................................................. 4-9

Figure 4-4. GHG Emissions from the Power Sector Relative to Total Domestic GHG 

Emissions (2011) ......................................................................................................... 4-11

Figure 4-5. Post-Combustion CO2 Capture for a Pulverized Coal Power Plant ................... 4-14

Figure 4-6. Pre-Combustion CO2 Capture for an IGCC Power Plant.................................... 4-15

Figure 4-7. Growth of U.S. Oil Production from CO2-based EOR ........................................ 4-21

Figure 4-8. U.S. CO2 Storage Capacity and CO2-EOR operations ........................................ 4-22

Figure 4-9. National Average Retail Electricity Price (1960 – 2011).................................... 4-29

Figure 4-10. Average Retail Electricity Price by State (cents/kWh), 2011........................... 4-31

Figure 4-11. Natural Gas Spot Price, Annual Average (Henry Hub)..................................... 4-34

Figure 4-12. Electricity Growth Rate (3-Year Rolling Average) and Projections from 

the Annual Energy Outlook 2013................................................................................ 4-35

Figure 5-1. Historical U.S. Power Plant Capacity Additions, by Technology, 1940-2011 .... 5-10

Figure 5-2. National Delivered Natural Gas Prices by Select AEO 2013 Scenario 

(2011$/MMBtu).......................................................................................................... 5-17

Figure 5-3. Illustrative Wholesale Levelized Cost of Electricity of Alternative New 

Generation Technologies by Cost Component, EPA................................................... 5-24

Figure 5-4. Illustrative Wholesale Levelized Cost of Electricity of Alternative New 

Generation Technologies Across Select Natural Gas Prices, EPA............................... 5-25

Figure 5-5. Projected Real National Delivered Natural Gas Price for Select AEO 2013 

Scenarios and Illustrative Path for > $10/MMBtu Levelized Cost.............................. 5-27

Figure 5-6. Levelized Regional Fuel Price from AEO 2013 Reference Case, 2020-2039 

(2011$/MMBtu).......................................................................................................... 5-29

Figure 5-7. Levelized Cost of Electricity, Uncontrolled Coal and Coal with Full and 

Partial CCS (1,100 lbs/MWh gross) .......................................................................... 5-32

Figure 5-8. Levelized Cost of Electricity, Nuclear and Coal with Partial CCS (1,100 

lbs/MWh gross)........................................................................................................ 5-33

Figure 5-9. Levelized Cost of Electricity Across a Range of Capacity Factors, CT and 

NGCC ($2011/MWh at $3.84/MMBtu Levelized Natural Gas Price) ....................... 5-35

Table 5-10. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired

Generating Units......................................................................................................... 5-36
1-1

EXECUTIVE SUMMARY

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

impacts of the proposed Standards of Performance for Greenhouse Gas Emissions for New 

Stationary Sources: Electric Utility Generating Units (herein referred to as the EGU New Source 

GHG Standards).

1.1 Background and Context of Proposed Rule

The proposed EGU New Source GHG Standards will set emission limits for greenhouse 

gas emissions (GHG) from new fossil fuel fired electric generating units (EGU) constructed in the 

United States in the future. This rulemaking will apply to carbon dioxide (CO2) emissions from 

any affected fossil fuel-fired EGU that sells more than one-third of its potential electric output 

and more than 219,000 megawatt-hours (MWh) net-electrical output to the grid on a three 

year rolling average basis. The United States Environmental Protection Agency (EPA) is 

proposing requirements for these sources because CO2 is a GHG and 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 (74 FR 66518) and summarized in Chapter 3 of this RIA, the anthropogenic 

buildup of GHGs in the atmosphere is very likely the cause of most of the observed global 

warming over the last 50 years.

On April 13, 2012, the EPA proposed new source performance standards for emissions 

of carbon dioxide for new affected fossil fuel-fired EGUs (77 FR 22392). After consideration of 

public comments received – totaling approximately 2.5 million – the EPA determined that 

significant revisions in its proposed approach are warranted to tailor the required emission 

limits to the different types of sources in the electricity sector. As such, the EPA is, in a separate 

action, rescinding the original proposal and is re-proposing standards of performance for new 

affected fossil fuel-fired EGUs.

The statutory authority for this action is Clean Air Act (CAA) section 111(b), which 

addresses standards of performance for new, modified, and reconstructed sources. Today’s 

proposal applies to new sources, which are sources that “commence construction” after 

publication of the proposal. Based on current information, the Wolverine project in Rogers City, 

Michigan appears to be the only fossil fuel-fired boiler or integrated gasification combined cycle 

(IGCC) EGU project presently under development without carbon capture and storage (CCS)

with an air permit that has not already commenced construction. We anticipate proposing 
1-2

standards for this project when we finalize today’s action if the project has not yet commenced 

construction and has not been canceled.

This rulemaking affects CAA section 111(b) new sources of GHG emissions from fossil 

fuel-fired EGUs but does not address GHG emissions from existing sources. This rulemaking also 

does not propose standards for modified or reconstructed sources. 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 eightyear NSPS timeframe.

1 EPA’s finding of no new, unplanned conventional coal-fired capacity 

(and therefore, no projected costs or quantified benefits) is robust beyond the analysis period 

(past 2030 in both U.S. Energy Information Administration – EIA – and EPA baseline modeling 

projections) and across a wide range of alternative potential market, technical, and regulatory 

scenarios that influence power sector investment decisions. Sections 5.8 to 5.11 of this RIA 

discuss the social costs and benefits of the proposed standards in any limited cases where new 

coal plant builds are affected by the standard.

This rule is consistent with the Climate Action Plan announced by the President in June 

2013 to cut the carbon pollution that causes climate change and affects public health. The 

President directed EPA to work expeditiously to complete carbon pollution standards for new 

power plants.2 It is also consistent with the President’s goal to ensure that “by 2035 we will 

generate 80 percent of our electricity from a diverse set of clean energy sources - including 

renewable energy sources like wind, solar, biomass and hydropower, nuclear power, efficient 

natural gas, and clean coal.”3 Additionally, this rule demonstrates to other countries that the 

United States is taking action to limit GHGs from its largest emissions sources, in line with our 

intention to demonstrate global leadership. The impact of GHGs is global, and U.S. action to 

reduce GHG emissions complements ongoing programs and efforts in other countries.

1.2 Summary of the Proposed Rule

This rule proposes emission standards for affected fossil fuel-fired units within existing 

subparts – natural gas-fired stationary combustion turbines and fossil fuel-fired electric utility 

steam generating units (boilers and IGCC). All affected new fossil fuel-fired EGUs would be 

required to meet an output-based emission rate of a specific mass of CO2 per MWh of 

 1 Conditions in the analysis year of 2022 are represented by a model year of 2020.

2 “The President’s Climate Action Plan.” June 2013. Available online at: 

http://www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf 3

“Blueprint for a Secure Energy Future.” March 30, 2011. Available online at: 

http://www.whitehouse.gov/sites/default/files/blueprint_secure_energy_future.pdf
1-3

electricity generated energy output on a gross basis. These standards would be met on a 12-

operating month rolling average basis. The EPA is proposing standards of performance for 

affected sources within the following subcategories: (1) natural gas-fired stationary combustion 

turbines with a heat input rating to the turbine engine that is greater than 850 million British 

Thermal units per hour (MMBtu/hr); (2) natural gas-fired stationary combustion turbines with a 

heat input rating to the turbine engine that is less than or equal to 850 MMBtu/hr; and (3) all 

fossil fuel-fired boilers and IGCC units. The respective emission limits are shown in table 1-1.

Table 1-1. Proposed Emission Limits

Source Emission Limit 

(lb CO2/MWh

Gross Basis)

Stationary natural gas-fired combustion turbine EGUs with a

heat input rating greater than 850 MMBtu/hr

1,000

Stationary natural gas-fired combustion turbine EGUs with a

heat input rating less than or equal to 850 MMBtu/hr 

1,100

Fossil fuel-fired boilers and IGCCs 1,100

This action also proposes an alternative emission limit, available only to new fossil-fuel 

fired boilers and IGCCs, which can be met over an 84-operating month rolling average basis. 

The alternative emission limit will be between 1,000 and 1,050 lb CO2/MWh of gross energy 

output.

1.3 Key Findings of Economic Analysis

As explained in detail in this document, energy market data and projections support the 

conclusion that, even in the absence of this rule, existing and anticipated economic conditions 

will lead electricity generators to choose new generation technologies that meet the proposed 

standard without the need for additional controls. The base case modeling the EPA performed 

for this rule (as well as modeling that the EPA has performed 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 natural gas combined cycle capacity. Alternatively, 

coal-fired capacity with partial CCS could also be built at costs similar to the costs power 

companies are paying for other, lower CO2-emitting, non-natural gas, baseload generation 

technologies. Analyses performed both by the EPA and the EIA4 project that generation 

technologies other than those utilizing coal (including natural gas-fired and renewable sources) 

 4

 Annual Energy Outlook (AEO) 2009- 2013.
1-4

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

projected economic market conditions.

Therefore, based on the analysis presented in Chapter 5, the EPA anticipates that the 

proposed EGU New 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 impacts on the price of electricity, employment 

or labor markets, or the US economy. Nonetheless, this rule may have several important 

beneficial effects described below.

This NSPS would provide regulatory certainty that any new coal-fired power plant must 

limit CO2 emissions by implementing some form of partial capture and storage. Therefore, the 

proposed regulation would provide an incentive for supporting research, development, and 

investment into technology to capture and store CO2. Rather than relying solely on dynamic

energy market conditions to limit emissions from new power plants, this rule provides 

additional certainty to help incentivize innovation that would lead to lower CO2 emissions in 

the future. The proposed rule is also a prerequisite for the regulation of existing sources within 

this source category under CAA section 111(d). 

While sector-wide modeling does not project any new coal-fired EGUs without CCS to be 

built in the absence of this proposal, we recognize that a few companies may choose to 

construct coal or other solid fossil fuel-fired units. In Chapter 5 of this RIA we present an 

analysis of the project-level costs of a new coal-fired unit with and without CCS, and estimate 

the social benefits of requiring CCS on a new uncontrolled unit. We also present a sensitivity 

analysis indicating that even in the unlikely event that market conditions change sufficiently to 

make the widespread construction of new conventional coal-fired units economical from the 

perspective of private investors, this rule would result in net benefits from avoided negative 

health and environmental effects.

The rule will reduce regulatory uncertainty by defining requirements for emission limits 

for GHG from new fossil fuel-fired EGU sources. In addition, the EPA intends this rule to send a 

clear signal about the current and future status of CCS technology. Identifying partial 

implementation of CCS technology as the best system of emission reductions (BSER) for coalfired power plants promotes further development of CCS, which is important for long-term CO2

emission reductions. Particularly because the CCS technologies have had limited application to 

date, additional CCS applications are expected to lead to improvements in these technologies’ 

performance and consequent reductions in their cost. Moreover, partial implementation of CCS 
1-5

is a viable CO2 control for new coal-fired power plants as identified in the BSER determination. 

Acknowledging that CCS is a viable control will encourage continued research, including, for 

example, continued research collaboration between the U.S. and China.5,6

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

http://energy.gov/articles/building-clean-energy-partnerships-china-and-japan. 6 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. 
2-1

CHAPTER 2

INTRODUCTION AND BACKGROUND

2.1 Introduction

In this action, the EPA seeks to set emission limits for GHGs, specifically CO2, emitted 

from fossil fuel-fired EGUs. This document presents the expected economic impacts of the 

proposed EGU New Source GHG Standards rule through 2022, including some projections for 

years up to 2030. Based on the analysis presented in Chapter 5, expected and anticipated 

economic conditions will lead electricity generators to choose fuels and technologies that are 

designed to meet the proposed standard without the need for additional capture or control,

even in the absence of the rule. As a result, this rule is expected to have no, or negligible, costs 

or monetized benefits associated with it. This chapter contains background information on the 

rule and an outline of the chapters of the report.

2.1.1 Statutory Requirement

Section 111 of the CAA requires performance standards for air pollutant emissions from 

categories of stationary sources that may reasonably contribute to endangerment of public 

health or welfare. In April 2007, the Supreme Court ruled in 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 must make decisions about 

whether to regulate GHGs under certain provisions of the CAA, based on relevant statutory 

criteria. The EPA issued a final determination that GHG emissions 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 the CAA (74 FR 66,496; 

Dec. 15, 2009). Because fossil fuel-fired EGUs contribute significantly to domestic CO2

emissions, the EPA is proposing this action to regulate these emissions from new EGU sources

under section 111 of the CAA.

On April 13, 2012, the EPA proposed new source performance standards for emissions 

of CO2 for new affected fossil fuel-fired EGUs (77 FR 22392). After consideration of public 

comments received – totaling approximately 2.5 million – the EPA determined that significant 

revisions in its proposed approach are warranted to tailor the required emission limits to the 

different types of sources in the electricity sector. As such, the EPA is, in a separate action, 

rescinding the original proposal and is re-proposing standards of performance for new affected 

fossil fuel-fired EGUs. This action addresses standards for new sources but does not address 

standards for modified, reconstructed, or existing sources. 
2-2

2.1.2 Regulatory Analysis 

In accordance with Executive Order 12866, Executive Order 13563, and EPA’s Guidelines 

for Preparing Economic Analyses, the EPA prepared this 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 source emission limits

that are the focus of this action. The EPA does not anticipate that any costs or quantified 

benefits will result from this proposed rule, if companies make the types of choices related to 

new generation that the EPA’s modeling, EIA’s modeling and many utility IRP’s indicate they are 

likely to make. If some companies do choose to build new coal plants, there could be some 

compliance costs. However, in these cases, the rule will result in net societal benefits under a 

range of assumptions.

For new sources, the EPA and other energy modeling groups such as EIA1 do not project 

that any new coal capacity without federally-supported CCS will be built in the analysis period.

This is due in part to the low levelized cost of base load NGCC capacity relative to coal capacity, 

relatively low growth in electricity demand, and use of energy efficiency and renewable energy 

resources. This conclusion holds under a range of sensitivity analyses as well as in the EPA’s 

baseline scenario. Furthermore, absent this rule, any new NGCC that may be built is expected 

to have an annual emission rate in compliance with the standard. Because this rule does not 

change these projections, it is expected to have no, or negligible, costs2 or quantified benefits 

 1 AEO 2009-2013. 2 Because of existing and anticipated trends in the marketplace, the EPA does not project that any EGUs expected 

to be built within the time frame of our analysis will have to install additional controls to meet the standard. 

Additionally, because new generators would already be required to monitor and report their CO2 emissions 

under the information collection requirements contained in the existing part 75 and 98 regulations (40 CFR part 

75 and 40 CFR part 98), any additional monitoring or reporting costs from this proposed rule should be 

negligible. 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 6 for more details on monitoring and reporting 

costs.
2-3

associated with it. Chapter 5 of this RIA also provides an illustrative analysis of the levelized cost 

of electricity and health and environmental impacts associated with representative new 

conventional coal and NGCC units, under a range of natural gas price assumptions. That 

analysis, along with information on historical3 and projected4 gas prices, supports the 

conclusion that this standard is highly likely to have no costs or benefits. While we do not 

project any new coal-fired EGUs without CCS to be built in the absence of this proposal, 

because some companies may choose to construct coal or other solid fossil fuel-fired units, 

Chapter 5 also includes an analysis of the project-level costs of a unit with and without CCS, to 

quantify the potential cost for a solid fossil fuel-fired unit with CCS. There is also a comparison

of the costs and benefits for the proposed standard that can be met using partial CCS and a 

more stringent alternative requiring full CCS. 

2.2 Background for the Proposed EGU New Source GHG Standards

2.2.1 Baseline and Years of Analysis

The rule on which this analysis is based proposes GHG emission limits for new 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 agencies as 

well as final federal rules. Additional legally binding and enforceable commitments for GHG 

reductions considered in the baseline are discussed in Chapter 5 of this RIA.

All analysis is presented for compliance through the year 20225 and all estimates are 

presented in 2011 dollars. CAA Section 111(b) requires that the 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. EPA’s finding of no new, unplanned conventional coalfired capacity (and therefore, no projected costs or quantified benefits) is 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 power 

sector investment decisions.6 Sections 5.8 to 5.11 of this RIA discuss the social costs and 

benefits of the proposed standards in any limited cases where new coal plant builds are 

 3 EIA. U.S. Natural Gas Prices. Available online at: http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm. 4

AEO 2009-2013. 5 Conditions in the analysis year of 2022 are represented by a model year of 2020. 6 For example, the low gas resource sensitivity scenario, one of the scenarios most favorable to new coal builds, 

does not begin to show new conventional coal builds until 2027. The No GHG Concern case does show limited 

amounts of conventional coal starting in 2023; however that model sensitivity case is unlikely to be reflected in 

actual markets given that investors factor in risks associated with all possible future policies (under both 

current authorities and potential legislation at the State and Federal levels) to reduce GHG emissions over the 

multi-decade life of the plant. 
2-4

affected by the standard. Any estimates presented in this report represent annualized 

estimates of the benefits and costs of the proposed EGU New Source GHG Standards rather 

than the net present value of a stream of benefits and costs in these particular years of 

analysis.7

2.2.2 Definition of Affected Sources

This action will directly regulate CO2 emissions from affected EGUs that commence 

construction after the issuance of this proposed rule. This rulemaking does not address GHG 

emissions from existing, modified, or reconstructed sources.

2.2.2.1 New Sources

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

of performance for new, modified, and reconstructed sources. Today’s proposal applies to new 

sources, which are sources that “commence construction” after publication of the proposal. 

Based on current information, the Wolverine project in Rogers City, Michigan appears to be the 

only fossil fuel-fired boiler or IGCC EGU project presently under development without CCS with 

an air permit that has not already commenced construction. We anticipate proposing 

standards for this project when we finalize today’s action if the project has not yet commenced 

construction and has not been canceled. See the preamble for further discussion.

2.2.2.2 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. 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. The significant majority of projects that the 

EPA believes EGUs are most likely to undertake in the foreseeable future that could increase 

the maximum achievable hourly rate of CO2 emissions would be pollution control projects that 

are exempt under this definition. The EPA is not proposing a standard of performance for 

modifications at this time. As a result, existing sources that undertake modifications will 

continue to be treated as existing sources and thus not subject to the requirements of this rule.

 7 However, 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. See Chapter 5 for details.
2-5

2.2.2.3 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).

Historically, very few power plants have undertaken reconstructions. We are not aware that 

any power plants are presently planning any project that would meet the requirements for a 

reconstruction. The EPA is not proposing a standard for reconstructions. As a result, sources 

that undertake reconstruction will be treated as existing sources and thus not subject to the 

requirements of this rule.

2.2.2.4 Existing Sources 

For the purposes of this rule, an existing EGU is defined as any fossil fuel-fired 

combustion unit that sells more than one-third of its potential electric output and more than 

219,000 MWh net-electrical output to the grid on a three year rolling average basis and was in 

operation or commenced construction on or before publication of the proposed rule. Existing 

sources are not covered in this proposed rule.

2.2.3 Regulated Pollutant

This rule sets a limit for CO2 emissions from affected sources. The EPA is proposing

these requirements because CO2 is a GHG and fossil fuel-fired power plants are the country’s 

largest stationary source emitters of GHGs. In 2009, the EPA found that by causing or 

contributing to climate change, GHGs endanger both the public health and the public welfare of 

current and future generations.

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 proposing separate N2O or CH4 emission limits or an equivalent CO2 emission limit because 

of a lack of available data for these affected sources. Additional information on the quantity 

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

before proposing standards for these pollutants.
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2.2.4 Emission Limits

This rule proposes emission standards for affected fossil fuel-fired units within existing 

subparts – natural gas-fired stationary combustion turbines and fossil fuel-fired electric utility 

steam generating units (boilers and IGCC units). The EPA is proposing standards of performance 

for affected sources within the following subcategories: (1) natural gas-fired stationary 

combustion turbines with a heat input rating to the turbine engine that is greater than 850 

million MMBtu/hr; (2) natural gas-fired stationary combustion turbines with a heat input rating 

to the turbine engine that is less than or equal to 850 MMBtu/hr; and (3) all fossil fuel-fired 

boilers and IGCC units. The respective emission limits are shown in table 2-1.

Table 2-1. Proposed Emission Limits

Subcategory Emission Limit 

(lb CO2/MWh)

Stationary natural gas-fired combustion turbine EGUs with a 

heat input rating greater than 850 MMBtu/hr

1,000

Stationary natural gas-fired combustion turbine EGUs with a 

heat input rating less than or equal to 850 MMBtu/hr

1,100

Fossil fuel-fired boilers and IGCC 1,100

This action also proposes an alternative emission limit, available only to new fossil fuelfired boilers and IGCC units, which can be met over an 84-operating month rolling average 

basis. The alternative emission limit will be between 1,000 and 1,050 lb CO2/MWh of gross 

energy output.

2.2.5 Emission Reductions

As will be discussed in more detail in Chapter 5 of this RIA, the EPA anticipates that the 

proposed EGU New Source GHG Standards will result in negligible changes in GHG emissions 

over the analysis period (through 2022 and following years). Even in the absence of this rule, 

the EPA expects that owners of new units will choose generation technologies that meet these 

standards due to expected economic conditions in the marketplace. 

2.3 Organization of the Regulatory Impact Analysis

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

economic effects of the proposed EGU New Source GHG Standards to fulfill the requirements of 

an RIA. This RIA includes the following chapters:
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 Chapter 3, Defining the Climate Change Problem and Rationale for the Rulemaking, 

describes the effects of GHG emissions on climate and offers support for the EPA 

undertaking this rulemaking.

 Chapter 4, Electric Power Sector Profile, describes the industry affected by the rule.

 Chapter 5, Costs, Benefits, Economic, and Energy Impacts, describes impacts of the 

proposed rule.

 Chapter 6, 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.
3-1

CHAPTER 3

DEFINING THE CLIMATE CHANGE PROBLEM AND RATIONALE FOR RULEMAKING

3.1 Overview of Climate Change Impacts from GHG Emissions

Through the implementation of CAA regulations, EPA addresses the negative 

externalities caused by air pollution. In 2009, the EPA Administrator found that elevated 

concentrations of greenhouse gases in the atmosphere may reasonably be anticipated both to 

endanger public health and to endanger public welfare. It is these adverse impacts that make it 

necessary for the EPA to regulate GHGs from EGU sources. This proposed rule is designed to set 

emission limits for CO2, in order to minimize the rate of increase of concentrations of these 

gases in the atmosphere, and therefore reduce the risk of adverse effects. 

This chapter summarizes the adverse effects on public health and public welfare 

detailed in the 2009 Endangerment Finding.1 The 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 basis for these effects.

3.1.1 Public Health

Climate change threatens public health in a number of ways: direct temperature effects, 

the effect of higher CO2 on other characteristics of air quality, the potential for changes in 

vector-borne diseases, and the potential for changes in the severity and frequency of extreme 

weather events. Additionally, susceptible populations may be particularly at risk. Each of these 

effects will be addressed in turn in this section, based on the 2009 Endangerment Finding.

Regarding direct temperature changes, it has already been observed that unusually hot 

days and heat waves are becoming more frequent, and that unusually cold days are becoming 

less frequent. Heat is already the leading cause of weather-related deaths in the United States. 

In the future, severe heat waves are projected to intensify in magnitude and duration over the 

portions of the United States where these events have already been observed. Heat waves are 

associated with marked short-term increases in mortality. Hot temperatures have also been 

associated with increased morbidity. If observed warming continues as projected, it will

increase heat related mortality and morbidity, especially among the elderly, young, and frail. 

Different segments of the population are sensitive to these trends for different reasons. The

most sensitive to hot temperatures are older adults, the chronically sick, the very young, city-

 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).
3-2

dwellers, and those taking medications that disrupt thermoregulation. Others that are 

demonstrated to be sensitive to this trend are the mentally ill, those lacking access to air 

conditioning, those working or playing outdoors, and socially isolated persons. As warming 

increases over time, these adverse effects would be expected to increase as the serious heat 

events become more frequent, prolonged, and extreme. 

Conversely, increases in temperature are also expected to lead to some reduction in the 

risk of death related to extreme cold. However it is not clear whether reduced mortality in the 

United States from cold would be greater or less than increased heat-related mortality in the 

United States due to climate change. However, there is a risk that projections of cold-related 

deaths, and the potential for decreasing their numbers due to warmer winters, can be 

overestimated unless they take into account the tendency for deaths to increase in winter for 

reasons which are not strongly associated with cold temperatures, such as influenza. To 

illustrate the difficulty of measuring the total effect of these two related trends, the latest 

USGCRP report (2009) refers to a study (Medina-Ramon and Schwartz, 2007) that analyzed daily 

mortality and weather data in 50 U.S. cities from 1989 to 2000 and found that, on average, cold 

snaps in the United States increased death rates by 1.6 percent, while heat waves triggered a 

5.7 percent increase in death rates. While a single study is not conclusive, this study concludes 

that increases in heat-related mortality due to global warming in the United States are likely to 

be greater than decreases in cold-related mortality. 

Climate change is expected to increase regional ozone pollution compared to what 

ozone levels would be in the absence of climate change, with associated risks in respiratory 

illnesses and premature death. In addition to human health effects, tropospheric ozone has 

significant adverse effects on crop yields, pasture and forest growth, and the composition of 

plant and animal species populations. 

Peer reviewed modeling studies discussed in the EPA’s Interim Assessment (2009) show 

that modeled climate change causes increases in summertime ozone concentrations over 

substantial regions of the country, though this was not uniform. Some areas showed little 

change or slight decreases, though the decreases tend to be less pronounced than the 

increases. The key metric for regulating U.S. air quality is the maximum daily 8-hour average 

ozone concentration. For those regions that showed climate-induced increases, the increase in 

2050, was in the range of 2 to 8 ppb, averaged over the summer season. The increases were 

substantially greater than 2 to 8 ppb during the peak pollution episodes that tend to occur over 

a number of days each summer. The overall effect of climate change was projected to increase 

ozone levels, compared to what would occur without this climate change, over broad areas of 
3-3

the country, especially on the highest ozone days and in the largest metropolitan areas with the 

worst ozone problems. Ozone decreases are projected to be less pronounced, and generally to 

be limited to some regions of the country with smaller population. 

In addition to impacts on heat-related mortality and air quality, there is also the 

potential for increased deaths, injuries, infectious diseases, and stress-related disorders and 

other adverse effects associated with social disruption and migration from more frequent 

extreme weather. Vulnerability to these disasters depends on the attributes of the people at 

risk and on broader social and environmental factors. 

Increases in the frequency of heavy precipitation events are associated with increased 

risk of deaths and injuries as well as infectious, respiratory, and skin diseases. Floods are lowprobability, high-impact events that can overwhelm physical infrastructure, human resilience, 

and social organization. Floods cause impacts to health that include deaths, injuries, infectious 

diseases, toxic contamination, and mental health problems. 

Increases in tropical cyclone intensity (hurricanes and tropical storms) are linked to 

increases in the risk of deaths, injuries, waterborne and food borne diseases, as well as posttraumatic stress disorders. Storm surge is the major killer in coastal storms, and the risk of 

death by drowning from surge will be heightened by the projected rising sea levels and 

increased storm intensity. Flooding caused by intense cyclonic events can cause health impacts 

including direct injuries as well as increased incidence of waterborne diseases.

According to the assessment literature, there will also likely be an increase in the spread 

of serial episodes of food and water-borne pathogens among susceptible populations 

depending on the pathogens’ survival, persistence, habitat range and transmission under 

changing climate and environmental conditions. Food borne diseases show some relationship 

with temperature. The range of some zoonotic disease carriers, such as the Lyme diseasecarrying tick, may increase with temperature. 

Climate change, including changes in CO2 concentrations, could impact the production, 

distribution, dispersion, and allergenicity of aeroallergens and the growth and distribution of 

weeds, grasses, and trees that produce them. These changes in aeroallergens and subsequent 

human exposures could affect the prevalence and severity of allergy symptoms. However, the 

scientific literature does not provide definitive data or conclusions on how climate change 

might impact aeroallergens and subsequently the prevalence of allergenic illnesses in the 

United States. It has generally been observed that the presence of elevated CO2 concentrations 
3-4

and temperatures stimulate plants to increase photosynthesis, biomass, water use efficiency, 

and reproductive effort. The IPCC concluded that pollens are likely to increase with elevated 

temperature and CO2. 

3.1.2 Public Welfare

As with public health, there are multiple pathways in which the greenhouse gas air 

pollution and resultant climate change affect climate-sensitive economic sectors and 

environmental media. These sectors include food production and agriculture; forestry; water 

resources; sea level rise and coastal areas; energy, infrastructure, and settlements; and 

ecosystems and wildlife. Impacts also arise from climate change occurring outside of the United 

States, such as national security concerns for the United States that may arise as a result of 

climate change impacts in other regions of the world. Each of these effects will be addressed in 

turn in this section, based on the 2009 Finding.

Regarding food production and agriculture, elevated CO2 concentrations can have a 

stimulatory effect, as may modest temperature increases and a resulting longer growing 

season. However, elevated CO2 concentrations may also enhance pest and weed growth. In 

addition, higher temperature increases, changing precipitation patterns and variability, and any 

increases in ground-level ozone induced by higher temperatures, can work to counteract any 

direct stimulatory carbon dioxide effect, as well as lead to their own adverse impacts. A

USGCRP report (2009) concluded that while for some crops such as grain and oilseed crops 

there may be a beneficial effect overall in the next couple decades, as temperature rises, these 

crops will increasingly begin to experience failure, especially if climate variability increases and 

precipitation lessens or becomes more variable. Changes in the intensity and frequency of 

extreme weather events such as droughts and heavy storms have the potential to have serious 

negative impact on U.S. food production and agriculture. Changing precipitation patterns, in 

addition to increasing temperatures and longer growing seasons, can change the demand for 

irrigation requirements, potentially increasing irrigation demand. 

With respect to livestock, higher temperatures will very likely reduce livestock 

production during the summer season in some areas, but these losses will very likely be 

partially offset by warmer temperatures during the winter season. The impact on livestock 

productivity due to increased variability in weather patterns will likely be far greater than the 

effects associated with an absolute change in average climatic conditions.

For the forestry sector there are similar factors to consider. There is the potential for 

beneficial effects due to elevated concentrations of carbon dioxide, increased temperatures,
3-5

and nitrogen deposition, but there is also the potential for adverse effects from increasing 

temperatures, changing precipitation patterns, increased insects and disease, and the potential 

for more frequent and severe extreme weather events. According to the science assessment 

reports on which the Administrator relied for the 2009 Finding, climate change has very likely 

increased the size and number of wildfires, insect outbreaks, and increased tree mortality in the 

Interior West, the Southwest, and Alaska, and will continue to do so. 

If existing trends in precipitation continue, it is expected that forest productivity will 

likely decrease in the Interior West, the Southwest, eastern portions of the Southeast, and 

Alaska, and that forest productivity will likely increase in the northeastern United States, the 

Lake States, and in western portions of the Southeast. An increase in drought events will very 

likely reduce forest productivity wherever such events occur. 

The sensitivity of water resources to climate change is very important given the 

increasing demand for adequate water supplies and services for agricultural, municipal, and 

energy and industrial uses, and the current strains on this resource in many parts of the 

country. According to the assessment literature, climate change has already altered, and will 

likely continue to alter the water cycle, affecting where, when, and how much water is available 

for all uses. With higher temperatures, the water-holding capacity of the atmosphere and 

evaporation into the atmosphere increase, and this favors increased climate variability, with 

more intense precipitation and more droughts. 

Climate change is causing and will increasingly cause shrinking snowpack induced by 

increasing temperature. In the western United States, there is already well-documented 

evidence of shrinking snowpack due to warming. Earlier meltings, with increased runoff in the 

winter and early spring, increase flood concerns and also result in substantially decreased 

summer flows. This pattern of reduced snowpack and changes to the flow regime pose very 

serious risks to major population regions, such as California, that rely on snowmelt-dominated 

watersheds for their water supply. While increased precipitation is expected to increase water 

flow levels in some eastern areas, this may be tempered by increased variability in the 

precipitation and the accompanying increased risk of floods and other concerns such as water 

pollution. 

Climate change will likely further constrain already over-allocated water resources in 

some regions of the United States, increasing competition among agricultural, municipal, 

industrial, and ecological uses. Increased incidence of extreme weather and floods may also 
3-6

overwhelm or damage water treatment and management systems, resulting in water quality 

impairments. 

According to the assessment literature, sea level is rising along much of the U.S. coast

and the rate of change will very likely increase in the future, exacerbating the impacts of 

progressive inundation, storm-surge flooding, and shoreline erosion. A large percentage of the 

U.S. population lives in these coastal areas. The most vulnerable areas are the Atlantic and Gulf 

Coasts, the Pacific Islands, and parts of Alaska. Cities such as New Orleans, Miami, and New 

York are particularly at risk, and could have difficulty coping with the sea level rise projected by 

the end of the century under a higher emissions scenario. Population growth and the rising 

value of infrastructure increases the vulnerability of coastal areas to climate variability and 

future climate change. Adverse impacts on islands present concerns for Hawaii and the U.S. 

territories. Reductions in Arctic sea ice increases extreme coastal erosion in Alaska, due to the 

increased exposure of the coastline to strong wave action. In the Great Lakes, where sea level 

rise is not a concern, both extremely high and low water levels resulting from changes to the 

hydrological cycle have been damaging and disruptive to shoreline communities. 

Coastal wetland loss is being observed in the United States where these ecosystems are 

squeezed between natural and artificial landward boundaries and rising sea levels. Up to 21 

percent of the remaining coastal wetlands in the U.S. mid-Atlantic region are potentially at risk 

of inundation between 2000 and 2100. Stress will increase on coastal habitats though the 

interaction of climate change with development and pollution related to development. 

Although increases in mean sea level over the 21st century and beyond are projected to

inundate unprotected, low-lying areas, the most devastating impacts are likely to be associated 

with storm surge. Superimposed on expected rates of sea level rise, projected storm intensity, 

wave height, and storm surge suggest more severe coastal flooding and erosion hazards. Higher 

sea level provides an elevated base from which storm surges occur and diminishes the rate at 

which low-lying areas drain, thereby increasing the risk of flooding from rainstorms. In New 

York City and Long Island, flooding from a combination of sea level rise and storm surge could 

be several meters deep. Projections suggest that the recurrence period of a 100-year flood 

event in this area might be reduced to 4–60 years by the 2080s. Additionally, some major urban 

centers in the United States, such as areas of New Orleans are situated in low-lying flood plains, 

presenting increased risk from storm surges. 

With respect to infrastructure, climate change vulnerabilities of industry, settlement,

and society are mainly related to changes in intensity and frequency of extreme weather events 
3-7

rather than to gradual climate change. Extreme weather events could threaten U.S. energy 

infrastructure (transmission and distribution), transportation infrastructure (roads, bridges, 

airports and seaports), water infrastructure, and other built aspects of human settlements. 

Moreover, soil subsidence caused by the melting of permafrost in the Arctic region is a risk to 

gas and oil pipelines, electrical transmission towers, roads, and water systems. 

Within settlements experiencing climate change stressors, certain parts of the 

population may be especially vulnerable based on their circumstances. These include the poor, 

the elderly, the very young, those already in poor health, the disabled, those living alone, 

and/or indigenous populations dependent on one or a few resources. In Alaska, indigenous 

communities are likely to experience disruptive impacts, including shifts in the range or 

abundance of wild species crucial to their livelihoods and well-being. 

Climate change is exerting major influences on natural environments and biodiversity, 

and these influences are generally expected to grow with increased warming. Observed 

changes in the life cycles of plants and animals include shifts in habitat ranges, timing of 

migration patterns, and changes in reproductive timing and behavior. 

The underlying assessment literature finds with high confidence that substantial 

changes in the structure and functioning of terrestrial ecosystems are very likely to occur with a 

global warming greater than 2 to 3 °C above pre-industrial levels, with predominantly negative 

consequences for biodiversity and the provisioning of ecosystem goods and services. With 

global average temperature changes above 2 °C, many terrestrial, freshwater, and marine 

species (particularly endemic species) are at a far greater risk of extinction than in the 

geological past. Climate change and ocean acidification will likely impair a wide range of 

planktonic and other marine calcifiers such as corals. Even without ocean acidification effects, 

increases in sea surface temperature of about 1 to 3 °C are projected to result in more frequent 

coral bleaching events and widespread coral mortality. In the Arctic, wildlife faces great 

challenges from the effects of climatic warming, as projected reductions in sea ice will 

drastically shrink marine habitat for polar bears, ice-inhabiting seals, and other animals. 

Some common forest types are projected to expand, others are projected to contract, 

and others, such as spruce-fir, are likely to disappear from the contiguous United States. 

Changes in plant species composition in response to climate change can increase ecosystem 

vulnerability to other disturbances, including wildfires and biological invasion. Disturbances 

such as wildfires and insect outbreaks are increasing in the United States and are likely to 

intensify in a warmer future with warmer winters, drier soils and longer growing seasons. The 
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areal extent of drought-limited ecosystems is projected to increase 11 percent per °C warming 

in the United States. In California, temperature increases greater than 2°C may lead to 

conversion of shrubland into desert and grassland ecosystems and evergreen conifer forests 

into mixed deciduous forests. Greater intensity of extreme events may alter disturbance 

regimes in coastal ecosystems leading to changes in diversity and ecosystem functioning. 

Species inhabiting salt marshes, mangroves, and coral reefs are likely to be particularly 

vulnerable to these effects. 

According to the USGCRP report of June 2009 and other sources, climate change 

impacts in certain regions of the world may exacerbate problems that raise humanitarian, 

trade, and national security issues for the United States.2 The IPCC identifies the most 

vulnerable world regions as Africa, especially the sub-Saharan region, because of current low 

adaptive capacity as well as climate change; small islands, due to high exposure of population 

and infrastructure to risk of sea-level rise and increased storm surge; Asian mega-deltas due to 

large populations and high exposure to sea level rise, storm surge, and river flooding; and the 

Arctic, because of the effects of high rates of projected warming on natural systems. Climate 

change has been described as a potential threat multiplier with regard to national security 

issues. While some of these international risks do not readily lend themselves to precise 

analyses or future projections, given the unavoidable global nature of the climate change 

problem it is appropriate and prudent to consider how impacts in other world regions may 

present risks to the U.S. population.

3.2 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.

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.

 2 ‘‘In an increasingly interdependent world, U.S. vulnerability to climate change is linked to the fates of other 

nations. For example, conflicts or mass migrations of people resulting from food scarcity and other resource limits, 

health impacts or environmental stresses in other parts of the world could threaten U.S. national security.’’ (Karl et 

al., 2009).
3-9

U.S. Environmental Protection Agency (2009). Assessment of the Impacts of Global Change on 

Regional U.S. Air Quality: A Synthesis of Climate Change Impacts on Ground-Level Ozone. 

An Interim Report of the U.S. EPA Global Change Research Program. U.S. Environmental 

Protection Agency, Washington, DC, EPA/600/R–07/094.

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.
4-1

CHAPTER 4

ELECTRIC POWER SECTOR PROFILE

4.1 Introduction

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

proposed EGU New Source GHG Standards, including the types of power-sector sources 

affected by the proposal, and provides background on the power sector and EGUs. In addition, 

this chapter provides some historical background on the EPA regulation of, and future 

projections for, the power sector.

4.2 Power Sector Overview

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

segments: generation, transmission, and distribution.

4.2.1 Generation

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

of the existing capacity for generating electricity does so by creating heat to create high 

pressure steam that is released to rotate turbines which, in turn, create electricity. The power 

sector consists of over 18,000 generating units, comprising fossil-fuel-fired units, nuclear units, 

and hydroelectric and other renewable sources dispersed throughout the country (see Table 4-

1).

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

residential uses, each of which consumes roughly a quarter to a third of the total electricity 

produced (see Table 4-2). Some of these uses are highly variable, such as heating and air 

conditioning in residential and commercial buildings, while others are relatively constant, such 

as industrial processes that operate 24 hours a day.
4-2

Table 4-1. Existing Electricity Generating Capacity by Energy Source, 2011

Energy Source

Number of 

Generators

Generator 

Nameplate 

Capacity (MW)

Generator Net 

Summer 

Capacity (MW)

Coal 1,400 343,757 317,640

Petroleum 3,738 57,537 51,208

Natural Gas 5,574 477,387 415,191

Other Gases 91 2,202 1,934

Nuclear 104 107,001 101,419

Hydroelectric Conventional 4,048 78,194 78,652

Wind 781 45,982 45,676

Solar Thermal and Photovoltaic 326 1,564 1,524

Wood and Wood-Derived Fuels 345 8,014 7,077

Geothermal 226 3,500 2,409

Other Biomass 1,660 5,192 4,536

Hydroelectric Pumped Storage 154 20,816 22,293

Other Energy Sources 81 1,697 1,420

Total 18,530 1,153,149 1,051,251

Source: Table 4.3, EIA Electric Power Annual, 2011

Note: This table presents generation capacity. Actual net generation is presented in Table 4-3.

Table 4-2. Total U.S. Electric Power Industry Retail Sales in 2011 (Billion kWh)

Sales/Direct Use 

(Billion kWh)

Share of Total 

End Use

Retail Sales

Residential 1,423 37.9%

Commercial 1,328 35.4%

Industrial 991 26.4%

Transportation 8 0.2%

Direct Use 133 3.5%

Total End Use 3,883 100%

Source: Table 2.2, EIA Electric Power Annual, 2011

In 2011, electric generating sources produced 3,949 billion kWh to meet electricity 

demand. Roughly 70 percent of this electricity was produced through the combustion of fossil 

fuels, primarily coal and natural gas, with coal accounting for the largest single share (see 

Table 4-3).
4-3

Table 4-3. Electricity Net Generation in 2011 (Billion kWh)

Net Generation 

(Billion kWh)

Fuel Source 

Share

Coal 1,718 43.5%

Petroleum 28 0.7%

Natural Gas 926 23.5%

Other Gases 3 0.1%

Nuclear 790 20.0%

Hydroelectric 312 7.9%

Other 172 4.3%

Total 3,949 100%

Source: Tables 3.2.A and 3.3.A, EIA Electric Power Annual, 2011

Note: Excludes generation from commercial and industrial sectors. Retail sales are not equal to net generation 

because net generation includes net exported electricity and loss of electricity that occurs through 

transmission and distribution.

Coal-fired generating units have historically supplied “base-load” electricity, the portion 

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

Along with nuclear generation, these 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 4-4). 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 coal-fired 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. 

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. Projections of 

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

Chapter 5 of this RIA.
4-4

Table 4-4. Coal Steam Electricity 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)

0 to 25 193 15% 45 15 2,849 1% 11,154

>25 to 49 108 9% 42 38 4,081 1% 11,722

50 to 99 162 13% 47 75 12,132 4% 11,328

100 to 149 269 21% 49 141 38,051 12% 10,641

150 to 249 81 6% 43 224 18,184 6% 10,303

250 and up 453 36% 34 532 241,184 76% 10,193

Totals 1,266 316,480

Source: National Electric Energy Data System (NEEDS) v.4.10

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 online in 2010 or earlier, and excludes those 

units with planned retirements.

4.2.2 Transmission

Transmission is the term used to describe the movement 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,

1 each 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 

operator; in others, individual utilities coordinate the operations of their generation, 

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

 1

These three network interconnections are the western US and Canada, corresponding approximately to the area 

west of the Rocky Mountains; eastern US and Canada, not including most of Texas; and a third network 

operating in most of Texas. These are commonly referred to as the Western Interconnect Region, Eastern 

Interconnect Region, and ERCOT, respectively.
4-5

Figure 4-1. Fossil Fuel-Fired Electricity Generating Facilities, by Size

Source: National Electric Energy Data System (NEEDS) 4.10 

Note: This map displays facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capacity on-line by the 

end of 2011. This includes planned new builds and planned retirements. In areas with a dense 

concentration of facilities, some facilities may be obscured.

4.2.3 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.

Transmission has generally been developed by the larger vertically integrated utilities 

that typically operate generation and distribution networks. Often distribution is handled by a 

large number of utilities that purchase and sell electricity, but do not generate it. 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.

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 
4-6

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.

4.3 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.

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 4-2 below). 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 4-2 below). Currently, there are 15 states 

where price deregulation of generation (restructuring) has occurred (“Active” in Figure 4-2 

below). Power sector restructuring is more or less at a standstill; there have been no recent 

proposals to the Federal Energy Regulatory Commission (FERC) for actions aimed at wider 

restructuring, and no additional states have recently begun retail deregulation activity.
4-7

Figure 4-2. Status of State Electricity Industry Restructuring Activities

Source: EIA 2010a. 

4.4 Emissions of Greenhouse Gases from Electric Utilities

The burning of fossil fuels, which generates about 70 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), CH4, and 

N2O. In 2011, the power sector accounted for 33 percent of total nationwide greenhouse gas

emissions, measured in CO2 equivalent, a slight increase from its 30 percent share in 1990.

Table 4-5 and Figure 4-3 show the contributions of the power sector relative to other major 

economic sectors. Table 4-6 and Figure 4-4 show the contributions of CO2 and other GHGs from 

the power sector.
4-8

Table 4-5. Domestic Emissions of Greenhouse Gases, by Economic Sector (million metric 

tonnes of CO2 equivalent)

Sector/Source 1990 1995 2000 2005 2011

Electricity Generation 1,866 1,992 2,336 2,446 2,201

Transportation 1,553 1,697 1,927 2,012 1,829

Industry 1,539 1,558 1,504 1,416 1,332

Agriculture 458 511 501 517 547

Commercial 388 391 376 374 378

Residential 345 367 386 371 357

U.S. Territories 34 41 46 58 58

Total Emissions 6,183 6,557 7,076 7,195 6,702

Source: EPA 2013

Figure 4-3. Domestic Emissions of Greenhouse Gases, 2011 (million metric tonnes of CO2

equivalent)

Source: EPA 2013

Other

4,501

67%

Electricity 

Generation

2,201

33%
4-9

Table 4-6. Greenhouse Gas Emissions from the Electricity Sector (Generation, Transmission 

and Distribution), 2011 (million metric tonnes of CO2 equivalent)

Source Total Emissions

CO2 2,175.5

CO2 from Fossil Fuel Combustion 2,158.5

Coal 1,722.7

Natural Gas 408.8

Petroleum 26.6

Geothermal 0.4

Incineration of Waste 12.4

Other Process Uses of Carbonates 4.6

CH4 0.4

Stationary Combustion* 0.4

Incineration of Waste +

N2O 18.3

Stationary Combustion* 17.9

Incineration of Waste 0.4

SF6

** 7.0

Electrical Transmission and Distribution 7.0

Total 2,201.2

Source: EPA 2013

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

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

+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.

The amount of CO2 emitted during the combustion of fossil fuels varies according to the 

carbon content and heating value of the fuel used (EIA, 2000) (see Table 4-7). Coal has higher 

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

emits around 1.7 times as much carbon per unit of energy when burned as does natural gas 

(EPA 2013).
4-10

Figure 4-4. GHG Emissions from the Power Sector Relative to Total Domestic GHG Emissions 

(2011)

Source: EPA 2013

39%

74%

5% 0.1% 0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

CO2 SF6 N2O CH4

Other

Power Sector
4-11

Table 4-7. Fossil Fuel Emission Factors in EPA Modeling Applications

Fuel Type Carbon Dioxide (lbs/MMBtu)

Coal 

Bituminous 205.2 – 206.6

Subbituminous 212.7 – 213.1

Lignite 213.5 – 217.0

Natural Gas 117.1

Fuel Oil 

Distillate 161.4

Residual 161.4 – 173.9

Biomass* 195

Waste Fuels 

Waste Coal 205.7

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.4.10. See also Table 9.9 of IPM Documentation.

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

emissions from initial photosynthesis (carbon sink) or harvesting activities and transportation (carbon 

source).

4.5 Carbon Dioxide Control Technologies

In the power sector there are currently only a few technical approaches available for 

significantly reducing the CO2 emissions of new fossil fuel combustion sources intended for 

intermediate and baseload operations. These include the use of: CCS, highest efficiency designs 

(e.g. supercritical or ultrasupercritical steam units, IGCC, or combined-cycle combustionturbine/steam-turbine units), and/or low-emitting fuels (e.g. natural gas rather than coal).

Daily peak electricity demands, involving operation for relatively few hours per year, are 

often most economically met by simple-cycle 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 30-33 percent (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 
4-12

gas its CO2 emission rate per MWh could be 40-60 percent higher than a more efficient NGCC 

unit.

Baseload 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 fertilizer, and CO2 can be captured for use in EOR. 

4.5.1 Carbon Capture and Storage

Carbon capture technology has been successfully applied since 1930 on several smaller 

scale industrial facilities and is currently in the demonstration phase for power sector 

applications. There are currently larger-scale projects under construction or in the advanced 

planning stages. 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).

For post-combustion capture, CO2 is stripped from the flue gas by passing the flue gas 

through a liquid absorbent which selectively reacts with the gaseous carbon dioxide to remove

it from the combustion gas stream. The absorbent, upon saturation, transfers to a downstream 

operation which regenerates the absorbent by desorbing the CO2 back to gaseous form. The 

absorbent recycles back into the process to repeat the capture cycle while the removed carbon 

dioxide is compressed, sent to storage and sequestered. This process is illustrated for a 

pulverized coal power plant in Figure 4-5. For post-combustion, a station's net generating 

output could be 20-30 percent lower due to the energy needs of the capture process.
4-13

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 gaseous components (“syngas”) under heat and pressure and some percentage 

of the carbon contained in the syngas is captured before combustion. For pre-combustion 

technology, a significant amount of energy is needed to gasify the fuel(s). This process is 

illustrated in Figure 4-6. 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 the current state of CCS technology, see the “Report of the Interagency Task Force on 

Carbon Capture and Storage” (2010).2

 2 For more information on the cost and performance of CCS, see http://www.netl.doe.gov/energyanalyses/baseline_studies.html.

Figure 4-5. Post-Combustion CO2 Capture for a Pulverized Coal Power Plant
4-14

Source: Interagency Task Force on Carbon Capture and Storage 2010

4.6 Geologic Sequestration

4.6.1 Availability of Geologic Sequestration

Geologic storage potential for CO2 is widespread and available throughout the U.S. and 

Canada. Geologic formations suitable for sequestration include depleted oil and gas fields, 

deep coal seams, and saline formations. The Department of Energy’s (DOE) National Energy 

Technology Laboratory (NETL) estimates the current total CO2 storage resource is 

approximately 2,380 to 20,353 billion metric tons (2,625 to 22,435 billion tons) in the U.S. and 

Canada. 3

 DOE’s estimates are intended to be used as an initial assessment of potential geologic 

storage. The assessments are intended to identify general geographical distribution of CO2

storage resources. This resource estimation is volumetrically based on physically accessible 

CO2 storage in specific formations in sedimentary basins without consideration of injection 

rates, regulations, economics, or surface land usage. Other types of geologic formations such 

as organic rich shale and basalt may have the ability to store CO2, and DOE is currently 

 3 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).

Figure 4-6. Pre-Combustion CO2 Capture for an IGCC Power Plant
4-15

evaluating their potential future storage capacity. Potential sequestration sites must undergo 

appropriate site characterization to ensure that the site can safely and securely store CO2. 

Estimates of CO2 storage resources by state/province from the DOE report are provided 

in Table 4-8. These state and province level estimates are obtained from DOE’s National Carbon 

Sequestration Database and Geographic Information System (NATCARB). Nearly every state in 

the U.S. has or is in close proximity to carbon storage potential including vast areas offshore. 

Information and methods used in estimating CO2 storage resource can be found in the 

“Methodology for Development of Geologic Storage Estimates for Carbon Dioxide” in Appendix 

B of the Carbon Utilization and Storage Atlas.

4

 It should be noted that the assessment of U.S. 

sequestration potential is an ongoing process. There is significant uncertainty in areas such as 

the Atlantic offshore due to a relative paucity of data and other factors.

In addition, the Department of Interior’s U.S. Geological Survey (USGS) recently 

completed an evaluation of the technically accessible storage resource for carbon storage for 

36 sedimentary basins in the onshore areas and State waters of the United States.5

 The USGS 

assessment estimates a range of 2,300 to 3,700 billion metric tons and a mean of 3,000 billion 

metric tons of CO2 storage potential across the United States. Technically accessible storage 

resources are those that can be accessed using today’s technology and pressurization and 

injection techniques. For comparison, this amount is 500 times the 2011 annual U.S. energyrelated CO2 emissions of 5.5 Gigatons (Gt)6

 Areas that were assessed by the USGS for CO2

storage compliment and are not identical to the areas assessed by DOE, NATCARB. The USGS

estimates are fractions of the total in-place resource that may be recoverable with 

technological advances or unforeseen changes in economic factors. This partly explains the 

difference between the USGS and DOE storage potential estimates. The USGS assessment 

methodology for CO2 storage resources focuses on the technically accessible resource, not a 

total in-place resource volume. In addition, the USGS methodology is not an economic 

assessment, nor does it incorporate engineering constraints in the estimation of the volume of 

the resource. The methodology does not take into account potential storage formations with 

salinities less than 10,000 ppm (parts per million; mg/L (milligrams per liter)) total dissolved 

solids (TDS) which is the definitional limit the U.S. Environmental Protection Agency uses for 

underground sources of drinking water. Similar to the DOE’s storage resource assessment, the 

 4 Ibid.

5 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment 

of geologic carbon dioxide storage resources – Summary: U.S. Geological Survey Factsheet 2013-3020, 

6p.http://pubs.usgs.gov/fs/2013/3020/. 6 U.S. Energy Information Administration, 2012
4-16

USGS methodology does not apply to site-specific evaluation of storage resources or capacity.7

The USGS assessment provides further evidence of the widespread availability CO2 storage 

reserves in the U.S. based on the comprehensive evaluation of the technically accessible 

storage resource for carbon storage for 36 sedimentary basins in the onshore areas and State 

waters of the United States.8

Table 4-8. Total CO2 Storage Resource9

Million Metric Tons*

State/Province Low Estimate High Estimate

ALABAMA 122,490 694,380 

ALASKA 8,640 19,750 

ALBERTA 41,840 131,230 

ARIZONA 130 1,170 

ARKANSAS 6,180 63,670 

BRITISH COLUMBIA 910 3,860 

CALIFORNIA 33,890 420,630 

COLORADO 37,610 357,190 

CONNECTICUT

DELAWARE 40 40 

DISTRICT OF COLUMBIA

FLORIDA 102,740 555,010 

GEORGIA 145,340 159,050 

HAWAII

IDAHO 40 390 

ILLINOIS 10,020 116,820 

INDIANA 32,020 68,210 

IOWA 10 50 

KANSAS 10,880 86,340 

KENTUCKY 2,920 7,650 

LOUISIANA 169,500 2,103,980 

MAINE

MANITOBA 1,720 3,520 

MARYLAND 1,860 1,930 

MASSACHUSETTS

 7 Brennan, S.T., Burruss, R.C., Merrill, M.D., Freeman, P.A., and Ruppert, L.F., 2010, A probabilistic assessment 

methodology for the evaluation of geologic carbon dioxide storage: U.S. Geological Survey Open-File Report 

2010–1127, 31 p., available online at http://pubs.usgs.gov/of/2010/1127. 8 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment 

of geologic carbon dioxide storage resources – Summary: U.S. Geological Survey Factsheet 2013-3020, 

6p.http://pubs.usgs.gov/fs/2013/3020/. 9 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).
4-17

Table 4-8. Total CO2 Storage Resource, cont.

.

*States/Provinces with a “zero” value represent estimates of minimal CO2 storage resource, while states/provinces 

with a blank represent areas that have not yet been assessed by the RCSPs

Million Metric Tons*

State/Province Low Estimate High Estimate

MICHIGAN 19,050 47,210 

MINNESOTA

MISSISSIPPI 145,010 1,185,030 

MISSOURI 10 170 

MONTANA 84,580 912,720 

NEBRASKA 23,770 113,240 

NEVADA

New Brunswick

NEW HAMPSHIRE

NEW JERSEY 0 0

NEW MEXICO 42,760 359,090 

NEW YORK 4,640 4,640 

Newfoundland & 

Labrador

NORTH CAROLINA 1,340 18,390 

NORTH DAKOTA 67,090 147,480 

Northwest Territories

Nova Scotia

Offshore Federal Only 489,840 6,440,090 

OHIO 13,460 13,460 

OKLAHOMA 56,950 244,550 

Ontario

OREGON 6,810 93,700 

PENNSYLVANIA 22,100 22,100 

PUERTO RICO

Quebec

RHODE ISLAND

SASKATCHEWAN 38,690 121,910 

SOUTH CAROLINA 30,100 34,180 

SOUTH DAKOTA 8,760 24,030 

TENNESSEE 430 3,860 

TEXAS 443,800 4,329,930 

UTAH 25,470 240,910 

VERMONT

VIRGINIA 440 2,910 

WASHINGTON 36,620 496,730 

WEST VIRGINIA 16,650 16,650 

WISCONSIN 0 0

WYOMING 72,690 684,850 

North America Total 2,379,840 20,352,700 
4-18

4.6.2 Enhanced Oil and Gas Recovery in the U.S.

Geologic storage options also include use of CO2 in enhanced oil recovery. Enhanced 

recovery (ER), which includes both enhanced oil and gas recovery (EOR and EGR), refers to the 

injection of fluids into a reservoir to increase oil and/or gas production efficiency. ER is typically 

conducted at a reservoir after production yields have decreased from primary production. 

Fluids commonly used for ER include brine, fresh water, steam, nitrogen, alkali solutions, 

surfactant solutions, polymer solutions, and carbon dioxide. EOR using supercritical carbon 

dioxide, sometimes referred to as carbon dioxide ‘flooding’ or CO2-EOR, involves injecting 

carbon dioxide into an oil reservoir to help mobilize the remaining oil and make it available for 

recovery. The crude oil and CO2 mixture is produced, and sent to a separator where the crude 

oil is separated from the gaseous hydrocarbons and CO2. The gaseous CO2-rich stream then is 

typically dehydrated, purified to remove hydrocarbons, recompressed, and reinjected into the 

oil or natural gas reservoir to further enhance recovery. The DOE’s Regional Carbon 

Sequestration Partnerships (RCSPs) have documented the location of more than 225 billion 

metric tons of CO2 storage potential in oil and gas reservoirs across over 30 states. 10

CO2-EOR has been successfully used at many production fields throughout the U.S. to 

increase oil recovery. The oil and natural gas industry in the United States has over 40 years of 

experience of injection and monitoring of CO2 in the deep subsurface for the purposes of 

enhancing oil and natural gas production. This experience provides a strong foundation for the 

injection and monitoring technologies that will be needed for successful deployment of CCS. 

Although deep saline formations provide the most CO2 storage opportunity (2,102 to 20,043 

billion metric tons), oil and gas reservoirs are currently estimated to have 226 billion metric 

tons of CO2 storage resource.11 EPA anticipates that many early geologic sequestration (GS) 

projects may be sited in active or depleted oil and gas reservoirs because these formations have 

been previously well characterized for hydrocarbon recovery, likely already have suitable 

infrastructure (e.g., wells, pipelines, etc.), and may be suitable for long term containment of 

CO2. 

4.6.3 Trends in CO2-EOR

CO2-EOR is the fastest-growing EOR technique in the U.S., providing approximately 281,000 

barrels of oil per day in the U.S. which equals about 6% percent of U.S. crude oil production.12,13

 10 Ibid. 11 Ibid. 12 Oil and Gas Journal EOR Survey, April 2010. 13 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil 

Recovery (CO2-EOR), DOE/NETL-2011/1504, June 20, 2011.
4-19

The vast majority of CO2-EOR is conducted in oil reservoirs in the U.S. Permian Basin, which 

extends through southwest Texas and southeast New Mexico. Other U.S. states where CO2-

EOR is utilized are Alabama, Colorado, Illinois, Kansas, Louisiana, Michigan, Mississippi, New 

Mexico, Oklahoma, Utah, and Wyoming. A well-established and expanding network of pipeline 

infrastructure supports CO2-EOR in these areas (Figure 4-8). The CO2 supply for EOR operations 

is largely obtained from underground formations or domes that contain CO2. While natural 

sources of CO2 comprise the majority of CO2 supplied for EOR operations, recent developments 

targeting anthropogenic sources of CO2 (e.g., ethanol plants, gas processing, refineries, power 

plants) have expanded or led to planned expansions in existing infrastructure related to CO2-

EOR.14 Several hundred miles of dedicated CO2 pipeline is under construction, planned, or 

proposed that would allow continued growth in CO2 supply for EOR (see Figure 4-8). 

Anthropogenic sources of CO2 for EOR continue to increase as new projects are being 

planned or implemented. Based on an evaluation of publicly available sources15, there are 

currently 23 industrial source CCS projects in 12 states that are either operational, underconstruction, or actively being pursued which are or will supply captured CO2 for the purposes 

of EOR. This demonstrates that CCS projects associated with large point sources are occurring 

due to a demand for CO2 by EOR operations. Nationally, according to EPA’s Greenhouse Gas 

Reporting Program, approximately 60 million metric tons of CO2 was received for injection to 

enhanced oil recovery operations in 2011. A recent study by DOE found that the market for 

captured CO2 emissions from power plants created by economically feasible CO2-EOR projects 

would be sufficient to permanently store the CO2 emissions from 93 large (1,000 MW) coalfired power plants operated for 30 years.16 There are also several state and Federal subsidy 

programs that are in place that can make CCS more affordable.17 Based on all of these factors, 

EPA anticipates opportunities to utilize CO2-EOR operations for geologic storage to continue to 

increase. 

Based on a recent resource assessment by DOE, the application of next generation CO2-

EOR technologies would significantly increase oil production areas, further expanding the 

geographic extent and accessibility of CO2-EOR operations in the U.S. 18 Additionally, oil and gas 

 14 Ibid. 15 See technical supporting memo document (Docket EPA-HQ-OAR-2013-0495) Documentation for the Summary of 

Carbon Dioxide Industrial Capture to Enhanced Oil Recovery Projects. 16 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil 

Recovery (CO2-EOR)”, DOE/NETL-2011/1504, June 20, 2011. 17 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010). 18 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil 

Recovery (CO2-EOR)”, DOE/NETL-2011/1504, June 20, 2011.
4-20

fields now considered to be ‘depleted’ may resume operation because of increased availability 

and decreased cost of anthropogenic carbon dioxide, thereby increasing the demand for and 

accessibility of CO2 utilization. 

As demonstrated in this RIA, the use of CO2 for EOR can significantly lower the cost of 

implementing CCS. The opportunity to sell the captured CO2 for EOR, rather than paying 

directly for its long-term storage, strongly improves the overall economics of the new 

generating unit. A commercial market for CO2 creates a role for CO2-EOR to continue CCS 

deployment. According to the International Energy Agency, of the CCS projects under 

construction or at an advanced stage of planning, 70% intend to use captured CO2 to improve 

recovery of oil in mature fields (enhanced oil recovery, CO2-EOR). 19 Further, smaller, nongeologic sequestration markets exist for CO2 as well, including food products, which can lower 

the cost of CCS.

Figure 4-7. Growth of U.S. Oil Production from CO2-based EOR

Source: NETL 2010

 19 Tracking Clean Energy Progress 2013, International Energy Agency (IEA), Input to the Clean Energy Ministerial, 

OECD/IEA 2013. 
4-21

Figure 4-8. U.S. CO2 Storage Capacity and CO2-EOR operations 

Source: EPA 2013: Data sources: EPA’s Greenhouse Gas Reporting Program; Department of Energy, NATCARB; 

Department of Transportation, National Pipeline Management System.

4.6.4 Alternatives to Geologic Sequestration 

EPA recognizes there may be other commercial applications or end-uses for captured 

CO2 which creates CO2 market incentives and potentially for a meeting performance standard 

beyond injecting it underground for long-term containment. For example, alternatives to 

geologic sequestration such as applications such as mineralization of CO2 for the production of 

precipitated calcium carbonate and some production process of cement have been identified as 

potential alternatives to geologic sequestration. The CCS Task Force report notes that there are 

several factors for determining the viability of CO2 reuse, and there are currently significant 

technical barriers to large scale commercial-scale reuse. First, rates of conversion must be 

comparable to rates of CO2 capture. Second, energy requirements for conversion must be low. 

Third, potential volumes of reactants and/or products may limit the scale of reuse relative to 

total emissions. Finally, reuse options need to consider the long-term fate of CO2 and its 

lifecycle emissions.20 The CCS Task Force also notes there are other potential commercial uses 

 20 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010).
4-22

for captured CO2, such as in food and beverage manufacturing, pulp and paper manufacturing, 

the rubber and plastic industry, fire suppression, and refrigeration and cooling.

As noted in the preamble, however, EPA has not yet determined if such uses would be 

applicable towards meeting the standard. Consideration of how these alternatives could meet 

the performance standard involves understanding the ultimate fate of the captured CO2 and 

the degree to which the method permanently isolates the CO2 from the atmosphere, as well as 

existing methodologies to verify this permanent storage.

4.7 GHG and Clean Energy Regulation in the Power Sector

4.7.1 State Policies

Several states have also recently established emission performance standards or other 

measures to limit emissions of GHGs from new EGUs that are comparable to this proposal in 

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 short tons in 2014. This emissions budget is reduced 2.5% annually 

from 2015 to 2020.

In September 2006, California Governor Schwarzenegger signed into law Senate Bill 

1368. The law limits long-term investments in baseload 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 baseload generation owned 

by, or under long-term contract to publicly owned utilities, of 1,100 lb CO2/MWh.

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% of the state GHG emissions. EGUs are includes 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 
4-23

percent annually through 2014, then 3 percent each year until 2020. 

In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, which 

established statewide GHG emissions reduction goals, and imposed an emission standard that 

applies to any baseload 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. 

Baseload generation facilities must initially comply with an emission limit of 1,100 lb CO2/MWh.

In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, which mandated that 

facilities generating baseload electricity, whether gas- or coal-fired, must have emissions equal 

to or less than 1,100 lb CO2/MWh, and prohibited utilities from entering into long-term 

purchase agreements for baseload 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. This 

regulation establishes CO2 emission standards for new and modified electric generators greater 

than 25 MW. The standards vary based on the type of facility: baseload facilities must meet a 

CO2 standard of 925 lb/MWh or 120 lb/MMBtu, and peaking facilities must meet a CO2

standard of 1,450 lbs/MWh or 160 lbs/MMBtu.

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 30 states and the District of Columbia 

have enforceable RPS or other mandatory renewable capacity policies, and 7 states have 

voluntary goals.21 These programs vary widely in structure, enforcement, and scope. 

4.7.2 Federal Policies

In April 2007, the Supreme Court concluded that GHGs met the CAA definition of an air 

pollutant, giving the EPA the authority to regulate GHGs under the CAA contingent upon an

agency determination that GHG emissions from new motor vehicles cause or contribute to air 

pollution that may reasonably be anticipated to endanger public health or welfare. This 

decision to regulate GHG emissions for motor vehicles set the stage for the determination of 

whether other sources of GHG emissions, including stationary sources, would need to be 

regulated as well.

 21 EIA 2012a
4-24

In response to the FY2008 Consolidated Appropriations Act (H.R. 2764; Public Law 110–

161), the EPA issued the Mandatory Reporting of Greenhouse Gases Rule (74 FR 5620) which 

required reporting of GHG data and other relevant information from fossil fuel suppliers and 

industrial gas suppliers, direct greenhouse gas emitters, and manufacturers of heavy-duty and 

off-road vehicles and engines. The purpose of the rule was to collect accurate and timely GHG 

data to inform future policy decisions. As such, it did not require that sources control 

greenhouse gases, but sources above certain threshold levels must monitor and report 

emissions.

In August 2007, the EPA issued a prevention of significant deterioration (PSD) permit to 

Deseret Power Electric Cooperative, authorizing it to construct a new waste-coal-fired EGU near 

its existing Bonanza Power Plant, in Bonanza, Utah. The permit did not include emissions 

control requirements for CO2. The EPA acknowledged the Supreme Court decision, but found 

that decision alone did not require PSD permits to include limits on CO2 emissions. Sierra Club 

challenged the Deseret permit. In November 2008, the Environmental Appeals Board (EAB) 

remanded the permit to the EPA to reconsider “whether or not to impose a CO2 BACT (best 

available control technology) limit in light of the ‘subject to regulation’ definition under the 

CAA.” The remand was based in part on EAB’s finding that there was not an established EPA 

interpretation of the regulatory phrase “subject to regulation.” 

In December 2008, the Administrator issued a memo indicating that the PSD Permitting 

Program would apply to pollutants that are subject to either a provision in the CAA or a 

regulation adopted by the EPA under the CAA that requires actual control of emissions of that 

pollutant. The memo further explained that pollutants for which the EPA regulations only 

require monitoring or reporting, such as the provisions for CO2 in the Acid Rain Program, are 

not subject to PSD permitting. Fifteen organizations petitioned the EPA for reconsideration, 

prompting the agency to issue a revised finding in March 2009. After reviewing comments, the 

EPA affirmed the position that PSD permitting is not triggered for a pollutant such as GHGs until 

a final nationwide rule requires actual control of emissions of the pollutant. For GHGs, this 

meant January 2011 when the first national rule limiting GHG emissions for cars and light trucks 

was scheduled to take effect. Therefore, a permit issued after January 2, 2011, would have to 

address GHG emissions.

The Administrator signed two distinct findings in December 2009 regarding greenhouse 

gases under section 202(a) of the Clean Air Act. The endangerment finding indicated that 

current and projected concentrations of the six key well-mixed greenhouse gases —CO2, CH4, 

N2O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and SF6 — in the atmosphere 
4-25

threaten the public health and welfare of current and future generations. These greenhouse 

gases have long lifetimes and, as a result, become homogeneously distributed through the 

lower level of the Earth’s atmosphere (IPCC, 2001). This differentiates them from other 

greenhouse gases that are not homogeneously distributed in the atmosphere. The cause and 

contribute finding indicated that the combined emissions of these well-mixed greenhouse gases 

from new motor vehicles and new motor vehicle engines contribute to the greenhouse gas 

pollution which threatens public health and welfare. Both findings were published in the 

Federal Register on December 15, 2009 (Docket ID EPA-HQ-OAR-2009-0171). These findings did 

not themselves impose any requirements on any industry or other entities, but allowed the EPA

to regulate greenhouse gases under the CAA (see preamble section II.E for regulatory 

background). This action was a prerequisite to implementing the EPA's proposed greenhouse 

gas emission standards for light-duty vehicles, which was finalized in January 2010. Once a 

pollutant is regulated under the CAA, it is subject to permitting requirements under the PSD 

and Title V programs. The 2009 Endangerment Finding and a denial of reconsideration were 

challenged in a lawsuit; on June 26, 2012, the DC Circuit Court upheld the Endangerment 

Finding and the Reconsideration Denial, ruling that the Finding was neither arbitrary nor 

capricious, was consistent with Massachusetts v. EPA, and was adequately supported by the 

administrative record. The Court found that the EPA had based its decision on “substantial 

scientific evidence,” noted that the EPA’s reliance on assessments was consistent with the 

methods decision-makers often use to make a science-based judgment, and stated that “EPA’s 

interpretation of the governing CAA provisions is unambiguously correct.”

In May 2010, the EPA issued the final Tailoring Rule which set thresholds for GHG 

emissions that define when permits under the New Source Review and Title V Operating Permit 

programs are required for new and existing industrial facilities. Facilities responsible for nearly 

70 percent of the national GHG emissions from stationary sources, including EGUs, were 

subject to permitting requirements under the rule. This rule was upheld by the D.C. Circuit in 

2012.

The EPA entered into two proposed settlement agreements in December 2010 to issue 

rules that will address greenhouse gas emissions from fossil fuel-fired power plants and 

refineries. These two industrial sectors make up nearly 40 percent of the nation’s greenhouse 

gas emissions. On March 27, 2012, EPA proposed NSPS for new source natural gas, coal, and 

other solid fossil-fired EGUs. After consideration of information provided in more than 2.7 

million comments on this proposal, as well as consideration of continuing changes in the 

electricity sector, the EPA determined that revisions in its proposed approach are warranted. 
4-26

This rule replaces that proposal. Existing source standards are not addressed in this action.

Details of the settlement agreements can be found on the EPA website.22

4.7.3 Proposed Federal Policies, Non-GHG

EPA is reviewing public comment and developing final regulations for the following 

three proposed rules, which will impact EGUs: Steam Electric Effluent Limitation Guidelines, 

Cooling Water Intake Structures, and Coal Combustion Residuals (CCR). These three proposed 

rules are summarized below. In general, most EPA rulemakings affecting the power sector 

focus on existing sources. Therefore, few interactions are likely between other power sector 

rules and this rule, which focuses only on new sources.

On June 7, 2013, EPA proposed a regulation that would strengthen the controls on 

discharges from certain steam electric power plants by revising technology-based effluent 

limitations guidelines and standards for the steam electric power generating point source 

category. Existing steam electric power plants contribute 50-60 percent of all toxic pollutants 

discharged to surface waters by all industrial categories currently regulated in the United States 

under the Clean Water Act. Furthermore, power plant discharges to surface waters are 

expected to increase as pollutants are increasingly captured by air pollution controls and 

transferred to wastewater discharges. This proposal would reduce the amount of toxic metals 

and other pollutants discharged to surface waters from power plants. EPA has proposed new 

requirements for both existing and new generating units. EPA estimates that the compliance 

costs for a new unit (capital and operations & maintenance) under the proposed standards 

represent at most 1.5 percent of the annualized cost of building and operating a new 1,300 MW 

coal-fired plant, with capital costs representing less than 1 percent of the overnight 

construction costs, and annual O&M costs representing less than 5 percent of the cost of 

operating a new plant.

 Section 316(b) of the CWA, 33 U.S.C. 1326(b), requires that standards applicable to 

point sources under sections 301 and 306 of the Act require that the location, design, 

construction, and capacity of cooling water intake structures reflect the best technology 

available to minimize adverse environmental impacts. In April 2011, EPA proposed new 

standards to reduce injury and death of fish and other aquatic life caused by cooling water 

intake structures at existing power plants and manufacturing facilities. The proposed rule would 

subject existing power plants and manufacturing facilities withdrawing in excess of 2 million of 

gallons per day (MGD) of cooling water to an upper limit on the number of fish destroyed 

 22 http://www.epa.gov/airquality/ghgsettlement.html
4-27

through impingement, as well as site-specific entrainment mortality standards. Certain plants 

that withdraw very large volumes of water would also be required to conduct studies for use by 

the permit writer in determining site-specific entrainment controls for such facilities. Finally, 

under the proposed rule, new generating units constructed at existing power plants would be 

required to reduce the intake of cooling water associated with the new unit, to a level that 

could be attained by using a closed-cycle cooling system. EPA is continuing the process of 

addressing comments and finalizing the rule.

 On June 21, 2010, EPA co-proposed regulations that included two approaches to 

regulating the disposal of CCRs generated by electric utilities and independent power 

producers. CCRs are residues from the combustion of coal in steam electric power plants and 

include materials such as coal ash (fly ash and bottom ash) and flue gas desulfurization (FGD)

wastes. Under one proposed approach, EPA would list these residuals as ``special wastes,'' 

when destined for disposal in landfills or surface impoundments, and would apply the existing 

regulatory requirements established under Subtitle C of RCRA to such wastes. Under the second 

proposed approach, EPA would establish new regulations applicable specifically to CCRs under 

subtitle D of RCRA, the section of the statute applicable to solid (i.e., non-hazardous) wastes. 

Under both approaches, CCRs that are beneficially used would remain exempt under the Bevill 

exclusion. While the Agency is still evaluating all the available information and comments, and 

while a final risk assessment for the CCR rule has not yet been completed, reliance on the data 

and analyses discussed in the preamble to the recent Steam Electric ELG proposal may have the 

potential to lower the CCR rule risk assessment results by as much as an order of magnitude. If 

this proves to be the case, EPA’s current thinking is that, the revised risks, coupled with the ELG 

requirements that the Agency may promulgate, and the increased Federal oversight such 

requirements could achieve, could provide strong support for a conclusion that regulation of 

CCR disposal under RCRA Subtitle D would be adequate.

4.8 Revenues, Expenses, and Prices

Due to lower retail electricity sales, total utility operating revenues declined in 2011 to 

$281 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008 

levels in 2011, operating expenses were appreciably lower and as a result, net income also rose 

in comparison to both 2009 and 2010 (see Table 4-9). 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.

Electricity sales and revenues associated with the generation, transmission, and distribution of 
4-28

electricity are expected to rebound and increase modestly by 2015, when revenues are 

projected to be roughly $359 billion (see Table 4-10).

Table 4-9 shows that investor-owned utilities (IOUs) earned income of about 11.9

percent compared to total revenues in 2011. Based on EIA's Annual Energy Outlook 2013, Table 

4-10 shows that the power sector is projected to derive revenues of $359 billion in 2015.

Assuming the same income ratio from IOUs (with no income kept by public power), and using 

the same proportion of power sales from public power as observed in 2011, the EPA projects 

that the power sector will expend over $320 billion in 2015 to generate, transmit, and 

distribute electricity to end-use consumers.

Over the past 50 years, real retail electricity prices have ranged from around 7 cents per 

kWh in the early 1970s, to around 11 cents, reached in the early 1980s. Generally, retail 

electricity prices do not change rapidly and do not display the variability of other energy or 

commodity prices, although the frequency at which these prices change varies across different 

types of customers. Retail rate regulation has largely insulated consumers from the rising and 

falling wholesale electricity price signals whose variation in the marketplace on an hourly, daily, 

and seasonal basis is critical for driving lowest-cost matching of supply and demand. In fact, the 

real price of electricity today is lower than it was in the early 1960s and 1980s (see Figure 4-9).

Figure 4-9. National Average Retail Electricity Price (1960 – 2011)

Source: EIA 2013

0

2

4

6

8

10

12

14

1960 1970 1980 1990 2000 2010

cents/KWh (2011$)
4-29

Table 4-9. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities 

for 2010 ($millions)

2009 2010 2011

Utility Operating Revenues 276,124 285,512 280,520

Electric Utility 249,303 260,119 255,573

Other Utility 26,822 25,393 24,946

Utility Operating Expenses 244,243 253,022 247,118

Electric Utility 219,544 234,173 228,873

Operation 154,925 166,922 161,460

Production 118,816 128,831 122,520

Cost of Fuel 40,242 44,138 42,779

Purchased Power 67,630 67,284 61,447

Other 10,970 17,409 18,294

Transmission 6,742 6,948 6,876

Distribution 3,947 4,007 4,044

Customer Accounts 5,203 5,091 5,180

Customer Service 3,857 4,741 5,311

Sales 178 185 185

Admin. and 

General 15,991 17,120 17,343

Maintenance 14,092 14,957 15,772

Depreciation 20,095 20,951 22,555

Taxes and Other 29,081 31,343 29,086

Other Utility 24,698 18,849 18,245

Net Utility Operating Income 31,881 32,490 33,402

Source: Table 8.3, EIA Electric Power Annual, 2011

Note: This data does not include information for public utilities.
4-30

Table 4-10. Projected Revenues by Service Category in 2015 for Public Power and InvestorOwned Utilities (billions)

Generation $207

Transmission $40

Distribution $111

Total $359

Source: EIA 2013

Note: Data are derived by taking either total electricity use (for generation) or sales (transmission and 

distribution) and multiplying by forecasted prices by service category from Table 8 of EIA AEO 2013

(Electricity Supply, Disposition, Prices, and Emissions).

On a state-by-state basis, retail electricity prices vary considerably. The Northeast and 

California have average retail prices that can be as much as double those of other states (see 

Figure 4-10).

Figure 4-10. Average Retail Electricity Price by State (cents/kWh), 2011

Source: EIA 2012
4-31

4.9 Natural Gas Market

The natural gas market in the United States has historically experienced significant price 

volatility from year to year, between seasons within a year, and can undergo major price swings 

during short-lived weather events (such as cold snaps leading to short-run spikes in heating 

demand). Over the last decade, gas prices (both Henry Hub prices and delivered prices to the 

power sector) have ranged from below $3 to nearly $10/mmBtu on an annual average basis 

(see Figure 4-11). During that time, the daily price of natural gas reached as high as 

$15/mmBtu. Recent forecasts of natural gas availability have also experienced considerable 

revision as new sources of gas have been discovered and have come to market, although there 

continues to be some uncertainty surrounding the precise quantity of the resource base.

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 AEO 2012 (EIA 2012):

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 

uneconomical to produce. The production of natural gas from shale formations 

has rejuvenated the natural gas industry in the United States.

The U.S. Energy Information Administration's Annual Energy Outlook 2012 (Early 

Release) estimates that the United States possessed 2,214 trillion cubic feet (Tcf) of 

technically recoverable natural gas resources as of January 1, 2010. Natural gas from 

proven and unproven shale resources accounts for 542 Tcf of this resource estimate. 

Many shale formations, especially the Marcellus, are so large that only small portions of 

the entire formations have been intensively production-tested. Consequently, the 

estimate of technically recoverable resources is highly uncertain, and is regularly 

updated as more information is gained through drilling and production. At the 2010 rate 

of U.S. consumption (about 24.1 Tcf per year), 2,214 Tcf of natural gas is enough to 

supply over 90 years of use. Although the estimate of the shale gas resource base is 

lower than in the prior edition of the Outlook, shale gas production estimates increased 

between the 2011 and 2012 Outlooks, driven by lower drilling costs and continued 
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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.23

EIA’s projections of natural gas conditions did not change substantially in AEO 2013 

from the AEO 2012, and EIA is still forecasting abundant reserves consistent with the above 

findings. Recent historical data reported to EIA is also consistent with these trends, with 2012 

being the highest year on record for domestic natural gas production.24 The average delivered 

natural gas price to the power sector was $3.44 per MMBtu in 2012, down from $4.78/MMBtu 

in 2011.25 

EIA projections of future natural gas prices assume trends that are consistent with 

historical and current market behavior, technological and demographic changes, and current 

laws and regulations.

26 Depending on actual conditions, there may be significant variation from 

the price projected in the reference case and the price observed. To address this uncertainty, 

EIA issues a range of alternative cases, including cases with higher and lower economic growth, 

which address many of the uncertainties inherent in the long-term projections. The EPA 

describes the AEO 2013 reference case and a number of relevant alternative cases in the 

analyses in Chapter 5.

 23 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 24 http://www.eia.gov/dnav/ng/hist/n9010us2a.htm 25 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) 26 EIA 2010b.
4-33

Figure 4-11. Natural Gas Spot Price, Annual Average (Henry Hub)

Source: EIA 2010c, EIA 2011, EIA 2012, EIA 2013

4.10 Electricity Demand and Demand Response

Electricity performs a vital and high-value function in the economy. Historically, growth 

in electricity consumption has been closely aligned with economic growth. Overall, the U.S. 

economy has become more efficient over time, producing more output (gross domestic 

product – GDP) per unit of energy input, with per capita energy use fairly constant over the past 

30 years (EIA, 2010d). The growth rate of electricity demanded has also been in overall decline 

for the past sixty years (see Figure 4-12), with several key drivers that are worth noting. First, 

there has been a significant structural shift in the U.S. economy towards less energy-intensive 

sectors, like services.27 Second, companies have strong financial incentives to reduce 

expenditures, including those for energy. Third, companies are responding to the marketplace 

and continually develop and bring to market new technologies that reduce energy 

 27 EIA 2013

0

2

4

6

8

10

12

1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040

2011 dollars per million Btu

Natural Gas Spot Price, Annual Average (Henry Hub)

EIA Historical

EIA Projected (AEO 2011)

EIA Projected (AEO 2012)

EIA Projected (AEO 2013)
4-34

consumption. Fourth, other policies, such as energy efficiency standards at the state and 

Federal level, have helped address certain market failures. These broader changes have altered 

the outlook for future electricity growth (see Figure 4-10). 

Figure 4-7. Electricity Growth Rate (3-Year Rolling Average) and Projections from the Annual 

Energy Outlook 2013

Source: EIA 2009, EIA 2013

Energy efficiency initiatives have become more common, and investments in energy 

efficiency are projected to continue to increase for the next 5 to 10 years, driven in part by the 

growing number of states that have adopted energy efficiency resource standards. These 

investments, and other energy efficiency policies at both the state and federal level, create 

incentives to reduce electricity consumption and peak load. According to EIA, demand-side 

management provided actual peak load reductions of 33.3 GW in 2010. For context, the current 

coal fleet is roughly 314 GW of capacity.

Demand for electricity, especially in the short run, is not very sensitive to changes in 

prices and is considered relatively price inelastic, although some demand reduction does occur 

in response to price. With that in mind, the EPA modeling does not typically incorporate a 

“demand response” in its electric generation modeling (Chapter 5) to the increases in electricity 

prices typically projected for EPA rulemakings. Electricity demand is considered to be constant 

in EPA modeling applications and the reduction in production costs that would result from 

lower demand is not considered in the primary analytical scenario that is modeled. This leads to 

some overstatement in the private compliance costs that the EPA estimates for rules where 
4-35

compliance costs are anticipated for a rulemaking. Note that this NSPS is not anticipated to 

create compliance costs for projected new EGU sources.

4.11 References

Brennan, S.T., Burruss, R.C., Merrill, M.D., Freeman, P.A., and Ruppert, L.F. A probabilistic 

assessment methodology for the evaluation of geologic carbon dioxide storage: U.S. 

Geological Survey Open-File Report 2010–1127. 2010. Available online at 

http://pubs.usgs.gov/of/2010/1127.

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/.

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). Improving Domestic Energy Security and 

Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil Recovery (CO2-EOR). 

June 20, 2011. DOE/NETL-2011/1504. Available online at: 

http://www.netl.doe.gov/energyanalyses/refshelf/PubDetails.aspx?Action=View&PubId=391.

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.

Oil and Gas Journal. Enhanced Oil Recovery Survey. 2010. Volume 108, Issue 14, April 19, 2010.

p.41.

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.
4-36

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: s 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. 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.
4-37

U.S. Geological Survey Geologic (USGS) National assessment of geologic carbon dioxide storage 

resources – Summary: U.S. Geological Survey Factsheet 2013-3020. 2013. Available 

online at: http://pubs.usgs.gov/fs/2013/3020/.
5-1

CHAPTER 5

COSTS, BENEFITS, ECONOMIC, AND ENERGY IMPACTS

5.1 Synopsis

This chapter reports the compliance cost, benefits, economic, and energy impact 

analyses performed for the proposed EGU New Source GHG Standards. 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 analysis to determine the potential impacts of this action. 

The primary finding of this assessment is that in the absence of this proposed rule, all

projected unplanned1 capacity additions affected by this proposal during the analysis period 

would already be compliant with the rule’s requirements (e.g., combined cycle natural gas, low 

capacity factor natural gas combustion turbine, and small amounts of coal with CCS supported 

by Federal and State funding). The analysis period is defined as through 20222 to reflect that 

CAA Section 111(b) requires that the NSPS be reviewed every eight years. EPA’s conclusion was 

based on:

• EIA power sector modeling projections

• EPA power sector modeling projections

• Electric utility integrated resource planning (IRP) documents

• Projected new EGUs reported by industry to EIA

EPA’s finding of no new, unplanned conventional coal-fired capacity is 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 

power sector investment decisions. As a result, the proposed 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 EPA does not project any new coal-fired EGUs 

without CCS to be built in the absence of this proposal, this chapter presents an analysis of the 

project-level costs of building new coal-fired capacity with and without CCS to demonstrate 

 1 Unplanned capacity represents projected capacity additions that are not under construction.

2 IPM output for other years has been made available in the docket and is discussed where appropriate throughout 

the document.
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that a requirement of partial CCS would not preclude new coal construction. An additional 

illustrative analysis, presented at the end of this chapter, shows that even in the unlikely event 

that new, noncompliant EGU capacity would be built in the absence of this rule the proposed

EGU New Source GHG Standards would provide net social benefits under a range of 

assumptions.

5.2 Requirements of the Proposed GHG EGU NSPS

In this action, the EPA is proposing standards of performance for two basic categories of 

new units that have not commenced construction: (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 size and operational criteria.

The EPA is proposing standards of performance for affected sources within the following

subcategories: (1) natural gas-fired stationary combustion turbines with a heat input rating to 

the turbine engine that is greater than 850 MMBtu/hr; (2) natural gas-fired stationary 

combustion turbines with a heat input rating to the turbine engine that is less than or equal to 

850 MMBtu/hr; and (3) all fossil fuel-fired boilers and IGCC units. All affected new fossil fuelfired EGUs would be required to meet an output-based emission rate of a specific mass of CO2

per MWh of electricity generated energy output on a gross basis. New natural gas-fired 

stationary combustion turbines with a heat input rating greater than 850 MMBtu/hr would be 

required to meet a standard of 1,000 lb CO2/MWh of gross energy output. New natural gasfired stationary combustion turbines with a heat input rating less than or equal to 850 

MMBtu/hr would be required to meet a standard of 1,100 lb CO2/MWh of gross energy output. 

New fossil fuel-fired boilers and IGCC units would be required to meet a standard of 1,100 lb 

CO2/MWh of gross energy output. These standards would be met on a 12-operating month 

rolling average basis. An alternative emission limit, available only to new fossil-fired boilers and 

IGCC units, can be met over an 84-operating month rolling average basis. The alternative 

emission limit will be between 1,000 and 1,050 lb CO2/MWh of gross energy output. 

The proposed action applies to sources based on electric sales. More specifically, a 

facility is covered if it sells more than 1/3 of its potential electric output and more than 219,000 

MWh net electric output to the grid. The proposed definition does not explicitly exclude simple 

cycle combustion turbines, but as a practical matter, it is generally expected not to apply as 

most simple cycle combustion turbines sell less than 1/3 of their potential electric output. For 

potential combustion turbines that anticipate selling more than 1/3 of their potential electric 

output, there are more cost effective and lower emitting technologies that could be 

constructed consistent with the proposed standards as will be demonstrated later in this
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chapter. Please refer to the preamble for additional detail concerning affected sources and 

standards of performance.

5.3 Power Sector Modeling Framework

5.3.1 Modeling Overview

Over the last decade, 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. Current forecasts for the utilization of new and existing generating 

capacity are a key input into informing the design of EPA’s proposal. 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 built in recent years; however, EPA does not 

expect the construction of any new, unplanned, conventional coal-fired capacity through the 

analysis period. This conclusion is based in part on the Agency’s own power sector modeling 

utilizing IPM as well as EIA’s Annual Energy Outlook 2013 (AEO 2013) projections.

IPM, developed by ICF Consulting, 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. EPA used IPM to project likely future 

electricity market conditions with and without the proposed rule. In addition to IPM, EPA has 

closely examined the AEO 2013 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:3

“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 

 3 http://www.eia.gov/oiaf/aeo/overview/
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cost, cost of utility and nonutility technologies, expected load shapes, fuel markets, regulations, 

and other factors. EIA’s AEO projections independently support EPA’s conclusions in that it 

projects no new generation capacity being constructed through the analysis period that would 

not already meet the level of the standard even in the absence of the standard. Both sets of 

modeling results are presented in Section 5.4.

5.3.2 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. 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. 4

 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.5

Although the Agency typically focuses on broad system effects when assessing the 

economic impacts of a particular policy, 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 

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 

are based on assumptions used in the EIA’s AEO.

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 

 4 http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html 5 http://www.epa.gov/airmarkt/progsregs/epa-ipm/BaseCasev410.html#documentation
5-5

American gas market. This module consists of 114 supply, demand, and storage nodes and 14 

liquefied natural gas regasification 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 84 

coal supply curves, 12 coal sulfur grades, and the coal transport network, which consists of 

1,230 linkages representing rail, barge, and truck and conveyer linkages. The coal supply curves

in IPM, which are publicly available6, were developed during a thorough bottom-up, mine-bymine 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. The coal supply curves were developed in consultation with Wood 

Mackenzie, one of the leading energy consulting firms and specialists in coal supply. 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. 

EPA has used IPM extensively over the past two decades to analyze options for reducing 

power sector emissions. Recently, 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), and the Mercury and Air Toxics Standards (MATS).7

 

The model undergoes periodic formal peer review, which includes separate expert 

panels for both the model itself and EPA’s key modeling input assumptions.8 The rulemaking 

process also provides opportunity for expert review and comment by a variety of 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. 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 highly 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, in 

 6 v4.10 of the coal supply curves may be found in Appendix 9-4 of http://www.epa.gov/airmarkt/progsregs/epaipm/BaseCasev410.html#documentation 7 All of the IPM projections conducted for this rulemaking are available at EPA’s website and in the public docket. 8 http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html
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the late 1990’s, the Science Advisory Board reviewed IPM as part of the CAA Amendments

Section 812 prospective studies that are periodically conducted.9 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 states (e.g., for 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 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 NOx emissions and the formation of ozone in densely populated areas 

in the northeast. 

5.4 Analyses of Future Generating Capacity

5.4.1 Base Case Power Sector Modeling Projections

EPA conducted analysis and modeling in support of the April 2012 EGU GHG New Source 

Standards proposal, and concluded that new unplanned noncompliant base load power plants 

are not expected to be economic well beyond the analysis period. EPA conducted an analysis of 

the economic impacts by modeling a base case scenario of future electricity market conditions. 

EPA’s IPM modeling relied on the AEO 2010 for the electric demand forecast for the U.S. and 

employed a set of EPA assumptions regarding fuel supplies, the performance and cost of 

electric generation technologies, pollution controls, and numerous other parameters.

10 The 

base case accounts for the effects of the finalized MATS and CSAPR rules, and New Source 

Review settlements and state rules through December 2010 impacting sulfur dioxide (SO2), 

NOx, directly emitted particulate matter and CO2.

11

The most current EIA projections are reflected in AEO 2013 and are summarized in the 

following tables alongside the EPA projections. New coal-fired capacity through 2030 in the 

 9 http://www.epa.gov/air/sect812/ 10 http://www.epa.gov/airmarkt/progsregs/epa-ipm/proposedEGU_GHG_NSPS.html 11 The legal status of CSAPR and CAIR has no impact on this proposal’s evaluation, as neither CSAPR nor CAIR 

significantly influences the type of new capacity additions projected to be economic.
5-7

AEO 2013 reference case is entirely CCS-equipped and would be in compliance with this 

proposal (0.3 GW). The projected CCS-equipped capacity is assumed to occur in response to 

existing Federal, State, and local incentives for the technology.12 According to the AEO 2013 –

which represents existing policies and regulations influencing the power sector - the vast 

majority of new, unplanned generating capacity is forecast to be either natural gas-fired or 

renewable.13 The economics favoring new natural gas combined cycle (NGCC) additions instead 

of conventional coal are robust under a range of sensitivity cases examined in the AEO 2013. 

Sensitivity cases that 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 also forecast zero unplanned additions of coal-fired capacity without CCS 

in the analysis period. Recent previous versions of the AEO came to similar conclusions. Based 

on these previous AEO analyses, DOE concluded 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."14 

In comparing the EPA and EIA modeling projections reported here, the most important 

variables influencing the choice of technology for new generating capacity are more favorable 

to new coal-fired capacity in the EPA analysis. For example, electric demand in 2020 was 

assumed to be 4,305 billion kWh (taken from AEO 2010) in EPA’s modeling projections, which is 

over 4% higher than electric demand in AEO 2013. 15 Projected fuel prices for natural gas and 

coal are also more favorable to new coal-fired capacity relative to new NGCC capacity in the 

EPA analysis than in the AEO 2013 projections.

 

 12 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. 13 http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm 14 Department of Energy (2011). Report on the First Quadrennial Technology Review. Available at 

http://energy.gov/sites/prod/files/QTR_report.pdf. 15 In a long-term power sector modeling framework, calendar years are typically grouped into model run years. In 

EPA’s IPM projections reported in this chapter, 2020 is the run year that is representative of results from 

calendar years 2017-2024. Consequently, the chapter often presents 2020 projections and results from EPA 

and EIA as opposed to projections for the last year of the analysis period (2022).
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Table 5-1. Reference Case Unplanned Cumulative Capacity Additions (GW)

EPA AEO 2013

Capacity Type 2020 2020 2025 2030

Conventional Coal 0 0 0 0

Coal with CCS 2 0.3 0.3 0.3

Natural Gas CC 7.0 3.1 17.4 48.2

Natural Gas CT 3.0 15.4 28.0 43.3

Nuclear 0 0 0 0

Renewables16 26.9 3.7 6.4 10.5

Distributed Generation 0 0.9 1.9 3.1

Total 38.9 23.4 54.1 105.4

Notes: The sum of the table values in each column may not match the total figure due to rounding.

Source: EPA 2020 projection from IPM run by EPA, 2011; EIA 2020-2030 projection from EIA Annual Energy Outlook 2013

The capacity projections of EIA and 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 5-2), due in large part 

to its significant levelized cost of electricity17 (LCOE) advantage over coal-fired generating 

technologies. A greater discussion of the relative LCOE of different generating technologies is 

provided beginning in Section 5.5.

 16 Renewable projections are higher in the EPA reference case due largely to EPA’s 2011 modeling projections 

predating AEO 2013 projections; therefore, all renewable builds that occurred in the interim would be 

accounted for in AEO 2013 as ‘planned’ capacity and are omitted from the table above. The overall amount of 

total renewable capacity by 2020 is largely similar. 17The 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 5-1. Historical U.S. Power Plant Capacity Additions, by Technology, 1940-2011

Source: Form EIA-860 (2011)

Note: Renewables include hydro, geothermal, biomass, solar, and wind energy technologies. 

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 2013, and reflect the most costeffective dispatch and investment decisions modeled, given a variety of variables and 

constraints. Even without the deployment of unplanned 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 (39% of total 2020 

generation in AEO2013 and 46% in EPA’s projections), as displayed in Table 5-2. 
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Table 5-2. 2011 U.S. Electricity Net Generation and Projections for 2020, 2025, and 2030

(Billion kWh)

Historical EPA AEO 2013

2011 2020 2020 2025 2030

Coal 1,718 1,976 1,640 1,707 1,745

Oil 15 Negligible 15 16 16

Natural Gas 926 869 1,078 1,127 1,221

Nuclear 790 840 885 912 908

Hydroelectric 318 286 289 291 292

Non-Hydro Renewables 164 289 270 295 310

Other 18 45 5 9 13

Total 3,949 4,305 4,182 4,356 4,506

Source: Historical data from Form EIA-860, 2011. EPA 2020 projection from IPM run by EPA, 2011; EIA 2020-2030 projection 

from EIA Annual Energy Outlook 2013Notes: Net summer generating capacity. The sum of the table values in each column may 

not match the total figure due to rounding. “Non-Hydro Renewables” include biomass, geothermal, solar, and wind electric 

generation capacity. The capacity of a generating unit that is co-firing gas in a coal boiler is split in this table between 

“pulverized coal” and “Oil/Gas Steam” proportionally by fuel use.

It has been previously noted that since the time of the IPM Base Case analysis, 

projections for key market variables are now less favorable to the development of coal-fired

capacity. State and regional regulations have necessarily evolved since EPA’s 2011 modeling 

projections, 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 the 

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) – According to EIA, 30 states and the 

District of Columbia have an enforceable RPS, or similar laws.18 There are eight 

other States that have voluntary goals.19 These 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. 

 18 http://www.eia.gov/forecasts/aeo/legs_regs_all.cfm#state 19 http://www.dsireusa.org/rpsdata/index.cfm
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• 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.20 In general, these plans confirm the expectation that utilities 

anticipate that any new sources of generation will be from renewables, in 

response to state and federal regulations and incentives, and natural gas prices. 

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. 

Any recently adopted state and local climate or related electricity sector regulations that 

are not included in the IPM Base Case analysis, California’s AB 32 for example, also make the 

development of coal-fired capacity less favorable.

5.4.2 Alternative Scenarios from AEO 2013 

Power sector modeling that projects no new, unplanned, conventional coal-fired 

capacity in the analysis period have been demonstrated to be 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 26 scenarios contained in the AEO 2013, none projected

unplanned, conventional coal capacity in the analysis period, including the four scenarios that 

may be considered most favorable to the development of coal-fired capacity displayed below:21

 20 E.g., http://www.pacificpower.net/about/irp.html 21 AEO 2013 scenario definitions: High Economic Growth increases annual real GDP growth by 0.4%; Low Coal Cost 

assumes greater regional productivity growth rates and lower wages, equipment, and transportation costs for 

the coal industry; Low Oil and Gas Resource reduces the ultimate estimated recovery of shale gas, tight gas, 

and tight oil by 50%; No GHG Concern removes the perceived risk of incurring costs under a future GHG policy 

from market investment decisions.
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Table 5-3. AEO 2013 Unplanned Cumulative Capacity Additions, GW (202022)

Capacity Type Reference High 

Growth

Low Coal 

Cost

Low Gas 

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 18.5 19.5 17.6 13.7 17.8

Nuclear 0 0 0 0 0

Non-Hydro Renewables 3.7 13.5 5.0 5.2 4.1

Other 0.9 0.6 0.8 0.2 0.8

Total 23.4 33.9 23.8 19.3 23.1

5.4.3 Power Sector Fuel Price Dynamics and Trends

As mature technologies, the cost and performance characteristics of conventional coalfired capacity and NGCC are projected by EPA to be relatively stable over time in comparison to

emerging generation technologies.23 Therefore, expectations of future fuel prices play a key 

role in determining the overall cost competitiveness of conventional coal versus NGCC.

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 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% 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 

 22 The 2020 run year represents conditions out through 2022, consistent with the eight year NSPS review cycle. 23 http://www.epa.gov/airmarkt/progsregs/epa-ipm/docs/v410/Chapter4.pdf
5-13

States to consume a predominantly domestic supply of gas for many years and produce 

more natural gas than it consumes.

The U.S. Energy Information Administration's Annual Energy Outlook 2013 Early 

Release projects U.S. natural gas production to increase from 23.0 trillion cubic feet in 

2011 to 33.1 trillion cubic feet in 2040, a 44% increase. Almost all of this increase in 

domestic natural gas production is due to projected growth in shale gas production, 

which grows from 7.8 trillion cubic feet in 2011 to 16.7 trillion cubic feet in 2040.24

Recent historical data reported to EIA is also consistent with these trends, with 2012 

being the highest year on record for domestic natural gas production.25 The average delivered 

natural gas price to the power sector was $3.44 per MMBtu in 2012, down from $4.78/MMBtu 

in 2011.26 

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.27,28 EPA and EIA modeling incorporates the impact of 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 2013), 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.” 29

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 

 24 http://www.eia.gov/energy_in_brief/article/about_shale_gas.cfm 25 http://www.eia.gov/dnav/ng/hist/n9010us2a.htm 26 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) 27 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). 28 EIA. 2013. U.S. Crude Oil and Natural Gas Proved Reserves, 2011. 

http://www.eia.gov/naturalgas/crudeoilreserves/pdf/uscrudeoil.pdf 29 NERC, Long-Term Reliability Assessments for 2012. New capacity includes both planned and conceptual 

resources as defined by NERC.
5-14

capital investments, while utilizing scenario testing 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 scenario testing presented 

throughout this analysis.

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.30

Taken together, current and expected natural gas and coal market trends are 

contributing to a fundamental shift in the economic conditions for new power plant 

development that utilities and developers have recognized and responded to in planning.

31

5.4.4 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 5-5.

 30 http://www.eia.gov/forecasts/aeo/assumptions/pdf/coal.pdf 31 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.
5-15

Table 5-4. National Delivered 2020 Fuel Prices by AEO 2013 Scenario (2011$/MMBtu)

Scenario32 Natural Gas Coal

Reference 5.00 2.52

High Growth 5.45 2.57

Low Growth 4.64 2.47

High Coal Cost 5.26 2.93

Low Coal Cost 4.85 2.17

High Gas/Oil Resource 3.60 2.47

Low Gas/Oil Resource 6.18 2.78

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 2013, 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 price that informs 

capacity expansion decisions in 2020 is not the 2020 price, but the entire future fuel price 

stream. For example, Figure 5-6 displays EIA’s natural gas price projections for the Reference 

Case and several scenarios through 2040.

 32 AEO 2013 scenario definitions: High Economic Growth increases annual real GDP growth by 0.4%; Low Economic 

Growth decreases real GDP growth by 0.6%; 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%; Low Oil and Gas Resource reduces the ultimate estimated recovery of shale gas, tight gas, and tight oil by 

50%.
5-16

Figure 5-2. National Delivered Natural Gas Prices by Select AEO 2013 Scenario 

(2011$/MMBtu)

Natural gas prices are expected to increase after 2020 in all scenarios33; however, rising

natural gas prices through 2040 – including in EIA’s low gas/oil resource scenario - are still not 

sufficient to support new, conventional coal-fired generation in the analysis period (i.e., 

through 2022), demonstrating that natural gas prices at currently low levels are not required to 

persist for NGCC to maintain its economic advantage over coal-fired technologies.

While the uniformity of EIA scenarios in projecting no new, unplanned, conventional 

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 private cost 

advantages of NGCC over conventional coal during the analysis period the following section

adopts a static, engineering cost analysis.

 33 Coal prices are also expected to rise in all scenarios.

0

2

4

6

8

10

12

2015 2020 2025 2030 2035 2040

Reference

High growth

Low growth

High coal cost

Low coal cost

High resource

Low resource

No GHG concern
5-17

5.5 Levelized Cost of Electricity Analysis

5.5.1 Overview of the Concept of Levelized Cost of Electricity

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 as well as alternative AEO 2013 scenarios, the proposed EGU New Source GHG 

Standards are not projected to result in any emission reductions, monetized benefits, or costs.

Despite this conclusion, it is important to supplement the power sector modeling 

projections to quantify the robustness of the economic advantage of new NGCC relative to new 

coal without CCS. To achieve this task, EPA will rely on the concept of LCOE. 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 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 LCOE include capital, fixed operating and maintenance 

(FOM), variable operating and maintenance (VOM), and fuel.

The levelized capital cost is the result of the annualized capital cost spread over the 

annual output of the generation facility. 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 (i) and book life (n).

34

The levelized capital and FOM costs may be calculated by taking the annualized capital 

and FOM (expressed in $/kW-yr) 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 8760 hours).

The VOM, which is already expressed in terms of cost per unit output, may be presented 

with or without fuel expense. The fuel expense is typically the largest component of VOM (nonfuel 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. To 

calculate a levelized fuel cost, it is necessary to introduce the concept of a levelized fuel price. 

 34 The interest rate assumed for NGCC projects is 9.06%; the interest rate assumed for coal-fired projects is 9.57%. 

Both types of projects are assumed to have a 30-year book life, resulting in a capital recovery factor of 9.78% 

for NGCC projects and 10.23% for coal-fired projects.
5-18

Because levelized costs consider the entire lifecycle of the facility, the levelized fuel 

price calculates the single value payments necessary to reflect the stream of annual delivered 

fuel prices over the economic life of the facility at a given discount rate.35 Levelizing fuel prices 

recognizes the necessity to consider the trajectory of fuel costs over the facility’s entire 

economic life.

It should be noted that there are other important considerations beyond 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, 

and 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.). Broader system-wide power sector modeling – such as the 

analyses conducted by EPA and scenarios conducted by EIA – is able to more effectively capture 

these considerations.

5.5.2 Cost and Performance of Technologies 

The NGCC and coal-fired generation technology cost and performance assumptions that 

form the basis for the LCOE analysis in this chapter are sourced from the DOE’s NETL.36 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 IGCC facilities.

37,38 The 

CO2 capture sensitivity analysis included an evaluation of the cost, performance, and 

 35 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. EPA utilized a 5% discount rate to calculate levelized fuel 

prices, a value consistent with the discount rate embedded in IPM. 36 http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf 37 All potential build types are compliant with all current environmental regulations, including EPA’s Mercury and 

Air Toxics Standards (MATS). 38 For an emerging technology like CCS, costs can be estimated for a “first-of-a-kind” (FOAK) plant or an “nth-of-akind” (NOAK) plant, the latter of which has lower costs due to the “learning by doing” and risk reduction 

benefits that result from serial deployments as well as from continuing research, development and 

demonstration projects. The estimates provided in Table 5-5 for a new NGCC unit and for a SCPC plant without 

CO2 capture are based on mature technologies and are thus NOAK costs. For plants that utilize technologies 

that are not yet fully mature, such the IGCC or any plant that includes CO2 capture, the cost estimates in Table 

5-5 represent a plant that is somewhere between FOAK and NOAK, sometimes referred to as “next-of-a-kind”. 

Because there are a number of projects currently under development, the EPA believes it is reasonable to focus 

on the next-of-a-kind costs provided in Table 5-5. See the preamble for additional discussion.

.
5-19

environmental profile of these facilities under different configurations that were tailored to 

achieve a specific level of carbon capture. EPA selected NETL cost and performance 

characteristics for NGCC to ensure that the cost comparisons between NGCC and coal-fired 

technologies – the primary comparison made in this chapter – represented a single, internally 

consistent framework. For technologies where NETL cost and performance estimates were not 

available or sufficiently recent – such as for nuclear and simple cycle CT – EPA adopted EIA’s

AEO 2013 estimates of LCOE.

To represent a new SCPC facility, NETL assumed a new boiler with a combination of lowNOx burners (LNB) with overfire air (OFA) and a selective catalytic reduction (SCR) system for 

NOx control. The plant was assumed to have a fabric filter and a wet limestone FGD scrubber 

for particulate matter and SO2 control, respectively. For configurations including CCS, the plant 

was assumed to have a sodium hydroxide (NaOH) polishing scrubber to ensure that the flue gas 

entering the CO2 capture system has a SO2 concentration of 10 ppmv or less. The SCPC w/ CCS

plant configurations were equipped with Fluor’s Econamine FG PlusSM process for postcombustion CO2 capture via temperature swing absorption with a monoethanolamine (MEA) 

solution as the chemical solvent.

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 MEA 

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 

will: (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.

39 The “slip stream” approach – which leads to lower capital and operating costs

– was adopted by EPA for cost and performance estimates under partial capture.

For a new IGCC EGU, the NETL study evaluated a number of IGCC plant configurations. 

EPA adopted the configurations presented as the most viable – from both an economic and 

technological perspective – for the no capture, partial capture, and full capture cases. The no 

CO2 capture case employed an IGCC that used the two-stage acid gas (SelexolTM) process for 

acid gas control (i.e., hydrogen sulfide (H2S) and CO2) but no WGS reactor. The 25 percent CO2

 39 NETL based this determination primarily upon literature review. Please refer to page 2 of 

http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf
5-20

capture case utilized the same two-stage SelexolTM unit to maximize CO2 capture from the 

unshifted syngas. To achieve higher CO2 capture levels – including full capture - the IGCC was 

assumed to be configured with a two-stage WGR with bypass and the two-stage acid gas 

(SelexolTM) scrubbing system. 40 In summary, the technology cost and performance 

characteristics utilized by EPA in developing the LCOE estimates provided in this chapter are 

listed below in Table 5-7.

Table 5-5. Technology Cost and Performance (2011$)

Capacity Type Total Overnight 

Capital Cost ($/kw)

Fixed Operations 

& Maintenance 

($/kw-yr)

Variable 

Operations & 

Maintenance 

($/MWh)

2020 Fuel 

Cost 

($/MMBtu)

Net Plant 

HHV 

Efficiency 

(%)

NGCC 891 26.7 1.8 5.00 50.2

SCPC 2,452 70.6 7.7 2.94 39.3

SCPC w/ Partial CCS 

(1,100 lbs/MWh

gross)

3,301 90.7 10.5 2.94 34.5

SCPC w/Full CCS

(200 lbs/MWh gross) 4,391 116.6 14.1 2.94 28.4

IGCC 2,969 94.8 9.3 2.94 39.0

IGCC w/ Partial CCS 

(1,100 lbs/MWh

gross)

3,274 103.2 10.1 2.94 37.3

IGCC w/ Full CCS

(150 lbs/MWh gross) 4,086 125.6 12.1 2.94 32.6

Notes: The coal assumed is a bituminous coal with a sulfur content of 2.8% (dry) at a price of $2.94/MMBtu, consistent with the 

NETL analysis from which technology cost and performance as well as fuel price was sourced.

41 The natural gas price is the 2020

price from EIA’s AEO 2013 Reference Case. NETL explains that there are a range of future potential costs that are up to 15% 

below, or 30% above the central estimate provided in Table 5-5.), 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.

 40 For additional detail and discussion on the specific technology configurations selected for this analysis, please 

refer to the preamble. 41 http://www.netl.doe.gov/energy-analyses/pubs/BaselineCostUpdate.pdf
5-21

5.5.3 Levelized Cost of Electricity of New Generation Technologies

This section presents four LCOE comparisons42: 

1. NGCC to Uncontrolled Coal – to demonstrate the cost advantages of NGCC over a 

range of natural gas prices and regional market conditions.

2. Uncontrolled Coal to Coal with partial CCS – to demonstrate that any requirement 

for CCS could be accommodated and would not, based on the cost increment of 

constructing and operating the CCS portion, preclude new coal construction.

3. Coal with partial CCS to Nuclear – to demonstrate that the overall cost of building 

coal with partial CCS is not fundamentally different than the overall cost of 

constructing a nuclear facility.

4. NGCC to CT – to demonstrate the unlikelihood of a new combustion turbine being 

built with the expectation of exceeding a 33% annual capacity factor and thus being 

covered by this proposal.

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 impacts of emissions from these technologies is considered beginning in Section 

5.7. 

Additionally, it is important to note that both EIA and 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. EIA developed the CUA to address differences in 

how investments in new capacity are evaluated in power sector models as compared to 

resource planning exercises commonly conducted by the industry. 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.

43 Therefore, the CUA 

reflects the additional risk typically assigned by project developers and utilities to GHG-

 42 “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. 43 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
5-22

intensive projects in a context of climate uncertainty. When comparing private investment 

costs, 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 therefore necessary to adopt in evaluating the 

behavioral response to the cost competitiveness of alternative generating technologies.44 

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.”45

Therefore, EPA recognizes the application of the CUA is context dependent – as a part of the

planning process it is appropriately applied in an evaluative sense to prospective projects, and 

then removed once a project transitions from planning to execution. Although a perspective 

that omits the CUA is inconsistent with the purposes of the analysis contained in this section 

(i.e., analyzing the project characteristics and market conditions that would lead a developer or 

utility to select a certain project, not determine what the actual project costs would be once 

that project selection is made), LCOE estimates for uncontrolled coal-fired projects are 

presented both with and without the CUA. All LCOE estimates of coal-fired facilities with CCS 

(partial or full) are presented without the CUA.

5.5.4 Levelized Cost of Electricity of NGCC and Uncontrolled Coal

EPA’s base LCOE estimates for NGCC, SCPC, and IGCC are displayed below by cost 

component (capital, FOM, VOM, fuel) and assume a construction date of 2020:

 44 For example, a 2011 Synapse Report lists 15 utilities that adopted a value for CO2 in their integrated resource 

planning. http://www.synapse-energy.com/Downloads/SynapsePaper.2011-02.0.2011-CarbonPaper.A0029.pdf. In addition to utilities, several state commissions have mandated the inclusion of a cost of 

CO2 in long-term planning (e.g., Minnesota utilities must adopt a price beginning in 2017). 45 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
5-23

Figure 5-3. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation 

Technologies by Cost Component, EPA46

Notes: The coal assumed is a bituminous coal with a sulfur content of 2.8% (dry) at a price of $2.94/MMBtu, 

consistent with the NETL analysis from which technology cost and performance was sourced47. The $2.94/MMBtu 

delivered coal price is assumed for all years; therefore, the price serves as both the 2020 fuel cost as well as the 

levelized fuel cost over any future period of time. This assumption produces a 20-year levelized coal price consistent 

with the AEO2013 Reference Case’s $2.79/MMBtu projection average delivered price to the electricity sector for all 

coals. A capacity factor of 85 percent is assumed across all technologies. For comparison, EIA estimates levelized 

costs under AEO 2013 assumptions for SCPC and IGCC are $99/MWh and $122/MWh, respectively, including a 3% 

CUA and excluding transmission investment costs.48 The levelized costs presented above are based on NETL 

assumptions and will necessarily differ from AEO 2013 levelized costs for a variety of reasons, including cost and 

performance characteristics, financial assumptions, and fuel input prices. The LCOE for NGCC assumes a 

$6.11/MMBtu levelized natural gas price – additional information on this assumption is provided later in this section 

(see Table 5-6).

On a levelized cost basis, NGCC is significantly cheaper than all of the uncontrolled coalfired options, including those options that assume no CUA. In addition to the disparity in LCOE 

totals, the cost composition exhibits fundamental differences between natural gas- and coal-

 46 Although 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 units 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 facilities). These potential differences do not fundamentally change the analysis presented 

in this chapter. 47 http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf 48 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm

59

92 

81

112 

97 

- 

20 

40 

60 

80 

100 

120 

NGCC SCPC (w/ CUA) SCPC (w/o 

CUA)

IGCC (w/ CUA) IGCC (w/o 

CUA)

2011$/MWh

Fuel

VO&M

FO&M

Capital
5-24

fired facilities, with NGCC dominated by fuel expense and 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.

The figure below presents the LCOE of an NGCC facility at three levelized natural gas 

price levels. For reference, the base LCOE estimates for SCPC and IGCC are included as well.

49

Figure 5-4. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation 

Technologies Across Select Natural Gas Prices, EPA

It is only when natural gas prices exceed $10/MMBtu on a levelized basis (in 2011 

dollars) that new coal-fired generation without CCS approaches parity with NGCC in terms of 

LCOE (none of the EPA sensitivities or AEO 2013 scenarios described in this chapter project

national average natural gas prices near that level). 50 To achieve a $10/MMBtu levelized price 

 49 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, EPA believes the cost and performance of these units are broadly similar 

and therefore well represented by new, conventional coal-fired facilities (i.e. SCPC).

50 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; the point is that these analyses do not 

59

69

86

92

112

0

20

40

60

80

100

120

NGCC 

($6.11/MMBtu)

NGCC 

($7.5/MMBtu)

NGCC 

($10/MMBtu)

SCPC (w/ CUA) IGCC (w/ CUA)

2011$/MWh
5-25

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 5-6 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).

Table 5-6. Levelized Natural Gas Prices by Select AEO 2013 Scenario (2011$/MMBtu)

Scenario

20-Year AEO 

Projection

(2020-2039)

30-Year AEO-Based 

Projection

(2020-2049)

Reference 6.11 6.79

High Growth 6.69 7.30

Low Growth 5.64 6.32

High Coal Cost 6.51 7.28

Low Coal Cost 6.00 6.74

High Gas/Oil Resource 4.09 4.40

Low Gas/Oil Resource 7.63 8.50

Note: Discount rate of 5%, consistent with IPM assumptions. The 30-year natural 

gas price is calculated by applying the price increase from 2039 to 2040 in all subsequent 

years through 2049.

To achieve a price that exceeds $10/MMBtu on a 20-year levelized basis in 2020 would

require a natural gas price projection more than 30% higher than EIA’s low resource scenario in 

all years – see Figure 5-5 below. This elevated natural gas price would result in a 

$10.15/MMBtu average annual price in 2030 ($16.23/MMBtu nominal) and a $13.66/MMBtu 

price in 2039 ($27.27/MMBtu nominal).51

 

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. 51 Nominal prices assuming an annual inflation rate of 2.5%.
5-26

Figure 5-5. Projected Real National Delivered Natural Gas Price for Select AEO 2013 

Scenarios and Illustrative Path for > $10/MMBtu Levelized Cost

To conclude the comparison of NGCC with uncontrolled coal-fired alternatives, it is 

important to note that the LCOE calculations are based on assumptions regarding the average 

national cost of generation at new facilities. It is known that there is significant spatial variation

in the costs of new generation due to design differences, labor wage and productivity 

differences, and delivered fuel prices among other potential factors.52 

For example, EIA utilizes capital cost scalars to capture regional differences in labor, 

material, and construction costs. The minimum and maximum capital cost scalars across all 

regions in AEO 2013 for SCPC, IGCC, and NGCC build options are presented below in Table 5-7:

53

Table 5-7. AEO 2013 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

 52 http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf 53 Excluding the New York City and Long Island areas, as well as those areas of the country that prohibit the 

development of new, uncontrolled coal-fired facilities.

0

2

4

6

8

10

12

14

16

2011$/MMBtu

Required Natural Gas Price 

for >$10/MMBtu Levelized 

on a 20-Year Basis

Low resource

Reference

High resource
5-27

Applying the regional capital cost scalars displayed above to the base LCOE estimates 

developed earlier in this section produces only a small change in the relative competitiveness of

the technologies as seen in Table 5-8.

Table 5-8. LCOE Estimates with Minimum and Maximum AEO 2013 Regional Capital Cost 

Scalars (2011$/MWh)

Capacity Type Reference (w/ 3% 

CUA)

Minimum Capital 

Cost Scalar

Maximum Capital 

Cost Scalar

SCPC 92 86 100

IGCC 112 106 120

NGCC 59 58 62

The LCOE of SCPC in the lowest capital cost region still results in an LCOE that is ~40%

higher than an NGCC located in the most expensive capital cost region. IGCC remains more 

than 70% higher under a similar adjustment. In addition to the relatively small changes in LCOE 

displayed above, the relative movement in LCOE that can be attributed to regional variations in 

capital cost is further muted by the fact that a high or low capital cost region for coal-fired build 

types is projected to be a high or low capital cost region for gas-fired build types. Due to its 

capital-intensive nature, the most favorable regions for development of new coal-fired capacity 

over NGCC are the lowest cost areas – an assumption that only narrows NGCC’s LCOE 

advantage by $5/MWh for both SCPC and IGCC. To completely negate the base $33/MWh

LCOE advantage of NGCC over SCPC solely with a reduction in coal-fired capital costs, overnight 

capital costs for SCPC would have to be reduced from $2,452/kW to ~$800/kW; IGCC overnight 

capital costs would have to be reduced to~$500/kW.

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 2013 

are the Western Electricity Coordinating Council/Southwest (‘Southwest’) and the Florida 

Reliability Coordinating Council (FRCC). The 20-year levelized natural gas and coal price 

forecasts (2020-2039) in the AEO 2013 reference case are displayed in Figure 5-6 for both 

regions.
5-28

Figure 5-6. Levelized Regional Fuel Price from AEO 2013 Reference Case, 2020-2039 

(2011$/MMBtu)54

While the FRCC region experiences the highest overall natural gas prices, the Southwest 

region realizes a greater $/MMBtu differential between coal and natural gas prices under the 

AEO projections; the impact on the LCOE of SCPC, IGCC, and NGCC is reported in Table 5-9 for 

both sets of fuel prices.

Table 5-9. LCOE Estimates For Minimum and Maximum AEO 2013 Regional Capital Cost 

Scalars (2011$/MWh)

Capacity Type Reference (w/ 3% 

CUA) FRCC Fuel Prices Southwest Fuel Prices

SCPC (w/ 3% CUA) 92 97 89

IGCC (w/ 3% CUA) 112 117 109

NGCC 59 65 62

Due to the greater fuel price differential, the more favorable region for the 

development of coal-fired facilities from an LCOE perspective is the Southwest, where the 

regional fuel prices reduce the LCOE advantage of NGCC to $27/MWh over SCPC and $47/MWh

over IGCC.

 54 Assuming 5% discount rate.

6.95

6.43

3.51

2.6

0

1

2

3

4

5

6

7

8

FRCC WECC-Southwest

20-Year Levelized Fuel Price (2011$/MMBtu)

Natural Gas Coal
5-29

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.

5.5.5 Levelized Cost of Electricity of Uncontrolled Coal and Coal with Carbon Capture and 

Storage (CCS)

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, it is possible that a limited number of conventional 

coal-fired power plants might be constructed in the analysis period. In these circumstances, EPA 

believes that any requirement 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 coalfired facility.

55

One factor in this determination is the availability of ER opportunities for new coal-fired 

facilities. ER, which includes both EOR and EGR, refers to the injection of fluids into a reservoir 

to increase oil and/or gas 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 (2,102 to 20,043 billion metric tons), oil and gas reservoirs are estimated to have 

226 billion metric tons of CO2 storage resource.56 

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 

Energy Agency, of the CCS projects under construction or at an advanced stage of planning, 

70% intend to use captured CO2 to improve recovery of oil in mature fields, including Southern 

Company’s Kemper County Energy Facility, Summit Power’s Texas Clean Energy Project, and the 

Hydrogen Energy California Project.

 55 The preamble provides a complete list of existing sources that have demonstrated CCS as well as new coal-fired 

facilities that will utilize CCS and are very near to completion. 56 U.S. Department of Energy National Energy Technology Laboratory (2012). United States Carbon Utilization and 

Storage Atlas, Fourth Edition.
5-30

There are two EOR opportunities presented in Figure 5-16 – ‘High’ and ‘Low.’ The high 

EOR opportunity assumes a CO2 sale price of $40 per metric ton; the low EOR opportunity 

assumes a CO2 sale price of $20 per metric ton.57 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.58 Costs for the transportation, storage, and monitoring (TSM) of CO2 are 

included in this analysis. For non-EOR applications, TSM costs of ~$5-$15 dollars per ton of CO2

are applied based on the level of capture.59 Figure 5-7 compares the LCOE for uncontrolled coal

to coal with partial CCS both with and without EOR. Although this proposal has determined 

partial CCS is BSER for affected coal-fired facilities, the LCOE associated with full capture is 

presented as well for illustrative purposes.

 57 The High and Low CO2 sale prices utilized by 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. 58 For EOR applications the point of sale is typically the facility fence line, in which case the coal facility operator 

will avoid the TSM cost. Consequently, the economic benefit of EOR may be greater than simply the price paid 

for CO2. 59 This range is broadly consistent with estimates provided by NETL (http://www.netl.doe.gov/energyanalyses/pubs/QGESS_CO2T%26S_Rev2_20130408.pdf ) and the Global CCS Institute 

(http://www.globalccsinstitute.com/publications/economic-assessment-carbon-capture-and-storagetechnologies-2011-update). 
5-31

Figure 5-7. Levelized Cost of Electricity, Uncontrolled Coal and Coal with Full and Partial 

CCS (1,100 lbs/MWh gross)

NOTE: EIA estimated LCOE under AEO 2013 assumptions for full capture SCPC+CCS is estimated at a LCOE 

of $134 without EOR. No estimate is provided for IGCC+CCS or partial capture technologies.

60

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 existing or under construction CO2 pipelines). 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 4 for a more detailed discussion of ER, including its geographic availability, 

expected future growth, and overall impact on the economics of CCS.

5.5.6 Levelized Cost of Electricity of Coal with Carbon Capture and Storage and Nuclear

There are five nuclear units currently under construction in the United States – Vogtle 

Units 3 and 4, Summer Units 2 and 3, and Watts Bar 2 – as well as nine active applications 

under U.S. Nuclear Regulatory Commission (NRC) review covering an additional 14 potential 

units. The addition of Units 3 and 4 at Georgia Power’s Plant Vogtle will be the first new 

nuclear units built in the United States in 30 years. Although it is unlikely that all of the 

proposed nuclear projects will be built, the renewed interest in new nuclear facilities – despite 

persistently high capital costs – is driven by a host of factors, including climate and air quality 

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

0

20

40

60

80

100

120

140

160

SCPC IGCC

LCOE (2011$/MWh)

Uncontrolled (w/ CUA)

Uncontrolled (w/o CUA)

Partial CCS

Partial CCS - Low EOR

Partial CCS - High EOR

Full CCS

Full CCS - Low EOR

Full CCS - High EOR
5-32

concern, the value attached to fuel diversity, regional or local base load capacity needs, and 

supportive regulatory environments. 

As shown in Figure 5-8 on an LCOE basis, the cost of new nuclear is similar to the cost of 

new coal with partial CCS without EOR. Factoring in the revenues associated with the low EOR 

opportunity ($20 per ton of CO2 and no transportation storage and monitoring – TSM –

obligation) reduces the cost of coal with CCS to levels that are 6-10% lower than new nuclear; 

assuming a high EOR opportunity ($40 per ton of CO2 and no TSM obligation) reduces the cost 

of SCPC with CCS and IGCC with CCS to 18% and 9% below new nuclear, respectively. The 

current activity related to new nuclear development at a cost that is broadly similar to coal with 

CCS is a demonstration of the industry’s willingness to develop higher cost projects that 

produce low-emitting base load capacity that contributes to fuel diversity.

Figure 5-8. Levelized Cost of Electricity, Nuclear and Coal with Partial CCS (1,100 lbs/MWh 

gross)

5.5.7 Levelized Cost of Simple Cycle Combustion Turbine and Natural Gas Combined Cycle

CTs fulfill a fundamentally different function in power sector operations than that of 

NGCC and coal-fired 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 

107 110

96

88

109

101

97

0

20

40

60

80

100

120

Nuclear SCPC+CCS SCPC+CCS 

(Low EOR)

SCPC+CCS 

(High EOR)

IGCC+CCS IGCC+CCS 

(Low EOR)

IGCC+CCS 

(High EOR)

LCOE (2011$MWh)
5-33

electricity (cost per kWh) at higher capacity factors and consequently are typically utilized at 

levels well below the proposed threshold for sources affected by the proposed EGU New 

Source GHG Standards (1/3 of potential electric output). Instead, these units are most often 

built to ensure reserve margins are met during peak periods (typically in the summer), and in 

some instances are able to generate additional revenues by selling capacity into power 

markets. Thus, in practice, EPA expects that potential CT units would not meet the applicability 

threshold in this proposed action and would not be subject to any standard.

Mirroring real world behavior, relatively low levels of CT generation are projected in 

both EPA and EIA modeling frameworks. AEO 2013 projects a capacity factor for CTs of less than 

20% in all regions and in all years. EPA’s IPM modeling projects a capacity factor for individual 

new CTs of 8.5% or less in all simulation years. Thus, these potential new units do not meet the 

applicability threshold for this proposal, and there is no projected cost or emissions impact on 

new CT units.

To illustrate the economic impracticality of utilizing combustion turbines in an 

intermediate and base load mode of operation, Figure 5-18 displays the LCOE estimates for a CT 

and NGCC at increasing capacity factors. The estimates utilize the AEO2013 Reference Case 

natural gas price for 2014 (representative of the lowest – and therefore most favorable to the 

relative levelized cost of a CT – natural gas price during the analysis period).
5-34

Figure 5-9. Levelized Cost of Electricity Across a Range of Capacity Factors, CT and NGCC 

($2011/MWh at $3.84/MMBtu Levelized Natural Gas Price)

In the LCOE figure above, utilizing a CT for generation is less expensive than an NGCC 

only at capacity factors of less than 20%.

61 If expected utilization is greater than 20%, 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. Unanticipated short term utilization 

of CTs above a 33% capacity factor would not be expected to alter this dynamic as utilization is 

evaluated over a 3-year averaging period to determine the applicability of the proposed 

standards.

5.6 Comparison of Emissions from Generation Technologies

As discussed earlier in this chapter, NGCC units are on average expected to be more 

economical to build and operate than new coal units. These natural gas units also have lower 

emission profiles for CO2 and criteria air pollutants than new coal units. While the proposed 

EGU New Source GHG Standards is anticipated to have negligible costs or quantified benefits 

under a range of likely market conditions, it is instructive to consider the differences in 

emissions of CO2 and other air pollutants between the two types of units. 

 61 CT cost, performance, and financial assumptions from AEO 2013.

- 

50 

100 

150 

200 

250 

300 

350 

5% 10% 15% 20% 25% 30% 35% 40% 45% 50%

LCOE (2011$/MWh)

Capacity Factor

NGCC CT
5-35

As Table 5-19 below shows, emissions from a typical new NGCC unit are significantly 

lower than those from a new coal unit.62 For example, a typical new supercritical pulverized 

coal facility that burns bituminous coal in compliance with new utility regulations (e.g., MATS)

would have considerably greater CO2, SO2, NOx, toxic metals, acid gases, and particulate

emissions than a comparable natural gas combined cycle facility. A typical natural gas 

combined cycle unit emits two million metric tons less CO2 per year than a typical new 

conventional coal unit, as well as 2,000 fewer short tons SO2 and about 1,200 fewer short tons 

of NOx each year. Importantly, these differences in emissions assume a new coal unit that 

complies with all applicable final regulations, including MATS. 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. Further information on these pollutants’ health effects 

is included in the next subsection.

Table 5-10. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired 

Generating Units

Natural Gas CC SCPC SCPC+CCS (1,100 

lbs/MWh Gross)

IGCC IGCC+CCS (1,100 

lbs/MWh Gross)

Emissions

(tons/

year)

Emission 

Rate 

(lbs/

MWh 

net)

Emissions

(tons/

year)

Emission 

Rate 

(lbs/

MWh 

net)

Emissions

(tons/

year)

Emission 

Rate 

(lbs/

MWh 

net)

Emissions

(tons/

year)

Emission 

Rate 

(lbs/

MWh 

net)

Emissions

(tons/year)

Emission 

Rate 

(lbs/

MWh 

net)

SO2 10 0.0041 1,700 0.74 1,100 0.48 23 0.010 30 0.013

NOx 130 0.060 1,400 0.61 1,500 0.69 1,200 0.52 1,200 0.52

CO2

1.7 

million 800 4.0 million 1,800 2.7 million 1,200 3.8 million 1,700 3.0 million 1,400

Notes: SO2 and NOx in short tons, CO2 in metric tons. 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 

above (e.g., that 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% dry, etc.). Here we further assume all units are of the same capacity (600 MW 

net). Utilizing a consistent net capacity metric across plant types requires a higher gross capacity for those types with greater

need for auxiliary power. The tons of emissions associated with a facility are driven by gross capacity. 

5.7 Benefits of Reducing GHGs and Other Pollutants

Society is not only affected by differences in the private generating costs of different 

technologies, it also experiences the benefit or the burden of relative differences in emissions 

 62 Estimated emissions of CO2, SO2, and NOX for the illustrative new coal and natural gas combined cycle units

could vary depending on a variety of assumptions including heat rate, fuel type, and emission controls, to name 

a few.
5-36

produced by these generation technologies. As such, the appropriate social welfare

comparison should also account for the health, ecological and other emissions impacts of 

different generation technologies. In particular, emissions of CO2 and other pollutants lead to 

additional social costs of these technologies. Any relative differences in these emissions 

between newly built electric generating technologies would translate into relative climaterelated and human health benefits. This section provides a general discussion about how the 

climate-related and human health benefits of emission reductions are estimated. 

5.7.1 Social Cost of Carbon

The social cost of carbon (SCC) is a metric that estimates the monetary value of impacts

associated with marginal changes in CO2 emissions in a given year. It is intended to include (but 

is not limited to) changes in net agricultural productivity, human health, property damages 

from increased flood risk, and the value of ecosystem services due to climate change. It is

typically used to assess the avoided damages, i.e. benefits, of rulemakings that achieve 

marginal reductions in CO2 emissions. This analysis applies SCC to illustrate the value of the 

difference in CO2 emissions among different generation technologies discussed in Section 5.5. 

The federal government typically uses the SCC to estimate the social benefits of CO2

reductions from regulatory actions that impact cumulative global emissions. An interagency 

process that included the EPA and other executive branch entities used three integrated 

assessment models (IAMs) to develop SCC estimates and selected four global values for use in 

regulatory analyses. Three values are based on the average SCC from the three IAMs, at 

discount rates of 5, 3, and 2.5 percent. SCCs at several discount rates are included because the 

literature shows that the SCC 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 SCC 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

SCC distribution (representing less likely, but potentially catastrophic, outcomes). The SCC 

Technical Support Document (SCC TSD) provides a complete discussion of the methods used to 

develop these estimates.63

 63 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support Document: Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon, with 

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, 
5-37

The federal government recently updated these estimates, using new versions of each 

integrated assessment model and published them in May 2013. The 2013 process did not revisit 

the 2010 interagency modeling decisions (e.g., with regard to the discount rate, reference case 

socioeconomic and emission scenarios or equilibrium climate sensitivity). Rather, 

improvements in the way damages are modeled are confined to those that have been 

incorporated into the latest versions of the models by the developers themselves and used in 

peer-reviewed publications. The model updates that are relevant to the SCC estimates include: 

an explicit representation of sea level rise damages in the Dynamic Integrated Climate and 

Economy (DICE) and Policy Analysis of the Greenhouse Effect (PAGE) models; updated 

adaptation assumptions, revisions to ensure damages are constrained by GDP, updated 

regional scaling of damages, and a revised treatment of potentially abrupt shifts in climate 

damages in the PAGE model; an updated carbon cycle in the DICE model; and updated damage 

functions for sea level rise impacts, the agricultural sector, and reduced space heating 

requirements, as well as changes to the transient response of temperature to the buildup of

GHG concentrations and the inclusion of indirect effects of methane emissions in the Climate 

Framework for Uncertainty, Negotiation, and Distribution (FUND) model.64

The SCC estimates from the updated versions of the models are higher than those 

reported in the 2010 TSD, which were used in the April 2012 EGU New Source GHG Standards

RIA. By way of comparison, the four 2020 SCC estimates reported in the 2010 TSD and used in 

the April 2012 EGU New Source GHG Standards proposal were $7, $28, $44 and $86 per metric 

ton (2011$). The corresponding four updated SCC estimates for 2020 are $13, $46, $69, and 

$138 per metric ton (2011$).65,66 

 

Office of Science and Technology Policy, and Department of Treasury (February 2010). Also available at 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf 64 Docket ID EPA-HQ-OAR-2013-0495, Technical Support Document: Technical Update of the Social Cost of Carbon 

for Regulatory Impact Analysis Under Executive Order 12866, Interagency Working Group on Social Cost of 

Carbon, with 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 (May 2013). Also available at

http://www.whitehouse.gov/sites/default/files/omb/inforeg/social_cost_of_carbon_for_ria_2013_update.pdf 65 The 2010 and 2013 TSDs present SCC in $2007. The estimates were adjusted to $2011 using GDP Implicit Price 

Deflator, http://www.gpo.gov/fdsys/pkg/ECONI-2013-02/pdf/ECONI-2013-02-Pg3.pdf. 66 The 2010 SCC TSD concluded that a global measure of the benefits from reducing U.S. emissions is preferable. 

The development of a domestic SCC is greatly complicated by the relatively few region- or country-specific 

estimates of SCC in the literature. See Interagency Working Group on Social Cost of Carbon. 2010. Technical 

Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866.
5-38

When attempting to assess the incremental economic impacts of carbon dioxide 

emissions, the analyst faces a number of serious challenges. A report from the National 

Academies of Science (NRC 2009) points out that any assessment will suffer from uncertainty, 

speculation, and lack of information about (1) future emissions of greenhouse gases, (2) the 

effects of past and future emissions on the climate system, (3) the impact of changes in climate 

on the physical and biological environment, and (4) the translation of these environmental 

impacts into economic damages.67 As a result, any effort to quantify and monetize the harms 

associated with climate change will raise serious questions of science, economics, and ethics 

and should be viewed as provisional.

The 2010 SCC TSD noted a number of limitations to the SCC analysis, including the 

incomplete way in which the integrated assessment models capture catastrophic and noncatastrophic 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 because of 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.

The limited amount of research linking climate impacts to economic damages makes the 

interagency modeling exercise even more difficult.

While the new versions of the models used to estimate the values presented below 

offer some improvements in these areas, further work remains warranted. Accordingly, the EPA 

and other agencies continue to engage in research on modeling and valuation of climate 

impacts with the goal to improve these estimates. Additional details are provided in the SCC 

TSDs.

Table 5-11 presents the updated global SCC estimates for the years 2015 to 2050. In 

order to calculate the dollar value for emission reductions, the SCC 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 SCC.68 The SCC increases 

 67 National Research Council (2009). Hidden Costs of Energy: Unpriced Consequences of Energy Production and Use. 

National Academies Press. See docket ID EPA-HQ-OAR-2009-0472-11486. 68 This analysis considered the climate impacts of only CO2 emission change, as the U.S. Interagency Working 

Group on the Social Cost of Carbon has thus far only considered estimates for the social cost of CO2. While CO2

is the dominant GHG emitted by the sector, we recognize the representative facilities within these comparisons 

may also have different emission rates for other climate forcers which will serve a minor role in determining 

the overall social cost of generation.
5-39

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 SCC 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.

Table 5-11. Social Cost of CO2, 2015-2050a (in 2011$)

Year

Discount Rate and Statistic

5% Average 3% Average 2.5% Average 3%

95th percentile

2015 $13 $41 $62 $116

2020 $13 $46 $69 $138

2025 $15 $51 $75 $154

2030 $17 $55 $81 $170

2035 $20 $61 $86 $188

2040 $22 $66 $93 $205

2045 $26 $70 $98 $220

2050 $29 $76 $105 $236

a The SCC values vary depending on the year of CO2 emissions and are defined in real terms. These SCC values are 

stated in $/metric ton.

5.7.2 Health Co-Benefits of SO2 and NOx Reductions 

Reducing power sector CO2 under this rule would also result in reductions of SO2 and 

NOX emissions, which in turn would yield health benefits (we refer to these additional benefits 

as “co-benefits”). SO2 is a precursor for fine particulate matter (PM2.5) formation while NOX is a 

precursor for PM2.5 and ground-level 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 significant 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, 2013b). 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 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. 
5-40

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).

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 RIA for MATS (U.S. EPA, 

2011).

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. However, when assessing the co-benefits of differences in emissions from 

different generation technologies in the following sections, the EPA does not assert a specific 

location for the new unit. As a result, the EPA does not have the data to perform a full health 

impact assessment for a specific modeled scenario.69 Instead, the EPA relied on a nationalaverage 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 

utilized detailed air quality modeling of power sector SO2 and NOX emissions along with the 

BenMAP model70 to 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 

Technical Support Document (TSD) on estimating the BPT of reducing PM2.5 and its precursors 

(U.S. EPA, 2013a). 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, 2013a). 

 69 If the EPA conjectured a location for a particular new unit it may be possible to perform a full health impact 

assessment of different technologies 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. For more information on the EPA’s 

methods for conducting health impact assessments, please refer to Chapter 5 of the final PM NAAQS RIA. (U.S. 

EPA, 2012) 70 Available at http://www.epa.gov/air/benmap. 
5-41

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 the emissions of other air and 

water pollutants between the different generating technologies, including, for example, 

directly-emitted PM. 

As we do not conjecture a specific location for the new units being compared, this RIA is 

unable to include the type of detailed uncertainty assessment found in the 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 these uncertainties, use of BPT estimates come with 

additional uncertainty. Specifically, all 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, 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 purely illustrative as the EPA does not assert 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 4 and 9 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% 

discount rate or between $34 million and $76 million (2011$) using a 7% discount rate. 

Additionally, reducing one thousand tons of annual NOX from U.S. EGUs has been estimated to 

yield up to 1 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% discount rate or between $5.0 million and $11 

million (2011$) using a 7% 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 
5-42

mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a higher primary 

estimate based on Lepeule et al. (2012).

Table 5-12. Monetized Health Co-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 $5,5000

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 As described in Section 5.7.2, the SO2- and NOX-related BPT estimates are from the Technical Support Document 

on Estimating the Benefit Per Ton of Reducing PM2.5 from 17 Sectors (U.S. EPA, 2013a) and are adjusted to 2011$.

5.8 Comparison of Health and Welfare Impacts from Generation Technologies

As previously discussed in this chapter, the emissions of GHGs and other pollutants 

associated with new sources of electricity generation are greater for coal-fired units than for 

natural gas combined cycle units (even when accounting for compliance with MATS). Reducing

the emissions associated with electricity generation results in both climate and human health 

and non-health benefits. 

To consider the social benefits associated with the adoption of lower emitting new 

generation technologies, we determine the differences in emissions in the illustrative emission 

profiles between technologies in Table 5-10 and apply the 2020 social benefit values discussed 

in Section 5.7. Specifically, we multiply the difference in CO2 emissions between two 

technologies by the estimates of the SCC, multiply the difference in SO2 and NOX emissions by 

the PM2.5-related SO2 and NOX BPT estimates, and add those values to get a measure of 2020 

social benefits of the adoption of lower emitting generation technology. We subsequently 

divide by the number of MWh underlying the emission estimates to derive the social benefits

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. Furthermore, there may be differences in 
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upstream greenhouse gas emissions (in particular, methane) from different technologies but 

those were not quantified for this assessment.

Table 5-13 reports the 2020 incremental climate and health benefits associated with an 

illustrative new NGCC plant relative to illustrative new SCPC and IGCC coal plants, given 

different mortality risk studies and assumptions about the discount rate. 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, 2020 incremental benefits 

associated with generation from a representative new natural gas combined cycle unit relative 

to a new coal unit are $6.6 to $95 per MWh (2011$).71

The precise social benefits associated with reduced CO2 emissions, which are the focus 

of this rule, depend on the specific fuels used but 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. As with the relative investment costs of a new coal unit and a new 

natural gas combined cycle system, the precise incremental health co-benefits associated with 

lower emissions depend on the location under consideration and the specific fuels that would 

be used. An ideal benefit-cost analysis would account for these local circumstances (and 

consider alternative sources of generation). 

However, these factors will not change the qualitative conclusion. There will always be 

incremental climate and human health benefits associated with a new natural gas combined 

cycle unit relative to a new coal unit, independent of the location.

 71 Different discount rates are applied to SCC than to the other benefit estimates because CO2 emissions are longlived and subsequent damages occur over many years. Moreover, several rates are applied to SCC 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 SCC interagency group centered its attention on 

the 3 percent discount rate but emphasized the importance of considering all four SCC estimates. See the 2010 

SCC 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.
5-44

Table 5-13. 2020 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Illustrative 

New Natural Gas Combined Cycle Generation Relative to New SCPC or IGCC Coal 

Generation without CCS72

SCPC IGCC

CO2-Related Benefits using SCC

5% Discount Rate $5.6 $5.4

3% Discount Rate $20 $19

2.5% Discount Rate $31 $29

3% Discount Rate (95th percentile) $61 $58

PM2.5-Related Co-Benefits from SO2 and NOX Reductions

3% discount rate

Krewski et al. (2009) $15 $1.4

Lepeule et al. (2012) $35 $3.1

7% discount rate

Krewski et al. (2009) $14 $1.2

Lepeule et al. (2012) $31 $2.8

Combined CO2-Related and PM2.5-Related Benefits 

Discount Rate Applied to PM2.5-Related Benefits 

(range based on adult mortality function)

SCC Discount Rate 3% 7% 3% 7%

5% Discount Rate $21 to $40 $20 to $37 $6.7 to $8.5 $6.6 to $8.2

3% Discount Rate $36 to $55 $34 to $52 $21 to $22 $20 to $22

2.5% Discount Rate $46 to $65 $44 to $62 $30 to $32 $30 to $32

3% Discount Rate (95th percentile) $76 to $95 $75 to $92 $59 to $61 $59 to $60

Notes: The emission rates and operating characteristics of the units being compared in this table are reported in Table 5.10. Benefits are 

estimated for a 2020 analysis year. The range of benefits within each SCC value and discount rate for PM2.5-related benefits pairing 

reflects the use of two core estimates of PM2.5-related premature mortality.73 The EPA has evaluated the range of potential impacts per 

MWh by combining all SCC values with health benefits values at the 3 percent and 7 percent discount rates. To be consistent with 

concepts of intergenerational discounting, values for health benefits, which occur within a generation, would only be combined with SCC 

values using a lower discount rate, e.g. the 7 percent health benefit estimates would be combined with 5 percent or lower SCC values, 

but the 3 percent health benefit would not be combined with the 5 percent SCC value. While the 5 percent SCC and 3 percent health

benefit estimate falls within the range of values we analyze, this individual estimate should not be used independently in an analysis, as it 

is represents a combination of discount rates that is unlikely to occur. Combining the 3 percent SCC values with the 3 percent health 

benefit values assumes that there is no difference in discount rates between intragenerational and intergenerational impacts.

 72 The benefits presented here are estimated on an output basis to enable easier comparisons and to illustrate the potential 

impacts of moving from new coal without CCS to new NGCC. 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 plant with a small natural gas plant, or a comparison of a waste coal or petroleum coke facility to a 

natural gas plant of a comparable size and capacity factor). However, the incremental benefits associated with other 

facilities that could be built, and which would be subject to this proposal, 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 local conditions, as discussed previously. 73 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 conventional coal unit. Other studies of the social costs of coal and natural gas fired 

generation provide similar findings (Muller et. al., 2011; NRC, 2009).74

As explained previously, 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 cost differential. Even so, it is possible that a limited number of unplanned coalfired power plants will be constructed during the analysis period. In these circumstances, units 

built with CCS in place of conventional coal-fired units would result in relative climate and 

human health and non-health benefits. Table 5-14 reports the 2020 incremental benefits 

associated with an illustrative new coal-fired plant with CCS relative to illustrative new SCPC 

and IGCC coal plants, given different mortality risk studies and assumptions about the discount 

rate. Depending on the coal-fired generation type, discount rate, and mortality risk study used, 

2020 incremental benefits associated with generation from a representative new coal-fired unit 

with CCS relative to a new coal unit without CCS are $2.0 to $45 per MWh (2011$).75 

 74 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). 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). 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 natural gas combined cycle units. 75 Different discount rates are applied to SCC than to the other benefit estimates because CO2 emissions are longlived and subsequent damages occur over many years. Moreover, several rates are applied to SCC 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 SCC interagency group centered its attention on 

the 3 percent discount rate but emphasized the importance of considering all four SCC estimates. See the 2010 

SCC 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.
5-46

Table 5-14. 2020 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from CoalFired Generation with CCS meeting 1,100 lbs/MWh Relative to New Coal-Fired 

Generation Without CCS

SCPC IGCC 

CO2-Related Benefits using SCC

5% Discount Rate $3.2 $2.1

3% Discount Rate $11 $7.5

2.5% Discount Rate $17 $11

3% Discount Rate (95th percentile) $34 $23

PM2.5-Related Benefits from SO2 and NOX Reductions

3% discount rate

Krewski et al. (2009) $4.7 *

Lepeule et al. (2012) $11 *

7% discount rate

Krewski et al. (2009) $4.2 *

Lepeule et al. (2012) $9.5 *

Combined CO2-Related and PM2.5-Related Benefits 

Discount Rate Applied to PM2.5-Related Benefits 

(range based on adult mortality function)

SCC Discount Rate 3% 7% 3% 7%

5% Discount Rate $7.9 to $14 $7.4 to $13 $2.0 to $2.0 $2.0 to $2.1

3% Discount Rate $16 to $22 $16 to $21 $7.4 to $7.5 $7.4 to $7.5

2.5% Discount Rate $22 to $28 $22 to $27 $11 to $11 $11 to $11

3% Discount Rate (95th percentile) $39 to $45 $39 to $44 $22 to $23 $22 to $23

*IGCC with CCS results in a small SO2 emissions increase when compared to IGCC without CCS. As a result, there would be a 

negligible health disbenefit associated with these emissions increases. 

Notes: Benefits are estimated for a 2020 analysis year. The range of benefits within each SCC value and discount rate for PM2.5-

related benefits pairing reflects the use of two core estimates of PM2.5-related premature mortality.76 The EPA has evaluated 

the range of potential impacts per MWh by combining all SCC values with health benefits values at the 3 percent and 7 percent 

discount rates. To be consistent with concepts of intergenerational discounting, values for health benefits, which occur within a 

generation, would only be combined with SCC values using a lower discount rate, e.g. the 7 percent health benefit estimates 

would be combined with 5 percent or lower SCC values, but the 3 percent health benefit would not be combined with the 5 

percent SCC value. While the 5 percent SCC and 3 percent health benefit estimate falls within the range of values we analyze, 

this individual estimate should not be used independently in an analysis, as it is represents a combination of discount rates that 

is unlikely to occur. Combining the 3 percent SCC values with the 3 percent health benefit values assumes that there is no 

difference in discount rates between intragenerational and intergenerational impacts.

5.9 Illustrative Analysis – Benefits and Costs across a Range of Gas Prices

As the analysis in Sections 5.4 and 5.5 demonstrated, under a wide range of likely 

electricity market conditions – including the EPA and EIA baseline scenarios as well as multiple 

alternative scenarios – the EPA projects that the industry will choose to construct new units

 76 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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that already meet the standards of this proposed rulemaking, regardless of this proposal. In this 

section, we consider the unlikely scenario where construction of new supercritical coal capacity 

without CCS occurs during the analysis period in the absence of the rule. The analysis in this 

section indicates that in this scenario, which implies that the proposed EGU New Source GHG 

Standards would result in costs to the investor, but would lead to greater climate and human 

health benefits and is highly likely to provide net benefits to society as a whole. 77

The starting point for this analysis is the illustrative comparison (presented in Section 

5.5.4) of the relative LCOE of representative new SCPC and IGCC coal EGUs and representative 

NGCC units.

78 This comparison demonstrates 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 $33 and $38 per MWh less than for a representative new 

SCPC or IGCC coal unit, respectively (see Figure 5-3).79 This is consistent with the EPA’s 

projection, discussed at length in this chapter, that the proposed EGU New Source GHG 

Standards are not projected to impose any costs (or generate quantified net benefits) under 

current and likely future market conditions.

To supplement this determination, this section presents an analysis of 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, we evaluate how changes in 

natural gas prices affect differences in private and social cost of new technologies. In general, 

this analysis shows that there would likely be a net social benefit,80 even under scenarios with 

higher than expected gas prices, if new NGCC units were built in place of new coal-fired units as 

a result of this policy. Under some conditions, higher natural gas prices may result in a net 

social cost, holding all other parameters constant and disregarding social benefits that we are 

 77 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. 78 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, at particularly high fuel 

prices this might not be the case. 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. 79 LCOE of NGCC relative to SCPC with 3% CUA and IGCC without 3% CUA. 80 The benefits estimated in this section are based on a single year (2020) 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.
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unable to monetize.

81 Additionally, given certain market conditions, some operators may 

choose to construct a new coal-fired unit with CCS. The relative private costs and social benefits 

of a new coal-fired unit with CCS are discussed in Section 5.10.

5.9.1 Likely Natural Gas Prices 

 As shown earlier, it is only when natural gas prices reach $10.94/MMBtu on a levelized 

basis (in 2011 dollars) that new coal-fired generation without CCS becomes competitive in 

terms of its cost of electricity. None of the EPA sensitivities or AEO2013 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.

82

5.9.2 Unexpectedly High Natural Gas Prices

At natural gas prices above $10.94/mmBtu, the private levelized cost of electricity for a 

representative new SCPC unit falls below that of a new NGCC unit. Therefore, at anticipated 

levelized fuel prices above that price level some new SCPC coal units might be constructed in 

the absence of this proposed rulemaking, provided there is sufficient demand and new coal 

without CCS is competitive with other generating technologies.83 In this scenario, there would 

be some compliance cost if a new NGCC unit or a coal-fired unit with CCS were built as a result 

of the standard. However, generation from either a new NGCC unit or a coal-fired unit with CCS 

would also have incremental environmental and health benefits by reducing global warming 

pollution and particulate matter (as a result of SO2 and NOx emissions) relative to generation 

from a new coal unit.

For average annual natural gas prices greater than $10.94/mmBtu, the resulting 

emission reduction benefits of building NGCC will outweigh the costs of constructing an NGCC 

unit in lieu of a coal plant without CCS – indicating that the standard would yield net benefits 

 81 The net cost scenario is unlikely to occur over our analysis period and for a significant period beyond. For 

example, 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. It is important to note that this analysis is 

limited in the types of benefits and costs considered, given that it does not address the life-cycle pollution 

associated with fossil fuels along with the limitations of current SCC estimates. As previously discussed, the 

current SCC 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. 82 EIA’s projected natural gas price for 2022 in its reference scenario for AEO2013 is $5.31 (in 2011 dollars). EIA’s 

“Low oil and gas resource” scenario projects an average delivered electricity sector gas price of $6.64/mmBtu 

(in 2011 dollars) in 2022. 83 See section 5.5 for a discussion of how local conditions and other factors may influence the LCOE comparison. 
5-49

for the analysis year. For example, at an average annual gas price of $11/MMBtu, the 

illustrative NGCC unit would generate power for approximately $1/MWh more than an SCPC 

coal unit on a levelized basis,84 and result in incremental benefits from emissions of $20 to 

$95/MWh (see analysis of 2020 relative benefits of NGCC: table 5-13).85 The net benefit of this 

scenario would be $19 to $95/MWh.86 As illustrated in section 5.10, if an SCPC coal unit with 

CCS (as opposed to an NGCC unit) were built instead of an SCPC coal unit without CCS, the CCS 

equipped unit would result in an incremental cost of $18/MWh and incremental benefits from 

emissions of $7.4 to $45/MWh relative to an SCPC unit without CCS (see analysis of 2020 

relative benefits of CCS: table 5-14). The net impact of this scenario would range from a net 

cost of $11/MWh to a net benefit of $27/MWh. 

For context, a natural gas price level of $10/MMBtu (in 2011 dollars) is higher than any 

annual natural gas price to the electric power sector since at least 1996, when the EIA data 

series stops.

87 In addition, the highest projected average annual natural gas price during the 

analysis period in any of the AEO2013 scenarios cited in this chapter is $6.64/MMBtu in the Low 

Oil and Gas Resource scenario. Further, the continued development of unconventional natural 

gas resources in the U.S. suggests that gas prices would actually tend to be towards the lower 

end of the historical range. As discussed above, none of the EIA sensitivity cases (which account 

for future fuel prices for both gas and coal) show scenarios where noncompliant coal becomes 

more economic than NGCC before 2020.

5.9.3 Unprecedented Natural Gas Prices

At extremely high natural gas prices, the generating costs of coal without CCS would be 

sufficiently lower than the cost of new natural gas that the net benefit of the standard in a 

given year could be negative (i.e., a net cost) under some ranges of benefit estimates. For 

example, at gas prices of $14/MMBtu, the illustrative NGCC unit would generate power for 

roughly $21 and $16/MWh more than conventional SCPC and IGCC coal units, respectively but 

result in social benefits from lower emissions of $20 to $95/MWh and $6.6 to $61/MWh 

relative to the SCPC and IGCC coal units, respectively (see analysis of 2020 relative benefits of 

NGCC: table 5-13). If an NGCC unit were built as a result of the standard, the resulting net 

 84 Assuming an increase of $6.80/MWh in the cost of gas generation for every $1/MMBtu increase in natural gas 

prices. 85 Assuming that coal prices do not increase along with natural gas prices as they historically have. 86 The higher value of net benefits calculated here is equal to the higher value of incremental benefits due to 

rounding. 87 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).
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impact would range from a net social cost of $1.5/MWh to a net social benefit of $74/MWh

relative to SCPC and from a net social cost of $9.5/MWh to a net social benefit of $45/MWh 

relative to IGCC.

As noted in the previous subsection, natural gas prices at these levels would be 

unprecedented as they have not been observed as long as EIA has collected data on natural gas 

prices. As a result, the EPA believes that the probability of natural gas prices reaching average 

annual levels at which this standard would generate net social costs under some ranges of 

benefit estimates is extremely small. 

We emphasize that differences in generating costs, plant design, local factors, and the 

relative differences between fuels costs can all have major impacts on the precise 

circumstances under which this standard would be projected to have no costs, net social 

benefits or net social costs. However, based on historical and expected average annual gas 

prices, we project that this standard is most likely to have negligible costs, and, if it does result 

in costs, it is also likely to produce positive, although modest, net social benefits. The 

probability that this proposed standard would result in net social costs is exceedingly low.

5.10 Illustrative Analysis – Benefits and Costs of CCS Compared with Conventional Coal

The previous section evaluated the social benefit of an investor constructing a new 

NGCC unit in lieu of an uncontrolled unit in response to the proposed rule. If an operator chose 

to construct a new coal unit, this proposed rule would result in some costs in order to build a 

unit with partial CCS. However, there would also be climate and other benefits resulting from 

reductions in CO2, SO2, and NOX emissions.88 For each coal-fired generation type, SCPC and 

IGCC, the EPA analyzed the cost and 2020 emission impacts for the proposed emission limit 

using partial capture, plus a more stringent full capture scenario. Consistent with the LCOE 

estimates provided earlier in this chapter, the partial capture CCS scenarios achieve the 

proposed emissions rate of 1,100 lb CO2/MWh gross output. The full capture CCS scenarios 

achieve an emissions rate of 200 lb CO2/MWh and 150 lb CO2/MWh for SCPC and IGCC, 

respectively. Tables 5-15 and 5-16 show the costs and 2020 net benefits per MWh of each of 

these scenarios relative to a no capture scenario. 

In the near term, any new coal-fired EGU with CCS would most likely be located in areas 

amenable to using the captured CO2 in EOR operations. This is because EOR provides a revenue 

 88 When comparing the private costs of different technologies, we account for the CUA in the investor decision 

making, but when we compare the difference in the social costs of these technologies (i.e., the private cost plus 

the cost associated with their emissions) the CUA is not included. 
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stream that is not available for other forms of geologic storage. For example, the Texas Clean 

Energy project89 is planning to capture 90% of the CO2 and sell it for EOR. To evaluate the 

potential revenues from EOR we estimate the revenue in each scenario if CO2 could be sold for 

$20 to $40/ton based on assumptions used by NETL in evaluating the EOR opportunities.90

Table 5-15. Illustrative Costs and 2020 Social Benefits for SCPC with Partial Capture and Full 

Capture CCS Relative to SCPC without CCS (per MWh 2011$)

Partial CCS Full CCS

Additional LCOE of CCSa $29 $66

Revenue from EOR (Low - High EOR) $14 to $22 $32 to $54

Additional LCOE, net of EOR $15 to $7 $34 to $12

Value of Monetized Benefits for 2020 Emissions

SCC 5% with Krewski 3% to SCC 3% (95th) with Lepeule 3%b $7.9 to $45 $22 to $120

Net Monetized Benefits for 2020 Emissions

Without EOR Revenue -$21 to $16 -$44 to $59

With EOR Revenue -$7.1 to $38 -$12 to $110 a LCOE of SCPC without CCS does not include 3% CUA. b

Benefits are estimated for a 2020 analysis year. Values shown are calculated using different discount rates. Four 

estimates of the SCC in the year 2020 were used: $13, $46, and $69 per metric ton (average SCC at discount rates of 

5, 3, and 2.5 percent, respectively) and $138 per metric ton (95th percentile SCC at 3 percent). The average SCC at 5 

percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate. 

See RIA 5.7.1 for complete discussion about these estimates.

Table 5-16. Illustrative Costs and 2020 Social Benefits for IGCC with Partial Capture and Full 

Capture CCS Relative to IGCC without CCS (per MWh 2011$)

Partial CCS Full CCS

Additional LCOE of CCSa $12 $39

Revenue from EOR (Low - High EOR) $8 to $12 $27 to $45

Additional LCOE, net of EOR $4 to $0 $12 to -$6

Value of Monetized Benefits for 2020 Emissions

SCC 5% with Krewski 3% to SCC 3% (95th) with Lepeule 3%b $2 to $22 $8.3 to $94

Net Monetized Benefits for 2020 Emissions

Without EOR Revenue -$10 to $11 -$31 to $55

With EOR Revenue -$2 to $23 -$3.7 to $100 a LCOE of IGCC without CCS does not include 3% CUA. b Benefits are estimated for a 2020 analysis year. Values shown are calculated using different discount rates. Four 

estimates of the SCC in the year 2020 were used: $13, $46, and $69 per metric ton (average SCC at discount rates of 

5, 3, and 2.5 percent, respectively) and $138 per metric ton (95th percentile SCC at 3 percent). The average SCC at 5 

percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate. 

See RIA 5.7.1 for complete discussion about these estimates.

 89 http://www.texascleanenergyproject.com/ 90 http://www.netl.doe.gov/energy-analyses/pubs/storing%20co2%20w%20eor_final.pdf
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The EPA estimated the benefits associated with avoided CO2, SO2, and NOX emissions 

using the methods described previously in this chapter. Similarly, the cost estimates EPA used 

are described previously in this chapter. As before, it is important to note that these 

comparisons omit additional benefits that may be associated with the abatement of 

greenhouse gas emissions.

5.11 Impact of the Proposed Rule on Option Costs

Consistent with EPA’s practice in evaluating the benefits and costs of significant rules, 

Section 5.5 of this chapter uses detailed electricity sector modeling of expected market 

conditions, along with alternative scenario analysis, to demonstrate, that under a broad range 

of conditions, new EGUs expected to be built in the period of analysis would be in compliance 

with this proposed rule, even in the absence of this rule. As a result, the quantifiable benefits 

and costs of the proposed EGU New Source GHG Standards are zero in the analysis period. This 

analysis is extended in Sections 5.9 through 5.10 to acknowledge unexpected conditions that 

could occur during the period of analysis in which the construction of a new coal unit without 

CCS 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 proposed rule 

instead. This section further extends, and draws on, those analyses to discuss, qualitatively,

how EPA views the potential social benefits and costs of the proposed EGU New Source GHG 

Standards. 

When there is uncertainty about future conditions that could impact an investment 

decision, investors place a value on retaining the ability to choose from a range of different 

investments. This is referred to as “option value.” Any cost of this proposed rule is the 

investor’s loss of the option value associated with the ability to build new coal units without 

CCS. In the future, as uncertainty in market conditions is resolved investors will respond to 

expected electricity demand based on the available choice set, taking as given other market and 

regulatory constraints. The cost that society incurs when the choices available to the investors 

are restricted is represented by the least cost option value associated with the choices that are 

eliminated (Dixit and Pindyck, 1994; Trigeorgis, 1996). This option value is determined by the 

likelihood that the restricted choices would be exercised absent the policy, the social cost of 

substitutes, and the value of being able to adjust diversity of fuels that can be used by the 

generating fleet. 91 If it is highly unlikely that the restricted choices would be exercised in the 

 91 The option value associated with constructing new coal-fired capacity without partial CCS as part of a portfolio 

that hedges against uncertainty in future fuel prices will be conditional upon the current composition of the 

fleet. If the current stock was constructed in expectation of relative fuel prices that more strongly favored 
5-53

absence of the policy, or substitutes are available at a minimal incremental cost, then the 

option value will be negligible, and therefore so to will be the social cost of the restriction.

In the case of this proposal, the choice set for firms that generate and sell electricity is 

not being significantly restricted. The proposal eliminates the option to construct new 

uncontrolled coal units, for which there are other generating substitutes, including renewables, 

natural gas, and coal with CCS.92 The value of this option is conditional upon the likelihood that 

it would be exercised during the analysis period and the cost of available substitutes. As 

discussed in Section 5.9 it is highly unlikely that over the analysis period there will be enough 

expansion in relative fuel prices (i.e. natural gas prices relative to coal) to make new coal-fired 

EGUs cost competitive. Therefore, the option value, from the perspective of society, associated 

with allowing investors to construct a new coal fired EGU is currently expected to be minimal. 

As a result, any impact this proposal may have on the option value will be minimal as well. 

If current conditions were significantly different and there existed a higher probability 

that the option to build a new coal-fired unit without SCC might be exercised during the 

analysis period, the impact on the option value will be primarily driven by the incremental cost 

of increasing utilization at existing units, investing in cost-saving energy efficiency or 

constructing a new unit with a substitute fuel (e.g., renewables, natural gas, etc.). Because 

investors retain the ability to construct coal with CCS, the effect on the option value will be 

equal to the incremental cost of CCS.93 Additionally, this is based not on the cost of CCS today, 

but the expected cost of CCS in the future. If market conditions were to deviate significantly 

from expectations such that the likelihood of investors constructing new coal units with CCS 

increased, so would research and development spending on the technology, thereby driving 

down its expected costs. 

It is difficult to precisely estimate the option cost of this proposed rule given the 

numerous sources of uncertainty that influence investment decisions in the electricity sector

and existing modeling tools. However, the analysis reported in this 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 no quantifiable costs. 

Furthermore, considering the additional analysis in sections 5.9 and 5.10 and the discussion 

 

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. 92 By definition the option value associated with coal without partial CCS will be less than the option value

associated with the ability to construct and operate any type of new coal fired unit.. 93 Including any additional costs associated with differences in electricity transmission, coal delivery, etc. 

associated with a coal unit with CCS being constructed in lieu of the construction of a non-compliant unit. 
5-54

above, the option cost of the rule is concluded to be small and bounded by the cost of CCS. 

Additionally, if conditions arise that would have lead to the construction of coal-fired units 

without CCS absent the proposed rule, the quantifiable social benefits of limiting the 

construction of those units likely exceed the cost. However, as discussed throughout this RIA,

when considering the most likely outcomes, the proposed rule is anticipated to yield no 

monetized benefits and impose negligible costs over the analysis period.

5.12 Summary of Costs, Benefits, and Energy Impacts

Under a wide range of electricity market conditions – including EPA’s baseline scenario 

as well as multiple sensitivity analyses – EPA projects that the industry will choose to construct 

new units that already meet these standards, regardless of this proposal. As a result, EPA 

anticipates that the proposed EGU New Source GHG Standards will result in negligible CO2 

emission changes, energy impacts, benefits or costs for new units constructed by 2020. 

Likewise, the Agency does not anticipate any notable impacts on the price of electricity or 

energy supplies. Additionally, for the reasons described above, the proposed rule is not 

expected to raise any reliability concerns, since reserve margins will not be impacted and the 

rule does not impose any requirements on existing facilities.

5.13 Macroeconomic and Employment Impacts

These proposed EGU New Source GHG Standards is not anticipated to change GHG 

emissions for newly constructed electric generating units, and is anticipated to impose 

negligible costs or monetized benefits. EPA typically presents the economic impacts to 

secondary markets (e.g., changes in industrial markets resulting from changes in electricity 

prices) and impacts to employment or labor markets associated with proposed rules based on 

the estimated compliance costs and other energy impacts, 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 proposed rule, there are no notable macroeconomic or

employment impacts expected as a result of this proposed rule. 

5.14 References

Dixit, Avinash and Pindyck, Robert. Investment Under Uncertainty. 1994. Princeton University 

Press.

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.
5-55

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.

P.L. Joskow. 2011. Comparing the Costs of Intermittent and Dispatchable Electricity Generating 

Technologies. American Economic Review. vol. 101:238-41.

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. 2011, January 2. Coal’s burnout. The Washington Post. Retrieved from 

http://www.washingtonpost.com/newssearch. 

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. 

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.

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.

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.
5-56

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). 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. 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 6

STATUTORY AND EXECUTIVE ORDER ANALYSES

6.1 Synopsis

This chapter presents discussion and analyses relating to Executive Orders and statutory 

requirements relevant to the proposed EGU New Source GHG Standards. We discuss analyses 

conducted to meet the requirements of Executive Orders 12866 and 13563, as well as potential 

impacts to affected small entities required by the Regulatory Flexibility Act (RFA), as amended 

by the Small Business Regulatory Enforcement Fairness Act (SBREFA). We also discuss the 

requirements of the Unfunded Mandates Reform Act of 1995 (UMRA) and assess the impact of 

the proposed rule on state, local and tribal governments and the private sector, along with the 

analysis conducted to comply with the Paperwork Reduction Act (PRA). In addition, we address 

the requirements of Executive Order (EO) 13045: Protection of Children from Environmental 

Health and Safety Risks; EO 13132: Federalism; EO 13175: Consultation and Coordination with 

Indian Tribal Governments; EO 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations; EO 13211: Actions that Significantly Affect 

Energy Supply, Distribution, or Use; and the National Technology Transfer and Advancement 

Act (NTTAA). 

6.2 Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, 

Improving Regulation and Regulatory Review

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.” 

Accordingly, the EPA submitted this action to the Office of Management and Budget (OMB) for 

review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any 

changes made in response to OMB recommendations have been documented in the docket for 

this action.

In addition, the EPA prepared an analysis of the potential costs and benefits associated 

with this action. This analysis is contained in this RIA. Based on the analysis presented in 

Chapter 5, the EPA believes this rule will have negligible compliance costs associated with it, 

over a range of likely sensitivity conditions, because electric power companies would choose to 

build new EGUs that comply with the regulatory requirements of this proposal even in the 

absence of the proposal given existing and expected market conditions. The EPA does not 

project any new coal-fired EGUs without CCS to be built in the absence of this proposal. 

However, because some companies may choose to construct coal or other solid fossil fuel-fired 
6-2

units, this RIA also analyzes project-level costs of a unit with and without CCS, to quantify the 

potential cost for a solid fossil fuel-fired unit with CCS and estimate the social benefits of 

requiring CCS on a new uncontrolled unit.

6.3 Paperwork Reduction Act

The information collection requirements in this proposed rule have been submitted for 

approval to the Office of Management and Budget under the Paperwork Reduction Act, 44 

U.S.C. 3501 et seq. The information collection requirements are not enforceable until OMB 

approves them. The Information Collection Request (ICR) document prepared by the EPA has 

been assigned EPA ICR tracking number 2465.02 and OMB control number 2060-0685. 

 This proposed action will impose minimal new information collection burden on 

affected sources beyond what those sources are already 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 PRA, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060-

0626 and 2060-0629, respectively. Apart from certain reporting costs based on requirements in 

the NSPS General Provisions (40 CFR part 60, subpart A), which are mandatory for all 

owners/operators subject to CAA section 111 national emission standards, there are no new 

information collection costs, as the information required by this proposed rule is already 

collected and reported by other regulatory programs. The recordkeeping and reporting 

requirements 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. 

The EPA believes that electric power companies will choose to build new EGUs that 

comply with the regulatory requirements of this proposal because of existing and expected 

market conditions. The EPA does not project any new coal-fired EGUs that commence 

construction after this proposal to commence operation over the 3-year period covered by this 

ICR. We estimate that 17 new affected NGCC units will commence operation during that time 

period. As a result of this proposal, those units will be required to prepare a summary report, 

which includes reporting of emissions and downtime every 3 months.

When a malfunction occurs, sources must report them according to the applicable 

reporting requirements of 40 CFR part 60, subparts Da and KKKK or subpart TTTT 60.5530. An 

affirmative defense to civil penalties for exceedances of emission limits that are caused by 
6-3

malfunctions is available to a source if it can demonstrate that certain criteria and requirements 

are satisfied. The criteria ensure that the affirmative defense is available only where the event 

that causes an exceedance of the emission limit meets the narrow definition of malfunction1

and where the source took necessary actions to minimize emissions. In addition, the source 

must meet certain notification and reporting requirements. For example, the source must 

prepare a written root cause analysis and submit a written report to the Administrator 

documenting that it has met the conditions and requirements for assertion of the affirmative 

defense. 

To provide the public with an estimate of the relative magnitude of the burden 

associated with an assertion of affirmative defense, the EPA has estimated what the 

notification, recordkeeping, and reporting requirements associated with the assertion of the 

affirmative defense might entail. The EPA’s estimate for the required notification, reports, and 

records, including the root cause analysis, associated with a single incident totals approximately 

$3,141, and is based on the time and effort required of a source to review relevant data, 

interview plant employees, and document the events surrounding a malfunction that has 

caused an exceedance of an emission limit. The estimate also includes time to produce and 

retain the record and reports for submission to the EPA. The EPA provides this illustrative 

estimate of this burden, because these costs are only incurred if there has been a violation, and 

a source chooses to take advantage of the affirmative defense.

Given the variety of circumstances under which malfunctions could occur, as well as 

differences among sources' operation and maintenance practices, we cannot reliably predict 

the severity and frequency of malfunction-related excess emissions events for a particular 

source. It is important to note that the EPA has no basis currently for estimating the number of 

malfunctions that would qualify for an affirmative defense. Current historical records would be 

an inappropriate basis, as this rule applies only to sources built in the future. Of the number of 

excess emissions events that may be reported by source operators, only a small number would 

be expected to result from a malfunction, and only a subset of excess emissions caused by 

malfunctions would result in the source choosing to assert an affirmative defense. Thus, we 

believe the number of instances in which source operators might be expected to avail 

themselves of the affirmative defense will be extremely small. In fact, we estimate that there 

will be no such occurrences for any new sources subject to 40 CFR part 60, subpart Da or KKKK

 1 Malfunction means any sudden, infrequent, and not reasonably preventable failure of air pollution control and 

monitoring equipment, process equipment, or a process to operate in a normal or usual manner which causes, 

or has the potential to cause, the emission limitations in an applicable standard to be exceeded. Failures that 

are caused in part by poor maintenance or careless operation are not malfunctions.
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over the 3-year period covered by this ICR. We expect to gather information on such events in 

the future, and will revise this estimate as better information becomes available.

The annual information collection burden for this collection consists only of reporting 

burden as explained above. The reporting burden for this collection (averaged over the first 3 

years after the effective date of the standards) is estimated to be $15,570 and 396 labor hours. 

This estimate includes quarterly summary reports which include reporting of emissions and 

downtime. All burden estimates are in 2010 dollars, consistent with the information collection 

request. Average burden hours per response are estimated to be 8 hours. The total number of 

respondents over the 3-year ICR period is estimated to be 36. Burden is defined at 5 CFR 

1320.3(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 EPA's regulations in 40 CFR are listed in 40 CFR part 9.

To comment on the Agency's need for this information, the accuracy of the provided 

burden estimates, and any suggested methods for minimizing respondent burden, the EPA has 

established a public docket for this rule, which includes this ICR, under Docket ID number EPAHQ-OAR-2013-0495. Submit any comments related to the ICR to the EPA and OMB. See 

ADDRESSES section at the beginning of this notice for where to submit comments to the EPA. 

Send comments to OMB at the Office of Information and Regulatory Affairs, Office of 

Management and Budget, 725 17th Street, NW, Washington, DC 20503, Attention: Desk Officer 

for EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days 

after publication in the Federal Register, a comment to OMB is best assured of having its full 

effect if OMB receives it by 30 days after publication in the federal register. The final rule will

respond to any OMB or public comments on the information collection requirements contained 

in this proposal. 

6.4 Regulatory Flexibility Act 

The RFA generally requires an agency to prepare a regulatory flexibility analysis of any 

rule subject to notice and comment rulemaking requirements under the Administrative 

Procedure Act or any other statute unless the agency certifies that the rule will not have a 

significant economic impact on a substantial number of small entities. Small entities include 

small businesses, small organizations, and small governmental jurisdictions.
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For purposes of assessing the impacts of this rule on small entities, small entity is 

defined as: 

(1) A small business that is defined by the Small Business Administration’s regulations at 

13 CFR 121.201 (for the electric power generation industry, the small business size standard is 

an ultimate parent entity defined as having a total electric output of 4 million MWh or less in 

the previous fiscal year. The NAICS codes for the affected industry are in Table 6-1 below);

(2) A small governmental jurisdiction that is a government of a city, county, town, school 

district, or special district with a population of less than 50,000; and 

(3) A small organization that is any not-for-profit enterprise which is independently 

owned and operated and is not dominant in its field.

Table 6-1. Potentially Regulated Categories and Entitiesa

Category NAICS Code Examples of Potentially Regulated Entities

Industry 221112 Fossil fuel electric power generating units.

State/Local 

Government

221112b Fossil fuel electric power generating units owned by municipalities.

a Include NAICS categories for source categories that own and operate electric power generating units (includes boilers and 

stationary combined cycle combustion turbines).

b State or local government-owned and operated establishments are classified according to the activity in which they are 

engaged.

After considering the economic impacts of this proposed rule on small entities, the 

Administrator of EPA certifies that this action will not have a significant economic impact on a 

substantial number of small entities. 

We do not include an analysis of the illustrative impacts on small entities that may result

from implementation of this proposed rule by states because we anticipate negligible

compliance costs over a range of likely scenarios as a result of this proposal. Thus the cost-tosales ratios for any affected small entity would be zero costs as compared to annual sales 

revenue for the entity. The EPA believes that electric power companies will choose to build new 

EGUs that comply with the regulatory requirements of this proposed rule because of existing 

and expected market conditions. (See the Chapter 5 for further discussion of sensitivities.) The 

EPA does not project any new coal-fired EGUs without CCS to be built. Accordingly, there are no 

anticipated economic impacts as a result of this proposed rule.
6-6

Nevertheless, the EPA is aware that there is substantial interest in this rule among small 

entities (municipal and rural electric cooperatives). In light of this interest, prior to the April 13, 

2012 proposal (77 FR 22392), the EPA determined to seek early input from representatives of 

small entities while formulating the provisions of this proposed regulation. Such outreach is 

also consistent with the President’s January 18, 2011 Memorandum on Regulatory Flexibility, 

Small Business, and Job Creation, which emphasizes the important role small businesses play in 

the American economy. This process enabled the EPA to hear directly from these 

representatives, at a very preliminary stage, about how it should approach the complex 

question of how to apply Section 111 of the CAA to the regulation of GHGs from these source 

categories. The EPA’s outreach regarded planned actions for new and existing sources, but only 

new sources will be affected by this proposed action.

The EPA conducted an initial outreach meeting with small entity representatives on 

April 6, 2011. The purpose of the meeting was to provide an overview of recent EPA proposals 

impacting the power sector. Specifically, overviews of the Transport Rule, the Mercury and Air 

Toxics Standards, and the Clean Water Act 316(b) Rule proposals were presented.

The EPA conducted outreach with representatives from 20 various small entities that 

potentially would be affected by this rule. The representatives included small entity 

municipalities, cooperatives, and private investors. We distributed outreach materials to the 

small entity representatives; these materials included background, an overview of affected 

sources and GHG emissions from the power sector, an overview of CAA section 111, an 

assessment of CO2 emissions control technologies, potential impacts on small entities, and a 

summary of the listening sessions. We met with eight of the small entity representatives, as 

well as three participants from organizations representing power producers, on June 17, 2011, 

to discuss the outreach materials, potential requirements of the rule, and regulatory areas 

where the EPA has discretion and could potentially provide flexibility.

A second outreach meeting was conducted on July 13, 2011. We met with nine of the 

small entity representatives, as well as three participants from organizations representing 

power producers. During the second outreach meeting, various small entity representatives 

and participants from organizations representing power producers presented information 

regarding issues of concern with respect to development of standards for GHG emissions.

Specifically, topics suggested by the small entity representatives and discussed included: boilers 

with limited opportunities for efficiency improvements due to New Source Review (NSR)

complications for conventional pollutants; variances per kilowatt-hour and in heat rates over 

monthly and annual operations; significance of plant age; legal issues; importance of future 
6-7

determination of carbon neutrality of biomass; and differences between municipal government 

electric utilities and other utilities.

While formulating the provisions of this proposed regulation, the EPA also considered 

the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule 

(77 FR 22392). We invite comments on all aspects of the proposal and its impacts, including 

potential adverse impacts, on small entities.

6.5 Unfunded Mandates Reform Act (UMRA)

This proposed rule does not contain a Federal mandate that may result in expenditures 

of $100 million or more for State, local, or tribal governments, in the aggregate, or the private 

sector in any one year. The EPA believes this proposed rule will have negligible compliance 

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 

proposed rule because of existing and expected market conditions. (See Chapter 5 for further 

discussion of sensitivities.) The EPA does not project any new coal-fired EGUs without CCS to be 

built. Thus, this proposed rule is not subject to the requirements of sections 202 or 205 of 

UMRA.

This proposed rule is also not subject to the requirements of section 203 of UMRA 

because it contains no regulatory requirements that might significantly or uniquely affect small 

governments.

In light of the interest in this rule among governmental entities, the EPA initiated 

consultations with governmental entities while formulating the provisions of the proposed 

regulation (77 FR 22392, April 13, 2012). The EPA invited the following 10 national 

organizations representing state and local elected officials to a meeting held on April 12, 2011, 

in Washington DC: 1) National Governors Association; 2) National Conference of State 

Legislatures, 3) Council of State Governments, 4) National League of Cities, 5) U.S. Conference 

of Mayors, 6) National Association of Counties, 7) International City/County Management 

Association, 8) National Association of Towns and Townships, 9) County Executives of America, 

and 10) Environmental Council of States. These 10 organizations representing elected state and 

local officials have been identified by the EPA as the “Big 10” organizations appropriate to 

contact for purposes of consultation with elected officials. The purposes of the consultation 

were to provide general background on the proposal, answer questions, and solicit input from 
6-8

state/local governments. The EPA’s consultation regarded planned actions for new and existing 

sources, but only new sources will be affected by this proposed action. 

During the meeting, officials asked clarifying questions regarding CAA section 111 

requirements and efficiency improvements that would reduce CO2 emissions. In addition, they

expressed concern with regard to the potential burden associated with impacts on state and 

local entities that own/operate affected utility boilers, as well as on state and local entities with 

regard to implementing the rule. Subsequent to the April 12, 2011 meeting, the EPA received a 

letter from the National Conference of State Legislatures. In that letter, the National 

Conference of State Legislatures urged the EPA to ensure that the choice of regulatory options 

maximizes benefit and minimizes implementation and compliance costs on state and local 

governments; to pay particular attention to options that would provide states with as much 

flexibility as possible; and to take into consideration the constraints of the state legislative 

calendars and ensure that sufficient time is allowed for state actions necessary to come into 

compliance.

While formulating the provisions of this proposed regulation, the EPA also considered 

the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule 

(77 FR 22392).

6.6 Executive Order 13132, Federalism

This proposed 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, as specified in EO 13132. This action will not impose substantial direct compliance 

costs on state or local governments nor will it preempt state law. Thus, Executive Order 13132 

does not apply to this action. Prior to the April 13, 2012 proposal (77 FR 22392), the EPA 

consulted with state and local officials in the process of developing the proposed rule to permit 

them to have meaningful and timely input into its development. The EPA’s consultation 

regarded planned actions for new and existing sources, but only new sources will be affected by 

this action. The UMRA discussion in this chapter includes a description of the consultation. The 

EPA met with 10 national organizations representing state and local elected officials to provide 

general background on the proposal, answer questions, and solicit input from state/local 

governments. The UMRA discussion in the preamble includes a description of the consultation.

While formulating the provisions of this proposed regulation, the EPA also considered the input 

provided in the over 2.5 million public comments on the April 13, 2012 proposed rule (77 FR 
6-9

22392). In the spirit of EO 13132, and consistent with EPA policy to promote communications 

between the EPA and state and local governments, the EPA specifically solicits comment on this

proposed action from state and local officials.

6.7 Executive Order 13175, Consultation and Coordination with Indian Tribal 

Governments

This action does not have tribal implications, as specified in Executive Order 13175 (65 

FR 67249, November 9, 2000). It would neither impose substantial direct compliance costs on 

tribal governments, nor preempt Tribal law. This proposed rule would impose requirements on 

owners and operators of new EGUs. The EPA is aware of three coal-fired EGUs located in Indian 

Country but is not aware of any EGUs owned or operated by tribal entities. The EPA notes that 

this proposal does not affect existing sources such as the three coal-fired EGUs located in Indian 

Country, but addresses CO2 emissions for new EGU sources only. Thus, Executive Order 13175 

does not apply to this action.

Although Executive Order 13175 does not apply to this action, EPA consulted with tribal 

officials in developing this action. Because the EPA is aware of Tribal interest in this proposed 

rule, prior to the April 13, 2012 proposal (77 FR 22392), the EPA offered consultation with tribal 

officials early in the process of developing the proposed regulation to permit them to have 

meaningful and timely input into its development. The EPA’s consultation regarded planned 

actions for new and existing sources, but only new sources would be affected by this proposed 

action.

Consultation letters were sent to 584 tribal leaders. 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. Other tribes participated in the call for information 

gathering purposes. In this meeting, the EPA provided background information on the GHG 

emission standards to be developed and a summary of issues being explored by the agency. 

Tribes suggested that the EPA consider expanding coverage of the GHG standards to include 

combustion turbines, lowering the 250 MMBtu per hour heat input threshold so as to capture 

more EGUs, and including credit for use of renewables. The tribes were also interested in the 

scope of the emissions averaging being considered by the agency (e.g., over what time period, 

across what units) for a possible existing source standard. In addition, the EPA held a series of 
6-10

listening sessions on the proposed action. 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. 

While formulating the provisions of this proposed regulation, the EPA also considered 

the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule 

(77 FR 22392).

The EPA will also hold additional meetings with tribal environmental staff to inform 

them of the content of this proposal, as well as provide additional consultation with tribal 

elected officials where it is appropriate. We specifically solicit additional comment on this 

proposed rule from tribal officials.

6.8 Executive Order 13045, Protection of Children from Environmental Health Risks and 

Safety Risks

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those 

regulatory actions that concern health or safety risks, such that the analysis required under 

section 5-501 of the Order has potential to influence the regulation. This action is not subject to 

EO 13045 because it is based solely on technology performance. 

6.9 Executive Order 13211, Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use

This proposed action is not a “significant energy action” as defined in Executive Order 

13211 (66 FR 28355, May 22, 2001), because it is not likely to have a significant adverse effect 

on the supply, distribution, or use of energy. This proposed action is anticipated to have 

negligible impacts on emissions, costs or energy supply decisions for the affected electric utility 

industry.

6.10 National Technology Transfer and Advancement Act

Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 15 U.S.C. 272 note) directs 

the EPA to use Voluntary Census Standards (VCS) in their regulatory and procurement activities 

unless to do so would be inconsistent with applicable law or otherwise impractical. VCS are 

technical standards (e.g., materials specifications, test methods, sampling procedures, business 

practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA 

directs the EPA to provide Congress, through annual reports to the OMB, with explanations 

when an agency does not use available and applicable VCS.
6-11

This proposed rulemaking involves technical standards. The EPA proposes to use the 

following standards in this proposed rule: D5287-08 (Standard Practice for Automatic Sampling 

of Gaseous Fuels), D4057-06 (Standard Practice for Manual Sampling of Petroleum and 

Petroleum Products), and D4177-95 (2010) (Standard Practice for Automatic Sampling of 

Petroleum and Petroleum Products). The EPA is proposing use of Appendices B, D, F, and G to 

40 CFR part 75; these Appendices contain standards that have already been reviewed under the 

NTTAA.

The EPA welcomes comments on this aspect of the proposed rulemaking and, 

specifically, invites the public to identify potentially-applicable VCS and to explain why such 

standards should be used in this action. 

6.11 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive 

policy on environmental justice. Its main provision directs Federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental justice part of their mission by 

identifying and addressing, as appropriate, disproportionately high and adverse human health 

or environmental effects of their programs, policies, and activities on minority populations and 

low-income populations in the U.S.

This proposed rule limits GHG emissions from new fossil fuel-fired EGUs by establishing 

national emission standards for CO2. The EPA has determined that this proposed rule will not 

result in disproportionately high and adverse human health or environmental effects on 

minority, low-income, and indigenous populations because it increases the level of 

environmental protection for all affected populations without having any disproportionately 

high and adverse human health or environmental effects on any population, including any 

minority, low-income, or indigenous populations. 
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-13-003

September 2013