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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 (and 

under some proposed options, reconstructed) fossil fuel fired electric generating units (EGU)

constructed in the United States in the future.1This 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. . 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 CAA 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.
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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 the 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.

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 

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 condition coal-fired 

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

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

Administration (EIA), 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. or are not covered to the 

NSPS.
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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, EPA does not anticipate that the proposed EGU GHG NSPS will 

result in notable CO2 emission changes, energy impacts, monetized benefits, costs, or economic 

impacts by 2020. Accordingly, EPA also does not anticipate that this rule will have any impacts 

on the price of electricity, employment or labor markets, or the US economy. may 

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 provides an important safeguard 

against 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 an illustrative economic analysis indicating that even in the 

unlikely event that market conditions change sufficiently to make the construction of new 

conventional coal-fired units economic from the perspective of private investors, such units 

would be expected to impose net social costs relative to new NGCC units, implying net benefits 

from this proposed rule.

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

limiting GHG from new EGU sources. 

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.”4In 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 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. Carbon capture also can help to 

 

4

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

http://www.whitehouse.gov/sites/default/files/blueprint_secure_energy_future.pdf
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improve U.S. energy production through enhanced oil recovery, as highlighted by a series of 

regional assessments conducted for DOE.6

Finally, 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.

 

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.
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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. 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.

Section 111(b) authorizes EPA to issue NSPS for CO2 from new sources. Upon finalization 

of the CO2 NSPS for new sources, Section 11(d) requires EPA to conduct a rulemaking 

establishing standards for existing sources, which states would implement through the submit 

of implementation plans to the EPA. 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.7This action addresses Section 111(b) for new sources but does not address 

Section 111(d) existing sources at this time. Existing sources will be addressed in a separate 

action at a later date by the EPA.

 

7

http://www.epa.gov/airquality/ghgsettlement.html
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1.3 Regulatory Analysis 

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

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

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 benefits will result from those parts of the standards. For new 

sources, EPA 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 baseload 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 not anticipated to have any costs 

or monetized 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 historical and projected 

gas prices, indicates that this standard is highly likely to have no costs or benefits; that there is 

some small probability that the standard produces net benefits; and that the probability that 

the standard results in net costs to society is exceedingly low.
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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.8

As described in the preamble, EPA does not have information indicating that affected 

EGUs would undertake modifications, and is thus not proposing any standards for 

modifications. Additionally, 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.

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 

 

8

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.
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commitments for GHG reductions considered in the baseline are discussed in Chapter 5 of this 

RIA.

All analysis is presented for a compliance year on or before 2020 and all estimates are 

presented in 2007$. 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.
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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 
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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 that emit CO2 as a byproduct are specifically exempted from the definition of 

“modifications” under 40 CFR 60.14(e)(5). 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.

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, approximately 90 coal plants have been permitted. Of those, 40 (or less than 

half) have actually commenced construction. Thirty projects have been cancelled and 
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approximately 15 sources (the transitional sources) have active permits. Based on this history

and current economic conditions,– in particular, . 

EPA believes the 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, the EPA believes that very few power plants have undertaken 

reconstructions. We 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 about the type of source; the type of 

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

cost and emissions reductions, that is needed to propose a standard of performance for 

reconstructions. EPA is soliciting comment on these issues.

The EPA is not proposing standards of performance for reconstructions at this time, but 

is instead soliciting comment on two different options. Under the first, we would not 

promulgate a standard of performance concerning reconstructions when we finalize this action, 

but, depending on the information we receive, we may propose and finalize such a standard at 

a later time. Under the second option, we would finalize a standard of performance. Under one 

sub-option, we would finalize a standard of 1,800 lb CO2/MWh (gross). This would be consistent 

with the first phase requirement for new sources availing themselves of the alternative 

compliance option to use a 30-year average. A second sub-option would treat reconstructed 

sources the same as any other new source (e.g. subject to an emission limit of 1,000 lb 

CO2/MWh). This sub-option could be based on the view that if the owner of a source plans to 

invest enough capital into an existing unit to reach the reconstructed threshold, it is likely with 

the intent of significantly increasing the life of the plant. The purpose would be to avoid 

creating an incentive for an owner to forego building a new clean facility, in favor of merely 

reconstructing an existing facility that operated with higher emissions.
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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.

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 does not anticipate 

that the proposed EGU GHG NSPS will result in any changes in GHG emissions 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 do not anticipate that this rule will have any costs 

or monetized benefits during the analysis period, or any impacts on the price of electricity, 

labor markets, or the general economy.
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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. These proposed rules are designed to minimize emissions of 

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

therefore reducing the risk of adverse effects. The adverse effects on public health and public 

welfare detailed in the 2009 Endangerment Finding are summarized in this chapter.

9

The major 

assessments by the U.S. Global Climate 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 

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 

 

9

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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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 

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. 
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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 

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. 
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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, 

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 
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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 

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. 
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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. 

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. 
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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 

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 
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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.10 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. 

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 

 

10 ‘‘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).
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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 

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.
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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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4-1

CHAPTER 4

ELECTRIC POWER SECTOR PROFILE

4.1 Introduction

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

proposed EGU 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).

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%
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4-2

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.

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.

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%

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).

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%
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4-3

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.

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
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Totals 1,266

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

level of fuel efficiency. Table is limited to 

units with planned retirements.

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

Source: National Electric Energy Data System (NEEDS

Note: This map displays facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capa

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

concentration of facilities, some facilities may be obscured.

4.2.2 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 i

high voltage transmission lines,

11

 

11 These three network interconnections are the western US and 

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.

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4-4

316,480

National Electric Energy Data System (NEEDS) v.4.10

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

weighted or capacity-weighted average heat rate.) A lower heat rate indicates a higher 

efficiency. Table is limited to coal-steam units online in 2010 or earlier, and excludes those 

units with planned retirements.

Fired Electricity Generating Facilities, by Size

National Electric Energy Data System (NEEDS) 4.10 

facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capa

his includes planned new builds and planned retirements. In areas with a dense 

concentration of facilities, some facilities may be obscured.

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 

In the US and Canada, there are three separate interconnected networks of 

11 each operating at a common frequency. Within each of these 

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 

rconnect Region, and ERCOT, respectively.

Do Not Cite, Quote, Or Release During Review ***

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

A lower heat rate indicates a higher 

steam units online in 2010 or earlier, and excludes those 

facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capacity on-line by the 

his includes planned new builds and planned retirements. In areas with a dense 

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 

nterconnected networks of 

Within each of these 

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 
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4-5

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.

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 

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 
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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.

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

Source: EIA 2010b. 
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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.

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

equivalent)

Source: EPA 2011

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
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Electrical Transmission and Distribution

Total

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 (

carbon content than oil or natural gas and, thus, releases more CO

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).

Figure 4-4. GHG Emissions from the Power Sector 

Emissions (2009)

Source: EPA 2011

Table 4-7. Fossil Fuel Emission Factor

Fuel Type

Coal 

Bituminous 

Subbituminous 

Lignite 

Natural Gas 

Fuel Oil 

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Electrical Transmission and Distribution 12.8

2,193.0

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

rule, which specifically regulates GHG emissions from combustion.

Eq. or 0.05 percent.

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. C

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

EPA 2011).

from the Power Sector Relative to Total Domestic GHG 

Fuel Emission Factors in EPA Modeling Applications

Carbon Dioxide (lbs/MMBtu)

205.2 – 206.6

212.7 – 213.1

213.5 – 217.0

117.1

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12.8

2,193.0

emitted during the combustion of fossil fuels varies according to the 

7). Coal has higher 

during combustion. Coal 

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

Relative to Total Domestic GHG 

Carbon Dioxide (lbs/MMBtu)
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Distillate 161.4

Residual 161.4 – 173.9

Biomass* 195

Waste Fuels 

Waste Coal 205.7

Petroleum Coke 225.1

Fossil Waste 321.1

Non-Fossil Waste 0

Tires 189.5

Municipal Solid Waste 91.9

Source: Documentation for IPM Base Case v.4.10. See also Table 9.9 of IPM Documentation.

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

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

source).

4.5 Pollution Control Technologies

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

(1) carbon capture and storage; (2) improved fuel efficiency; (3) switching to lower-emitting 

fuels; (4) increased generation share from lower-emitting sources; (5) decreased loss of power 

via transmission and distribution systems; and (6) 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 demonstration projects for large-scale power sector applications

are currently under construction but have not operated.. 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 
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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.

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

Source: Interagency Task Force on Carbon Capture and Storage 2010

Pre-combustion capture is mainly applicable to IGCC facilities, where the fuel is 

converted into 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).
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Figure 4-6. Pre-Combustion CO2 Capture for an IGCC Power Plant

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.12 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 

 

12 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.
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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 6-8.

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 NOxformation. 

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)
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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 
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“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 
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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.
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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.13

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.

 

13 http://www.epa.gov/airquality/ghgsettlement.html
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Over the past 50 years, real retail electricity prices have ranged from around 7 cents per 

kWh in the early 1970s, to around 11 cents, reached in the early 1980s. Generally, retail 

electricity prices do not change rapidly and do not display the variability of other energy or 

commodity prices, although the frequency at which these prices change varies across different 

types of customers. Retail rate regulation has largely insulated consumers from the rising and 

falling wholesale electricity price signals whose variation in the marketplace on an hourly, daily, 

and seasonal basis is critical for driving lowest-cost matching of supply and demand. In fact, the 

real price of electricity today is lower than it was in the early 1960s and 1980s (see Figure 4-7).

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.
***E.O. 12866 Review–Draft

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

Owned 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

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

Source: EIA 2010a

On a state-by-state basis, retail electricity prices vary considerably.

California have average retail prices that can be as much as 

Figure 4-8).

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Projected Revenues by Service Category in 2015 for Public Power and Investor

Owned Utilities (billions)

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).

National Average Retail Electricity Price (1960 – 2009)

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 

Do Not Cite, Quote, Or Release During Review ***

Projected Revenues by Service Category in 2015 for Public Power and InvestorData 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 

The Northeast and 

se of other states (see 
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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.
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Figure 4-9. Natural Gas Spot Price, Annual Average (Henry Hub)

Source: EIA 2010c, EIA 2011

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, 2010d). 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 energy expenditures. 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 failures. These 

broader changes have altered the outlook for future electricity growth (see Figure 4-10). 
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-2%

0%

2%

4%

6%

8%

10%

12%

-2%

0%

2%

4%

6%

8%

10%

12%
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-2%

0%

2%

4%

6%

8%

10%

12%

-2%

0%

2%

4%

6%

8%

10%

12%
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-2%

0%

2%

4%

6%

8%

10%

12%

-2%

0%

2%

4%

6%

8%

10%

12%
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Figure 4-10. Electricity Growth Rate (3 Year Rolling Average) and Projections from the 

Annual Energy Outlook 2011

Source: EIA 2009, EIA 2011

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 

-2%

0%

2%

4%

6%

8%

10%

12%

-2%

0%

2%

4%

6%

8%

10%

12%
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4-26

growing number of states that have adopted energy efficiency resource standards.14 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 

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. 

 

14 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.
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

4-27

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.

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

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

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

online at: http://www.eia.gov/totalenergy/data/annual/pdf/aer.pdf.

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2011. 2011. Available 

online at: http://www.eia.gov/forecasts/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 projected during the 

analysis period (through 2020) are compliant with the requirements of this rule (e.g. combined 

cycle natural gas).).). This conclusion also holds for several sensitivity analyses EPA performed. 

As a result, under a wide range of likely future electricity market conditions,,, this proposed 

EGU GHG NSPS is not expected to change GHG emissions for newly constructed EGUs, nor is it 

anticipated to impose notable 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., and 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.

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 

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 ..... 
5-2

There is one principal reason why EPA expects no unplanned coal-fired power plants will 

be constructed over the time horizon considered for this analysis. Generating technologies for 

new plants using natural gas produce electricity at lower levelized cost than other 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. This circumstance is different than that of a few years ago 

because current and forecast natural gas prices are considerably lower than the levels seen 

over the past decade, largely due to advances in hydraulic fracturing and horizontal drilling 

techniques that have opened up new shale gas resources and hydraulic fracturingsubstantially 

increased the supply of natural gas. Based on these market conditions, on average the levelized 

cost of generation from a new natural gas power plant is expected to be lower than the cost of 

generation from a new coal-fired power plant.

15

 This trend has already been observed recently, 

as natural gas-fired capacity was the technology of choice for power generation over the last 

few years (see Figure 5-1).

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

 

15 Levelized Cost of New Generation in the Annual Energy Outlook (AEO) 2011, 

http://205.254.135.24/oiaf/aeo/electricity_generation.html 
5-3

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

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

Numerous energy sector modeling efforts, including recent projections from the Energy 

Information Administration (EIA), have provided results that are consistent with these findings. 

The Annual Energy Outlook (AEO) for 2011 shows a very modest amount of CCS-equipped new 

coal-fired power coming online past 2012, however since these plants are CCS-equipped in 

response to Federal incentives, they would be in compliance with this proposal.

16

 According to 

the AEO 2011, the majority of new generating capacity is forecast to be either natural gas-fired 

or renewable, with some lesser amounts of nuclear power. The AEO 2011 is based on existing 

policy and regulations, such as state Renewable Portfolio Standard programs and Federal tax 

credits for renewables.17 BasedBasedBased on EIA analysis, DOE concluded that “the low 

 

16 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.

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

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Capacity (M

W)

Other

Gas (CC and CT)

Renewable/Hydro

Nuclear

Coal
5-4

capital expense, technical maturity, and dispatchability of natural gas generation are likely to 

dominate investment decisions under current policies and projected prices."18 The economics 

favoring new NGCC builds instead of conventional coal are robust under a range of sensitivity 

cases examined in the AEO. Unplanned additions of coal by 2020 increase in sensitivity cases 

that separately examine higher economic growth, lower coal prices, low fossil costs, no concern 

regarding future GHG policy, slow oil and gas technology deployment, low shale gas recovery 

per play, and low shale gas recovery per well. In addition, EIA’s AEO 2012 Early Release does 

not forecast new unplanned coal capacity over the period analyzed. Furthermore, it projects an 

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

that natural gas is likely to be the fossil fuel of choice during the analysis period. The AEO 2012

ER also has lower electric demand projections than those used in IPM, 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.19 

EPA has used IPM extensively over the past two decades in order 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.20

The baseline information in this RIA includes the recently finalized Mercury and Air 

Toxics Standards (MATS) and Cross State Air Pollution Rule (CSAPR).).). ). 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.

 

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

http://energy.gov/sites/prod/files/QTR_report.pdf.

19 http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation

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

As noted above, 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 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

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.

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
5-6

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 Granular Model

EPA typically presents IPM outputs in aggregate, in order to support analysis reflecting 

nationwide impacts of a policy. Some additional regional detail is presented, where 

appropriate. Although the Agency typically focuses on the broader 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, 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 

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 
5-7

(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

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 proposed 

MATS and the proposed Transport Rule (finalized as CSAPR).21

The IPM base case projection includes a 1 percent growth in electricity demand, similar 

to EIA’s Annual Energy Outlook for 2010, which serves as the basis for IPM’s electric demand 

projection. 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. 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 

 

21 http://www.epa.gov/airquality/powerplanttoxics, and http://www.epa.gov/airtransport.
5-8

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). Relative to current levels, EPA anticipates that the existing 

coal fleet will increase generation while gas-fired sources will not change significantly by 2020. 

This dynamic largely emanates from somewhat atypical supply and demand trends experienced 

in energy markets over the past few years, where overall electricity demand has been soft, 

natural gas prices have dropped considerably, and coal prices have risen. 

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

2010 2020

Pulverized Coal 317 299

Natural Gas Combined Cycle 201 212

Combustion Turbine 138 143

Oil/Gas Steam 115 90

Non-Hydro Renewables 31 73

Hydro 99 99

Nuclear 102 106

Other 5 7

Total 1,009 1,029

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

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

Note: “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 0.129

Natural Gas 901 873

Nuclear 807 841

Hydroelectric 258 287

Non-hydro Renewables 139 288

Other 4 45

Total 3,972 4,309
5-9

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 rojection from IPM run by EPA, 2011.

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 corecore ?central parameter estimates that underly the reference case. Even under 

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

new coal-fired power plants, the AEO 2011 shows no new (unplanned) coal builds through 

2025. 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.22 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. Therefore, while the fairly robust expectation is 

that no new unplanned coal capacity will be built within the time horizon of this analysis, there 

remains a very small probability that new coal capacity might be constructed absent this 

regulation. We return to this issue in section 5.12, below. 

In addition to 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. The low 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 thatthatthat electricity 

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

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

similar to the reference case in AEO 2010). Charts 5.xx and 5.yy illustrate electricity demand 

and natural gas price in these sensitivity analyses. Note that the EPA sensitivity analyses show 

considerably higher natural gas prices and higher electricity demand growth than the 

comparable AEO 2011 scenarios, which is a result of XXXX .

23

 

 

22 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. 

23 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 3.5% 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 
5-10

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

 

2020 that is 6.5% higher than the reference case AEO 2011 demand for 2020, and 3.4% 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).

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
5-11

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. 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.

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 newnewnew units. 

Analysis performed by EPA, along with information from other sources, suggests that the 

standards as specified in this proposed rule are not likely to result in notable emission changes, 

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/m

mBtu)
5-12

energy impacts, monetized benefits, 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.24

5.6.1 New Units

This proposal requires that all new fossil-fuel fired units of 25 megawatt or greater 

capacity be able to meet an emission rate standard of 1,000 lbs CO2/MWh on a gross basis. It 

also proposes an alternative standard 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. 

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.25 AsAsAs discussed in section 5.5, nonono 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 forecast 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, nor any costs.

As described above, 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 or combustion turbine generation or coal-fired generation with CCS (the latter 

is assumed to be built with support from federal grants). The EIA’s AEO 2011 modeling makes 

similar conclusions. A number of major utilities have made public announcements consistent 

with these modeling results.26

 

24 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.

25 Natural gas combustion turbines are not covered by this proposal.

26 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 
5-13

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 

5-3. 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.28 

Note that this figure only shows the costs to the generator and does not reflect social costs 

associated with 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 2020,29

electricity generated by natural gas combined cycle units is less expensive on average than coal 

generation. 

 

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.

28 See http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html, and 

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

29 EIA projects a U.S. average coal price of $1.65/MMBtu in 2020 ($2009). Bituminous coals are roughly $2. EPA 

and EIA both project delivered (power sector) natural gas price of roughly $5/mmBtu in 2020.
5-14

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

Technologies, EPA ($2007)

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. 

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. For context, even EIA’s most pessimistic gas 

sensitivity case (“low shale gas recovery per well”) only projects an electricity sector gas price 

of $6.79 in 2020 (the “low shale gas recovery per play” scenario projects a price of 

$5.93/mmBtu in 2020).

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

$/M

Wh
5-15

ItItIt 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.30 

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. . However, the results are expected to hold for the majority of situations.

Table 5-3. 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 6.1

 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

This rule also proposes an alternative standard that would allow new units to meet the 

1,000 lbs CO2/MWh standard using a 30 year averaging period. To the extent market 

participants have alternative views of both cost and development of CCS, new conventional 

 

30 http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf
5-16

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 in 

turn 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. 

Others have done research to explore the cost and efficiency of varying levels of capture 

relative to building alternative energy technologies.31 This ongoing research indicates that 

lower levels of carbon capture at new coal facilities could be cost competitive with these 

technologies, and the costs of meeting the proposed emission rate immediately could be 

achievable and economic. 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.

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 the proposed NSPS, EPA is taking comment on different 

approaches to regulation of reconstructed sources. The options for reconstructed sources, in 

general, include (i) establishing the standard of performance at the same level as for new 

sources, (ii) establishing the standard performance at 1,800 lb CO2/MWh, or (iii) not 

establishing a standard of performance for reconstructed units at this time.

 

31 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
5-17

EPA would not expect either alternative to change firms’ behavior because they would 

be expected to choose technologies that are compliant with the standard even in the absence 

of the standard. The costs associated with reconstructing coal-fired units are likely to be similar 

to the cost of building a new natural gas-fired unit. Thus, even if this provision is triggered, EPA 

believes that the economic analysis outlined above showing that natural-gas-fired generation is 

significantly more cost effective than building a reconstructed coal plant results in the choice of 

natural gas combined cycle or coal with CCS technology (i.e., existing unit operators are likely to 

choose technologies for independent market reasons that are already compliant with the new 

source NSPS included in this proposal).

5.6.3 Modified Units

As explained in the preamble, 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 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. The EPA is 

soliciting comment on this issue, but in the meantime, the EPA is not proposing standards for 

modifications. The Agency believes that it does not, at present, have adequate information as 

to the type of action, its costs, or the amount of its CO2 emissions, on which to base a proposed 

standard of performance. Therefore, sources that undertake physical or operational changes 

that increase their maximum achievable hourly CO2 emission rate will be treated as existing 

sources, and thus they will not be subject to the proposed EGU GHG NSPS requirements for 

new sources.

5.6.4 Transitional Units

In the proposal, EPA identifies transitional sources as those sources that have received 

final PSD permits, but have not actually commenced construction. EPA is proposing that as long 

as units commence construction within a set amount of time, construction can proceed without 

being affected by this rule. While this proposed rule sets no standard for the transitional 

source subcategory of new sources, these sources may become subject to an existing source 

standard in a subsequent rulemaking. 

EPA believes that there are approximately 15 such units discussed previously in Chapter 

2. Historically, obtaining a permit does not guarantee that a unit will end up being constructed. 

In the last 10 years, 88 coal plants have been permitted. Of those, 40 (or fewer than half) have 
5-18

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

sources (the transitional sources) have active permits. Based on this history and current 

economic conditions, EPA believes that at least some number of these units would not likely 

proceed to construction, regardless of the requirements of this rule. Based on this history, EPA 

believes that at least some number of these units would not likely proceed to construction, 

regardless of the requirements of this rule. For these units, this rule adds no costs. Once a unit 

has received a final PSD permit, it must commence construction within 18 months. The units 

EPA has potentially identified as “transitional” were permitted prior to this rule being proposed. 

EPA is proposing that as long as units commence construction within 12 months, construction 

can proceed without being affected by this rule. For these units, this rule adds no additional 

costs and will not result in any monetized benefits.

In the absence of this rule, EPA believes the coal units within this transitional category 

that are most likely to commence construction are those that have received public incentives to 

install CCS. Under the proposed rule, these units could commence construction within the 

proposed time-frame without incurring any requirement to reduce CO2 emissions. EPA believes 

that the economics demonstrated above also apply to the other transitional units; such that

building natural gas-fired combined cycle generation is likely to be a less expensive option than 

traditional coal-fired generation, even in the absence of this rule. The developers of the 

projects already permitted are likely considering these economic factors and may ultimately 

choose not to commit to actual construction of these previously proposed coal and petroleum 

coke plants.

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

Reconstructed, Modified, and Transitional Electric Generating Units

UnderUnderUnder a wide range of likely electricity market conditions – including EPA’s 

baseline scenario as well as multiple sensitivity analyses – EPA projectsprojectsprojects that the 

industry will choose to construct new units that already meet these standards, regardless of 

this proposal. AsAsAs a result, EPA does not anticipate that the proposed EGU GHG NSPS will 

result in notable CO2 emission changes, energy impacts, or costs for new units constructed by 

2020. Likewise, the Agency does not anticipate anyanyany notable impacts on the price of 

electricity or energy supplies. 

This finding is supported by EPA modeling of the base case, which does not project the 

future construction of new coal-fired capacity 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
5-19

appropriated funding to DOE for CCS deployment. 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). 

In addition, future electricity demand expectations have trended downwards in recent 

forecasts, reducing the need for new capacity by 2020 (see Chapter 4 for more discussion on 

future electricity demand)))... Electricity demand is anticipated to grow by roughly 1 percent 

per year, and total electricity demand is projected to be 4,104 billion kWh by 2015. Table 5-2

shows current electricity generation alongside EPA’s projection for 2020 using IPM. 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. 

5.9 Benefits of Reduced Regulatory Uncertainty

Because most major actors in the power sector anticipate eventual CO2 emissions policy 

for power plants, a performance standard for new sources can reduce uncertainty by setting 

clear parameters for the planning of new generation. The presence of sustained regulatory 

uncertainty may affect the decisions of firms, leading them to potentially forgo more profitable 

investment strategies that would occur in the presence of increased regulatory certainty 

(Teisberg 1993, Hoffmann et al., 2009). In particular, uncertainty regarding future greenhouse 

gas policy may affect firms’ decisions with regards to the timing and types of investments made 

in new electricity generating capital (Blyth et al., 2007). A significant reduction in regulatory 

uncertainty may then increase the expected profits for firms within the electricity generating 

sector by allowing them to optimize investment decisions with a greater understanding as to 

the future operating environment (e.g., Reinelt and Keith, 2007; Patiño-Echeverri et al., 2009). 

EPA is not able to directly quantify or monetize this benefit at this time.

5.10 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 not anticipated to have monetized benefits or costs

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.
5-20

As Table 5-4 below shows, emissions from a typical new natural gas combined cycle 

facility are significantly lower than those from a traditional coal unit.32 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, metals, acid gases, and particulate emissions than a comparable natural gas

combined cycle facility. A typical natural gas combined cycle unit emitsemitsemits two million 

metric tons less CO2 per year than a typical new conventional coal unit, as well as, 2,000 fewer 

short tons SO2 and 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.

Table 5-4. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired Generating Units

Conventional Coal Natural Gas CC Coal with CCS

SO2 tons/year 2,000 --- Negligible

NOx tons/year 1,400 200 1,100

CO2 mtmtmt/year 3.6 million 1.6 million 0.45 million

Notes: SO2 and NOxin short tons, CO2in metric tons. Relative emissions for new well controlled 600 MW (net) units running at 

85 percent capacity factor. Assumed coal is high sulfur bituminous with scrubber and SCR, data are based on EPA assumptions 

used in IPM.

5.11.5.11511 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 the external 

social costs associated with different generation technologies. The. 

Here we provide a general discussion aboutThe 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 presented in Table 5.4. 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, 

 

32 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

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 SCC Technical Support Document (SCC TSD) 

provides a complete discussion of the methods used to develop these SCC estimates.33 

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.34 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 5-55-55-5 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.

 

33 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

34 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.
5-22

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, 

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.35 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.

 

35 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.
5-23

Table 5-5. 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 are dollar-year and emissions-year specific.

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 avoiding 

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 
5-24

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 and years of operation, 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 estimated 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) of 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 XXXXX).).). Additionally, reducing 

one thousand tons of annual NOX from U.S. EGUs in 2020 has been estimated to yield up to 1 

incidence of premature mortality avoided annually and annual monetized PM2.5-related health 

benefits (including these incidences of 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.

36

5.12 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. 

 

36 The SO2 and NOX benefit per-ton 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 (Air Quality 

Modeling Technical Support Document for the final Transport Rule; 

http://epa.gov/airtransport/pdfs/AQModeling.pdf) used to develop a previous rulemaking affecting power 

sector emissions of SO2 and NOX to develop these benefit per-ton values, which are methodologically 

consistent with those reported in Fann et al. (2009). As such, the national average benefit per-ton 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 benefit per-ton 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 benefit 

per-ton estimates do not reflect emission reductions after implementation of EPA’s Mercury and Air Toxics 

Standards. EPA provides two estimates of PM2.5 mortality impacts, a low estimate based on Pope et al. (2002) 

and a high estimate based on Laden et al. (2006).
5-25

In this section, we consider the unlikely event that future market conditions would 

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 aaa representative NGCC unitunitunit.

37

 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 should account for the 

pollution damages associated with the competing generation technologies in addition to 

private generating costs. This section further explores the social costs of this NSPS standard 

across a wide range of natural gas prices, a key factor in the cost of the policy. It begins by 

estimating illustrative environmental damages per MWh for coal relative to gas generation and 

then uses these estimates to conduct an illustrative breakeven analysis for the social costs of 

the policy.38

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 

estimated 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 (i.e., different combinations of natural gas 

and coal prices and electricity demand). The effects of the proposed EGU GHG NSPS could then 

be estimated in each of those scenarios, and the resulting estimated benefits and costs (which 

would depend on the amount of new generation capacity built, the technologies used, the 

 

37 By fixing generation in this comparison, we are assuming that both technologies generate the same benefits in 

the form of electricity generating services. For a discussion of the usefulness of a levelized cost analysis, and 

when it provides informative results and when it does not, see for example Joskow 2010 and 2011. 

38 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. 
5-26

location of new generating plants, and so on). The analysis would then estimate the probability 

distribution of those outcomes (for example, the probability distribution of future natural gas 

prices or future electricity demand). Finally, the analysis would integrate the estimated 

benefits and costs over the 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 

XXXX. Nonetheless, EPA is inviting comment on whether such an analysis would be practical 

and feasible, and if so how it might be carried out. If commenters believe that such an analysis 

would be practical, EPA invites comment on what parameters should be treated as uncertain 

(e.g., natural gas and coal prices, electricity demand) and on the specific probability 

distributions that should be used for those parameters.

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.

5.12.1 Illustrative Environmental Damages per MWh 

As previously discussed in this ppchapterchapter, 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 5.10. The external costs are defined as the damages 

associated with pollution that are not accounted for in the private investor's decision making.39

To illustrate the external costs associated with new generation options we combine the 

illustrative emission profiles for the new units, as provided in Table 5-4, and the illustrative 

damage estimates discussed in the previous section.40 Specifically, for each generating 

technology we multiply the CO2 emissions by the estimates of the SCC and add that to the SO2

 

39 See Baumol and Oates, 1988. 

40 Only the direct emissions of three pollutants (CO2, SO2, and Nox) are considered in this illustrative exercise. 

Other pollutants and lifecycle emissions are not considered.
5-27

emissions multiplied by the PM2.5-related SO2 benefit per-ton estimates41, subsequently 

dividing by MWh42 to estimate the external costs per unit of generation.

Table 5-XX 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. DependingDependingDepending on the 

discount rate and epidemiology study used, damages associated with generation from a 

representative new coal unit are $18 to $99 per MWh, while damages associated with the 

illustrative new natural gas combined cycle unit are $3 to $29 per MWh (2007$).43 

It is important to note that although the ranges appear to overlap, for any set of 

assumptions (i.e., any specific epidemiology study and choice of SCC value), the 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 $24 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 $52 of pollution damages per MWh from a 

new conventional coal unit compared to a new NGCC plant. 6

 

41 See footnote 23 in section 5.11 for a description of the benefit-per-ton values. In this exercise they are 

interpreted as damage per-ton values.

42 See footnote 19 in section 5.10.

43 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.
5-28

Table 5-6. Pollution Damages ($/MWh) from Illustrative New Coal Unit Relative to New 

Natural Gas Combined Cycle Unit 

DiscountDiscountDiscount rate applied to health 

co-benefitsbenefitsbenefits

SCC Discount Rate 3% Discount Rate 7% Discount Rate

5% $17 - $37 $16 - $33

3% $25 - $45 $24 - $42

2.5% $32 - $52 $31 - $49

3% (95th percentile) $50 - $70 $49 - $66

Notes: The range of costs within each SCC value and discount rate for SO2 and NOx pollution damages pairing reflects the use of two PM2.5-

related estimates of premature mortality, Pope et al. (2002) representing the low estimate and Laden et al. (2006) represent the high estimate. 

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 NOx and SO2 emissions in the Eastern U.S.

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. AA full 

benefit-cost analysis Anwould account for these local circumstances (and consider alternative 

sources of generation).44 rHowever, these factors will not change the qualitative conclusion. 

That said, the damages associated with CO2 emissions, which is 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. 

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. Other studies of the social costs of 

coal and natural gas fired generation provide similar findings (Muller et. al, 2011; NRC, 2009).45 

An important implication is that even ififif market conditions changed sufficiently so 

thatthatthatwhere new coal units became marginally more profitable to operate, these new 

 

44 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 and NOX

emissions. Therefore, the benefits for any specific unit can be very different than the estimates shown here. 

45 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. 
5-29

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. 

5.12.2 Social Costs Across A Range of Gas Prices - Breakpoint 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 5.10 and 5.11.

At current natural prices, the estimated levelized cost of electricity for a representative 

natural gas combined cycle unit is roughly $27 per MWh less than for a representative new 

conventional coal unit (see Figure 5-4). ThisThisThis is consistent with EPA’s projection, 

discussed at length above, thatthatthatBecause the proposed EGU GHG NSPS will not impose 

any social costs (or generate monetized 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 identifiesidentifiesidentifies three relevant 

regionsregionsregionsdescribes in the price of natural gas: likely: gas prices, unexpectedly high 

natural gas prices, and unprecedented natural gas prices. These price regions are defined by 

two distinct thresholds, or “breakpoints,” in the price of natural gas: 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. 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.

47

 

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 

 

47 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.
5-30

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 2012 is $X.XX (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 $6.79 in 2020 (the “low shale gas recovery per play” scenario projects a price 

of $5.93/mmBtu in 2020). In other words, even under 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 anticipatedwillwillanticipatedbewillzero.

Unexpectedly High Natural Gas Prices. In this illustrative analysis, at natural gas prices 

above $9.60/mmBTU, the levelized cost of electricity for a representative new conventional 

coal unit falls below that of a new NGCC unit. Above that price level, therefore, 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. 

However, these coal units would also impose environmental and health damages in the form of 

global warming pollution and particulate matter (as a result of SOx and NOx emissions) – social 

costs that would be avoided by building an NGCC unit instead. 

For a range of natural gas prices above $9.60/mmBtu, the resulting social costs will 

outweigh the difference in the private cost in this illustrative example – indicating that the 

proposed standard would yield net benefits. For example, at gas prices of $10/MMBTU, the 

illustrative non-CCS coal unit would generate power for $[3]/MWh less than an NGCC unit48, 

but result in greater pollution damages of $16-70/MWh (see table 5-XX).

50

 Under the proposed 

 

48 Assuming an increase of $6.80/MWh in the cost of gas generation for every $1/MMBTU increase in natural gas 

prices. AWAITING CONFIRMATION

50 Again, assuming that coal prices do not increase along with natural gas prices as they historically have. See 

previous footnote.
5-31

standard, if anananthe NGCC unit were built instead, the resulting net social benefit would be 

$[13] to [67]/MWh. 

. For context, we note that these circumstances are less likely than the zero cost 

scenario outlined above. To put this gas price breakpoint into historical context, $9.60/MMBTU 

is higher than any annual gas price observed over the last 10 years, and it has only been 

reached temporarily in 9 of the last 120 months. 51 52 Looking forward, the continued 

development of unconventional natural gas resources in the U.S. suggests that gas prices would 

actually tend to be towards the lower end of the historical range. As discussed above, none of 

the EIA sensitivity cases (which 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., net social costssocial 

costssocial costs) under some assumptions for environmental damage costs. For example, at 

gas prices of $15/MMBTU, the illustrative non-CCS coal unit would generate power for roughly 

$[36]/MWh less than an NGCC unit but result in social costs of $16-70/MWh (see table 5-XX). 

Under the proposed standard, if an NGCC unit were built instead, the (or an alternative energy 

strategy at this price point under a broader scenario analysis), resulting net social benefit would 

range from $[-19] to [34]/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 [NAME OTHER ASSUMPTIONS FOR SO2], 

natural gas prices above $[XX]/mmBtu in this illustrative example would result in net social 

costs from the proposed standard. Alternatively, using an SCC value of XXX and SO2 

assumptions of YYY, the corresponding threshold for natural gas prices would be $ZZ/mmBtu. 

Natural gas prices above these levels would be unprecedented. Annual natural gas prices 

delivered to the electricity sector have not exceeded $ 9.26 /MMBTU over the last 15 years, 

and projected prices do not begin to approach this level in any of EIA’s scenarios. As a result, 

based on historical gas prices as well as projections, EPA believes that there is an extremely 

 

51 See: http://www.eia.gov/dnav/ng/hist/n3045us3A.htm

52 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.
5-32

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 

net costs. However, based annual gas prices over the last 15 years, we project that this 

standard is most likely to have no notable costs, that there is some small probability that it 

produces net benefits, and an exceedingly low probability that it results in net costs. 

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 

FOR 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 31% 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 mostly 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 project53 is planning to capture 90% of the CO2 and sell it for enhanced oil 

recovery. 

 

53 http://www.texascleanenergyproject.com/
5-33

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.54 We also considered 

a lower revenue sensitivity where CO2 could be sold for $15/ton (equivalent to the cost 

assumed for the transport and storage of CO2 in the analysis). Costs for the IGCC unit with 90% 

capture and the ultra-supercritical coal-fired unit without CCS were derived from IPM version 

4.10.55 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. Costs for the IGCC unit with 

30% capture were derived from the costs for the IGCC unit with 90% CCS using best engineering 

judgment. EPA estimated the benefits associated with avoided CO2 and SO2 emissions in a 

similar fashion to the one described above [REFERENCE TECHNICAL MEMO IN THE DOCKET]

Table 5-7. Illustrative Costs and Benefits for two CCS Scenarios Compared to Conventional 

Coal Plant (Millions 2007$) – NOTE – WILL BE REVISED TO $/MWh FOR 

CONSISTENCY

USCPS to IGCC with 

30% Capture

USCPC to IGCC with 

90% Capture

Additional Gross Annual Private Costs $80.0 $130.3

Revenue from EOR $17.4 (@$15/ton) $143.7 (@$45/ton)

Net Additional Annual Private Costs $62.6 ($13.4)

Value of Quantified Benefits

 SCC 3% with Pope 7% $58 $109

 SCC 3% with Laden 3% $101 $151

Net Benefits

 SCC 3% with Pope 7% ($4.6) $122.4

 SCC 3% with Laden 3% $38.4 $164.4

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 

 

54 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)”, 

DOE/NETL-2011/1504 (June 2011); and “Storing CO2 with Enhanced Oil Recovery, DOE/NETL-402/1312 

(February 2008).

55http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html
5-34

suggests that, at relatively low prices for EOR revenue ($15/MWh), CCS generation can 

generate net social benefits compared to conventional coal generation.

EPA recognizes that this illustrative analysis is somewhat novel, and requests comment 

on ways to incorporate uncertainty about future economic factors (and gas prices in particular) 

into the consideration of the social cost of this rule.

5.13 Macroeconomic and Employment Impacts

This proposed EGU GHG NSPS is not anticipated to change GHG emissions for newly 

constructed electric generating units, nor is it anticipated to impose notable costs or have 

notable economic or employment impacts. EPA typically presents the economic impacts to 

secondary markets (e.g., changes in industrial markets resulting from changes in electricity 

prices) and impacts to employment or labor markets associated with proposed rules based on 

the estimated compliance costs and other energy impacts, which serve as an input to such 

analyses. However, since the EPA does not forecast a change in behavior relative to the 

baseline in response to this proposed rule, there are no notable macroeconomic or

employment impacts expected as a result of this proposed rule. 

5.14 References

U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for 

Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for 

Environmental Assessment – RTP Division. December. Available on the Internet at 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.

U.S. Environmental Protection Agency (U.S. EPA). 2006. Air Quality Criteria for Ozone and 

Related Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. Washington, DC: U.S. 

EPA. February. Available on the Internet at 

<http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923>.

U.S. Environmental Protection Agency (U.S. EPA). 2008. Integrated Science Assessment for 

Oxides of Nitrogen and Sulfur –Ecological Criteria National (Final Report). National 

Center for Environmental Assessment, Research Triangle Park, NC. EPA/600/R-08/139. 

December. Available on the Internet at 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485>.
5-35

U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis (RIA) for the 

final Transport Rule. Office of Air and Radiation, Washington, DC. June. Available on the 

Internet at <http://www.epa.gov/airtransport/pdfs/FinalRIA.pdf>.Fann, N., C.M. 

Fulcher, B.J. Hubbell. 2009. The influence of location, source, and emission type in 

estimates of the human health benefits of reducing a ton of air pollution. Air Qual 

Atmos Health 2:169–176.

Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 2006. Reduction in Fine Particulate Air 

Pollution and Mortality. American Journal of Respiratory and Critical Care Medicine 

173:667-672.

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

Reinelt, Peter S.; Keith, David W. Carbon Capture Retrofits and the Cost of Regulatory

Uncertainty. Energy Journal, 2007, Vol. 28 Issue 4, p101-127

Hoffmann, Volker H. and Trautmann, Thomas and Hamprecht, Jens. Regulatory Uncertainty: A 

Reason to Postpone Investments? Not Necessarily. Journal of Management Studies 

2009 46 (7), 1467-6486.

Teisberg, E.O. An option valuation analysis of investment choices by a regulated firm. 

Management Science, 1994, 40 (4) 535-548.

Blyth, W. and Yang, M. and Bradley, R. Climate policy uncertainty and investment risk. 2007. 

OECD/IEA.

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.

W. J. Baumol and W. E. Oates, The Theory of Environmental Policy. 2nd Edition. Cambridge 

University Press: New York (1988).

P.L Joskow. 2010. Comparing the Cost of Intermittent and Dispatchable Electricity Generating 

Technologies. MIT Center for Energy and Environmental Policy Research Working Paper 

10-013.

P.L. Joskow, 2011. "Comparing the Costs of Intermittent and Dispatchable Electricity Generating 

Technologies," American Economic Review, vol. 101:238-41.

N.Z. Muller, R. Mendelsohn, and W. Nordhaus. Environmental Accounting for Pollution in the 

United States Economy. American Economic Review. 101:1649-1675.
5-36

National Research of Council (NRC). 2009. Hidden Costs of Energy: Unpriced Consequences of 

Energy Production and Use. National Academies Press: Washington, D.C.
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6-1

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.56 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. EPA believes this rule will have no compliance 

costs associated with it, over a range of likely sensitivity conditions, because even in the 

absence of the rule electric power companies will choose to build new EGUs that comply with 

the regulatory requirements of this proposal because of existing and expected market 

 

56 Electricity Generating Unit Greenhouse Gas New Source Performance Standard - The NSPS would be established 

under section 111(b) of the Clean Air Act (CAA). 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

6-2

conditions. Because our modeling shows that natural gas-fired plants are the facilities of choice, 

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 non-compliant coal-fired EGUs 

to be built.

6.3 Paperwork Reduction Act

The PRA, 44 U.S.C. 3501 et seq., requires that and information collection request (ICR) 

be prepared and submitted for approval to the Office of Management and Budget for rules 

with information collection burden. 

 Because it is anticipated that this proposed rule would not impose notable 

recordkeeping and reporting requirements beyond what new affected sources would already 

be subject to under the authorities of CAA parts 75 and 98 authorities, an ICR has not been 

prepared for this proposed action. 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. 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 OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR 

part 9. 

As previously explained, the EPA believes that electric power companies will choose to 

build new EGUs that comply with the regulatory requirements of this proposal because of 

existing and expected market conditions. The EPA does not project any new coal-fired EGUs 

that commence construction after this proposal to commence operation over the 3-year period 

covered by this ICR. We estimate that 31 new NGCC units would be built during that time 

period. We do not expect information collection costs for those new units because, as stated 

above, the information that would be required by this proposed rule would already be collected 

and reported by other regulatory programs.

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 

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

6-3

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 

which source operators might be expected to avail themselves of the affirmative defense will 

be extremely small. 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 
***E.O. 12866 Review–Draft–Do Not Cite, Quote, Or Release During Review ***

6-4

to gather information on such events in the future, and will revise this estimate as better 

information becomes available.

EPA is accepting comment on the need for this information, the accuracy of the 

provided burden estimates, and any suggested methods for minimizing respondent burden, 

including the use of automated collection techniques. 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 

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 221112bFossil fuel electric power generating units owned by the federal 
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government.

State/Local 

Government

221112bFossil 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 do not anticipate any 

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 natural gas-fired plants are the facilities of choice, 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 non-compliant coal-fired EGUs 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.
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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.

57 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.

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 

 

57 http://www.epa.gov/airquality/listen.html
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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 milion 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 no 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 natural gas-fired plants 

are the facilities of choice, 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 

non-compliant coal-fired EGUs to be built. Thus, this proposed rule is not subject to the 

requirements of sections 202 or 205 of UMRA. This proposed rule is also not subject to the 

requirements of section 203 of UMRA because it contains no regulatory requirements that 

might significantly or uniquely affect small governments. 

In light of 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 
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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 

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 
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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.

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 an 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 
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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 

expectedto 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 not anticipated to have 

notable impacts on emissions, costs or energy supply decisions for the affected electric utility 

industry.

6.11 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 
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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.

6.10 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive 

policy on environmental justice. Its main provision directs Federal agencies, to the greatest 

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 minority or low-income populations, 

including any minority, low-income, or indigenous populations.