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-12-001

March 2012

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

CAA Clean Air Act

CCS Carbon Capture and Sequestration or Carbon Capture and Storage

CH4 Methane

CO2 Carbon Dioxide

CSAPR Cross State Air Pollution Rule

DOE U.S. Department of Energy

EAB Environmental Appeals Board

EGU Electric Generating Unit

EGU GHG NSPS Standards of Performance for Greenhouse Gas Emissions for New 

Stationary Sources for Electric Utility Generating Units

EIA U.S. Energy Information Administration

EO Executive Order

EOR Enhanced Oil Recovery

EPA U.S. Environmental Protection Agency

FERC Federal Energy Regulatory Commission

GHG Greenhouse Gas

HFC Hydrofluorocarbons

HRSG Heat Recovery Steam Generator

ICR Information Collection Request

IGCC Integrated Gasification Combined Cycle

IOU Investor Owned Utility

IPCC Intergovernmental Panel on Climate Change

IPM Integrated Planning Model

kWh Kilowatt-hour

MATS Mercury and Air Toxics Standards

mmBtu Million British Thermal Units

MW Megawatt

MWh Megawatt-hour

N2O Nitrous Oxide

NEEDS National Electric Energy Data System

NETL National Energy Technology Laboratory

NGCC Natural Gas Combined Cycle
v

NOX Nitrogen Oxide

NRC National Research Council

NSPS New Source Performance Standard

NTTAA National Technology Transfer and Advancement Act

O&M Operations and Maintenance

OMB Office of Management and Budget

PC Pulverized Coal

PM2.5 Fine Particulate Matter

PRA Paperwork Reduction Act 

PSD Prevention of Significant Deterioration

psi Pounds per Square Inch

RFA Regulatory Flexibility Act

RIA Regulatory Impact Analysis

SBA Small Business Administration

SBREFA Small Business Regulatory Enforcement Fairness Act

SCC Social Cost of Carbon

SF6 Sulfur Hexafluoride

SIP State Implementation Plan

SO2 Sulfur Dioxide

SPC Supercritical Pulverized Coal

Tcf Trillion Cubic Feet

TSD Technical Support Document

UMRA Unfunded Mandates Reform Act

USGCRP U.S. Global Change Research Program

VCS Voluntary Consensus Standards
vi

TABLE OF CONTENTS

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

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

ES.2 Summary of Proposed Rule ............................................................................... ES-2

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

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

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

1.2 Background .......................................................................................................... 1-1

1.3 Regulatory Analysis.............................................................................................. 1-1

1.4 Regulated Entities................................................................................................ 1-3

1.5 Regulated Pollutant ............................................................................................. 1-3

1.6 Baseline and Years of Analysis............................................................................. 1-4

1.7 Organization of the Regulatory Impact Analysis ................................................. 1-4

Chapter 2 Control Strategies................................................................................................. 2-1

2.1 Synopsis................................................................................................................ 2-1

2.2 Definition of Affected Sources............................................................................. 2-1

2.3 Control Strategies................................................................................................ 2-4

2.4 Analytical Baseline ............................................................................................... 2-4

2.5 Emission Reductions............................................................................................ 2-4

Appendix 2A Potential Transitional Units............................................................................2A-1
vii

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.......................................................................................................... 3-10

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 Pollution Control Technologies.......................................................................... 4-11

4.6 GHG Regulation in the Power Sector................................................................. 4-16

4.7 Revenues, Expenses, and Prices ........................................................................ 4-18

4.8 Electricity Demand and Demand Response....................................................... 4-22

4.9 References ................................................................................................................. 4-24

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

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

5.2 Background .......................................................................................................... 5-1

5.3 External Review of EPA Applications of IPM........................................................ 5-6

5.4 IPM is a Detailed Bottom-Up Model.................................................................... 5-7

5.5 Base Case and Sensitivity Analysis of Future Generating Capacity ..................... 5-8

5.6 Analysis of Applicability of Proposed EGU GHG NSPS to Projected New 

Generating Capacity........................................................................................... 5-14

5.7 Costs, Economic, and Energy Impacts of the Proposed Rule for New 

Electric Generating Units................................................................................... 5-19

5.8 Comparison of Emissions from Generation Technologies................................. 5-19

5.9 Benefits of Reducing GHGs and Conventional Pollutants ................................. 5-21
viii

5.10 Illustrative Analysis of the Social Costs of New Generating Sources................. 5-26

5.11 Macroeconomic and Employment Impacts....................................................... 5-37

5.12 References.................................................................................................................. 5-37

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 as Amended by the Small Business Regulatory 

Enforcement Fairness Act of 1996, 5 U.S.C. et seq.............................................. 6-4

6.5 Unfunded Mandates Reform Act of 1995 ........................................................... 6-7

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

6.7 Executive Order 13175, Consultation and Coordination with Indian Tribal 

Governments ....................................................................................................... 6-9

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....................................... 6-11

6.11 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations............................................. 6-11
ix

LIST OF TABLES

Table 4-1. Existing Electricity Generating Capacity by Energy Source, 2009........................ 4-2

Table 4-2. Total U.S. Electric Power Industry Retail Sales in 2010 (Billion kWh).................. 4-2

Table 4-3. Electricity Net Generation in 2010 (Billion kWh)................................................. 4-3

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

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

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

tons of CO2 equivalent)........................................................................................ 4-8

Table 4-6. Electricity Generation-Related Greenhouse Gas Emissions, 2009 (million metric 

tons of CO2 equivalent)........................................................................................ 4-9

Table 4-7. Fossil Fuel Emission Factors in EPA Modeling Applications .............................. 4-10

Table 4-8. Existing Coal-Fired EGU Efficiency Improvements Reported for Actual Efficiency 

Improvement Projects....................................................................................... 4-14

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

for 2010 ($millions)............................................................................................ 4-19

Table 4-10. Projected Revenues by Service Category in 2015 for Public Power and InvestorOwned Utilities (billions).................................................................................... 4-20

Table 5-1. Total Generation Capacity in 2010 and Projected by 2020 (GW)...................... 5-10

Table 5-2. 2010 U.S. Electricity Net Generation and EPA Base Case Projections for 2020 

(Billion kWh)....................................................................................................... 5-10

Table 5-3. Projected New Capacity in 2020........................................................................ 5-14

Table 5-4. Estimated Levelized Cost of New Generation Resources from EIA, U.S. Average 

(2016)................................................................................................................. 5-18

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

Generating Units................................................................................................ 5-21

Table 5-6. Social Cost of CO2, 2015-2050 (in 2007 dollars) ................................................ 5-24

Table 5-7. Pollution Damages ($/MWh) from Illustrative New Coal Unit Relative to New 

Natural Gas Combined Cycle Unit...................................................................... 5-30

Table 5-8. Illustrative Costs and Benefits for two CCS Scenarios Compared to Conventional 

Coal Plant (per MWh 2007$) ............................................................................. 5-36

Table 6-1. Potentially Regulated Categories and Entities..................................................... 6-5
x

LIST OF FIGURES

Figure 4-1. Fossil Fuel-Fired Electricity Generating Facilities, by Size ................................... 4-5

Figure 4-2. Status of State Electricity Industry Restructuring Activities................................ 4-7

Figure 4-3. Domestic Emissions of Greenhouse Gases, 2009 (million metric tons of CO2

equivalent)........................................................................................................... 4-8

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

(2009)................................................................................................................. 4-10

Figure 4-5. Post-Combustion CO2 Capture for a Pulverized Coal Power Plant.................... 4-12

Figure 4-6. Pre-Combustion CO2 Capture for an IGCC Power Plant .................................... 4-13

Figure 4-7. National Average Retail Electricity Price (1960 – 2009).................................... 4-20

Figure 4-8. Average Retail Electricity Price by State (cents/kWh), 2009............................. 4-21

Figure 4-9. Natural Gas Spot Price, Annual Average (Henry Hub)....................................... 4-22

Figure 4-10. Electricity Growth Rate (3 Year Rolling Average) and Projections from the Annual 

Energy Outlook 2011 ......................................................................................... 4-23

Figure 5-1. Historical U.S. Power Plant Capacity Additions, by Technology.......................... 5-4

Figure 5-2. Projected Levels of Electricity Demand in 2020, EPA and EIA........................... 5-12

Figure 5-3. Projected Natural Gas Prices in 2020, EPA and EIA (Delivered, Power Sector). 5-13

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

Technologies, EPA...................................................................................................... 5-16
ES-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 for Electric Utility Generating Units (herein referred to as EGU GHG NSPS).

ES.1 Background and Context of Proposed Rule

The proposed EGU GHG NSPS will limit greenhouse gas emissions (GHG) from new fossil 

fuel fired electric generating units (EGU) constructed in the United States in the future.1 This 

rulemaking will apply to carbon dioxide (CO2) emissions from new electric generating sources 

that exceed 25 megawatts (MW) in capacity. The United States Environmental Protection 

Agency (EPA) is proposing requirements for these sources because CO2 is a GHG and 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 66,518; Dec. 15, 2009) 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. This action is taken in response to a proposed 

settlement agreement entered into on December 23, 2010 to issue rules that will deal with

GHGs from certain fossil fuel-fired EGUs.

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

covers the regulation of new, modified, and reconstructed sources. For the purposes of this 

rule, a new source is one that commences construction after the publication of the proposed 

rule, other than those sources EPA has classified as “transitional” sources described later in this 

RIA. A reconstructed source is generally defined as an existing source that conducts extensive 

replacement of components and is treated as a new source under CAA section 111. A 

modification is any physical change in, or change in the method of operation of, 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.

EPA is not proposing a standard of performance for a group of sources it is calling 

transitional sources as long as they commence construction2 within 12 months from the date of 

 1 For purposes of this rule, covered EGUs do not include simple cycle combustion turbines. In addition, units 

subject to emission requirements under the CAA solid waste combustion provisions (Section 129) would not be 

subject to requirements under this proposed rule. 2 EPA’s regulations define “commenced construction” as, in general, undertaking a continuous program of 

construction or entering into a binding contract to do so (40 CFR 51.165).
ES-2

this proposal. Transitional sources are affected EGUs that have received approval for their 

complete Prevention of Significant Deterioration (PSD) preconstruction permits, but that have 

not “commenced construction” by the date of today’s proposed rulemaking. EPA is aware of 

approximately 15 transitional sources, six of which are expected to utilize carbon capture and 

sequestration (CCS) technology. 

CAA section 111(d) covers regulation of existing stationary sources that are not 

regulated under other parts of the CAA (i.e., pollutants regulated under NAAQS requirements 

or NESHAP requirements) and to which a new source performance standard (NSPS) would apply 

if such existing source were a new source. 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. EPA is currently examining options for developing CO2 emission guidelines that 

will be used by states to develop plans establishing standards of performance as required by 

CAA section 111(d). CAA Section 111 (b) requires that this standard be reviewed every eight 

years, thus this regulatory requirement will likely be reviewed and potentially revised after the 

2020 timeframe. Therefore, this economic analysis focuses on benefits and costs of this 

proposal for the years through 2020.

This proposed rule is 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 

international commitments. The impact of GHGs is global, and U.S. action to reduce GHG 

emissions complements ongoing programs and efforts in other countries.

ES.2 Summary of Proposed Rule

This proposal requires that all new fossil-fuel fired units that exceed 25 MW in capacity 

be able to meet an emission rate standard of 1,000 pounds of CO2 per megawatt hour (lbs 

CO2/MWh) calculated over a rolling 12-month period. It also proposes an alternative 

compliance option that would allow units to meet the 1,000 lbs CO2/MWh standard using a 30-

year averaging period. These standards could be met either by natural gas combined cycle 

(NGCC) generation with no additional GHG control or coal-fired generation using CCS. The base 

case modeling EPA performed for this rule (as well as modeling that EPA has performed for 

 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
ES-3

other recent air rules) project that, even in the absence of this action, new fossil-fuel fired 

capacity constructed through 2020 will most likely be natural gas combined cycle capacity. 

Alternatively, with available federal funding and appropriate market conditions, coal-fired 

capacity with CCS could also be built. Any projected combustion turbine capacity would not be 

affected by this rule. Analyses performed both by EPA and the U.S. Energy Information 

Administration (EIA)4 project that generation technologies other than coal (including natural gas 

and renewable sources) are likely to be the technology of choice for new generating capacity

due to current and projected economic market conditions. This means that technologies 

planned for new sources currently envisioned by owners and operators of EGUs will meet the

regulatory requirements of this NSPS or are not covered by the NSPS.

ES.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 

in the marketplace will lead electricity generators to choose technologies that meet the

proposed standards. Therefore, based on the analysis presented in Chapter 5, EPA anticipates

that the proposed EGU GHG NSPS will result in negligible CO2 emission changes, energy 

impacts, quantified benefits, costs, and economic impacts by 2020. Accordingly, 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 provides legal assurance that any new coal-fired plants must limit CO2

emissions. Rather than relying solely on changeable energy market conditions to provide low 

emissions from new power plants in the future, this rule prevents the possible construction of 

uncontrolled, high-emitting new sources that might continue to emit at high levels for decades, 

contributing to accumulation of CO2 in the atmosphere. In Chapter 5 of this RIA, we present a 

sensitivity analysis indicating that even in the unlikely event that market conditions change 

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

perspective of private investors, the level of avoided negative health and environmental effects 

expected would imply net social benefits from this proposed rule.

The rule will reduce regulatory uncertainty by defining section 111(b) requirements for 

limiting GHG from new EGU sources. In addition, EPA intends this rule to send a clear signal 

about the future of CCS technology that, in conjunction with other policies such as Department 

 4

 Annual Energy Outlook (AEO) 2009- 2012.
ES-4

of Energy (DOE) financial assistance, the agency estimates will support development and 

demonstration of CCS technology from coal-fired plants at commercial scale, if that financial 

assistance is made available and under the appropriate market conditions.

5

 Carbon capture 

also has the potential to help to improve U.S. energy production through enhanced oil 

recovery, as highlighted by a series of regional assessments conducted for DOE.6

 5

A number of the sources that EPA has identified as transitional sources have received some form of DOE financial 

assistance to demonstrate CCS. Several additional projects have received funding but have not yet received air 

permits. Beyond these projects, prospects for additional federal funding are dependent on the overall budget 

process. 6 U.S. Department of Energy. DOE web page, “Ten Basin-Oriented CO2-EOR Assessments Examine Strategies for 

Increasing Domestic Oil Production.,” Available online at: 

http://www.fossil.energy.gov/programs/oilgas/eor/Ten_Basin-Oriented_CO2-EOR_Assessments.html.
1-1

CHAPTER 1

INTRODUCTION AND BACKGROUND

1.1 Introduction

In this action, EPA seeks to address the climate and health effects of GHGs, specifically 

CO2, emitted from fossil fuel-fired electricity generating units. This document presents the 

expected economic impacts of the proposed EGU GHG NSPS rule through 2020. Based on the 

analysis presented in Chapter 5, expected and anticipated economic conditions will lead 

electricity generators to choose technologies that meet the standard. As a result, this proposed 

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.

1.2 Background

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 that GHGs meet the definition of an 

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

Act apply to GHGs. As a result, EPA must make decisions about whether to regulate GHGs under 

certain provisions of the Act, based on relevant statutory criteria. EPA issued a final 

determination that GHG emissions endanger public health and welfare in the Endangerment 

and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air 

Act (74 FR 66,496; Dec. 15, 2009). Because fossil fuel-fired EGUs contribute significantly to 

domestic CO2 emissions, EPA is proposing to regulate these emissions from EGU sources under 

section 111 of the CAA.

This action responds to a proposed settlement agreement EPA entered into in 

December 2010 to issue rules that will address greenhouse gas emissions from fossil fuel-fired 

power plants. Details of the settlement agreement can be found on the EPA website.1 This 

action addresses standards for new sources but does not address existing sources at this time. 

Existing sources will be addressed in a separate action at a later date by the EPA.

1.3 Regulatory Analysis 

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

for Preparing Economic Analyses, EPA prepared this RIA for this “significant regulatory action.” 

 1 http://www.epa.gov/airquality/ghgsettlement.html
1-2

This proposal 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, however, EPA has attempted to provide a thorough analysis of the potential impacts of 

this rule, consistent with requirements of the Executive Orders, and will continue to analyze the 

potential impacts of this rule between the proposed and final rule.

This RIA addresses the potential costs and benefits of the new source guidelines that are 

the focus of the proposed action. The proposed rule regulates new sources. EPA does not 

anticipate that any costs or quantified benefits will result from those parts of the standards. 

For new sources, EPA (and other energy modeling groups such as EIA2

) does 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 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 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 the proposal does not change these 

projections, it is expected to have no, or negligible, costs3 or quantified benefits associated with 

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

and environmental damages associated with representative new conventional coal and natural 

gas combined cycle units, under a range of natural gas price assumptions. That analysis, along 

with information on historical4 and projected5 gas prices, indicates that this standard is highly 

likely to have no costs or benefits; that there is some small probability that the standard 

 2 AEO 2009-2012. 3 Because of existing and anticipated trends in the marketplace, EPA does not project that any generators expected 

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

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 proposal should be 

negligible. Costs are only incurred if there has been a violation and a source chooses to take advantage of the 

affirmative defense, in which the source can show that the violation was caused by a malfunction and the 

source took necessary actions to minimize emissions. See Chapter 6 for more details on monitoring and 

reporting costs. 4 EIA. U.S. Natural Gas Prices. Available online at: http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm. 5

AEO 2009-2012. 
1-3

produces net benefits; and that the probability that the standard results in net costs to society 

is exceedingly low. 

1.4 Regulated Entities

This action will directly regulate CO2 emissions from EGUs with capacity greater than 25 

MW that commence construction after the issuance of this proposal.6

As described in the preamble, EPA does not have enough information on potential 

reconstructions in order to issue a standard at this time. As a result, in today’s action, the EPA is 

not including a proposal for reconstructions. Instead, we solicit comment on how we should 

approach reconstructions and, depending on the information we receive, we may propose and 

finalize a standard for reconstructions at a later time. Additionally, EPA does not have 

information indicating that affected EGUs would undertake modifications, and is thus not 

proposing any standards for modifications. EPA is taking comment on this and in the future may 

choose to set a standard for modifications that is different than that for existing sources. 

Finally, EPA is not proposing a standard of performance for transitional sources as long as they 

commence construction within 12 months from the date of this proposal.

1.5 Regulated Pollutant

This rule proposes to limit CO2 emissions from affected sources. EPA is proposing these 

requirements because CO2 is a GHG and power plants are the country’s largest stationary 

source emitters of GHGs. In 2009, 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.

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. 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.

 6 For purposes of this rule, covered EGUs do not include simple cycle combustion turbines. In addition, units 

subject to emission requirements under CAA section 129 would not be subject to requirements under this 

proposed rule.
1-4

1.6 Baseline and Years of Analysis

The rule on which this analysis is based proposes the requirement for new EGUs to 

achieve lower levels of GHG emissions. 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. 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 2020 and all estimates are 

presented in 2007$. Because we expect similar economic conditions leading up to the year of 

analysis, we also would not anticipate costs or benefits in any year prior to 2020. Any estimates

presented in this report represent annualized estimates of the benefits and costs of the 

proposed EGU GHG NSPS rather than the net present value of a stream of benefits and costs in 

these particular years of analysis.

1.7 Organization of the Regulatory Impact Analysis

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

effects of the proposed EGU GHG NSPS to fulfill the requirements of a Regulatory Impact 

Analysis. This RIA includes the following chapters:

 Chapter 2, Control Strategies, defines the source categories affected by the proposal 

and describes the control strategies and regulatory alternatives for these source 

categories.

 Chapter 3, Defining the Climate Change Problem and Rationale for the Rulemaking, 

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

proposal.

 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.
2-1

CHAPTER 2

CONTROL STRATEGIES 

2.1 Synopsis

This section defines the source categories affected by the proposal, outlines regulatory 

actions included in the analytical baseline, and describes the control strategies and regulatory 

alternatives for new, modified, reconstructed, and transitional sources. Existing EGU GHG 

sources are not addressed in this action, but will be the subject of a subsequent action by the 

EPA.

2.2 Definition of Affected Sources 

2.2.1 Electric Utility Generating Unit

For the purposes of this rule, the EPA is proposing to define an EGU as any fossil fuelfired combustion unit that has the potential to produce more than 25 MW electrical output and 

serves as a generator that produces electricity for sale, with the exception of simple cycle 

turbines. For this rule, the term EGU includes steam generating units (“boilers”), NGCC 

combustion turbines and their associated heat recovery steam generator (HRSG) and duct 

burners, and Integrated Gasification Combined Cycle (IGCC, "coal gasification") units – including 

their combustion turbines and associated HRSGs. A unit that cogenerates steam and electricity 

or that cogenerates feedstocks (e.g., hydrogen or hydrocarbons from an IGCC) for chemical or 

fuel production and supplies more than one-third of its potential electric output capacity and 

more than 25 MW output to any utility power distribution system for sale is also considered to 

be an EGU for the purposes of this rule. This rule does not cover simple cycle turbines.

2.2.2 New Sources

Sources affected by the new source provisions of the proposal are sources that are both 

considered “EGUs” and are considered “new” as defined by this rule. The general NSPS 

provisions (40 CFR Part 60) define a new source as one that begins construction (or 

reconstruction) after the date the provisions are proposed. 

CAA section 111(a)(2) defines a “new source” as “any stationary source, the 

construction or modification of which is commenced after publication of regulations (or, if 

early, proposed regulations) prescribing a standard of performance under [CAA section 111] 

which will be applicable to such source.” In contrast, CAA section 111(a)(6) defines an “existing 

source” as “any stationary source other than a new source.” The definition of a “new source” 

applies for purposes of this rulemaking, except that special considerations come into play for 
2-2

sources undertaking physical or operational changes (modified sources), transitional sources, 

and sources undertaking reconstruction.

2.2.3 Modified Sources

The EPA does not have a sufficient base of information to develop a proposal for the 

relatively few affected sources that may take actions that would constitute “modifications,” as 

defined under the EPA’s NSPS regulations, and therefore be subject to requirements for new 

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. More details on the approach for modified sources can be 

found in the preamble.

EPA is not proposing a standard of performance for modifications at this time. As a 

result, sources that undertake modifications will be treated as existing sources and thus not 

subject to the requirements proposed in this notice, although they would be subject to 

requirements that the EPA intends to propose separately for existing EGUs. The EPA is soliciting 

comment on the treatment of modified sources and, depending on the information received, 

may issue proposed standards of performance in the future. 

2.2.4 Transitional Sources

This proposed rule sets no standard for transitional sources, although these sources may 

be subject to an existing source standard in a subsequent rulemaking. In this proposal, EPA 

identifies transitional sources as those sources that have received permits to construct, but 

have not actually commenced construction. EPA believes that there are approximately 15 units 

that would be classified as transitional sources (see Appendix 2A for a list of potential 

transitional units). EPA is proposing that as long as these units commence construction within 

one year of the effective date of this proposal, these sources will be classified as transitional 

sources for the purposes of this rule and will not be subject to the NSPS.

Historically, obtaining a permit does not guarantee that a unit will be constructed. In 

the last 10 years, 85 coal plants have been permitted. Of those, 40 (or less than half) have 
2-3

actually commenced construction. Thirty projects have been cancelled and approximately 15

sources (the transitional sources) have active permits. EPA notes that many variables in 

addition to permitting appear to contribute to the likelihood of project completion. Based on

this history and current economic conditions in particular, not all units are likely to proceed. 

EPA believes the transitional units that are most likely to commence construction are 

those that have received government incentives to install CCS. These units would be able to 

commence construction within the proposed rule time-frame. 

2.2.5 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 could meet the requirements for 

a reconstruction. In light of this limited experience concerning reconstructions, the Agency lacks

adequate information that is needed to propose a standard of performance for reconstructions. 

As a result, in today’s action, the EPA is not including a proposal for reconstructions. Instead, 

we solicit comment on how we should approach reconstructions and, depending on the 

information we receive, we may propose and finalize a standard for reconstructions at a later 

time. EPA is soliciting comment on the type of source that will undertake reconstruction; the 

type of changes; the extent of emissions increases; and the type of control measures, including 

their cost and emissions reductions.

2.2.6 Existing Sources 

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

combustion unit that has the potential to produce more than 25 MW output and serves a 

generator that produces electricity for sale and was in operation or commenced construction 

on or before publication of this proposed rule. Existing sources are not covered in this 

proposed action, but will be addressed in a subsequent rulemaking by the EPA.
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2.3 Control Strategies

This proposal requires that all new fossil-fuel fired units with greater than 25 MW

capacity be able to meet an emission rate standard of 1,000 lb CO2/MWh calculated over a 

rolling 12-month period. It also proposes an alternative compliance option that would allow 

units to meet the 1,000 lb CO2/MWh standard using a 30-year averaging period. These 

standards could be met by NGCC generation with no additional GHG control or coal-fired 

generation using carbon capture and sequestration technology. 

2.4 Analytical Baseline 

EPA used IPM v.4.10 to assess the baseline conditions described for the proposed new 

source performance standards. IPM is a dynamic linear programming model that can be used 

to examine the economic impacts of air pollution control policies for CO2 and other air 

pollutants throughout the contiguous U.S. for the entire power system. The modeling 

conducted for this proposal is discussed more extensively in Chapter 5 of this RIA. 

Documentation for IPM can be found in the docket for this rulemaking or at 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html. For more information on the 

analytical baseline see Chapter 5 of this report.

2.5 Emission Reductions 

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

proposed EGU GHG NSPS will result in negligible changes in GHGemissions over the analysis 

period (through 2020). 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. Likewise, we anticipate that this rule will have negligible costs, 

quantified benefits, and impacts on the price of electricity, labor markets, or the economy. 
2A-1

APPENDIX 2A

POTENTIAL TRANSITIONAL UNITS

Plant Name Size CO2 Mitigation Plan Location

Trailblazer 600 MW CCS – EOR (supercritical PC) TX

Taylorville 602 MW CCS – EOR/Geologic (IGCC) IL

Texas Clean Energy 

Project 400 MW CCS – EOR (IGCC) TX

Cash Creek Generation 761 MW CCS - IGCC KY

Power County Advanced 

Energy Center 520 MW CCS – EOR (IGCC) ID

Good Spring 270 MW CCS – IGCC PA

Limestone 3 750 MW Agreement to capture or offset 50% of 

CO2 (subcritical PC) – CCS ready TX

Holcomb 2 895 MW None (supercritical PC) KS

White Stallion 1320 MW None (subcritical CFB) TX

James De Young 78 MW None (subcritical CFB) MI

Wolverine 600 MW None (subcritical CFB) – CCS ready MI

Coleto Creek 650 MW None (supercritical PC) – CCS ready TX

Washington County 850 MW None (supercritical PC) GA

Bonanza 110 MW None (subcritical CFB, waste coal) UT

Two Elk 250 MW None (subcritical PC, waste coal) – CCS 

ready WY

Note: This table does not reflect an official list of transitional sources, but instead reflects sources that could potentially be 

considered transitional under the proposed regulation.

PC = pulverized coal

CCS = carbon capture and storage

CFB = circulating fluidized bed

EOR = enhanced oil recovery

IGCC = integrated gasification combined cycle
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CHAPTER 3

DEFINING THE CLIMATE CHANGE PROBLEM AND RATIONALE FOR RULEMAKING

3.1 Overview of Climate Change Impacts from GHG Emissions

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 EPA to regulate 

greenhouse gases from EGU sources. This proposed rule is designed to minimize emissions of 

greenhouse gases, minimize the rate of increase of concentrations of these gases, and 

therefore reduce the risk of adverse effects. As the analysis presented in Chapter 5 shows, 

existing and anticipated economic conditions in the marketplace will lead electricity generators 

to choose technologies that meet the proposed standards. However, rather than relying solely 

on changeable energy market conditions to provide low emissions from new power plants in 

the future, though this rule, EPA ensures that new electricity generation will be clean 

generation. 

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, 

air quality effects, 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 estimated 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 already occur. Heat waves are associated with 

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

 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).
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increased morbidity. The projected warming is therefore projected to increase heat related 

mortality and morbidity, especially among the elderly, young, and frail. The populations most 

sensitive to hot temperatures are older adults, the chronically sick, the very young, citydwellers, those taking medications that disrupt thermoregulation, 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 serious. 

Increases in temperature are also expected to lead to some reduction in the risk of 

death related to extreme cold. 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 effects of season and influenza, which is not strongly associated with 

monthly winter temperature. In addition, 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. 

The study concludes that increases in heat-related mortality due to global warming in the 

United States are unlikely to be compensated for by decreases in cold-related mortality. 

Regarding air quality effects, increases in regional ozone pollution relative to ozone 

levels without climate change are expected due to higher temperatures and weaker circulation 

in the United States relative to air quality levels without climate change. Climate change is 

expected to increase regional ozone pollution, 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 species composition. 

Modeling studies discussed in EPA’s Interim Assessment (2009) show that simulated 

climate change causes increases in summertime ozone concentrations over substantial regions 

of the country, though this was not uniform, and some areas showed little change or decreases, 

though the decreases tend to be less pronounced than the increases. For those regions that 

showed climate-induced increases, the increase in maximum daily 8-hour average ozone 

concentration, a key metric for regulating U.S. air quality, was in the range of 2 to 8 ppb, 

averaged over the summer season. The increases were substantially greater than this 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 
3-3

without this climate change, over broad areas of 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. Flood health impacts include deaths, injuries, infectious diseases, 

intoxications, and mental health problems. 

Increases in tropical cyclone intensity are linked to increases in the risk of deaths, 

injuries, waterborne and food borne diseases, as well as post-traumatic stress disorders. 

Drowning by storm surge, heightened by rising sea levels and more intense storms (as 

projected by IPCC), is the major killer in coastal storms where there are large numbers of 

deaths. Flooding 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 several 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, and 

the range of some zoonotic disease carriers such as the Lyme disease carrying tick may increase 

with temperature. 

Climate change, including changes in carbon dioxide 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 
3-4

illnesses in the United States. It has generally been observed that the presence of elevated 

carbon dioxide concentrations 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 carbon dioxide. 

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 sectors. 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 carbon dioxide concentrations can 

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

that results. However, elevated carbon dioxide 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 

effects associated with the average change in 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 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. Although water management practices in the United States are 

generally advanced, particularly in the West, the reliance on past conditions as the basis for 
3-6

current and future planning may no longer be appropriate, as climate change increasingly 

creates conditions well outside of historical observations. Increased incidence of extreme 

weather and floods may also 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 to climate variability and future climate 

change in coastal areas. 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. Coastal habitats will likely be increasingly stressed by 

climate change impacts interacting with development and pollution. 

Although increases in mean sea level over the 21st century and beyond will 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 for storm surges to build upon 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 return 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. 
3-7

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 

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 1–3 °C are projected to result in more frequent 

coral bleaching events and widespread 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 
3-8

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 

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 the Arctic, because of the effects of high rates of projected 

warming on natural systems; 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; and Asian mega-deltas 

due to large populations and high exposure to sea level rise, storm surge, and river flooding. 

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.

3.1.3 Recent Assessments

Since the Endangerment Finding was released, more recent assessments have produced 

similar conclusions to those of the assessments upon which the Finding was based. In May 

2010, the NRC published its comprehensive assessment, “Advancing the Science of Climate 

Change” (2010). It concluded that “climate change is occurring, is caused largely by human 

activities, and poses significant risks for — and in many cases is already affecting — a broad 

range of human and natural systems.” Furthermore, the NRC stated that this conclusion is 

based on findings that are “consistent with the conclusions of recent assessments by the U.S. 

 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

Global Change Research Program, the Intergovernmental Panel on Climate Change’s Fourth 

Assessment Report, and other assessments of the state of scientific knowledge on climate 

change.” These are the same assessments that served as the primary scientific references 

underlying the Administrator’s Endangerment Finding. Another NRC assessment, “Climate 

Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia,” was 

published in 2011. This report found that climate change due to carbon dioxide emissions will 

persist for many centuries. The report also estimate a number of specific climate change 

impacts, finding that every degree Celsius of warming could lead to increases in the heaviest 15 

percent of daily rainfalls of 3 to 10 percent, decreases of 5 to 15 percent in yields for a number 

of crops (absent adaptation measures that do not presently exist), decreases of Arctic sea ice 

extent of 25 percent in September and 15 percent annually averaged, along with changes in 

precipitation and stream flow of 5 to 10 percent in many regions and river basins. The 

assessment also found that for an increase of 4 degrees C nearly all land areas would 

experience average summers warmer than all but 5 percent of summers in the 20th century, 

that for an increase of 1 to 2 degrees C the area burnt by wildfires in western North America 

will likely more than double, that coral bleaching and erosion will increase due both to warming 

and ocean acidification, and that sea level will rise 1.6 to 3.3 feet by 2100 in a 3 degree C 

scenario. The assessment notes that many important aspects of climate change are difficult to 

quantify but that the risk of adverse impacts is likely to increase with increasing temperature, 

and that the risk of surprises can be expected to increase with the duration and magnitude of 

warming.

In the 2010 report cited above, the NRC stated that some of the largest potential risks 

associated with future climate change may come not from relatively smooth changes that are 

reasonably well understood, but from extreme events, abrupt changes, and surprises that 

might occur when climate or environmental system thresholds are crossed. Examples cited as

warranting more research include the release of large quantities of GHGs stored in permafrost 

(frozen soils) across the Arctic, rapid disintegration of the major ice sheets, irreversible drying 

and desertification in the subtropics, changes in ocean circulation, and the rapid release of 

destabilized methane hydrates in the oceans.

On ocean acidification, the same report noted the potential for broad, “catastrophic” 

impacts on marine ecosystems. Ocean acidity has increased 25 percent since pre-industrial 

times, and is projected to continue increasing. By the time atmospheric CO2 content doubles

over its preindustrial value, there would be virtually no place left in the ocean that can sustain 
3-10

coral reef growth. Ocean acidification could have dramatic consequences for polar food webs 

including salmon, the report said.

Importantly, these recent NRC assessments represent another independent and critical 

inquiry of the state of climate change science, separate and apart from the previous IPCC, NRC,

and USGCRP assessments.

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.

Karl, T., J. Melillo, and T. Peterson (Eds.) (2009). Global Climate Change Impacts in the United 

States. Cambridge University Press, Cambridge, United Kingdom.

Medina-Ramon, M. and J. Schwartz, 2007: Temperature, temperature extremes, and mortality: 

a study of acclimatization and effect modification in 50 U.S. cities. Occupational and 

Environmental Medicine, 64(12), 827-833.

National Research Council (2010). Advancing the Science of Climate Change. National Academy 

Press. Washington, DC.

National Research Council (2011). Climate Stabilization Targets: Emissions, Concentrations, and 

Impacts over Decades to Millennia. National Academy Press, Washington, DC.

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.
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CHAPTER 4

ELECTRIC POWER SECTOR PROFILE

4.1 Introduction

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

proposed EGU GHG NSPS, 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 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 involves creating heat to rotate turbines 

which, in turn, create electricity. The power sector consists of over 17,000 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.
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Table 4-1. Existing Electricity Generating Capacity by Energy Source, 2009

Energy Source

Number of 

Generators

Generator 

Nameplate 

Capacity (MW)

Generator Net 

Summer 

Capacity (MW)

Average 

Capacity 

Factor

Coal 1,436 338,723 314,294 63.8%

Petroleum 3,757 63,254 56,781 7.8%

Natural Gas 5,470 459,803 401,272 42.2%

Other Gases 98 2,218 1,932 10.1%

Nuclear 104 106,618 101,004 90.3%

Hydroelectric Conventional 4,005 77,910 78,518 39.8%

Wind 620 34,683 34,296 N/A

Solar Thermal and Photovoltaic 110 640 619 N/A

Wood and Wood Derived Fuels 353 7,829 6,939 N/A

Geothermal 222 3,421 2,382 N/A

Other Biomass 1,502 5,007 4,317 N/A

Pumped Storage 151 20,538 22,160 N/A

Other 48 1,042 888 N/A

Total 17,876 1,121,686 1,025,400 44.9%

Source: EIA 2009

Note: Average capacity factors not available for EIA’s 2010 Electric Power Annual. Additionally, EIA does not 

calculate average capacity factors for all energy sources presented in the table. 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 2010 (Billion kWh)

Sales/Direct Use 

(Billion kWh) Share of Total End Use

Retail Sales

Residential 1,445 37.2%

Commercial 1,330 34.2%

Industrial 971 25.0%

Transportation 8 0.2%

Direct Use 135 3.5%

Total End Use 3,889 100%

Source: EIA 2010a

In 2010, electric generating sources produced 4,125 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 2010 (Billion kWh)

Net Generation (Billion kWh) Fuel Source Share

Coal 1,847 44.8%

Petroleum 37 0.90%

Natural Gas 988 23.9%

Other Gases 11 0.3%

Nuclear 807 19.6%

Hydroelectric 260 6.3%

Other 175 4.2%

Total 4,125 100%

Source: EIA 2010a

Note: 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 

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 typically supplies “peak” 

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 relatively low natural gas prices, have resulted in more gas being utilized as base 

load energy. 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.
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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 US and Canada, there are three separate interconnected networks of 

high voltage transmission lines,

1 each operating at a common frequency. 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 business.

Transmission has generally been developed by the larger vertically integrated utilities 

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

number of utilities that often 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 
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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). Another 18 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 2010b. 

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 2009, 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 

tons of CO2 equivalent)

Implied Sectors 1990 1995 2000 2005 2009

Electric Power Industry 1,869 1,995 2,338 2,445 2,193

Transportation 1,545 1,695 1,932 2,017 1,812

Industry 1,564 1,591 1,544 1,442 1,323

Agriculture 429 465 485 493 490

Commercial 396 397 381 387 410

Residential 345 367 386 371 360

U.S. Territories 34 41 46 58 46

Total Emissions 6,182 6,551 7,113 7,214 6,633

Source: EPA 2011

Figure 4-3. Domestic Emissions of Greenhouse Gases, 2009 (million metric tons of CO2

equivalent)

Source: EPA 2011
4-9

Table 4-6. Electricity Generation-Related Greenhouse Gas Emissions, 2009 (million metric 

tons of CO2 equivalent)

Source Total Emissions

CO2 2,170.1

CO2 from Fossil Fuel Combustion 2,154.0

Coal 1,747.6

Natural Gas 373.1

Petroleum 32.9

Geothermal 0.4

Incineration of Waste 12.3

Limestone and Dolomite Use 3.8

CH4 0.7

Stationary Combustion* 0.7

Incineration of Waste +

N2O 9.4

Stationary Combustion* 9.0

Incineration of Waste 0.4

SF6

** 12.8

Electrical Transmission and Distribution 12.8

Total 2,193.0

Source: EPA 2011

* 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 and 

1.25 times as much as oil (EPA 2011).
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Figure 4-4. GHG Emissions from the Power Sector Relative to Total Domestic GHG Emissions 

(2009)

Source: EPA 2011

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).
4-11

4.5 Pollution Control Technologies

There are several methods to reduce CO2 emissions from the power sector, including 

carbon capture and storage and improved fuel efficiency, which are discussed in more detail in 

the following sections. Additional methods for CO2 reduction include switching to loweremitting fuels, increased generation share from lower-emitting sources, decreased loss of 

power via transmission and distribution systems, and improved end-use efficiency lowering 

electricity demand for the same level of service provided. The first three strategies are within 

the sphere of a generator’s decision-making, whereas the latter two strategies are only 

indirectly related to generators. The fourth strategy is an inherent property of the power 

system responding to the implicit value of emissions as grid operators make dispatch decisions 

to meet electricity demand at least cost (including the cost of harmful emissions). Increased 

construction of natural gas-fired EGU capacity will increase the number of lower-emitting 

sources from which grid operators may select to meet electricity demand.

4.5.1 Carbon Capture and Storage (CCS)

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. For post-combustion 

capture, flue gas CO2 stripping with 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.
4-12

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 the carbon 

contained in the syngas is captured before combustion. These processes are energy intensive. 

For post-combustion, a station's net generating output will be notably lower due to the energy 

needs of the capture process. For pre-combustion technology, a significant amount of energy is 

needed to gasify the fuel(s). This process is illustrated in Figure 4-6. For more detail on the 

current state of CCS technology, see the “Report of the Interagency Task Force on Carbon 

Capture and Storage” (2010).

Figure 4-5. Post-Combustion CO2 Capture for a Pulverized Coal Power Plant
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Source: Interagency Task Force on Carbon Capture and Storage 2010

4.5.2 Thermal Efficiency Improvements

As the thermal (i.e. fuel) efficiency of a coal-fired EGU is increased, less coal is burned 

per kilowatt-hour (kWh) generated, and there is a corresponding decrease in CO2 and other 

emissions per unit of energy generated. Numerous alternatives are available for improving 

generating unit efficiency (Sargent & Lundy, 2009). Regular maintenance can achieve and 

sustain optimal operational conditions, such as minimizing leakage of heat, assuring all 

components are operating optimally, maintaining furnace operation near peak efficiency, 

ensuring furnace soot removal system are functioning properly, and repairing tube leaks. 

Efficiency gains can also be achieved through replacement of inefficient or obsolete equipment, 

which can reduce parasitic power loads.2 There are many small actions that can be undertaken 

which, cumulatively, can result in notable efficiency improvements. Such improvements include 

optimizing air pre-heaters, installing heat recovery systems, reducing steam leaks, and

refurbishing the steam turbine. In a 2010 white paper, EPA summarized the efficiency 

 2 Reducing parasitic power loads increases the amount of generation for sale and therefore, where economical, 

plant managers have an incentive to avoid these losses. However, reducing these loads does not necessarily 

lower the gross CO2 emission rate of a plant, and therefore the structure of the proposed rule may not 

significantly increase the incentive to reduce these losses.

Figure 4-6. Pre-Combustion CO2 Capture for an IGCC Power Plant
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improvement techniques identified by the National Energy Technology Laboratory (NETL) 

through a review of published articles and technical papers (EPA, 2010). The summary of these 

findings is shown in Table 4-8.

Table 4-8. Existing Coal-Fired EGU Efficiency Improvements Reported for Actual Efficiency 

Improvement Projects

Efficiency 

Improvement 

Technology

Description

Reported

Efficiency

Increasea

Combustion 

Control 

Optimization

Combustion controls adjust coal and air flow to optimize steam production 

for the steam turbine/generator set. The technologies include instruments 

that measure carbon levels in ash, coal flow rates, air flow rates, CO levels, 

oxygen levels, slag deposits, and burner metrics as well as advanced coal 

nozzles and plasma assisted coal combustion. Combustion control for a coalfired EGU is complex and impacts a number of important operating 

parameters including combustion efficiency, steam temperature, furnace 

slagging and fouling, and NOx formation. 

0.15 to 0.84%

Cooling System 

Heat Loss 

Recovery

Controls are applied to recover a portion of the heat loss from the warm 

cooling water exiting the steam condenser prior to its circulation thorough a 

cooling tower or discharge to a water body. The identified technologies 

include replacing the cooling tower fill (heat transfer surface) and tuning the 

cooling tower and condenser.

0.2 to 1%

Flue Gas Heat 

Recovery

Flue gas exit temperature from the air pre-heater can range from 250- 350°F 

depending on the acid dew point temperature of the flue gas, which is 

dependent on the concentration of vapor phase sulfuric acid and moisture. 

For power plants equipped with wet FGD systems, the flue gas is further 

cooled to approximately 125°F as it is sprayed with the FGD reagent slurry. 

However, it may be possible to recover some of this lost energy in the flue 

gas to preheat boiler feedwater via use of a condensing heat exchanger.

0.3 to 1.5%

(continued)
4-15

Table 4-8. Existing Coal-Fired EGU Efficiency Improvements Reported for Actual Efficiency 

Improvement Projects (continued)

Efficiency 

Improvement 

Technology

Description

Reported

Efficiency

Increasea

Low-rank Coal 

Drying

Subbituminous and lignite coals contain relatively large amounts of moisture 

(15 to 40%) compared to bituminous coal (less than 10%). A significant 

amount of the heat released during combustion of low-rank coals is used to 

evaporate this moisture, rather than generate steam for the turbine. As a 

result, boiler efficiency is typically lower for plants burning low-rank coal. 

The technologies include using waste heat from the flue gas and/or cooling 

water systems to dry low-rank coal prior to combustion.

0.1 to 1.7%

Soot Blower

Optimization

Soot blowers intermittently inject high velocity jets of steam or air to clean 

coal ash deposits from boiler tube surfaces in order to maintain adequate 

heat transfer. Proper control of the timing and intensity of individual soot 

blowers is important to maintain steam temperature and boiler efficiency. 

The identified technologies include intelligent or neural-network soot 

blowing (i.e., soot blowing in response to real-time conditions in the boiler) 

and detonation soot blowing.

0.1 to 0.65%

Steam Turbine

Design

Recoverable energy losses can result from the mechanical design or physical 

condition of the steam turbine. For example, steam turbine manufacturers 

have improved the design of turbine blades and steam seals which can 

increase both efficiency and output (i.e., steam turbine dense pack 

technology).

0.84 to 2.6%

Source: EPA 2010, NETL 2008

a Reported efficiency improvement metrics adjusted to common basis by conversion methodology assuming 

individual component efficiencies for a reference plant as follows: 87 percent boiler efficiency, 40 percent

turbine efficiency, 98 percent generator efficiency, and 6 percent auxiliary load. Based on these assumptions, 

the reference power plant has an overall efficiency of 32 percent and a net heat rate of 10,600 Btu/kWh. As a 

result, if a particular efficiency improvement method was reported to achieve a 1 percentage point increase in 

boiler efficiency, it would be converted to a 0.37 percentage point increase in overall efficiency. Likewise, a 

reported 100 Btu/kWh decrease in net heat rate would be converted to a 0.30 percentage point increase in 

overall efficiency.

In addition to the techniques described above, new coal-fired EGU projects may use 

other methods to maximize thermal efficiency. Under constant energy input, a higher pressure 

and temperature for the water-steam cycle will increase the overall efficiency. Most existing 

boilers, however, are already operating at the maximum pressure and temperature that the

boiler is designed to withstand. Most existing coal-fired EGUs have subcritical boilers that 

typically operate at a pressure of 2,400 pounds per square inch (psi) and temperatures between 

1,000 to 1,050°F. “Supercritical” boilers are those that use steam pressures above 3200 psi and 

temperatures up to 1,100°F. Boilers that can operate above these conditions are considered 
4-16

“ultra-supercritical.” Examples of ultra-supercritical coal-fired EGUs in Canada, Europe, and 

Japan are cited as representing the highest efficiency coal-fired EGUs in the world (EPA, 2010). 

4.5.3 Other Approaches to Reduce GHG Emissions

While CCS and fuel efficiency improvements are more closely related to potential NSPS 

regulatory frameworks, they are not the only options available for EGUs to reduce emissions of 

CO2. As discussed previously, the amount of CO2 emitted during the combustion of fossil fuels 

varies according to the carbon content and heating value of the fuel used (see Table 4-7). 

Switching from a higher-emitting to a lower-emitting fuel will reduce CO2 emissions from an 

EGU, all other things equal. Similarly, increasing the share of generation from lower-emitting 

sources will also lead to a reduction in CO2 emissions. As with increased generation efficiency, 

improvements to efficiency in transmission and electricity use will also result in reductions in 

CO2 emissions. Note that these types of strategies would further reduce need for construction 

of new units. 

4.6 GHG Regulation in the Power Sector

In April 2007, the Supreme Court concluded that GHGs met the CAA definition of an air 

pollutant, giving EPA the authority to regulate GHGs under the CAA based on the 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.

In response to the FY2008 Consolidated Appropriations Act (H.R. 2764; Public Law 110–

161), EPA issued the Mandatory Reporting of Greenhouse Gases Rule (74 FR 5620) which 

required reporting 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, only that sources above certain threshold levels monitor and report 

emissions.

In August 2007, EPA issued a 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. EPA 

acknowledged the Supreme Court decision, but found that decision alone did not require PSD 
4-17

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 EPA to 

reconsider “whether or not to impose a CO2 BACT 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 EPA under the CAA that requires actual control of emissions of that 

pollutant. The memo further explained that pollutants for which 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 EPA for reconsideration, prompting 

the agency to issue a revised finding in March 2009. After reviewing comments, 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, it 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 

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 industry or other entities, but allowed EPA to 

regulate greenhouse gases under the Clean Air Act. 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 Clean Air Act, it is 

subject to permitting requirements under the PSD and Title V programs.
4-18

In May 2010, EPA issued the final Tailoring Rule which set thresholds for GHG emissions 

that define when permits under the New Source Review PSD 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.

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. For natural gas, oil, and coal-fired EGUs this rule establishes NSPS for new and 

reconstructed sources, with the exception of combustion turbines. Existing source standards 

will be addressed in a later action. Details of the settlement agreements can be found on the 

EPA website.3

4.7 Revenues, Expenses, and Prices

Due to lower retail electricity sales, total utility operating revenues declined in 2009 to 

$276 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008 

levels in 2010, operating expenses were appreciably lower and as a result, net income also rose 

in comparison to both 2008 and 2009 (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 

electricity are expected to rebound and increase modestly by 2015, when revenues are 

projected to be roughly $360 billion (see Table 4-10).

Table 4-9 shows that investor-owned utilities (IOUs) earned income of about 11.5

percent compared to total revenues in 2009. Based on EIA's Annual Energy Outlook 2011, Table 

4-10 shows that the power sector is projected to derive revenues of $360 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 2009, 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 

 3 http://www.epa.gov/airquality/ghgsettlement.html
4-19

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 4-7).

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

for 2010 ($millions)

2008 2009 2010

Utility Operating Revenues 298,962 276,124 284,373

Electric Utility 266,124 249,303 260,113

Other Utility 32,838 26,822 24,260

Utility Operating Expenses 267,263 244,243 250,122

Electric Utility 236,572 219,544 226,845

Operation 175,887 154,925 159,585

Production 140,974 118,816 128,808

Cost of Fuel 47,337 40,242 44,115

Purchased Power 84,724 67,630 67,284

Other 8,937 10,970 13,013

Transmission 6,950 6,742 6,948

Distribution 3,997 3,947 4,007

Customer Accounts 5,286 5,203 5,091

Customer Service 3,567 3,857 4,741

Sales 225 178 185

Admin. and 

General 14,718 15,991 17,115

Maintenance 14,192 14,092 14,962

Depreciation 19,049 20,095 20,930

Taxes and Other 26,202 29,081 27,646

Other Utility 30,692 24,698 23,277

Net Utility Operating Income 31,699 31,881 34,251

Source: EIA 2010a

Note: This data does not include information for public utilities.
4-20

Table 4-10. Projected Revenues by Service Category in 2015 for Public Power and InvestorOwned Utilities (billions)

Generation $195

Transmission 36

Distribution 129

Total $360

Source: EIA 2011

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 2011 (Electricity 

Supply, Disposition, Prices, and Emissions).

Figure 4-7. National Average Retail Electricity Price (1960 – 2009)

Source: EIA 2010a

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 4-8).
4-21

Figure 4-8. Average Retail Electricity Price by State (cents/kWh), 2009

Source: EIA 2009

4.7.1 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 $3 per mmBtu to as high as $9 on an annual average basis (see 

Figure 4-9). During that time, the daily price of natural gas reached as high as $15/mmBtu.

Recent forecasts of natural gas 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.

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.

4 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, 

 4 AEO 2010c.
4-22

which address many of the uncertainties inherent in the long-term projections. EPA uses the 

reference case and a number of alternative cases in its analyses.

Figure 4-9. Natural Gas Spot Price, Annual Average (Henry Hub)

Source: EIA 2010d, EIA 2011, EIA 2012

4.8 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 (GDP) per unit of 

energy input, with per capita energy use fairly constant over the past 30 years (EIA, 2010e). The 

growth rate of electricity demanded has also been in overall decline for the past sixty years (see 

Figure 4-8), 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. 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 consumption. Fourth, other policies, such as

energy efficiency standards at the state and Federal level, have helped address certain market 

0

1

2

3

4

5

6

7

8

9

10

1990 1995 2000 2005 2010 2015 2020 2025 2030 2035

2007 dollars per million Btu

EIA Historical Natural Gas Spot Price (Henry Hub)

EIA Projected (2011) Natural Gas Spot Price (Henry Hub)

EIA Projected (2012) Natural Gas Spot Price (Henry Hub)

EIA Projected (2010) Natural Gas Spot Price (Henry Hub)
4-23

failures. These broader changes have altered the outlook for future electricity growth (see 

Figure 4-10). 

Figure 4-10. Electricity Growth Rate (3 Year Rolling Average) and Projections from the Annual 

Energy Outlook 2011

Source: EIA 2009, EIA 2011

Note: Electricity demand projections in the AEO 2012 early release are very similar to those in AEO 2011 and would 

not be expected to change this figure noticeably.

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.5 These 

investments, and other energy efficiency policies at both the state and federal level, create 

incentives to reduce energy consumption and peak load. According to EIA, demand-side 

management provided actual peak load reductions of 31.7 GW in 2009. For context, the current 

coal fleet is roughly 320 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, EPA modeling does not typically incorporate a “demand 

response” in its electric generation modeling (Chapter 5) to the increases in electricity prices 

 5 To the extent that EIA includes these measures in its baseline forecast from the Annual Energy Outlook, EPA has 

also incorporated them into the baseline for purposes of assessing the economic impacts of this proposed rule. 

See AEO 2011 and Chapter 7 of the IPM documentation for more detail.

-2%

0%

2%

4%

6%

8%

10%

12%
4-24

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 EPA estimates for rules where compliance 

costs are anticipated for a rulemaking. Note that this NSPS is not anticipated to create 

compliance costs for new EGU sources. 

4.9 References

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.

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. 

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.

Sargent & Lundy, LLC. Coal-fired Power Plant Heat Rate Reductions. January 2009. Available 

online at: http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf.

U.S. Energy Information Administration (U.S. EIA). Carbon Dioxide Emissions from the 

Generation of Electric Power in the United States. July 2000. Available online at: 

ftp://ftp.eia.doe.gov/environment/co2emiss00.pdf.

U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2003. 2003. Available 

online at: http://www.eia.gov/electricity/annual/archive/03482003.pdf.

U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2009. 2009. Available 

online at: http://www.eia.gov/electricity/annual/archive/03482009.pdf. 

U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2010. 2010a. Available 

online at: http://www.eia.gov/electricity/annual/.

U.S. Energy Information Administration (U.S. EIA). “Status of Electricity Restructuring by State.” 

2010b. Available online at: 

http://www.eia.gov/cneaf/electricity/page/restructuring/restructure_elect.html.
4-25

U.S. Energy Information Administration (U.S. EIA). AEO 2010 Retrospective Review. 2010c. 

Available online at: http://www.eia.gov/forecasts/aeo/retrospective/. 

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010d. 

Available online at: http://www.eia.gov/oiaf/archive/aeo10/index.html. 

U.S. Energy Information Administration (U.S. EIA). Annual Energy Review 2010. 2010e. 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. Environmental Protection Agency (U.S. EPA). Available and Emerging Technologies for 

Reducing Greenhouse Gas Emissions from Coal-Fired Electric Generating Units. October 

2010. Available online at: http://www.epa.gov/nsr/ghgdocs/electricgeneration.pdf. 

U.S. Environmental Protection Agency (U.S. EPA). Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990–2009. April 2011. Available online at: 

http://epa.gov/climatechange/emissions/downloads11/US-GHG-Inventory-2011-

Complete_Report.pdf. 
5-1

CHAPTER 5

COSTS, BENEFITS, ECONOMIC, AND ENERGY IMPACTS

5.1 Synopsis

This chapter reports the compliance cost, economic, and energy impact analysis 

performed for the EGU GHG NSPS. EPA used IPM, developed by ICF Consulting, in this analysis. 

IPM is a dynamic linear programming model that can be used to examine air pollution control 

policies throughout the United States for the entire power system. EPA used the IPM model to 

forecast likely future electricity market conditions with and without the proposed rule.

Even in a baseline scenario without the proposed rule, the only capacity additions 

subject to this rule projected during the analysis period (through 20201) are compliant with the 

requirements of this rule (e.g., combined cycle natural gas and small amounts of coal with CCS 

supported by DOE funding). This conclusion also holds for several sensitivity analyses EPA 

performed. As a result, under a wide range of future electricity market conditions, this 

proposed EGU GHG NSPS is not expected to change GHG emissions for newly constructed 

EGUs, and is anticipated to impose negligible costs, economic impacts, or energy impacts on the 

EGU sector or society. An additional illustrative analysis, presented at the end of this chapter, 

indicates that even in the unlikely event that electricity market conditions change enough to 

support additional new coal, the proposed EGU GHG NSPS would provide net benefits. This 

analysis concluded based on sensitivity analyses that the price of natural gas would have to 

increase to approximately $10/mmBtu for coal boilers without CCS to become competitive with 

combined cycle natural gas units, which is projected to be very unlikely.2

5.2 Background

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 mix of new, and utilization of 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 

 1 Note that while the analysis presented in this RIA is for the year 2020, IPM projections were also made for 2030 

and are available in the docket. 2 This chapter presents all costs in 2007$.
5-2

does not forecast the construction of any new unplanned coal-fired additions over the time 

horizon of this analysis (through the year 2020). For more detailed discussion of this forecast, 

see section 5.5.

Under current and foreseeable future market conditions affecting new capacity 

additions, gas-fired generating technologies can produce electricity at a lower levelized cost 

than coal-fired generating technologies, and therefore utilities are expected to rely heavily on 

combustion turbines and combined cycle plants using natural gas when they do need to expand 

capacity during the time horizon considered for this analysis. 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 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.

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 
5-3

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.3

Based on these market conditions, and detailed analysis and modeling conducted by 

EPA, the levelized cost of generation from a new natural gas power plant is expected to be

lower on average than the levelized cost of generation from a new coal-fired power plant.4,5 

This trend has already been observed recently, as natural gas-fired capacity has been the 

technology of choice for power generation over the last few years (see Figure 5-1).

 3 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 4 See Table 5-4, which reports the levelized cost of new generation in the Annual Energy Outlook (AEO) 2011. 5 Note that EPA’s analysis, which is consistent with this expectation, is based on sophisticated IPM modeling, and is 

not based on simplified LCOE assumptions.
5-4

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

Source: National Electric Energy Data System (NEEDS) v4.10_PTox 

Note: Renewables include geothermal, biomass, solar, and wind energy technologies. A considerable amount of 

renewables were built in 2009 and 2010, and these are reflected in EPA modeling applications but not necessarily 

in NEEDS. 

Numerous energy sector modeling efforts, including recent projections from EIA, have 

provided results that are consistent with these findings. The Annual Energy Outlook (AEO) for 

2011 shows a modest amount of CCS-equipped new coal-fired power coming online past 2012

that would be in compliance with this proposal.

6

 EIA includes some additional new coal with 

CCS in its baseline (2 GW), an assumption which EPA has adopted in IPM. The new CCS is in 

response to existing Federal incentives for the technology (the Emergency Economic 

Stabilization Act of 2008 and the American Reinvestment and Recovery Act of 2009). According 

to the AEO 2011, the majority of new generating capacity is forecast to be either natural gasfired or renewable, with some lesser amounts of nuclear power. The AEO 2011 is based on 

 6 AEO 2011 has a small amount of planned coal capacity that is under construction and expected to come online in 

the next year. This capacity represents certain units that likely fit the definition of transitional sources under 

this proposal. It also has 2 GW of unplanned coal capacity, which reflects new coal with CCS in response to 

Federal incentives.

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Capacity (MW)

Other

Gas (CC and CT)

Renewable/Hydro

Nuclear

Coal
5-5

existing policy and regulations, such as state Renewable Portfolio Standard programs and 

Federal tax credits for renewables.7 Based on EIA analysis, 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."8 The economics favoring 

new NGCC additions instead of conventional coal are robust under a range of sensitivity cases 

examined in the AEO. Unplanned additions of coal by 2020 are also not forecast in sensitivity 

cases that separately examine higher economic growth, lower coal prices, lower capital costs 

for fossil capacity, no risk premium for greenhouse gas emissions liability from conventional 

coal, slower oil and gas technology deployment, lower shale gas recovery per play, and lower

shale gas recovery per well. In addition, the EIA’s AEO 2012 Early Release (AEO 2012 ER) does 

not forecast new unplanned coal capacity without CCS through 2020. Furthermore, it projects 

an increase over AEO 2011 in the price of coal relative to natural gas, strengthening the 

conclusion that natural gas-fired generating technologies are likely to be the fossil fuel of choice

during the analysis period. The AEO 2012 ER also has lower electricity demand projections than 

those used in IPM, reflecting an extended economic recovery and increasing energy efficiency 

in end-use appliances,9 which would result in the need for less new capacity in general.

EPA uses IPM to support its understanding of the economic and emissions impacts of air 

regulations on the power sector. IPM forecasts show patterns of future power plant 

deployment that are similar to those presented in AEO 2011, and also forecasts no construction 

of new conventional coal-fired power plants under the base case.10 

A number of major utilities have made public announcements consistent with these 

modeling results.11

IPM has been used for evaluating the economic and emission impacts of environmental 

policies for over two decades. The economic modeling presented in this chapter has been 

developed specifically for analysis of the power sector. Thus, the model has been designed to 

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

8 Department of Energy (2011). Report on the First Quadrennial Technology Review. Available at 

http://energy.gov/sites/prod/files/QTR_report.pdf. 9 AEO 2012 Early Release Overview

10 http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation 11 For example: “We have no other coal-fueled generation planned at this time... When we do need new capacity, 

it is highly likely that we will look to natural gas plants instead of coal, especially if natural gas prices remain as 

low as projected.” AEP January 1, 2011, Washington Post; “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.
5-6

reflect the industry as accurately as possible. 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. More detail on IPM can be 

found in the model documentation, which provides additional information on the assumptions 

discussed here as well as all other assumptions and inputs to the model.

5.3 External Review of EPA Applications of IPM

EPA has used IPM extensively over the past two decades to analyze options for reducing 

power-sector emissions. The model has been used by the Agency to support regulatory 

initiatives as well as legislative proposals designed to address air emissions for the power 

sector. All of the IPM scenarios conducted for this rulemaking are available at EPA’s website 

and in the public docket.12

The model undergoes periodic formal peer review, which includes separate expert 

panels for both the model itself and EPA’s key modeling input assumptions. For example, over 

the past ten years several separate panels of independent experts have been convened to 

review IPM’s coal supply and transportation assumptions, natural gas assumptions, and model 

formulation.

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. The feedback that the Agency receives provides a highly detailed check for key input 

assumptions, model representation, and modeling results.

The Agency has used IPM in several recent regulatory contexts. The model has been 

used to support the Agency’s analytics for the Clean Air Interstate Rule, CSAPR, MATS, and over 

a dozen legislative analytical efforts to forecast the costs, emission changes, and power sector 

impacts of various policies to reduce power sector emissions. As part of the rulemaking 

process, EPA is required to respond to every significant comment submitted. 

The model has also been used by states (e.g., for Regional Greenhouse Gas Initiative, 

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.

 12 http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html
5-7

More specifically, the model has received extensive review by energy and 

environmental modeling experts over the past two decades. States have used the model 

extensively to inform issues related to ozone in the northeastern portion of the 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. In the late 

1990’s, the Science Advisory Board reviewed IPM as part of the CAA Amendments Section 812 

prospective studies that are periodically conducted. The model has also undergone 

considerable interagency scrutiny as part of a series of legislative analyses over the past 

decade. These analyses explored a variety of approaches to controlling emissions from the 

power sector, and the results were presented to Congress in a comparative manner in order to 

evaluate the merits of policy proposals. The model was also used to support the Agency’s 

power sector analyses of legislative climate proposals in 2005, continuing through 2010. 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 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.

5.4 IPM is a Detailed Bottom-Up Model

EPA applies IPM to consider nationwide impacts of environmental policies, which can 

also be considered at a regional level of detail appropriate to the functional organization of the 

power section. 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. For example, the model 

includes 32 power regions with detailed representation of the inter-regional transmission 

system and reflects the regional aspects of natural gas and coal markets. When considering 

which new units are most cost effective to build and operate, the model considers the relative 

economics of various technologies based on their unique capital costs, operation and 

maintenance (O&M) costs, fuel costs and emission profiles. The capital costs for new units are 

regionalized through the application of regional adjustment factors that capture 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 the model’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 supports fuel price projections, a key component of new power plant economics. The 

model includes an endogenous representation of the North American natural gas supply system 
5-8

through a natural gas module that reflects a full supply/demand equilibrium of the North 

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 available, were developed during a thorough bottom-up, mine-bymine based approach that depict 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 that are implemented in EPA modeling applications. The 

coal curves used by EPA 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 the rulemaking process for CSAPR and MATS. 

5.5 Base Case and Sensitivity Analysis of Future Generating Capacity

5.5.1 Base Case Analysis

EPA began its analysis of the economic impacts of the proposed NSPS by conducting a 

base case analysis of future generating capacity. This base case incorporates the final MATS and 

the final Transport Rule (finalized as CSAPR).

13 In addition to MATS and CSAPR, the baseline 

takes into account emissions reductions associated with the implementation of all finalized 

federal rules, state rules and statutes, and other binding, enforceable commitments that are 

applicable to the power industry and which govern the installation and operation of pollution 

controls during the timeframe covered in the analysis. EPA’s IPM modeling for this rule relies on 

EIA’s Annual Energy Outlook for 2010’s electric demand forecast for the US and employs a set 

of EPA assumptions regarding fuel supplies, the performance and cost of electric generation 

technologies, pollution controls, and numerous other parameters.

 13 http://www.epa.gov/airquality/powerplanttoxics and http://www.epa.gov/airtransport. 
5-9

The IPM base case projection is based on an electricity demand growth assumption of 

0.8 percent annually on average, similar to EIA’s Annual Energy Outlook for 2010, and slightly 

higher than the 0.7 percent annual average growth in the AEO 2012 ER. Total electricity 

demand is projected to be 4,086 billion kWh by 2015. Table 5-2 shows current electricity 

generation alongside EPA’s projection for 2020 using IPM. This new demand will be fulfilled by 

existing generating capacity that is currently not being fully utilized, and new renewable and 

gas-fired generating capacity (see Table 5-1). The change in coal represents only retirements of 

existing plants and no new unplanned coal builds. These projections are the result of least-cost 

dispatching using IPM, and reflect the most cost-effective dispatch and investment option, 

given a variety of variables and constraints. Although most new generating capacity will be 

renewable and natural gas-fired, U.S. electricity demand will continue to be met by a diverse 

mix of electricity generation sources (see Table 5-2). In addition, coal is projected to continue 

to provide the largest share of America’s electricity.14 By 2020, EPA forecasts roughly 27 GW of 

new renewable capacity, 2 GW of coal with CCS, and 10 GW of new natural gas-fired capacity. 

Although 2 GW of coal with CCS is included in the base case in response to incentives under 

existing law, overall coal capacity is forecast to decline in response to current economics, along 

with some retirements due to other air regulations (CSAPR and MATS). 

 14 Coal-fired generation is projected to increase above 2009 actual levels. 2020 natural gas-fired generation is 

projected to be lower than 2010, due in large part to the smaller relative difference in delivered natural gas and 

coal prices in different areas of the country projected to occur in 2020 than occurred in 2010. While the 

projected narrowing of this gas price and coal price differential may increase dispatch (generation) from 

existing coal units, it is insufficient to shift the economic decision to favor new conventional coal-fired capacity, 

which requires consideration of capital costs in addition to generation costs. The same trend is seen in AEO 

2011 projections.
5-10

Table 5-1. Total Generation Capacity in 2010 and Projected by 2020 (GW)

2010 2020

Pulverized Coal 316 304

Natural Gas Combined Cycle 199 212

Combustion Turbine 135 143

Oil/Gas Steam 111 90

Non-Hydro Renewables 31 73

Hydro 99 99

Nuclear 102 106

Other 5 4

Total 998 1,030

Source: 2010 data from EPA's NEEDS v.4.10 PTR. 2020 projections from Integrated Planning Model run by EPA.

Notes: 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.

Table 5-2. 2010 U.S. Electricity Net Generation and EPA Base Case Projections for 2020 

(Billion kWh)

Historical Projected

2010 2020

Coal 1,828 1,976

Oil 35 0.126

Natural Gas 901 869

Nuclear 807 840

Hydroelectric 258 286

Non-hydro Renewables 139 289

Other 4 45

Total 3,972 4,305

Notes: The sum of the table values in each column may not match the total figure due to rounding.

Source: 2010 data from EIA Electric Power Annual 2010, Table 2.1; 2020 projection from IPM run by EPA, 2011.

5.5.2 Sensitivity Analyses

Forecasts suggesting that new coal is unlikely to be built by 2020 have been shown 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 a series of distinct 

scenarios that explore specific issues and examine a future state of the world that deviates 

from the core parameter estimates that underlie the AEO reference case. Even under 
5-11

alternative scenarios where assumptions might improve the relative economic value of building 

new coal-fired power plants, the AEO 2011 does not project new coal capacity being built 

through 2025, beyond the coal capacity already planned outside of the modeling. Relevant 

scenarios include higher economic growth forecast, lower cost of coal supply, lower capital 

costs of fossil fuel-fired energy technologies, and less optimistic natural gas supply.15 Although 

new coal capacity is built in some of these scenarios after 2025, CAA Section 111(b) requires 

that this standard be reviewed every eight years, thus this regulatory requirement will likely be 

reviewed and potentially revised after the 2020 timeframe, which serves as the primary focus 

of this analysis. In addition to studying the alternative scenarios analyzed by EIA, EPA also 

conducted three additional sensitivity analyses using IPM: a low shale gas recovery scenario, a 

high electricity demand scenario, and a combination of the two.16 The lower shale recovery 

scenario assumed, that 50 percent less natural gas is recovered from each shale play relative to 

the base case (effectively lowering shale reserves by 50 percent, similar to the AEO 2011 low 

shale gas recovery scenario). The high electricity demand scenario assumed that electricity 

demand grows at an annual average rate of 1.1 percent, similar to EIA’s high economic growth 

scenario for AEO 2010 (compared to about 0.8 percent in the EPA baseline, which is similar to 

the reference case in AEO 2010). Figure 5-2 and 5-3 illustrate electricity demand and natural 

gas price in these sensitivity analyses. Note that the EPA structured the sensitivity analyses 

such that natural gas prices and electricity demand growth are both considerably higher than

the comparable AEO 2011 scenarios.17

 15 Conversely, modeling in support of the AEO 2011 show that new natural gas combined cycle capacity is expected 

to be higher in 2020 in the low fossil cost and high economic growth scenarios relative to the reference case. 16 Although EPA and EIA do not typically combine scenarios (as EPA did with the natural gas and demand 

sensitivity in this analysis), this scenario was performed to demonstrate that even when considering the 

occurrence of two independent and highly unlikely assumptions that influence new power plant additions, new 

unplanned coal is not expected to be built through 2020. 17 EPA’s baseline electricity demand forecast used in IPM v4.10 is based on the demand forecast in AEO 2010. AEO 

2010 electricity demand forecast for the year 2020 is roughly 2.5% higher than the 2020 forecast in AEO 2011. 

EPA’s sensitivity with higher electricity demand growth (using the AEO 2010) uses an electricity demand for 

2020 that is about 6% higher than the reference case AEO 2011 demand for 2020, and about 3% higher than 

the demand in the AEO 2011 high economic growth scenario. The EPA sensitivity with higher electric demand 

represents a very conservative view of electricity demand in 2020 (meaning that its electricity demand 

projection is considerably higher than the most recent reference case forecast, therefore representing a future 

in which new coal-fired capacity would be of correspondingly higher economic value to build relative to the 

reference case forecast conditions).
5-12

Figure 5-2. Projected Levels of Electricity Demand in 2020, EPA and EIA

4,305

4,475

4,300

4,190

4,318

3,000

3,200

3,400

3,600

3,800

4,000

4,200

4,400

4,600

EPA - Base Case EPA - High Demand AEO 2010 AEO 2011 AEO 2011 - High 

Econ. Growth

TWh
5-13

Figure 5-3. Projected Natural Gas Prices in 2020, EPA and EIA (Delivered, Power Sector)

None of these analyzed scenarios resulted in new conventional coal-fired capacity being 

built in 2020 (see Figure 5-4) beyond 2 GW of coal with CCS, which is built in response to the 

financial incentives for CCS included in the Emergency Economic Stabilization Act of 2008 and 

American Recovery and Reinvestment Act of 2009, which authorized and/or appropriated 

funding to DOE for CCS deployment.18 In the short-term, most new capacity is projected as a 

mix of wind and natural gas in response to the competitive marketplace for fuels and other 

energy policies (such as tax credits and state renewable portfolio standards). These scenarios 

show similar results as EIA, and serve to further confirm the high likelihood that no new coal 

capacity is likely to be built by 2020 in baseline forecasts. See Table 5-3 for new capacity 

projections in 2020.

 18 A number of the sources that EPA has identified as transitional sources have received some form of DOE 

financial assistance to demonstrate CCS. Several additional projects have received funding but have not yet 

received air permits. Beyond these projects, prospects for additional federal funding are dependent on the 

overall budget process.

4.99

5.51

7.33

7.96

5.74

4.97 5.07

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

EPA - Base Case EPA - High 

Demand

EPA - Low Shale 

Recovery

EPA - High 

Demand + Low 

Shale Recovery

EIA - Low Shale 

Recovery (AEO 

2010)

EIA Reference 

Case - AEO 2011

Average Price 

(2011, EIA)

Delivered Price, Power Sector ($2007/mmBtu)
5-14

Table 5-3. Projected New Capacity in 2020

EPABase 

Case

EPAHigh 

Demand

EPA-Low 

Shale 

Recovery

EPA-High 

Demand + 

Low Shale 

Recovery

Coal +CCS 2.0 2.0 2.0 2.0

Natural Gas Combined Cycle 7.0 22.7 7.3 24.8

Combustion Turbine 3.0 3.2 2.4 2.4

Non-Hydro Renewables 26.9 27.6 27.3 31.5

Total 38.9 55.5 39.0 60.7

5.6 Analysis of Applicability of Proposed EGU GHG NSPS to Projected New Generating 

Capacity

As the second step in the analysis, EPA analyzed the applicability of the NSPS to new 

generating capacity anticipated to be built through 2020, and whether the requirements would 

require the regulated community to take actions different from those projected in the base 

case.

The proposed EGU GHG NSPS discusses potential requirements for new units Analysis 

performed by EPA, along with information from other sources, suggests that the standards as 

specified in this proposed rule are likely to result in negligible emission changes, other 

quantified benefits, energy impacts, costs, or economic impacts by 2020. This is because 

analyses performed both by EPA and EIA, as well as statements and actions of a number of 

major utilities, demonstrate that generation technologies other than coal (mostly natural gas 

and renewable sources) are likely to be the technologies of choice for new sources due to 

current and projected market conditions.19

5.6.1 New Units

This proposal requires that all new fossil-fuel fired units greater than 25 megawatt 

capacity be able to meet an emission rate standard of 1,000 lbs CO2/MWh on a gross basis. It 

also proposes an alternative compliance option that would allow new units to meet the 1,000 

lbs CO2/MWh standard using a 30 year averaging period. These standards could be met either 

by natural gas combined cycle generation or coal-fired generation using CCS. 

 19 EPA does not anticipate any oil or gas steam boilers to be constructed, either. Although these types of units 

would be subject to this rule, they have not been a technology of choice for the sector in recent years and are 

generally smaller (less than the 25 MW applicability threshold included as part of this rule). In addition, the 

operating economics also do not favor this technology, similar to the dynamic with conventional new coal-fired 

capacity.
5-15

Of the new generating capacity projected to be constructed by 2020, only the fossil-fuelfired boilers would be affected by the proposed EGU GHG NSPS. The NGCC units, which are the 

basis of the proposed standard, are projected to meet the proposed standard through their 

inherent design.20 As discussed in section 5.5, no new conventional coal-fired boilers are 

projected to be built (excluding new coal built with CCS). This implies that the NSPS will require 

no changes in design or construction of new EGUs forecasted in the base case. Thus, under the 

baseline projections as well as the sensitivity analyses presented above, the proposed EGU GHG 

NSPS will not result in any reduction in emissions, or any costs.

Engineering cost analysis, even outside of a least-cost system dispatch modeling 

environment, reaches similar conclusions. A comparison of levelized wholesale electricity costs 

for differing generation technologies and natural gas prices are shown in Figure 5-4 and Table 

5-4. It is important to note that both EIA and EPA include a capital charge rate adder (3

percent) for new conventional coal-fired generating capacity without CCS, which reflects the 

additional cost of raising capital that is currently reflected in the marketplace, related at least in 

part to uncertainty surrounding future greenhouse gas emission reduction requirements.21 

Note that this figure only shows the costs to the generator and does not reflect the additional 

social costs that are associated with damages from greenhouse gas emissions or conventional 

air pollutants. As the figure shows, with a delivered natural gas price of $5 per million British 

Thermal Units (mmBtu) and a delivered coal price of $2 per mmBtu, which reflect forecasted 

prices from IPM in 2020,22 electricity generated by natural gas combined cycle units is less 

expensive on average than coal generation. 

 20 Natural gas combustion turbines are not covered by this proposal. 21 EIA includes "a 3-percentage-point increase is added to the cost of capital for investments in GHG-intensive 

technologies, such as coal-fired power plants without CCS and CTL plants." Source: EIA AEO 2009, Issues in 

Focus. Reflecting Concerns Over Greenhouse Gas Emissions in AEO2009, available at: 

http://www.eia.gov/forecasts/archive/aeo09/issues.html

See also http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html 22 EIA projects a U.S. average power sector delivered coal price of $2.08/MMBtu in 2020 ($2007). EPA and EIA 

both project delivered (power sector) natural gas price of roughly $5/mmBtu in 2020.
5-16

($2007)

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

Technologies, EPA23

Notes: Assumptions derived from EPA’s application of IPM. Technologies include Coal without CCS, Natural Gas Combined 

Cycle with natural gas costing $5 per mmBtu, Natural Gas Combined Cycle with $8 per mmBtu costs of natural gas, and 

Integrated Gasification Combined Cycle with CCS (with 90 percent capture). In this graph coal is a high sulfur bituminous at $2 

mmBtu. Conventional Coal is at a heat rate of 8,875 Btu/kWh net, capacity factor of 85 percent assumed across all 

technologies. 

 23 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 could be built, they could exhibit different costs than presented here. For example, 

smaller new conventional coal facilities which would be more expensive on a $/kw basis and have a relatively 

higher LCOE, and some technologies could potentially have a lower LCOE if fuel could be obtained cheaply and 

capital costs remained similar, or lower than, an new base load convention coal plant (petroleum coke or waste 

coal). These differences do not fundamentally change the analysis presented in this chapter.

0

20

40

60

80

100

120

140

Conventional 

Coal (no 

investor 

climate 

concern)

Conventional 

Coal (w/ CO2 

Uncertainty 

Adder)

Natural Gas 

Combined 

Cycle ($5 gas)

Natural Gas 

Combined 

Cycle ($8 gas)

Natural Gas 

Combined 

Cycle ($9.60 

gas)

Coal + CCS

$/MWh
5-17

It is only when gas prices reach approximately $9.60/mmBtu (in 2007 dollars), that new 

coal-fired generation without CCS becomes competitive, in terms of dollars per megawatt hour 

wholesale cost of electricity generation (none of the EPA or EIA sensitivities with alternate 

assumptions for natural gas approach this price level). 

It is important to note that this analysis is based on assumptions regarding the average 

national cost of generation at new facilities. As reported by the EIA, there is expected to be 

significant spatial variation in the costs of new generation due to design differences, labor wage 

and productivity differences, location adjustments, among other potential differences.24 EPA 

acknowledges that there is some uncertainty around these estimates, and is unable to provide 

estimates for all variants. However, the results are expected to hold for the majority of 

situations. The analysis also does not explicitly consider new units designed to combust waste 

coal or petroleum coke (pet coke), which may be affected by this rule, but also may exhibit 

different local economics.25

This rule also proposes an alternative compliance option that would allow new units to 

meet the 1,000 lbs CO2/MWh standard using a 30 year averaging period.26 To the extent 

market participants have alternative views of both the cost and development of CCS, new 

conventional coal-fired capacity (or IGCC) could be built and operated for some time, with the 

intention to apply CCS with high removal efficiency at some later date, in order to achieve the 

required average rate over the 30 year period. Also the above analysis reflects national 

averages, and given their specific situation, a market participant could determine that the 

economics of building a coal-powered facility that immediately achieves a CO2 capture and/or 

removal rate consistent with the emission standard are favorable.

 24 http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf 25 This analysis also does not explicitly consider new units designed to combust waste coal or petroleum coke (pet 

coke), which may be affected by this rule, but can exhibit different economics. Most other energy models, 

including EIA’s application of NEMS, do not consider these technologies for new electricity sources because 

they are marginal technologies that are rarely built, and highly dependent upon specific local factors that are 

difficult to model and highly speculative (like the ability to obtain a very inexpensive local supply of suitable 

fuel). The models do include these technologies as part of the existing universe of sources, however. For 

context, there are currently 59 units nationwide that are designed to combust either waste coal or petroleum 

coke, with a total capacity of roughly 5 GW (or 0.5% of the entire fleet). To the extent that these technologies 

would be built absent this rule due to unique local economics and fuel supply, there would be certain costs and 

benefits associated with this proposed rule, although they would be expected to be small because these 

sources are not often built. EPA is taking comment and solicits additional information on its consideration of 

these technologies in the analysis. 26 IPM does not consider the impact of elevation on performance, and utilizes a uniform elevation performancebased assumption.
5-18

Table 5-4. Estimated Levelized Cost of New Generation Resources from EIA, U.S. Average 

(2016)

Plant Type Capacity 

Factor (%)

U.S. Average Levelized Costs (2009 $/ MWh)

for Plants Entering Service in 2016

Levelized 

Capital 

Cost

Fixed 

O&M

Variable 

O&M 

(Including 

fuel)

Transmission 

Investment

Total 

System 

Levelized 

Cost

Conventional Coal 85 65.3 3.9 24.5 1.2 94.8

Advanced Coal 85 74.6 7.9 25.7 1.2 109.4

Advanced Coal with CCS 85 92.7 9.2 33.1 1.2 136.5

Natural Gas-fired

 Conventional Combined 

Cycle 87 17.5 1.9 45.6 1.2 66.1

 Advanced Combined Cycle 87 17.9 1.9 42.1 1.2 63.1

 Advanced CC with CCS 87 34.6 3.9 49.6 1.2 89.1

 Conventional Comb. Turbine 30 45.8 3.7 71.5 3.5 124.5

 Advanced Combustion 

Turbine 30 31.6 5.5 62.9 3.5 103.5

Advanced Nuclear 90 90.1 11.1 11.7 1.0 113.9

Wind 34 83.9 9.6 0 3.5 97.0

Wind - Offshore 34 209.3 28.1 0 5.9 243.2

Solar PV 25 194.6 12.1 0 4.0 210.7

Solar Thermal 18 259.4 46.6 0 5.8 311.8

Geothermal 92 79.3 11.9 9.5 1.0 101.7

Biomass 83 55.3 13.7 42.3 1.3 112.5

Hydro 52 74.5 3.8 6.3 1.9 86.4

Source: EIA, AEO 2011

Others have researched the cost and efficiency of varying levels of capture relative to 

building other energy technologies.27 This ongoing research indicates that lower levels of 

carbon capture at new coal facilities could be cost competitive, and the costs of meeting the 

proposed emission rate immediately could be achievable. For example, The Clean Air Task 

Force has compiled data that indicates the levelized cost of electricity for a new supercritical 

pulverized coal unit with 50 percent CCS (or 1,080 lb/MWh CO2, which is just above the 

proposed standard) could be $116/MWh compared to $147/MWh for 90 percent removal. 

However, investment decisions will be made on a case by case basis dependent upon a number 

of factors, all of which are difficult to estimate in advance.

 27 Technical Options for Lowering Carbon Emissions from Power Plants. Clean Air Task Force (June, 2011). Available 

at: 

http://www.coaltransition.org/filebin/pdf/Technical_Options_for_Lowering_Carbon_Emissions_from_Power.p

df
5-19

5.6.2 Reconstructed Units

The EPA’s CAA Section 111 regulations define reconstructed sources as, in general, 

existing sources (i) that replace components to such an extent that the capital costs of the new 

components exceed 50 percent of the capital costs of an entirely new facility, and (ii) for which 

compliance with standards of performance for new sources is technologically and economically 

feasible (40 CFR 60.15). The Agency is aware that, in theory, operators of existing power plants 

may choose to reconstruct them, but we are not aware of any announced plans to do so. This 

provision is rarely triggered. In light of this limited experience concerning reconstructions, the 

Agency lacks adequate information that is needed to propose a standard of performance for 

reconstructions. As a result, in today’s action, the EPA is not including a proposal for 

reconstructions. Instead, we solicit comment on how we should approach reconstructions and, 

depending on the information we receive, we may propose and finalize a standard for 

reconstructions at a later time. 

5.6.3 Modified and Transitional Units

Modified and transitional units are described in the preamble and in Chapter 2 of this 

RIA. EPA does not anticipate any costs being associated with these units. 

5.7 Costs, Economic, and Energy Impacts of the Proposed Rule for New Electric Generating 

Units

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 GHG NSPS will result in negligible CO2 emission changes, 

energy impacts, 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.

5.8 Comparison of Emissions from Generation Technologies

As discussed earlier in this chapter, natural gas combined cycle 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 GHG NSPS is anticipated to have negligible costs or quantified benefits
5-20

under a range of likely market conditions, it is instructive to consider the differences in 

emissions of CO2 and conventional air pollutants between the two types of units. 

As Table 5-5 below shows, emissions from a typical new natural gas combined cycle 

facility are significantly lower than those from a traditional coal unit.28 For example, a typical 

new supercritical pulverized coal facility that burns bituminous coal in compliance with new 

utility regulations (e.g., CSAPR and MATS) would have considerably greater CO2, sulfur dioxide 

(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 930 fewer short tons SO2

and 1,200 fewer short tons of NOx each year. Importantly, these differences in emissions 

assume a new coal unit that complies with all applicable 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.

 28 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.
5-21

Table 5-5. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired Generating Units29

Conventional Coal Natural Gas CC Coal with CCS

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 940 0.42 10 0.0041 50 0.022

NOx 1,400 0.62 200 0.09 1,100 0.47

CO2 3.6 million 1,800 1.7 million 820 0.4 million 200

Notes: SO2 and NOx in short tons, CO2 in metric tons. As discussed in Section 5.4, the illustrative units represent relative 

emissions for new well controlled 600 MW (net) baseload units running at 85 percent capacity factor (85% capacity factor 

reflects operation of new baseload units and does not necessarily reflect the historic capacity factors of existing units with 

specifications similar to these illustrative units). Assumed coal is high sulfur bituminous with scrubber and SCR, data are based 

on EPA assumptions used in IPM.

5.9 Benefits of Reducing GHGs and Conventional Pollutants

Because emissions of CO2 and criteria air pollutants adversely affect human health and 

welfare, the differences in emissions presented above translate into differences in the external 

social costs associated with different generation technologies. Here we provide a general 

discussion about the differences in emissions of CO2 and criteria air pollutants in the previous 

illustrative example.

5.9.1 Social Cost of Carbon

The social cost of carbon (SCC) is a metric to estimate the monetary value of benefits 

associated with marginal changes in CO2 emissions, and may therefore be utilized to 

understand the value of the difference in CO2 emissions between the two representative units 

discussed in Section 5.8. The SCC is an estimate of the monetized damages associated with an 

incremental increase in carbon 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. Federal 

agencies typically use SCC estimates to assess the benefits of rulemakings that achieve marginal 

reductions in CO2 emissions. These estimates were developed through an interagency process 

that included EPA and other executive branch entities, and concluded in February 2010. The 

 29 The emissions presented here are estimated on an output basis to enable easier comparisons and to illustrate 

the potential impacts of moving from new coal to new natural gas. 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 small 

new conventional coal plant or a waste coal or petroleum coke facility). However, the emissions 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).
5-22

SCC Technical Support Document (SCC TSD) provides a complete discussion of the methods 

used to develop these SCC estimates.30 

The interagency group selected four SCC values for use in regulatory analyses: $7, $26, 

$42, and $81 per metric ton of CO2 emissions in 2020, in 2007 dollars.31,32 The first three values 

are based on the average SCC from three integrated assessment models, at discount rates of 5, 

3, and 2.5 percent, respectively. 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. 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. 

The SCC 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. 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 5-6 presents the 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.

When attempting to assess the incremental economic impacts of carbon dioxide 

emissions, the analyst faces a number of serious challenges. A recent report from the National 

Academies of Science (NRC 2009) points out that any assessment will suffer from uncertainty, 

 30 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, 

Office of Science and Technology Policy, and Department of Treasury (February 2010). Also available at 

http://epa.gov/otaq/climate/regulations.htm 31 Note that upstream emissions changes were not considered for this rule. There may be changes in greenhouse 

gas emissions (in particular, methane) due to changes in fossil fuel extraction and transport in response to this 

proposal, but those were not quantified. 32 The interagency group concluded that a global measure of the benefits from reducing U.S. GHG emissions should 

be the standard practice when conducting regulatory impact analysis in support of federal rule makings. 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.
5-23

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.33 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 interagency group 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 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. The interagency group hopes that over time 

researchers and modelers will work to fill these gaps and that the SCC estimates used for 

regulatory analysis by the Federal government will continue to evolve with improvements in 

modeling. It is important to emphasize that the interagency process is committed to updating 

these estimates as the science and economic understanding of climate change and its impacts 

on society improves over time. Specifically, they have set a preliminary goal of revisiting the 

SCC values within two years, or at such time as substantially updated models become available, 

and to continue to support research in this area. Additional details on these limitations are 

discussed in the SCC TSD.

 33 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.
5-24

Table 5-6. Social Cost of CO2, 2015-2050a (in 2007 dollars)

Year

Discount Rate and Statistic

5% Average 3% Average 2.5% Average 3%

95th percentile

2015 $6 $24 $38 $73

2020 $7 $26 $42 $81

2025 $8 $30 $46 $90

2030 $10 $33 $50 $100

2035 $11 $36 $54 $110

2040 $13 $39 $58 $119

2045 $14 $42 $62 $128

2050 $16 $45 $65 $136

a The SCC values vary depending on the year of CO2 emissions and are defined in real terms.

5.9.2 Health Impacts of SO2 and NOx

SO2 is a precursor for fine particulate matter (PM2.5) formation. NOX is a precursor for 

PM2.5 and ozone formation. As such, reductions of SO2 and NOX would in turn lower overall 

ambient concentrations of these pollutants as well as 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, 2006). 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 asthma attacks, hospital and emergency room visits, and school loss days. For a full 

discussion of the human health benefits of reducing SO2 and NOX emissions from power sector 

sources, including reducing methyl mercury, SO2, and NO2 exposure, please refer to the RIA for 

CSAPR (U.S. EPA, 2011). 

In addition to human health benefits, reducing SO2 and NOX emissions would also result 

in human welfare improvements by improving ecosystem services—the benefits that the public

obtains from ecosystems that directly or indirectly contribute to social welfare. SO2 and NOX

emissions can adversely impact vegetation, certain manmade materials, acidic deposition, 

nutrient enrichment, visibility, and climate (U.S. EPA, 2009; U.S. EPA, 2008). Reducing these 

harmful emissions improves human welfare. For more information about the welfare benefits 
5-25

of SO2 and NOX emission reductions from power sector sources, please refer to the Regulatory 

Impact Analysis for the CSAPR (U.S. EPA, 2011).

Because the health and welfare benefits of SO2 and NOx emissions in terms of 

incidences of health effects avoided or monetized value of health or welfare improvements 

depend on power plant location, the potential benefits cannot be quantified precisely for the 

purposes of this illustrative example. However, reducing one thousand tons of annual SO2 from 

U.S. EGUs in 2020 has been estimated34 to yield between 3 and 9 incidences of premature 

mortality avoided annually and annual monetized PM2.5-related health benefits (including these 

incidences of premature mortality avoided) between $30 million and $75 million (2007$) using 

a 3% discount rate or between $28 million and $67 million (2007$) using a 7% discount rate

(where the range is due to EPA’s use of two alternative primary estimates of PM2.5 mortality 

impacts, a lower primary estimate based on Pope et al. (2002) and a higher primary estimate 

based on Laden et al. (2006)). Additionally, reducing one thousand tons of annual NOX from U.S. 

EGUs in 2020 has been estimated35 to yield up to 1 incidence of premature mortality avoided 

annually and annual monetized PM2.5-related health benefits (including these incidences of 

 34 The SO2 and NOX benefit per-ton (BPT) values presented here consist of only PM2.5-related health benefits from 

reductions in SO2 and NOX (precursors to PM2.5 formation). EPA relied on air quality modeling used to develop 

a previous rulemaking affecting power sector emissions of SO2 and NOX to develop these BPT values (Air Quality 

Modeling Technical Support Document for the final Transport Rule; 

http://epa.gov/airtransport/pdfs/AQModeling.pdf). EPA utilized Transport Rule (Cross-State Air Pollution Rule) 

modeling rather than air quality modeling of EPA’s Mercury and Air Toxics Standards (MATS) because EPA did 

not estimate NOX BPT values for MATS and because the utilized Transport Rule modeling reduced emissions of 

SO2 and NOX independently, allowing for better estimation of PM2.5-related SO2 and NOX BPT values. The air 

quality modeling utilized reflects emission reductions in the eastern U.S. In order to better understand the 

relative difference between BPT values for emission reductions in the east and west, see Table 5C-3 of the 

MATS Regulatory Impact Analysis (RIA) <www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf>. Using this 

existing air quality modeling, EPA used BenMAP (www.epa.gov/air/benmap) to estimate the benefits of air 

quality improvements using projected 2020 population, baseline incidence rates, and economic factors. These 

BPT values are methodologically consistent with those reported in Fann et al. (2009). As EPA models avoided 

premature deaths among populations exposed to levels of PM2.5, we have lower confidence in levels below 

the lowest measured level (LML) for each study. However, studies using data from more recent years, during 

which time PM2.5 concentrations have fallen, continue to report strong associations with mortality. For more 

information refer to the MATS RIA. The average BPT values 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. 

These BPT values are purely illustrative as EPA does not assert a specific location for the illustrative coal and 

natural gas combined cycle units 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 very different than the 

estimates shown here. EPA notes that the BPT estimates do not reflect emission reductions after 

implementation of EPA’s Mercury and Air Toxics Standards. 35 Ibid.
5-26

premature mortality avoided) of between $2.5 million and $6.2 million (2007$) using a 3% 

discount rate or between $2.3 million and $5.6 million (2007$) using a 7% discount rate.

5.10 Illustrative Analysis of the Social Costs of New Generating Sources

As the analysis in sections 5.5 and 5.6 demonstrated, under a wide range of likely 

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. 

In this section, we consider the unlikely scenario where future market conditions 

support the construction of new conventional (advanced, but without CCS) coal capacity during 

the analysis period in the absence of the rule. The analysis in this section indicates that in this 

scenario, the proposed EGU GHG NSPS is highly likely to provide net benefits to society as a 

whole.

The starting point for this analysis is the illustrative comparison (presented in Figure 5-4 

above) of the relative private costs of constructing and operating a representative new 

conventional coal EGU and a representative NGCC unit.

36 This comparison shows that, at 

forecast relative fuel prices, there is a significant difference in the levelized cost of these two 

generating technologies. However, in the context of a social welfare analysis, the appropriate 

comparison between multiple options is on the basis of benefits and costs to society as a 

whole, and not solely the private cost to an investor. 

From the perspective of society, the appropriate cost comparison for new generation 

capacity should account for the pollution damages associated with the competing generation 

technologies in addition to private generating costs. This section further explores how the 

potential social benefits and costs of this NSPS standard may change across a wide range of 

natural gas prices, a key factor in the potential cost of the policy. It begins by estimating 

illustrative environmental damages per MWh for coal relative to gas generation and then uses 

 36 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. 
5-27

these estimates to conduct an illustrative sensitivity analysis for the potential social costs of the 

policy in this illustrative example.

37

It should be emphasized that the analysis presented here is illustrative, although EPA 

believes that it leads to a robust conclusion. From an analytical perspective, the challenge is to 

estimate expected benefits and costs given uncertainty about future market conditions. An 

ideal benefit-cost analysis would first model projected generation capacity and capacity 

additions for every plausible set of market conditions (e.g., different combinations of natural 

gas and coal supplies and electricity demand). The effects of the proposed EGU GHG NSPS 

could then be estimated in each of those scenarios including the resulting estimated benefits 

and costs (which would depend on the amount of new generation capacity built, the 

technologies used, the location of new generating plants, and so on). The analysis would then 

estimate the conditional probability distribution of those outcomes (for example, the 

probability distribution of future natural gas prices or future electricity demand conditional on 

the current information on supply). Finally, the analysis would integrate the estimated benefits 

and costs over the conditional probability distribution of outcomes, to arrive at the expected 

net benefits of the rule.

The analysis just described is beyond the scope of the current RIA, and EPA believes that 

the sensitivity cases presented in section 5.6.1, combined with the illustrative analysis here, 

provide a robust picture of the likely costs and benefits of the standard. Nonetheless, EPA is 

inviting comment on whether a more detailed analysis would be practical, feasible, and an 

effective use of limited analytical resources, and if so, how it might be carried out and what 

information it would be expected to provide. If commenters believe that such an analysis 

would be practical and appropriate, EPA invites comment on what variables should be treated 

as uncertain (e.g., natural gas and coal prices, electricity demand) and on the specific 

conditional and potentially joint probability distributions that should be used for the future 

state of those variables.

In the spirit of the “ideal” analysis just described, in the remainder of this section EPA 

provides an illustrative analysis focusing on uncertainty in the price of natural gas, which is a 

key determinant of the economics of electricity generation and therefore the potential impacts 

of this proposed rule.

 37 From an economic perspective, the analysis in sections 5.5 and 5.6 considered the net benefits of the rule under 

expected market conditions, and found those to be zero (because the rule would not affect what new capacity 

is built under those market conditions). The analysis in this section, while still purely illustrative, is an initial 

step toward estimating the expected net benefits of the rule as a function of market conditions.
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5.10.1 Illustrative Environmental Damages per MWh 

As previously discussed in this chapter, the damages associated with emissions from 

new sources of electricity generation are greater for coal-fired units than for natural gas 

combined cycle units (even when accounting for compliance with EPA’s recent Mercury and Air 

Toxics Standard). To gauge the general effect of accounting for both the private and external 

costs of electricity generation for new generation options we continue with the illustrative 

example from Section 5.8. The external costs are defined as the damages associated with

pollution that are not accounted for in the private investor's decision making.38

To illustrate the external costs associated with new generation options we combine the 

illustrative emission profiles for the new units, as provided in Table 5-5, and the illustrative 

emissions and damage estimates discussed in the previous two sections.

39 Specifically, for each 

generating technology we multiply the CO2 emissions by the estimates of the SCC and add that 

to the SO2 emissions40 multiplied by the PM2.5-related SO2 benefit per-ton estimates,

41

subsequently dividing by MWh to estimate the external costs per unit of generation. 

Table 5-7 reports the additional pollution damages from the illustrative new coal plant 

relative to the illustrative new natural gas plant given different mortality risk studies and 

assumptions about the discount rate. These pollution damages should be relatively invariant 

across natural gas prices and other economic factors. Depending on the discount rate and 

mortality risk study used, damages associated with generation from a representative new coal 

unit are $11 to $81 per MWh, while damages associated with the illustrative new natural gas 

combined cycle unit are $3 to $31 per MWh (2007$).42 

It is important to note that although the ranges appear to overlap, for any set of 

assumptions (i.e., any specific mortality risk study and choice of SCC value) estimate the 

 38 See Baumol and Oates, 1988. 39 Only the direct emissions of two pollutants (CO2 andSO2) are considered in this illustrative exercise. Other 

pollutants and lifecycle emissions are not considered. 40 See footnote 32 in section 5.8. 41 See footnote 34 in section 5.9.2 for a description of the benefit-per-ton values. In this exercise they are 

interpreted as damage-per-ton values. 42 Different discount rates are applied to SCC than to the other damage 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 “SCC 

TSD,” Interagency Working Group on Social Cost of Carbon (IWGSC). 2010. Technical Support Document: Social 

Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. Docket ID EPA-HQ-OAR-2009-

0472-114577. http://www.epa.gov/otaq/climate/regulations/scc-tsd.pdf for details.
5-29

pollution damages associated with new coal generation are significantly higher than those 

associated with new natural gas combined cycle generation in this illustrative, but 

representative example. For example, considering the SO2 per ton damages based on Pope et 

al. 2002 using a 7% discount rate and the SCC estimate based on the 3% discount rate, new 

generation based on conventional coal in this example would result in an additional $17 per 

MWh in pollution damages compared to a new NGCC plant. Alternately, damages that reflect 

the SO2 per ton damage estimate based on Laden et al. 2006 using a 3% discount rate and the 

SCC estimate based on a 2.5% discount rate suggest an additional $33 of pollution damages per 

MWh from a new conventional coal unit compared to a new NGCC plant. 

As with the relative investment costs of a new coal unit and a new natural gas combined 

cycle system, the actual environmental damages associated with these two technologies 

depends 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).43 However, these factors will not change the qualitative 

conclusion. The damages associated with CO2 emissions, which are the focus of this rule, do not 

depend on the location of generation. Furthermore, the damages associated with sulfur dioxide 

emissions from a new very well-controlled coal-fired unit firing low-sulfur coal would still be 

greater than the damages from a new natural gas combined cycle unit independent of the 

location.

 43 EPA does not assert a specific location for the illustrative coal and natural gas combined cycle units and is 

therefore unable to specifically determine the population that would be affected by their SO2 emissions. 

Therefore, the benefits for any specific unit can be very different than the estimates shown here. 
5-30

Table 5-7. Pollution Damages ($/MWh) from Illustrative New Coal Unit Relative to New 

Natural Gas Combined Cycle Unit 44

SCC Discount Rate Damages from CO2

5% $3

3% $11

2.5% $18

3% (95th percentile) $34

Damages from SO2 Only

Discount Rate Applied to Health Co-Benefits

Mortality-Risk 

Study 3% Discount Rate 7% Discount Rate

Pope (2002) $6 $6

Laden (2006) $16 $14

Combined Damages from CO2 and SO2

Discount Rate Applied to Health Co-Benefits

SCC Discount Rate 3% Discount Rate 7% Discount Rate

5% $9 - $19 $9 - $17

3% $17 - $27 $17 - $25

2.5% $24 - $33 $24 - $32

3% (95th percentile) $41 - $50 $40 - $48

Notes: Values in first two tables may not sum due to rounding.

The range of costs within each SCC value and discount rate for SO2 pollution damages pairing reflects the use of two core 

estimates of PM2.5-related premature mortality, Pope et al. (2002) representing the lower of our core estimates and Laden et 

al. (2006) represent the higher of our core estimates. Assumed coal is high sulfur bituminous with scrubber and SCR. The 

combinations of health studies and discount rates represent lower and higher valuations of impacts of SO2 emissions in the 

Eastern U.S. EPA has evaluated the range of potential impacts per MWh by combining all SCC values with health damages 

values at the 3 percent and 7 percent discount rates. To be consistent with concepts of intergenerational discounting, values for 

health damages, which occur within a generation, would only be combined with SCC values using a lower discount rate, e.g. the 

7 percent health damages estimates would be combined with 5 percent or lower SCC values, but the 3 percent health damages 

would not be combined with the 5 percent SCC value. While the 5 percent SCC and 3 percent health damages 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 damage values assumes that there is no difference in discount rates between intragenerational and intergenerational 

impacts.

 44 The damages presented here are estimated on an output basis to enable easier comparisons and to illustrate the 

potential impacts of moving from new coal to new natural gas. 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 damages

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 and CO2, on an output basis) except for differences in local conditions, as 

discussed below.
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The conclusion from this analysis is that there are significant environmental damages 

associated with electricity generation from a representative new conventional coal unit relative 

to a representative new natural gas combined cycle unit.45 Other studies of the social costs of 

coal and natural gas fired generation provide similar findings (Muller et. al, 2011; NRC, 2009).46

An important implication is that if market conditions changed sufficiently so that new coal units 

became marginally more profitable to operate, these new units are still likely to impose a net 

cost to society relative to a new natural gas plant. This idea is discussed in more detail in the 

next section.47 

5.10.2 Social Benefits and Costs across a Range of Gas Prices - Sensitivity Analysis

We now discuss how a consideration of the environmental damages associated with 

new coal and natural gas EGUs informs the comparison of the two technologies from the 

standpoint of net benefits – building on the illustrative comparison of a representative new coal 

unit and a representative natural gas unit developed in Sections 5.8 and 5.9

At current natural gas prices relative to other fuels, the difference in the estimated

levelized cost of electricity for a representative NGCC unit is roughly $27 per MWh less than for 

a representative new conventional coal unit (see Figure 5-4). This is consistent with EPA’s 

projection, discussed at length above, that the proposed EGU GHG NSPS will not impose any 

social costs (or generate quantified net benefits) under current and likely future market 

conditions. 

Because the impacts of this proposed rule depend on future natural gas prices, which 

are uncertain, EPA conducted an illustrative analysis of the impacts of the rule over a wide 

range of natural gas prices. This analysis considers two distinct thresholds in the price of natural 

 45 As previously noted in this section and the previous sections on the costs and damages associated with these 

technologies, EPA does not assert a specific location for the illustrative coal and natural gas combined cycle 

units and is therefore unable to specifically determine the population that would be affected by their SO2

emissions. Therefore, the benefits for any specific unit can be very different than the estimates shown here, 

though the proportion associated with CO2, which is a well dispersed global pollutant, will not be affected by 

location. 46 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. 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 NAS 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. 47 The presence of net benefits for a given regulatory option is a necessary but not a sufficient condition for 

optimal regulatory design. It does however; signify that the regulatory option is welfare improving for society.
5-32

gas at present: one price at which the private cost of a representative new coal unit falls below 

that of a representative NGCC unit, but the generation cost advantage remains outweighed by 

the environmental damages from the perspective of society as a whole; and an even higher 

price at which the environmental damages no longer outweigh the private cost advantage. This 

analysis presents three relevant ranges within the conditional distribution of future natural gas 

prices that can be classified as a range of likely gas prices, unexpectedly high natural gas prices, 

and unprecedented natural gas prices. It is important to note that this illustrative analysis 

considers variation in the natural gas price holding all else constant; as discussed above, an 

ideal analysis would vary other conditions simultaneously.

48 In general, this analysis shows that 

the policy would likely have a net benefit even under scenarios with much higher gas prices. 

Under some conditions, higher natural gas prices result in a net cost, holding all other 

parameters constant and disregarding benefits that we are unable to monetize.

49 However, it is 

important to note that this analysis is limited in the types of social benefits and costs 

considered, given that it does address the life-cycle pollution associated with fossil fuels along 

with the limitations of current SCC estimates, as previously discussed.

Likely Natural Gas Prices. As described earlier in this chapter, the base case modeling 

that EPA performed for this rule (as well as base case modeling that EPA has performed for 

other recent air rules) indicates that new fossil fuel-fired generating capacity projected to be 

built through 2020 will be either natural gas-fired combined cycle generation or coal-fired 

generation with CCS (the latter is assumed to be built with support from federal grants). This 

conclusion also holds for the high-demand and low-shale-gas sensitivity analyses considered 

above. As shown earlier in the illustrative analysis, it is only when gas prices reach 

approximately $9.60/mmBtu, that new conventional coal-fired generation becomes 

competitive with NGCC in terms of the levelized cost of electricity (in dollars per megawatt 

hour). 

Projections of future market conditions suggest that it is likely that natural gas prices 

will remain below this level. As noted earlier in this chapter, EIA’s projected natural gas price 

for 2020 in its reference scenario for AEO 2011 is $5.30 (in 2007 dollars). Even EIA’s most 

pessimistic gas sensitivity case (“low shale gas recovery per well”) only projects an electricity 

sector gas price of $7.01/mmBtu (in 2007 dollars) in 2020 (the “low shale gas recovery per play” 

scenario projects a price of $6.13/mmBtu (in 2007 dollars) in 2020). In other words, even under 

 48 For example, high economic growth would raise both natural gas and coal prices at the same time – extending 

the range of natural gas prices for which NGCC retained a cost advantage. 49 In reality this is unlikely to be the case. 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.
5-33

pessimistic natural gas sensitivity cases, NGCC is likely to remain the economic choice for 

generation over the next two decades even in the absence of this standard. In this scenario, it 

appears very likely that the costs – and benefits – of the proposed standard will be zero.

Unexpectedly High Natural Gas Prices. In this illustrative analysis, at natural gas prices 

above approximately $9.60/mmBtu, the private levelized cost of electricity for a representative 

new conventional coal unit falls below that of a new NGCC unit. Therefore, above that price 

level some new conventional coal units might be constructed in the absence of the standard,

provided there is sufficient demand and new coal without CCS is competitive with other 

generating technologies.50 However, these coal units would also impose additional 

environmental and health damages in the form of global warming pollution and particulate 

matter (as a result of SO2 and NOx emissions) – an element of social costs that are avoided by 

building an NGCC unit instead. 

For a range of natural gas prices above $9.60/mmBtu, the resulting external costs will 

outweigh the difference in the private costs in this illustrative example – indicating that the 

proposed standard would yield net benefits. For example, at gas prices of $10/MMBtu, the 

illustrative conventional coal unit would generate power for $3/MWh less than an NGCC unit,

51

but result in greater pollution damages of $9 to$50/MWh (see table 5-7).52 Under the 

proposed standard, if in this example the NGCC unit were built instead, the resulting net social 

benefit would be $6 to $47/MWh. 

For context, we note that these circumstances are far less likely than the zero cost 

scenario outlined above. To put this gas price point into historical context, $9.60/MMBtu is 

higher than any average annual gas price (in 2007 dollars) observed over the last 10 years, and 

it has only been reached temporarily in 8 of the last 120 months.53,54 Looking forward, the 

 50 See section 5.4 for a discussion of how local conditions and other factors influencing the levelized cost 

comparison may influence the natural gas price where the levelized cost of the conventional coal unit and the 

NGCC unit are the same. 51 Assuming an increase of $6.80/MWh in the cost of gas generation for every $1/MMBtu increase in natural gas 

prices. 52 Again, assuming that coal prices do not increase along with natural gas prices as they historically have. See 

previous footnote. 53 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 15 years (since 1996) and reports average monthly delivered natural gas 

prices to the electricity sector over the past 10 years (since 2001). 54 It is important to note that relatively high gases prices in a single month or year will not drive the investment 

decision in the technology employed for new generating units. Instead that decision will be motivated by 

expectations of relative fuel prices over the lifetime of the unit. Therefore given the historical path of natural 

gas prices and the forecasts for the future, it is highly unlikely that expectations of sustained high natural gas 

prices, to the degree necessary to drive technology choices, will be realized.
5-34

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 represent future price trajectories for both gas 

and coal) show scenarios where non-compliant coal becomes more economic than NGCC 

before 2020.

Unprecedented Natural Gas Prices. At extremely high natural gas prices, the private 

generating costs of non-compliant coal would be sufficiently lower than the cost of new natural 

gas that the net social benefit of the standard could be negative (i.e., a net cost) under some 

assumptions for environmental damages. For example, at gas prices of $15/MMBtu, the 

illustrative conventional coal unit would generate power for roughly $37/MWh less than an 

NGCC unit but result in social costs of $9 to $50/MWh (see table 5-7). Under the proposed 

standard, if an NGCC unit were built instead, the resulting net social impact would range from a 

net cost of $28 to a net benefit of $13/MWh. The point at which this standard would result in 

net social costs depends heavily upon the value for damages from GHGs and SO2. For example,

assuming an SCC using a 3% discount rate, along with a 7% discount rate for estimating benefits 

from reduced SO2 and the mortality-risk estimate from Pope (2002), natural gas prices above 

$12/mmBtu in this illustrative example would result in net social costs from the proposed 

standard. Alternatively, using an SCC value of 3% and using the mortality-risk estimate from 

Laden (2006) along with a 3% discount rate for PM benefits, the corresponding threshold for 

natural gas prices would be $14/mmBtu. Natural gas prices above these levels would be 

unprecedented. Average annual natural gas prices delivered to the electricity sector have not 

exceeded $9.47 /mmBtu (in 2007 dollars) over the last 15 years, and projected prices do not 

begin to approach this level in any of EIA’s scenarios.

55,56 As a result, based on historical gas 

prices as well as projections, EPA believes that there is an extremely small probability that 

natural gas prices will reach (let alone remain at) levels at which this standard would generate 

net social costs. 

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 benefits or 

 55 http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm. EIA reports average annual delivered natural gas 

prices to the electricity sector for the past 15 years (since 1996) and reports average monthly delivered natural 

gas prices to the electricity sector over the past 10 years (since 2001). 56 Note that while EIA forecasts natural gas prices to rise, it also forecasts coal price to rise as well. An ideal 

comparison of levelized costs in future time periods should account for the expected change in both natural gas 

and coal prices. 
5-35

net costs. However, based on average annual gas prices over the last 15 years, we project that 

this standard is most likely to have negligible costs, and, if it does impose costs, it likely also 

produces positive, although modest, net benefits. There is an exceedingly low probability that it 

results in net costs.

5.10.3 Illustrative Costs and Benefits of CCS Compared with Conventional Coal

The analysis above focuses on two well developed control technologies, conventional 

supercritical coal and natural gas combined cycle. Because these technologies are well 

developed, there is significantly more certainty about operating costs than for new, emerging 

technologies like coal with CCS. As a result, any analysis that examines the relative social costs 

of coal vs. coal with CCS is considerably more uncertain and should primarily be used as a guide

to the key sensitivities in the relative social costs. EPA compared the costs and damages for a 

model pulverized coal (PC) EGU using supercritical steam conditions (like the one used in the 

comparisons above) to and IGCC plant with a CCS system (e.g. Selexol). See technical memo 

“Control Cost and Environmental Impacts of the Proposed GHG NSPS on new Coal-Fired Electric 

Utility Generating Units” for more details.

EPA analyzed the cost and emission impacts for two scenarios. In the first scenario, 

partial capture achieves the proposed emissions rate of 1,000 lb CO2/MWh gross output. This 

requires that approximately 39% of the CO2 is captured and stored. EPA has not previously 

developed costs for such a unit, therefore, this analysis may not fully realize all of the cost 

savings possible from building a unit with significantly less than 90% capture (for instance, an 

IGCC could be built with a conventional gas turbine, rather than one designed for higher 

temperature characteristics of a higher hydrogen content fuel). A 90% capture system was also 

examined to analyze the cost of several proposed new coal-fired EGUs using CCS. 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 enhanced oil recovery (EOR) operations. This is because EOR provides a 

revenue stream that is not available for other forms of geologic storage. For example, the Texas 

Clean Energy project57 is planning to capture 90% of the CO2 and sell it for enhanced oil 

recovery. 

To evaluate the potential revenues from EOR we examined two options. We considered 

a case where CO2 could be sold for $45/ton based on recent DOE studies for the 90% capture 

case.

58 We also considered a lower revenue sensitivity where CO2 could be sold for $15/ton 

 57 http://www.texascleanenergyproject.com/ 58 US DOE / NETL studies have assumed a delivered CO2 price ranging from $40 - $45/tonne. “Improving Domestic 

Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil Recovery (CO2-EOR)”, 
5-36

(equivalent to the cost assumed for the transport and storage of CO2 in the analysis) for the 

partial capture case. Costs for the IGCC unit with 90% capture and the supercritical pulverized 

coal-fired (SPC) unit without CCS were derived from IPM version 4.10.59 These cost estimates 

are generally consistent with the range of studies estimating the cost of CCS that are available, 

however there is uncertainty around any such projections of technology costs, particularly for 

early movers of this technology. Capital costs for the IGCC unit with 39% capture were assumed 

to be 90% of the capital costs for an IGCC unit with 90% CCS. EPA estimated the benefits 

associated with avoided CO2 and SO2 emissions in a similar fashion to the one described above. 

See technical memo “Control Cost and Environmental Impacts of the Proposed GHG NSPS on 

new Coal-Fired Electric Utility Generating Units” for more details.

Table 5-8. Illustrative Costs and Benefits for two CCS Scenarios Compared to Conventional 

Coal Plant (per MWh 2007$)

SPC to IGCC with 39% 

Capture

SPC to IGCC with 90% 

Capture

Additional Gross Annual Private Costs $17 $34

Revenue from EOR $5 (@$15/ton) $37(@$45/ton)

Net Additional Annual Private Costs $12 ($3)

Value of Monetized Benefits

 SCC 3% with Pope 7% $13 $24

 SCC 3% with Laden 3% $23 $34

Net Monetized Benefits

 SCC 3% with Pope 7% $1 $27

 SCC 3% with Laden 3% $11 $37

This analysis suggests that the relative social cost of CCS compared to conventional coal 

is sensitive to the achieved generating costs for CCS units, the revenue stream from EOR, and 

the monetary value of avoided climate and other air pollution damages. However, it also 

suggests that, at relatively low prices for EOR revenue ($15/MWh), CCS generation can 

generate net social benefits compared to conventional coal generation. As before, it is 

important to note that these comparisons omit additional benefits that may be associated with 

the abatement of greenhouse gas emissions.

 

DOE/NETL-2011/1504 (June 2011); and “Storing CO2 with Enhanced Oil Recovery, DOE/NETL-402/1312 

(February 2008). 59http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html
5-37

5.11 Macroeconomic and Employment Impacts

This proposed EGU GHG NSPS is not anticipated to change GHG emissions for newly 

constructed electric generating units, and is anticipated to impose negligible costs or quantified

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. 

5.12 References

Baumol, W.J. and W. E. Oates, The Theory of Environmental Policy. 2nd Edition. Cambridge 

University Press: New York (1988).

Blyth, W. and Yang, M. and Bradley, R. Climate policy uncertainty and investment risk. 2007. 

OECD/IEA.

Dalia Patiño-Echeverri, Paul Fischbeck, and Elmar Kriegler. Economic and Environmental Costs 

of Regulatory Uncertainty for Coal-Fired Power Plants. Environmental Science & 

Technology 2009 43 (3), 578-584.

Hoffmann, Volker H. and Trautmann, Thomas and Hamprecht, Jens. Regulatory Uncertainty: A 

Reason to Postpone Investments? Not Necessarily. Journal of Management Studies 

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Joskow, P.L. 2010. Comparing the Cost of Intermittent and Dispatchable Electricity Generating 

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Pollution and Mortality. American Journal of Respiratory and Critical Care Medicine 

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climate proposals [Radio transcript]. Dow Jones News [Online]. Available: Dow Jones 

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Mufson, S. 2011, January 2. Coal’s burnout. The Washington Post. Retrieved from 

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Muller, N.Z., R. Mendelsohn, and W. Nordhaus. Environmental Accounting for Pollution in the 

United States Economy. American Economic Review. 101:1649-1675.

Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Calle, D. Krewski, K. Ito, and G.D. Thurston. 2002. 

Lung Cancer, Cardiopulmonary Mortality, and Long-term Exposure to Fine Particulate Air 

Pollution. Journal of the American Medical Association 287:1132-1141.

Reinelt, Peter S.; Keith, David W. Carbon Capture Retrofits and the Cost of Regulatory

Uncertainty. Energy Journal, 2007, Vol. 28 Issue 4, p101-127.

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Retrieved from http://www.energybiz.com/magazine/article/234577/reign-cheap-gas.

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Tong, S. 2010, November 1. Placing Bets on Clean Energy. [Radio transcript]. American Public 

Media: Marketplace [Online]. Available: Marketplace Programs on Demand.

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Energy Production and Use. National Academies Press: Washington, D.C.

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Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for 

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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 GHG NSPS.1 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, 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, 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, 

EPA believes this rule will have negligible compliance costs associated with it, over a range of 

likely sensitivity conditions, because even in the absence of the proposal, 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. Because our modeling shows 

 1 Electricity Generating Unit Greenhouse Gas New Source Performance Standard - The NSPS would be established 

under section 111(b) of the Clean Air Act (CAA). 
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that new fossil-fuel fired capacity constructed through 2020 will most likely be natural gas 

combined cycle capacity along with a small amount of coal with CCS supported by federal 

funding, the proposed standard of performance –– which is based on the emission rate of a 

new NGCC unit –– would not add costs. The EPA does not project any new coal-fired EGUs 

without CCS to be built.

6.3 Paperwork Reduction Act

The information collection requirements 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 Request (ICR) document prepared by the EPA has been assigned EPA ICR 

number 2465.01. 

 This proposed action would impose minimal new information collection burden on 

affected sources beyond what those sources would already be subject to under the authorities 

of CAA parts 75 and 98. OMB has previously approved the information collection requirements 

contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under 

the provisions of the 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 without CCS 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 would commence operation

during that time period. As a result of this proposal, those units would be required to prepare a 

summary report, which includes reporting of excess emissions and downtime every 6 months.

When a malfunction occurs, sources must report them according to the applicable 

reporting requirements of 40 CFR part 60, subpart TTTT. An affirmative defense to civil 
6-3

penalties for exceedances of emission limits that are caused by 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 malfunction (sudden, 

infrequent, not reasonable preventable, and not caused by poor maintenance and or careless 

operation) 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 the affirmative defense position adopted by a source, 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 totals $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.

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 source owners or operators previously operated their facilities in 

recognition that they were exempt from the requirement to comply with emissions standards 

during malfunctions. Of the number of excess emissions events reported by source operators, 

only a small number would be expected to result from a malfunction (based on the definition 

above), and only a subset of excess emissions caused by malfunctions would result in the 

source choosing to assert the affirmative defense. Thus, we believe the number of instances in 
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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 TTTT 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 semi-annual summary reports which include reporting of excess 

emissions and downtime. All burden estimates are in 2010 dollars. Average burden hours per 

response are estimated to be 16.5 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 proposed rule, which includes this ICR, under Docket ID 

number EPA-HQ-OAR-2011-0660. 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 as Amended by the Small Business Regulatory Enforcement 

Fairness Act of 1996, 5 U.S.C. et seq.

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.

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 
6-5

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.

Federal Government 221112b Fossil fuel electric power generating units owned by the federal 

government.

State/Local 

Government

221112b Fossil fuel electric power generating units owned by municipalities.

Tribal Government 921150 Fossil fuel electric power generating units in Indian Country.

a Include NAICS categories for source categories that own and operate electric power generating units (includes boilers and 

stationary combined cycle combustion turbines).

b Federal, state, or local government-owned and operated establishments are classified according to the activity in which they 

are engaged.

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 sensitivities as a result of this proposal. Thus the costto-sales 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 proposal because of existing 

and expected market conditions. (See the RIA for further discussion of sensitivities.) Because 

our modeling shows that new fossil-fuel fired capacity constructed through 2020 will most likely 

be natural gas combined cycle capacity along with a small amount of coal with CCS supported 

by federal funding, the proposed standard of performance –– which is based on the emission 

rate of a new NGCC unit –– would not add costs. The EPA does not project any new coal-fired 
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EGUs without CCS to be built. Accordingly, there are no anticipated economic impacts as a 

result of this proposal.

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, 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 has 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 would 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 Cross-State Air Pollution 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. The EPA 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 five listening sessions that EPA held in February and March 2011 with various 

stakeholder groups to get feedback from key stakeholders and the public before the agency 

initiated the rulemaking process for new greenhouse gas emissions standards.

2 EPA 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.

 2 http://www.epa.gov/airquality/listen.html
6-7

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 for 

both new and existing sources. Specifically, topics discussed included: boilers with limited 

opportunities for efficiency improvements due to 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 determination of carbon neutrality 

of biomass; and differences between municipal government electric utilities and other utilities.

Small entities expressed concern regarding units making modifications being regulated 

as new sources. As explained above, we are not proposing a standard of performance for 

modifications. As a result, sources that undertake modifications would be treated as existing 

sources and thus would not be subject to the requirements proposed in this notice. As also 

explained above, the EPA is not proposing standards of performance for existing proposed 

EGUs, which are referred to as transitional sources, that have acquired a complete 

preconstruction permit by the time of this proposal and that commence construction within 12 

months of this proposal. As a result, any transitional sources owned by small entities would not 

be subject to the standards of performance proposed in today’s rule.

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 of 1995

This proposed rule does not contain a Federal mandate that may result in expenditures 

of $100 million of 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 

proposal because of existing and expected market conditions. (See the RIA for further 

discussion of sensitivities.) As previously explained, because our modeling shows that new 

fossil-fuel fired capacity constructed through 2020 will most likely be natural gas combined 

cycle capacity along with a small amount of coal with CCS supported by federal funding, the 

proposed standard of performance –– which is based on the emission rate of a new NGCC unit 

–– would not add costs. The EPA does not project any new coal-fired EGUs without CCS to be 
6-8

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 interest in this rule among governmental entities, the EPA initiated 

consultations with governmental entities. 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 purpose of consultation with elected officials. The purposes of the consultations

were to provide general background on the proposal, answer questions, and solicit input from 

state/local governments. The EPA’s consultation regarded planned actions for new and existing 

sources, but only new sources would 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.

6.6 Executive Order 13132, Federalism

This proposed action does not have federalism implications. It would 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 
6-9

government, as specified in EO 13132. This proposed action would not impose substantial

direct compliance costs on state or local governments nor would it preempt state law. Thus, 

Executive Order 13132 does not apply to this action. 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 would be affected by this proposed action. 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 this chapter includes a description of the consultation. 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

Subject to the EO 13175 (65 FR 67249, November 9, 2000) EPA may not issue a 

regulation that has tribal implications, that imposes substantial direct compliance costs, and 

that is not required by statute, unless the Federal government provides the funds necessary to 

pay the direct compliance costs incurred by tribal governments, or EPA consults with tribal 

officials early in the process of developing the proposed regulation and develops a tribal 

summary impact statement. 

EPA has concluded that this proposed action would not have tribal implications. 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 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.

Because the EPA is aware of tribal interest in this proposed rule, the EPA offered 

consultation with tribal officials early in the process of developing this 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.
6-10

Consultation letters were sent to 584 tribal leaders. The letters provided information 

regarding 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 

listening sessions on this 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.

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 proposed action is not 

subject to EO 13045 because it is based solely on technology performance. The proposal is not 

expected to produce changes in emissions of greenhouse gases or other pollutants but does 

encourage the current trend towards cleaner generation, helping to protect air quality and 

children's health. The Agency recognizes that children are among the groups most vulnerable 

to climate change impacts and the public is invited to submit comments or identify peer 

reviewed studies relevant to this proposal.

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 
6-11

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.

This proposed rulemaking involves technical standards. The EPA cites 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. EPA has determined that this proposed rule would not 

result in disproportionately high and adverse human health or environmental effects on 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-12-001

March 2012