1

Fellner, Christian

From: Hutson, Nick

Sent: Thursday, December 19, 2013 2:52 PM

To: Fellner, Christian

Subject: Please docket - FW: Revised (RLSO) versions of preamble; EPA response

Attachments: 01 Executive Summary 0829.docx; 02 Intro and Background 0829.docx; 03 Defining the 

Climate Change Problem 0829.docx; 04 Electric Power Sector Profile 0829.docx; 05 Costs 

Benefits Economic and Energy Impacts 0829.docx; 06 Statutory and Executive Order 

Analyses 0829.docx

From: Hutson, Nick 

Sent: Friday, August 30, 2013 5:39 PM 

To: Frey, Nathan J. 

Cc: Culligan, Kevin; Wayland, Robertj; Tsirigotis, Peter 

Subject: RE: Revised (RLSO) versions of preamble; EPA response 

Revised RIA Chapters are attached.

From: Hutson, Nick 

Sent: Friday, August 30, 2013 5:36 PM 

To: 'Frey, Nathan J.' 

Cc: Culligan, Kevin; Wayland, Robertj; Tsirigotis, Peter 

Subject: Revised (RLSO) versions of preamble; EPA response 

Nathan

Attached to this email are three files:

(1) A PDF version of the redline changes to the preamble

(2) A MSWord version of the redline changes to the preamble

(3) An updated ‘EPA Response’ to the Interagency Comments

In emails immediately following this one, I will send versions of the ...

(1) Revised regulatory language

(2) Revised RIA chapters; and

(3) A DRAFT version of a TSD entitled “Fossil Fuel‐Fired Boiler and IGCC EGU Projects Under Development:

Status and Approach”

We have made many changes in response to comments from OMB and the Interagency Workgroup.  We are still

considering some comments.  Those are noted in the text and in the EPA Response.  We can continue to discuss specific

comments and other aspects of the package once you have had the opportunity to see the edits in these revised

versions.

Have a nice holiday and a relaxing time off next week.
2

Regards,

Nick

Nick Hutson, PhD

Energy Strategies Group

U.S. Environmental Protection Agency

Research Triangle Park, NC 27711

(919) 541‐2968

hutson.nick@epa.gov
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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

Fossil Fuel‐Fired Electric Utility Steam Generating Units and Stationary Combustion Turbines

(herein referred to as the EGU New Source GHG Standards).

1.1 Background and Context of Proposed Rule

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

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

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

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

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

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

proposing requirements for these sources because CO2 is a GHG and fossil fuel‐fired power

plants are the country’s largest stationary source emitters of GHGs. As stated in the EPA’s

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

the Clean Air Act (74 FR 66518) and summarized in Chapter 3 of this RIA, the anthropogenic

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

warming over the last 50 years.   

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

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

public comments received – totaling approximately 2.7 million – the EPA determined that

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

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

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

affected fossil fuel‐fired EGUs.

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

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

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

publication of the proposal, other than the Wolverine project in Rogers City, Michigan,

currently the only proposed coal‐fired EGU project without carbon capture and storage (CCS)

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

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

construction and has not been canceled.
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This rulemaking affects CAA section 111(b) new sources of GHG emissions from fossil

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

does not propose standards for modified or reconstructed sources. CAA Section 111(b) requires

that the new source performance standards (NSPS) be reviewed every eight years.  As a result,

this rulemaking’s analysis is primarily focused on projected impacts within the current eight‐

year NSPS timeframe.

1 – using 2020 as a base year within that timeframe.  However, the trend

of favoring NGCC over coal (and therefore the core findings of no projected costs or monetized

benefits) continues beyond the eight year NSPS timeframeupdate in both the Integrated

Planning Model (IPM) and U.S. Energy Information Administration (EIA) reference cases, as well

as in the vast majority of EIA sensitivity scenarios. Sections 5.8 to 5.10 of this RIA discuss the

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

builds are affected by the standard.

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

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

President directed EPA to Agency to work expeditiously to complete carbon pollution standards

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

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

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

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

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

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

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

1.2   Summary of the Proposed Rule  

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

subparts – natural gas‐fired stationary combustion turbines within subpart KKKK and fossil fuel‐

fired electric utility steam generating units (boilers and IGCCintegrated gasification combined

cycle – IGCC – units) within subpart Da. All affected new fossil fuel‐fired EGUs would be

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

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

operating month rolling average basis. Emission standards are proposed for existing

                                                      

1 Conditions in the analysis year of 2022 are represented by a model year of 2020. 2 “The President’s Climate Action Plan.” June 2013. Available online at:

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

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

http://www.whitehouse.gov/sites/default/files/blueprint_secure_energy_future.pdf  
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subcategories within subpart KKKK.  Those subcategories are: (1) natural gas‐fired stationary

combustion turbines with a heat input rating that is greater than 850 million British thermal

units per hour (MMBtu/hr) and (2) natural gas‐fired stationary combustion turbines with a heat

input rating that is less than or equal to 850 MMBtu/hr. A separate standard is proposed for

fossil fuel‐fired boilers and integrated gasification combined cycle (IGCC) units within subpart

Da. The respective emission limits are shown in table 1.‐1.   

Table 1‐.1. Proposed Emission Limits

Source Emission Limit 

(lb CO2/MWh 

Gross Basis) 

Stationary natural gas-fired combustion turbine EGUs with a 

heat input rating greater than 850 MMBtu/hr 

1,000 

Stationary natural gas-fired combustion turbine EGUs with a 

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

1,100 

Fossil fuel-fired boilers and IGCCs 1,100 

This action also proposes an alternative emission limit, available only to new solid fossil‐

fired boilers and IGCCsEGUs, which can be met over a 60‐operating month rolling average basis.

The alternative emission limit will be between 1,000950 and 1,050 lb CO2/MWh of gross

energy output.  

1.3   Key Findings of Economic Analysis  

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

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

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

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

for this rule (as well as modeling that the EPA has performed for other recent air rules) projects

that, even in the absence of this action, new fossil‐fuel fired capacity constructed through 2020

and the years following will most likely be natural gas combined cycle capacity. Alternatively,

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

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

technologies. Analyses performed both by the EPA and the U.S. Energy Information

Administration (EIA)

4 project that generation technologies other than those utilizing coal

                                                      

4

  Annual Energy Outlook (AEO) 2009‐ 2013.
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(including natural gas‐fired and renewable sources) are likely to be the technology of choice for

new generating capacity due to current and projected economic market conditions.  

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

proposed EGU New Source GHG Standards will result in negligible CO2 emission changes, energy

impacts, quantified benefits, costs, and economic impacts by 2020. Accordingly, the EPA also

does not anticipate this rule will have any impacts on the price of electricity, employment or

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

effects described below.   

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

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

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

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

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

additional certainty to help incentivize innovation that would lead to lowerCO2 emissions in the

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

source category under CAA section 111(d).    

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

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

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

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

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

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

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

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

health and environmental effects.  

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

forlimiting GHG from new fossil fuel‐fired EGU sources. In addition, the EPA intends this rule to

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

implementation of CCS technology as the best system of emission reductions (BSER) for coal‐

fired power plants promotes further development of CCS, which is important for long‐term CO2

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

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

performance and consequent reductions in their cost. Moreover, partial implementation of CCS
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is a viable CO2 control for new coal‐fired power plants as identified in the BSER determination.

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

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

                                                      

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

http://energy.gov/articles/building‐clean‐energy‐partnerships‐china‐and‐japan.   6 Friedman, Dr. Julio S. “A U.S. – China CCS Roadmap.” Lawrence Livermore National Laboratory Carbon

Management Program. http://www.nrcce.wvu.edu/cleanenergy/docs/Friedmann.pdf.  
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CHAPTER 2

INTRODUCTION AND BACKGROUND

2.1 Introduction

In this action, the EPA seeks to set emission limits for limit GHGs, specifically carbon

dioxide (CO2), emitted from fossil fuel‐fired electric utility generating units (EGUs). This

document presents the expected economic impacts of the proposed EGU New Source GHG

Standards rule through 20220, including some projections for years up to 2030beyond 2020.

Based on the analysis presented in Chapter 5, expected and anticipated economic conditions

will lead electricity generators to choose fuels and technologies that are designed to meet the

proposed standard without the need for additional capture or control, even in the absence of

the rule. As a result, this rule is expected to have no, or negligible, costs or monetized benefits

associated with it. This chapter contains background information on the rule and an outline of

the chapters of the report.

2.1.1   Statutory Requirement

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

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

health or welfare. In April 2007, the Supreme Court ruled in Massachusetts v. EPA that GHGs

meet the definition of an “air pollutant” under the CAA. This ruling clarified that the authorities

and requirements of the CAA apply to GHGs. As a result, the EPA must make decisions about

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

criteria. The EPA issued a final determination that GHG emissions endanger both the public

health and the public welfare of current and future generations in the Endangerment and Cause

or Contribute Findings for Greenhouse Gases Under Section 202(a) of the CAA (74 FR 66,496;

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

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

under section 111 of the CAA.  

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

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

comments received – totaling approximately 2.7 million – the EPA determined that significant

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

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

rescinding the original proposal and is re‐proposing standards of performance for new affected
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fossil fuel‐fired EGUs. This action addresses standards for new sources but does not address

standards for modified, reconstructed, or existing sources.   

2.1.2 Regulatory Analysis  

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

for Preparing Economic Analyses, the EPA prepared this RIA for this “significant regulatory

action.”This rule is not anticipated to have an annual effect on the economy of $100 million or

more or adversely affect in a material way the economy, a sector of the economy, productivity,

competition, jobs, the environment, public health or safety, or State, local, or tribal

governments or communities and is therefore not an “economically significant rule.” However,

under EO 12866 (58 FR 51,735, October 4, 1993), this action is a “significant regulatory action”

because it “raises novel legal or policy issues arising out of legal mandates.” As a matter of

policy, the EPA has attempted to provide a thorough analysis of the potential impacts of this

rule, consistent with requirements of the Executive Orders.

This RIA addresses the potential costs and benefits of the new source emission limits

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

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

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

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

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

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

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

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

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

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

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

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

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

                                                      

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

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

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

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

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

negligible. Costs are only incurred if there has been a violation of an emission standard caused by a malfunction

and a source chooses to assert an affirmative defense. The owner/operator must meet the burden of proving
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associated with it. Chapter 5 of this RIA also provides an illustrative analysis of the levelized cost

of electricity and health and environmental impacts associated with representative new

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

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

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

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

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

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

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

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

more stringent alternative requiring full CCS.       

2.2 Background for the Proposed EGU New Source GHG Standards

2.2.1 Baseline and Years of Analysis

The rule on which this analysis is based proposes GHG emission limits for new EGUs. The

baseline for this analysis, which uses IPM, includes state rules that have been finalized and/or

approved by a state’s legislature or environmental agencies as well as final federal rules.

Additional legally binding and enforceable commitments for GHG reductions considered in the

baseline are discussed in Chapter 5 of this RIA.  

All analysis is presented for compliance through the year 202205 and all estimates are

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

years.  As a result, this rulemaking’s analysis is primarily focused on projected impacts within

the current eight‐year NSPS timeframe. – using 2020 as a base year within that timeframe.  

However, the trend of favoring NGCC over coal (and therefore the core findings of no projected

costs or monetized benefits) continues beyond the 8 year NSPS timeframeupdate in both the

IPM and EIA reference cases, as well as in the vast majority of EIA sensitivity scenarios.6  

                                                                                                                                                                              

all of the requirements in an affirmative defense. See Chapter 6 for more details on monitoring and reporting

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

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

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

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

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

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

the multi‐decade life of the plant.   
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Sections 5.8 to 5.10 of this RIA discuss the social costs and benefits of the proposed standards

in any limited cases where new coal plant builds are affected by the standard. Any estimates

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

proposed EGU New Source GHG Standards rather than the net present value of a stream of

benefits and costs in these particular years of analysis.7

2.2.2 Definition of Affected Sources

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

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

emissions from existing, modified, or reconstructed sources.

2.2.2.1 New Sources

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

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

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

publication of the proposal, other than the Wolverine project in Rogers City, Michigan,

currently the only proposed coal‐fired EGU project without CCS with an air permit that has not

already commenced construction.  We anticipate proposing standards for this project when we

finalize today’s action if the project has not yet commenced construction and has not been

canceled. See the preamble for further discussion.

2.2.2.2 Modified Sources

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

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

not previously emitted. However, projects to install pollution controls required under other

CAA provisions are specifically exempted from the definition of “modifications” under 40 CFR

60.14(e)(5), even if they emit CO2 as a byproduct. The significant majority of projects that the

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

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

are exempt under this definition. More details on modified sources can be found in the

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

a result, existing sources that undertake modifications will continue to be treated as existing

sources and thus not subject to the requirements of this rule.  

                                                      

7 However, the CO2‐related benefits, which are estimated using the social cost of carbon, vary depending on the

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

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

more stressed in response to greater climatic change.  See Chapter 5 for details.
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2.2.2.3   Reconstructed Sources

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

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

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

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

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

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

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

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

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

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

requirements of this rule.

2.2.2.4 Existing Sources  

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

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

219,000 megawatt‐hours (MWh) net‐electrical output to the grid on a three year rolling

average basis and was in operation or commenced construction on or before publication of the

proposed rule. Existing sources are not covered in this proposed rule.

2.2.3 Regulated Pollutant

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

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

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

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

future generations.

The EPA is aware that other GHGs such as nitrous oxide (N2O) (and to a lesser extent,

methane (CH4)) may be emitted from fossil‐fuel‐fired EGUs, especially from coal‐fired

circulating fluidized bed combustors and from units with selective catalytic reduction and

selective non‐catalytic reduction systems installed for nitrogen oxide (NOX) control. The EPA is

not proposing separate N2O or CH4 emission limits or an equivalent CO2 emission limit because

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

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

before proposing standards for these pollutants.
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2.2.4 Emission Limits

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

subparts – natural gas‐fired stationary combustion turbines within subpart KKKK and fossil fuel‐

fired electric utility steam generating units (boilers and IGCC units) within subpart Da. Emission

standards are proposed for existing subcategories within KKKK. Those subcategories are:

natural gas‐fired stationary combustion turbines with a heat input rating that is greater than

850 million British thermal units per hour (MMBTU/hr) and natural gas‐fired stationary

combustion turbines with a heat input rating that is less than or equal to 850 MMBtu/hr. A

separate standard is proposed for fossil fuel‐fired boilers and IGCC units within subpart Da. The

respective emission limits are shown in table 2‐.1.

Table 2‐.1. Proposed Emission Limits

Subcategory Emission Limit 

(lb CO2/MWh) 

Stationary natural gas-fired combustion turbine EGUs with a 

heat input rating greater than 850 MMBtu/hr 

1,000 

Stationary natural gas-fired combustion turbine EGUs with a 

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

1,100 

Fossil fuel-fired boilers and IGCC 1,100 

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

fired boilers and IGCC unitssolid fossil‐fired EGUs, which can be met over a 60‐operating month

rolling average basis.  The alternative emission limit will be between 1,000950 and 1,050 lb

CO2/MWh of gross energy output.  

2.2.5 Emission Reductions

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

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

over the analysis period (through 2020 and following years). Even in the absence of this rule,

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

standards due to expected economic conditions in the marketplace.  

2.3 Organization of the Regulatory Impact Analysis

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

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

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

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

undertaking this rulemaking.

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

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

proposed rule.

 Chapter 6, Statutory and Executive Order Impact Analyses, describes the small

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

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

requirements.  
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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

Through the implementation of CAA regulations, EPA addresses the negative

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

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

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

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

emission limitsminimize for CO2 emissions of GHGs, in order to minimize the rate of increase of

concentrations of these gases in the atmosphere, and therefore reduce the risk of adverse

effects.  

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

detailed in the 2009 Endangerment Finding.1 The major assessments by the U.S. Global Change

Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the

National Research Council (NRC) served as the primary scientific basis for these effects.

3.1.1   Public Health

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

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

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

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

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

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

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

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

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

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

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

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

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

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

                                                           

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

74 Fed. Reg. 66,496 (Dec. 15, 2009).
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most sensitive to hot temperatures are older adults, the chronically sick, the very young, city‐

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

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

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

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

events become more frequent, prolonged, and extreme.   

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

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

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

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

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

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

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

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

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

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

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

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

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

be greater than decreases in cold‐related mortality.  

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

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

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

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

plant and animal species populations.  

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

that modeled climate change causes increases in summertime ozone concentrations over

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

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

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

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

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

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

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

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 low‐

probability, high‐impact events that can overwhelm physical infrastructure, human resilience,

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

diseases, toxic contamination, and mental health problems.  

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

increases in the risk of deaths, injuries, waterborne and food borne diseases, as well as post‐

traumatic stress disorders. Storm surge is the major killer in coastal storms, and the risk of

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

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

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

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

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

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

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

with temperature.  The range of some zoonotic disease carriers, such as the Lyme disease‐

carrying tick, may increase with temperature.  

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

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

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

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

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

might impact aeroallergens and subsequently the prevalence of allergenic illnesses in the
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United States. It has generally been observed that the presence of elevated CO2 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 CO2.  

3.1.2   Public Welfare

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

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

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

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

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

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

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

turn in this section, based on the 2009 Finding.

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

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

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

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

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

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

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

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

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

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

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

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

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

irrigation requirements, potentially increasing irrigation demand.  

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

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

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

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

effects associated with an absolute change in average climatic conditions.
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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

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

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

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

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

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

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

likely reduce forest productivity wherever such events occur.  

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

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

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

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

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

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

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

more intense precipitation and more droughts.  

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

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

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

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

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

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

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

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

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

pollution.  

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

some regions of the United States, increasing competition among agricultural, municipal,
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industrial, and ecological uses. Increased incidence of extreme weather and floods may also

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

impairments.  

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

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

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

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

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

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

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

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

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

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

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

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

hydrological cycle have been damaging and disruptive to shoreline communities.  

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

presenting increased risk from storm surges.  
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With respect to infrastructure, climate change vulnerabilities of industry, settlement,

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

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

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

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

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

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

Within settlements experiencing climate change stressors, certain parts of the

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

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

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

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

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

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

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

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

migration patterns, and changes in reproductive timing and behavior.  

The underlying assessment literature finds with high confidence that substantial

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

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

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

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

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

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

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

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

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

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

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

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

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

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

vulnerability to other disturbances, including wildfires and biological invasion. Disturbances
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such as wildfires and insect outbreaks are increasing in the United States and are likely to

intensify in a warmer future with warmer winters, drier soils and longer growing seasons. The

areal extent of drought‐limited ecosystems is projected to increase 11 percent per °C warming

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

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

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

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

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

vulnerable to these effects.   

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

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

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

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

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

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

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

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

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

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

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

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

present risks to the U.S. population.

3.2 References

40 CFR Chapter I [EPA–HQ–OAR–2009–0171; FRL–9091–8] RIN 2060–ZA14, “Endangerment and

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

Air Act,” Federal Register / Vol. 74, No. 239 / Tuesday, December 15, 2009 / Rules and

Regulations.

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

States. Cambridge University Press, Cambridge, United Kingdom.

                                                           

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

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

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

al., 2009).
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Medina‐Ramon, M. and J. Schwartz, 2007: Temperature, temperature extremes, and mortality:

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

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

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

Press. Washington, DC.

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

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

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

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

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

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

U.S. Global Change Research Program (USGCRP). Global Climate Change Impacts in the United

States.  Thomas R. Karl, Jerry M. Melillo, and Thomas C. Peterson, (eds.). Cambridge

University Press, 2009.
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CHAPTER 4

ELECTRIC POWER SECTOR PROFILE

4.1   Introduction

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

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

affected by the proposal, and provides background on the power sector and electric generating

units (EGUs). In addition, this chapter provides some historical background on the EPA

regulation of, and future projections for, the power sector.

4.2   Power Sector Overview

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

segments: generation, transmission, and distribution.

4.2.1   Generation

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

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

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

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

units, and hydroelectric and other renewable sources dispersed throughout the country (see

Table 4‐1).

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

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

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

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

as industrial processes that operate 24 hours a day.

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

Energy Source

Number of

Generators

Generator

Nameplate

Capacity (MW)

Generator Net

Summer

Capacity (MW)

Coal 1,400 343,757 317,640

Petroleum 3,738 57,537 51,208

Natural Gas 5,574 477,387 415,191

Other Gases 91 2,202 1,934

Nuclear 104 107,001 101,419

Hydroelectric Conventional 4,048 78,194 78,652

Wind 781 45,982 45,676

Solar Thermal and Photovoltaic 326 1,564 1,524

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

Geothermal 226 3,500 2,409

Other Biomass 1,660 5,192 4,536

Hydroelectric Pumped Storage 154 20,816 22,293

Other Energy Sources 81 1,697 1,420

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

Source: Table 4.3, EIA Electric Power Annual, 2011

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

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

Sales/Direct Use

(Billion kWh)

Share of Total

End Use

Retail Sales

Residential 1,423 37.9%

Commercial 1,328 35.4%

Industrial 991 26.4%

Transportation 8 0.2%

Direct Use 133 3.5%

Total End Use 3,883 100%

Source: Table 2.2, EIA Electric Power Annual, 2011

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

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

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

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

Net Generation

(Billion kWh)

Fuel Source

Share

Coal 1,718 43.5%

Petroleum 28 0.7%

Natural Gas 926 23.5%

Other Gases 3 0.1%

Nuclear 790 20.0%

Hydroelectric 312 7.9%

Other 172 4.3%

Total 3,949 100%

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

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

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

transmission and distribution.

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

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

Along with nuclear generation, these coal units meet the part of demand that is relatively

constant. Although much of the coal fleet operates as base load, there can be notable

differences across various facilities (see Table 4‐4). For example, coal‐fired units less than 100

megawatts (MW) in size compose 37 percent of the total number of coal‐fired units, but only 6

percent of total coal‐fired capacity. Gas‐fired generation is better able to vary output and is the

primary option used to meet the variable portion of the electricity load and has historically

supplied “peak” and “intermediate” power, when there is increased demand for electricity (for

example, when businesses operate throughout the day or when people return home from work

and run appliances and heating/air‐conditioning), versus late at night or very early in the

morning, when demand for electricity is reduced.  

The evolving economics of the power sector, in particular the increased natural gas

supply and subsequent relatively low natural gas prices, have resulted in more gas being

utilized as base load energy in addition to supplying electricity during peak load. Projections of

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

Chapter 5 of this RIA.
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Table 4‐4.   Coal Steam Electricity Generating Units, by Size, Age, Capacity, and Thermal

Efficiency (Heat Rate)

Unit Size Grouping

(MW) No. Units % of AllUnits Avg. Age

Avg. Net

Summer

Capacity

(MW)

Total Net

Summer

Capacity

(MW)

% Total

Capacity

Avg. Heat

Rate

(Btu/kWh)

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

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

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

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

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

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

Totals    1,266       316,480    

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

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

to a generation‐weighted or capacity‐weighted average heat rate.) A lower heat rate indicates a higher

level of fuel efficiency. Table is limited to coal‐steam units online in 2010 or earlier, and excludes those

units with planned retirements.

4.2.2   Transmission

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

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

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

high voltage transmission lines,1 each operating at a common frequencysynchronously. Within

each of these transmission networks, there are multiple areas where the operation of power

plants is monitored and controlled to ensure that electricity generation and load are kept in

balance. In some areas, the operation of the transmission system is under the control of a

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

generation, transmission, and distribution systems to balance their common generation and

load needs.

                                                      

1

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

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

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

Interconnect Region, and ERCOT, respectively.
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Figure 4‐1. Fossil Fuel‐Fired Electricity Generating Facilities, by Size

Source: National Electric Energy Data System (NEEDS) 4.10  

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

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

concentration of facilities, some facilities may be obscured.

4.2.3   Distribution

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

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

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

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

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

residences and businesses.

Transmission has generally been developed by the larger vertically integrated utilities

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

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

couple of decades, several jurisdictions in the United States began restructuring the power

industry to separate transmission and distribution from generation, ownership, and operation.

As discussed below, electricity restructuring has focused primarily on efforts to reorganize the

industry to encourage competition in the generation segment of the industry, including

ensuring open access of generation to the transmission and distribution services needed to
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deliver power to consumers. In many states, such efforts have also included separating

generation assets from transmission and distribution assets to form distinct economic entities.

Transmission and distribution remain price‐regulated throughout the country based on the cost

of service.

4.3   Deregulation and Restructuring

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

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

management between companies, restructuring sought a functional unbundling of the

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

implementation (shown as “Suspended” in Figure 4‐2 below). Eighteen other states that had

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

activity in 2001 (EIA, 2003) (“Not Active” in Figure 4‐2 below). Currently, there are 15 states

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

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

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

restructuring, and no additional states have recently begun retail deregulation activity.
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Figure 4‐2. Status of State Electricity Industry Restructuring Activities

Source: EIA 2010b.  

4.4 Emissions of Greenhouse Gases from Electric Utilities

The burning of fossil fuels, which generates about 70 percent of our electricity

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

of CO2 in particular, but also contributes to emissions of sulfur hexafluoride (SF6), CH4, and N2O.

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

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

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

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

the power sector.

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

tonnes of CO2 equivalent)

Sector/Source 1990 1995 2000 2005 2011

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

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

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

Agriculture 458 511 501 517 547

Commercial 388 391 376 374 378

Residential 345 367 386 371 357

U.S. Territories 34 41 46 58 58

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

Source: EPA 2013

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

equivalent)

Source: EPA 2013

Other

4,501

67%

Electricity

Generation

2,201

33%
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Table 4‐6.   Greenhouse Gas Emissions from the Electricity Sector (Generation, Transmission

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

Source Total Emissions

CO2 2,175.5

CO2 from Fossil Fuel Combustion 2,158.5

Coal 1,722.7

Natural Gas 408.8

Petroleum 26.6

Geothermal 0.4

Incineration of Waste 12.4

Other Process Uses of Carbonates 4.6

CH4 0.4

Stationary Combustion* 0.4

Incineration of Waste +

N2O 18.3

Stationary Combustion* 17.9

Incineration of Waste 0.4

SF6

** 7.0

Electrical Transmission and Distribution 7.0

Total 2,201.2

Source: EPA 2013

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

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

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

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

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

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

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

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

(2011)

Source: EPA 2013

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

Fuel Type Carbon Dioxide (lbs/MMBtu)

Coal  

Bituminous   205.2 – 206.6

Subbituminous   212.7 – 213.1

Lignite   213.5 – 217.0

Natural Gas   117.1

Fuel Oil    

Distillate   161.4

Residual   161.4 – 173.9

Biomass*   195

Waste Fuels    

Waste Coal   205.7

Petroleum Coke   225.1

Fossil Waste   321.1

Non‐Fossil Waste   0

Tires   189.5

Municipal Solid Waste   91.9

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

39%

74%

5% 0.1% 0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

CO2 SF6 N2O CH4

Other

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

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

source).

4.5   Carbon Dioxide Control Technologies

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

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

and baseload operations. These include the use of: CO2 capture and storage (CCS), highest

efficiency designs (e.g. supercritical or ultrasupercritical steam units, integrated gasification

combined‐cycle units (IGCC), or combined‐cycle combustion‐turbine/steam‐turbine units),

and/or low‐emitting fuels (e.g. natural gas rather than coal). CCS technologies can be applied

with any new combustion source to reduce its uncontrolled CO2 emission by as much as 90

percent (“full capture”), or by some lesser percentage (“partial capture”).

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

often most economically met by simple‐cycle combustion turbines (CT). Stationary CTs s used

for power generation can be installed quickly, at relatively low capital cost. They can be

remotely started and loaded quickly, and can follow rapid demand changes. Full‐load

efficiencies of large current technology CTs are 30‐33 percent (high heating value basis), as

compared to efficiencies of 50 percent or more for new combined‐cycle units that recover and

use the exhaust heat otherwise wasted from a CT .  A simple‐cycle CT’s lower efficiency causes

it to burn much more fuel to produce a MWh of electricity than a combined‐cycle unit. Thus,

when burning natural gas its CO2 emission rate per MWh could be 40‐60 percent higher than a

more efficient NGCC unit.  

Baseload electricity demand can be met with NGCC generation, coal and other fossil‐

fired steam generation, and as well as IGCC technology.  IGCC employs the use of a “gasifier” to

transform fossil fuels into synthesis gas (“syngas”) and heat.  The syngas is used to fuel a

combined cycle generator, and the heat from the syngas conversion can produce steam for the

steam turbine portion of the combined cycle generator.  Electricity can be generated through

this IGCC process somewhat more efficiently than through conventional boiler‐steam

generators.  Additionally, with gasification, some of the syngas can be converted into other

marketable products such as fertilizer, and CO2 can be captured for use in EOR.   

4.5.1   Carbon Capture and Storage (CCS).

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

scale industrial facilities and is currently in the demonstration phase for power sector
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applications. There are currently larger‐scale projects under construction or in the advanced

planning stages. CCS can be achieved through either pre‐combustion or post‐combustion

capture of CO2 from a gas stream associated with the fuel combusted. Furthermore, CCS can be

designed and operated for full capture of the CO2 in the gas stream (i.e., above 90 percent) or

for partial capture (below 90 percent).the amount of CO2 captured from the gas stream can

vary from upwards of 90 percent (full capture) to less than 90 percent (partial capture).

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

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

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

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

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

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

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

output could be 20‐30 percent lower due to the energy needs of the capture process.
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Source: Interagency Task Force on Carbon Capture and Storage 2010

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

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

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

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

illustrated in Figure 4‐6. Application of post‐combustion CCS with IGCC can be designed to use

no water‐gas shift, or single‐ or two‐stage shift processes, to obtain varying percentages of CO2

removal – from a “partial capture” percentage to 90 percent “full capture.” Pre‐combustion CCS

typically has a lesser impact on net energy output than does post‐combustion CCS. For more

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

Carbon Capture and Storage” (2010).

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

4.6 Geologic Sequestration  

4.6.1   Availability of Geologic Sequestration

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

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

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

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

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

Canada. 2

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

storage.  Other types of geologic formations such as organic rich shale and basalt may have the

ability to store CO2, and DOE is currently evaluating their potential future storage capacity.  

Potential sequestration sites must undergo appropriate site characterization to ensure that the

site can safely and securely store CO2.  Estimates of CO2 storage resources by state/province

from the DOE report are provided in Table 4‐89. These state and province level estimates are

obtained from DOE’s National Carbon Sequestration Database and Geographic Information

                                                      

2 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of

Fossil Energy, National Energy Technology Laboratory (NETL).

Figure 4‐6. Pre‐Combustion CO2 Capture for an IGCC Power Plant
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System (NATCARB).  Nearly every state in the U.S. has or is in close proximity to carbon storage

potential including vast areas offshore.  Information and methods used in estimating CO2

storage resource can be found in the “Methodology for Development of Geologic Storage

Estimates for Carbon Dioxide” in Appendix B of the Carbon Utilization and Storage Atlas3 (NETL

2012).  It should be noted that the assessment of U.S. sequestration potential is an ongoing

process. There is significant uncertainty in areas such as the Atlantic offshore due to a relative

paucity of data and other factors.

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

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

36 sedimentary basins in the onshore areas and State waters of the United States.4

  The USGS

assessment estimates a mean of 3000 billion metric tons of CO2 storage potential across the

United States.  For comparison, this amount is 500 times the 2011 annual U.S. energy‐related

CO2 emissions of 5.5 Gigatons (Gt)5  Areas that were assessed by the USGS for CO2 storage

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

assessment provides further evidence of the widespread availability CO2 storage reserves in the

U.S. based on the comprehensive evaluation of the technically accessible storage resource for

carbon storage for 36 sedimentary basins in the onshore areas and State waters of the United

States.6

Table 4‐8.9   Total CO2 Storage Resource7

Million Metric Tons*

State/Province Low Estimate High Estimate

ALABAMA                         122,490                         694,380  

ALASKA                              8,640                           19,750  

ALBERTA                           41,840                         131,230  

ARIZONA                                 130                             1,170  

                                                      

3 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of

Fossil Energy, National Energy Technology Laboratory (NETL). 4 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment

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

6p.http://pubs.usgs.gov/fs/2013/3020/. 5 U.S. Energy Information Administration, 2012 6 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment

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

6p.http://pubs.usgs.gov/fs/2013/3020/. 7 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of

Fossil Energy, National Energy Technology Laboratory (NETL).
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ARKANSAS                              6,180                           63,670  

BRITISH COLUMBIA                                 910                             3,860  

CALIFORNIA                           33,890                         420,630  

COLORADO                           37,610                         357,190  

CONNECTICUT   

DELAWARE                                    40                                   40  

DISTRICT OF COLUMBIA

FLORIDA                         102,740                         555,010  

GEORGIA                         145,340                         159,050  

HAWAII   

IDAHO                                    40                                 390  

ILLINOIS                           10,020                         116,820  

INDIANA                           32,020                           68,210  

IOWA                                    10                                   50  

KANSAS                           10,880                           86,340  

KENTUCKY                              2,920                             7,650  

LOUISIANA                         169,500                     2,103,980  

MAINE   

MANITOBA                              1,720                             3,520  

MARYLAND                              1,860                             1,930  

MASSACHUSETTS   

MICHIGAN                           19,050                           47,210  

MINNESOTA   

MISSISSIPPI                         145,010                     1,185,030  

MISSOURI                                    10                                 170  

MONTANA                           84,580                         912,720  

NEBRASKA                           23,770                         113,240  

NEVADA   

New Brunswick   

NEW HAMPSHIRE   

NEW JERSEY 0 0

NEW MEXICO                           42,760                         359,090  

NEW YORK                              4,640                             4,640  

Newfoundland  &

Labrador

NORTH CAROLINA                              1,340                           18,390  

NORTH DAKOTA                           67,090                         147,480  

Northwest Territories   

Nova Scotia   

Offshore Federal Only                         489,840                     6,440,090  

OHIO                           13,460                           13,460  

OKLAHOMA                           56,950                         244,550  

Ontario   

OREGON                              6,810                           93,700  
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PENNSYLVANIA                           22,100                           22,100  

PUERTO RICO   

Quebec   

RHODE ISLAND   

SASKATCHEWAN                           38,690                         121,910  

SOUTH CAROLINA                           30,100                           34,180  

SOUTH DAKOTA                              8,760                           24,030  

TENNESSEE                                 430                             3,860  

TEXAS                         443,800                     4,329,930  

UTAH                           25,470                         240,910  

VERMONT   

VIRGINIA                                 440                             2,910  

WASHINGTON                           36,620                         496,730  

WEST VIRGINIA                           16,650                           16,650  

WISCONSIN 0 0

WYOMING                           72,690                         684,850  

North America Total                     2,379,840                   20,352,700  

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

metric tons of CO2 storage potential in oil and gas reservoirs across over 30 states. 8

                                                      

8 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of

Fossil Energy, National Energy Technology Laboratory (NETL).
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CO2‐EOR has been successfully used at many production fields throughout the U.S. to

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

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

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

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

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

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

tons of CO2 storage resource.9  EPA anticipates that many early geologic sequestration (GS)

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

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

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

CO2.  

4.6.3 Trends in CO2‐EOR

Carbon dioxide EOR (CO2‐EOR) is the fastest‐growing EOR technique in the U.S., providing

approximately 281,000 barrels of oil per day in the U.S. which equals about 6% percent of U.S.

crude oil production.10,11 The vast majority of CO2‐EOR is conducted in oil reservoirs in the U.S.

Permian Basin, which extends through southwest Texas and southeast New Mexico. Other U.S.

states where CO2‐ EOR is utilized are Alabama, Colorado, Illinois, Kansas, Louisiana, Michigan,

Mississippi, New Mexico, Oklahoma, Utah, and Wyoming.   A well‐established and expanding

network of pipeline infrastructure supports CO2‐EOR in these areas (Figure 4‐89).  The CO2

supply for EOR operations is largely obtained from underground formations or domes that

contain CO2.  While natural sources of CO2 comprise the majority of CO2 supplied for EOR

operations, recent developments targeting anthropogenic sources of CO2 (e.g., ethanol plants,

gas processing, refineries, power plants) have expanded or led to planned expansions in

existing infrastructure related to CO2‐EOR.12  Several hundred miles of dedicated CO2 pipeline is

under construction, planned, or proposed that would allow continued growth in CO2 supply for

EOR (see Figure 4‐89).  

                                                      

9 U.S. Department of Energy National Energy Technology Laboratory (2012). United States Carbon Utilization and

Storage Atlas, Fourth Edition. 10 Oil and Gas Journal EOR Survey, April 2010.    11 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2‐Enhanced Oil

Recovery (CO2‐EOR)”, DOE/NETL‐2011/1504, June 20, 2011 12 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2‐Enhanced Oil

Recovery (CO2‐EOR)”, DOE/NETL‐2011/1504, June 20, 2011
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Anthropogenic sources of CO2 for EOR continue to increase as new projects are being

planned or implemented.  Based on an evaluation of publicly available sources13, there are

currently twenty‐two three (223) industrial source CCS projects in twelve (12) states that are

either operational, under‐construction, or actively being pursued which are or will supply

captured CO2 for the purposes of EOR.  This demonstrates that CCS projects associated with

large point sources are occurring due to a demand for CO2 by EOR operations.  Nationally,

according to EPA’s Greenhouse Gas Reporting Program, over 64 million metric tons of CO2 was

received for injection to enhanced oil recovery operations in 2011.  A recent study by DOE

found that the market for captured CO2 emissions from power plants created by economically

feasible CO2‐EOR projects would be sufficient to permanently store the CO2 emissions from 93

large (1,000 MW) coal‐fired power plants operated for 30 years.14   There are also several state

and Federal subsidy programs that are in place that can make CCS more affordable.15  Based on

all of these factors, EPA anticipates opportunities to utilize CO2‐EOR operations for geologic

storage to continue to increase.  

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

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

geographic extent and accessibility of CO2‐EOR operations in the U.S. 16  Additionally, oil and gas

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

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

accessibility of CO2 utilization.   

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

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

for its long‐term storage, strongly improves the overall economics of the new generating unit. A

commercial market for CO2 creates a role for CO2‐EOR to continue CCS deployment. According

to the International Energy Agency, of the CCS projects under construction or at an advanced

stage of planning, 70% intend to use captured CO2 to improve recovery of oil in mature fields

                                                      

13 See technical supporting memo document (Docket EPA‐HQ‐OAR‐2013‐XXXXEPA‐HQ‐OAR‐2013‐0495)

Documentation for the Summary of Carbon Dioxide Industrial Capture to Enhanced Oil Recovery Projectsfor

sources of industrial source CCS projects. 14 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2‐Enhanced Oil

Recovery (CO2‐EOR)”, DOE/NETL‐2011/1504, June 20, 2011 15 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010). 16 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2‐Enhanced Oil

Recovery (CO2‐EOR)”, DOE/NETL‐2011/1504, June 20, 2011
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(enhanced oil recovery, CO2‐EOR). 17   Further, smaller, non‐geologic sequestration markets exist

for CO2 as well, including food products, which can lower the cost of CCS.

Figure 4‐7.8: Growth of U.S. Oil Production from CO2‐based EOR

Source: NETL 2010

                                                      

17 Tracking Clean Energy Progress 2013, International Energy Agency (IEA), Input to the Clean Energy Ministerial,

OECD/IEA 2013.
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Figure 4‐9: U.S. CO2 Storage Capacity and CO2‐EOR operations

   Figure 4‐8.9: U.S. CO2 Storage Capacity and CO2‐EOR operations

Source: EPA 2013: Data sources: EPA’s Greenhouse Gas Reporting Program; Department of Energy, NATCARB;

Department of Transportation, National Pipeline Management System.

4.6.4 Alternatives to Geologic Sequestration  

EPA recognizes there may be other commercial applications or end‐uses for captured

CO2 which creates CO2 market incentives and potentially for a meeting performance standard

beyond injecting it underground for long‐term containment.  For example, alternatives to

geologic sequestration such as applications such as mineralization of CO2 for the production of

precipitated calcium carbonate and some production process of cement have been identified as

potential alternatives to geologic sequestration.  The Carbon Capture and Storage (CCS) Task

Force report notes that there are several factors for determining the viability of CO2 reuse, and

there are currently significant technical barriers to large scale commercial‐scale reuse.  First,

rates of conversion must be comparable to rates of CO2 capture.  Second, energy requirements

for conversion must be low. Third, potential volumes of reactants and/or products may limit

the scale of reuse relative to total emissions. Finally, reuse options need to consider the long‐
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term fate of CO2 and its lifecycle emissions.18 The CCS Task Force also notes there are other

potential commercial uses for captured CO2, such as in food and beverage manufacturing, pulp

and paper manufacturing, the rubber and plastic industry, fire suppression, and refrigeration

and cooling.

As noted in the preamble, however, EPA has not yet determined if such uses would be

applicable towards meeting the standard.  Consideration of how these alternatives could meet

the performance standard involves understanding the ultimate fate of the captured CO2 and

the degree to which the method permanently isolates the CO2 from the atmosphere, as well as

existing methodologies to verify this permanent storage.

4.7 GHG and Clean Energy Regulation in the Power Sector

4.7.1 State Policies

Several states have also recently established emission performance standards or other

measures to limit emissions of GHGs from new EGUs that are comparable to this proposal in

this rulemaking.  

In 2003, then‐Governor George Pataki sent a letter to his counterparts in the Northeast

and Mid‐Atlantic inviting themn to participate in the development of a regional cap‐and‐trade

program addressing power plant CO2 emissions.  This program, known as the Regional

Greenhouse Gas Initiative (RGGI), began in 2009 and sets a regional CO2 cap for participating

states.  The currently participating states include: Connecticut, Delaware, Maine, Maryland,

Massachusetts, New Hampshire, New York, Rhode Island, and Vermont.  The cap covers CO2

emissions from all fossil‐fired EGUs greater than 25 MW in participating states, and limits total

emissions to 91 million short tons in 2014.  This emissions budget is reduced 2.5% annually in

from 2015 to 2020.

In September 2006, California Governor Schwarzenegger signed into law Senate Bill

1368. The law limits long‐term investments in baseload generation by the state's utilities to

power plants that meet an emissions performance standard jointly established by the California

Energy Commission and the California Public Utilities Commission. The Energy Commission has

designed regulations that establish a standard for new and existing baseload generation owned

by, or under long‐term contract to publicly owned utilities, of 1,100 lb CO2/MWh.

In 2006 Governor Schwarzenagger also signed into law Assembly Bill 32, the Global

Warming Solutions Act of 2006.  This act includes a multi‐sector GHG cap‐and‐trade program

                                                      

18 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010).
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which covers approximately 85% of the state GHG emissions.  EGUs are includes in phase I of

the program, which began in 2013.  Phase II begins in 2020 and includes upstream sources.  The

cap is based on a 2 percent reduction from total 2012 expected emissions, and declines 2

percent annually through 2014, then 3 percent each year until 2020.     

In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, which

established statewide GHG emissions reduction goals, and imposed an emission standard that

applies to any baseload electric generation that commenced operation after June 1, 2008 and is

located in Washington, whether or not that generation serves load located within the state.

Baseload generation facilities must initially comply with an emission limit of 1,100 lb CO2/MWh.

In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, which mandated that

facilities generating baseload electricity, whether gas‐ or coal‐fired, must have emissions equal

to or less than 1,100 lb CO2/MWh, and prohibited utilities from entering into long‐term

purchase agreements for baseload electricity with out‐of‐state facilities that do not meet that

standard. Natural gas‐ and petroleum distillate‐fired facilities that are primarily used to serve

peak demand or to integrate energy from renewable resources are specifically exempted from

the performance standard.

In August 2011, New York Governor Cuomo signed the Power NY Act of 2011. This

regulation establishes CO2 emission standards for new and modified electric generators greater

than 25 MW.  The standards vary based on the type of facility: baseload facilities must meet a

CO2 standard of 925 lb/MWh or 120 lb/MMBtu, and peaking facilities must meet a CO2

standard of 1,450 lbs/MWh or 160 lbs/MMBtu.

Additionally, most states have implemented Renewable Portfolio Standards (RPS), or

Renewable Electricity Standards (RES).  These programs are designed to increase the renewable

share of a state’s total electricity generation.  Currently 30 states and the District of Columbia

have enforceable RPS or other mandatory renewable capacity policies, and 7 states have

voluntary goals.19  These programs vary widely in structure, enforcement, and scope.   

4.7.2 Federal Policies

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

pollutant, giving the EPA the authority to regulate GHGs under the CAA contingent upon an

agency determination that GHG emissions from new motor vehicles cause or contribute to air

pollution that may reasonably be anticipated to endanger public health or welfare. This

decision to regulate GHG emissions for motor vehicles set the stage for the determination of

                                                      

19 EIA 2012a
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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), the EPA issued the Mandatory Reporting of Greenhouse Gases Rule (74 FR 5620) which

required reporting of GHG data and other relevant information from fossil fuel suppliers and

industrial gas suppliers, direct greenhouse gas emitters, and manufacturers of heavy‐duty and

off‐road vehicles and engines. The purpose of the rule was to collect accurate and timely GHG

data to inform future policy decisions. As such, it did not require that sources control

greenhouse gases, but sources above certain threshold levels must monitor and report

emissions.

In August 2007, the EPA issued a prevention of significant deterioration (PSD) permit to

Deseret Power Electric Cooperative, authorizing it to construct a new waste‐coal‐fired EGU near

its existing Bonanza Power Plant, in Bonanza, Utah. The permit did not include emissions

control requirements for CO2. The EPA acknowledged the Supreme Court decision, but found

that decision alone did not require PSD permits to include limits on CO2 emissions. Sierra Club

challenged the Deseret permit. In November 2008, the Environmental Appeals Board (EAB)

remanded the permit to the EPA to reconsider “whether or not to impose a CO2 BACT limit in

light of the ‘subject to regulation’ definition under the CAA.” The remand was based in part on

EAB’s finding that there was not an established EPA interpretation of the regulatory phrase

“subject to regulation.”  

In December 2008, the Administrator issued a memo indicating that the PSD Permitting

Program would apply to pollutants that are subject to either a provision in the CAA or a

regulation adopted by the EPA under the CAA that requires actual control of emissions of that

pollutant. The memo further explained that pollutants for which the EPA regulations only

require monitoring or reporting, such as the provisions for CO2 in the Acid Rain Program, are

not subject to PSD permitting. Fifteen organizations petitioned the EPA for reconsideration,

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

EPA affirmed the position that PSD permitting is not triggered for a pollutant such as GHGs until

a final nationwide rule requires actual control of emissions of the pollutant. For GHGs, this

meant January 2011 when the first national rule limiting GHG emissions for cars and light trucks

was scheduled to take effect. Therefore, a permit issued after January 2, 2011, would have to

address GHG emissions.
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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 any industry or other entities, but allowed the EPA

to regulate greenhouse gases under the CAA (see preamble section II.E for regulatory

background). This action was a prerequisite to implementing the EPA's proposed greenhouse

gas emission standards for light‐duty vehicles, which was finalized in January 2010. Once a

pollutant is regulated under the CAA, it is subject to permitting requirements under the PSD

and Title V programs.  The 2009 Endangerment Finding and a denial of a reconsideration were

challenged in a lawsuit; on June 26, 2012, the DC Circuit Court upheld the Endangerment

Finding and the Reconsideration Denial, ruling that the Finding was neither arbitrary nor

capricious, was consistent with Massachusetts v. EPA, and was adequately supported by the

administrative record. The Court found that the EPA had based its decision on “substantial

scientific evidence,” noted that the EPA’s reliance on assessments was consistent with the

methods decision‐makers often use to make a science‐based judgment, and stated that “EPA’s

interpretation of the governing CAA provisions is unambiguously correct.”

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

emissions that define when permits under the New Source Review and Title V Operating Permit

programs are required for new and existing industrial facilities. Facilities responsible for nearly

70 percent of the national GHG emissions from stationary sources, including EGUs, were

subject to permitting requirements under the rule.  This rule was upheld by the D.C. Circuit in

2012.

The EPA entered into two proposed settlement agreements in December 2010 to issue

rules that will address greenhouse gas emissions from fossil fuel‐fired power plants and

refineries. These two industrial sectors make up nearly 40 percent of the nation’s greenhouse
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gas emissions. On March 27, 2012, EPA proposed NSPS for new source natural gas, coal, and

other solid fossil‐fired EGUs .  After consideration of information provided in more than 2.5 7

million comments on this proposal, as well as consideration of continuing changes in the

electricity sector, the EPA determined that revisions in its proposed approach are warranted.  

This rule replaces that proposal.  Existing source standards are not addressed in this action.

Details of the settlement agreements can be found on the EPA website.20

4.7.3. Proposed Federal Policies, Non‐GHG

EPA is reviewing public comment and developing final regulations for the following

three proposed rules, which will impact EGUs: Steam Electric Effluent Limitation Guidelines,

Cooling Water Intake Structures, and Coal Combustion Residuals (CCR).  These three proposed

rules are summarized below.  In general, most EPA rulemakings affecting the power sector

focus on existing sources. Therefore, few interactions are likely between other power sector

rules and this rule, which focuses only on new sources.

On Friday, June 7th, 2013, EPA proposed a regulation that would strengthen the

controls on discharges from certain steam electric power plants by revising technology‐based

effluent limitations guidelines and standards for the steam electric power generating point

source category. Existing steam electric power plants contribute 50‐60 percent of all toxic

pollutants discharged to surface waters by all industrial categories currently regulated in the

United States under the Clean Water Act. Furthermore, power plant discharges to surface

waters are expected to increase as pollutants are increasingly captured by air pollution controls

and transferred to wastewater discharges. This proposal would reduce the amount of toxic

metals and other pollutants discharged to surface waters from power plants. EPA has proposed

new requirements for both existing and new generating units. EPA estimates that the

compliance costs for a new unit (capital and O&M) under the proposed standards represent at

most 1.5 percent of the annualized cost of building and operating a new 1,300 MW coal‐fired

plant, with capital costs representing less than 1 percent of the overnight construction costs,

and annual O&M costs representing less than 5 percent of the cost of operating a new plant.  

  Section 316(b) of the CWA, 33 U.S.C. 1326(b), requires that standards applicable to

point sources under sections 301 and 306 of the Act require that the location, design,

construction, and capacity of cooling water intake structures reflect the best technology

available to minimize adverse environmental impacts.   In April 2011, EPA proposed new

standards to reduce injury and death of fish and other aquatic life caused by cooling water

                                                      

20 http://www.epa.gov/airquality/ghgsettlement.html
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intake structures at existing power plants and manufacturing facilities. The proposed rule would

subject existing power plants and manufacturing facilities withdrawing in excess of 2 million of

gallons per day (MGD) of cooling water to an upper limit on the number of fish destroyed

through impingement, as well as site‐specific entrainment mortality standards. Certain plants

that withdraw very large volumes of water would also be required to conduct studies for use by

the permit writer in determining site‐specific entrainment controls for such facilities. Finally,

under the proposed rule, new generating units constructed at existing power plants would be

required to reduce the intake of cooling water associated with the new unit, to a level that

could be attained by using a closed‐cycle cooling system. EPA is continuing the process of

addressing comments and finalizing the rule.

   On June 21, 2010, EPA co‐proposed regulations that included two approaches to

regulating the disposal of coal combustion residuals (CCRs) generated by electric utilities and

independent power producers. CCRs are residues from the combustion of coal in steam electric

power plants and include materials such as coal ash (fly ash and bottom ash) and flue gas

desulfurization (FGD) wastes. Under one proposed approach, EPA would list these residuals as

``special wastes,'' when destined for disposal in landfills or surface impoundments, and would

apply the existing regulatory requirements established under Subtitle C of RCRA to such wastes.

Under the second proposed approach, EPA would establish new regulations applicable

specifically to CCRs under subtitle D of RCRA, the section of the statute applicable to solid (i.e.,

non‐hazardous) wastes. Under both approaches, CCRs that are beneficially used would remain

exempt under the Bevill exclusion.  While the Agency is still evaluating all the available

information and comments, and while a final risk assessment for the CCR rule has not yet been

completed, reliance on the data and analyses discussed in the preamble to the recent Steam

Electric ELG proposal may have the potential to lower the CCR rule risk assessment results by as

much as an order of magnitude. If this proves to be the case, EPA’s current thinking is that, the

revised risks, coupled with the ELG requirements that the Agency may promulgate, and the

increased Federal oversight such requirements could achieve, could provide strong support for

a conclusion that regulation of CCR disposal under RCRA Subtitle D would be adequate.

4.8   Revenues, Expenses, and Prices

Due to lower retail electricity sales, total utility operating revenues declined in 2011 to

$281 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008

levels in 2011, operating expenses were appreciably lower and as a result, net income also rose
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in comparison to both 2009 and 2010 (see Table 4‐9). Recent economic events have put

downward pressure on electricity demand, thus dampening electricity prices and consumption

(utility revenues), but have also reduced the price and cost of fossil fuels and other expenses.

Electricity sales and revenues associated with the generation, transmission, and distribution of

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

projected to be roughly $359 billion (see Table 4‐10).

Table 4‐9 shows that investor‐owned utilities (IOUs) earned income of about 11.9

percent compared to total revenues in 2011. Based on EIA's Annual Energy Outlook 2013, Table

4‐10 shows that the power sector is projected to derive revenues of $359 billion in 2015.

Assuming the same income ratio from IOUs (with no income kept by public power), and using

the same proportion of power sales from public power as observed in 2011, the EPA projects

that the power sector will expend over $320 billion in 2015 to generate, transmit, and

distribute electricity to end‐use consumers.

Over the past 50 years, real retail electricity prices have ranged from around 7 cents per

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

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

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

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

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

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

real price of electricity today is lower than it was in the early 1960s and 1980s (see Figure 4‐79).
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Figure 4‐97. National Average Retail Electricity Price (1960 – 2011)

Source: EIA 2013

Table 4‐98.   Revenue and Expense Statistics for Major U.S. Investor‐Owned Electric Utilities

for 2010 ($millions)

2009 2010 2011

Utility Operating Revenues 276,124 285,512 280,520

Electric Utility 249,303 260,119 255,573

Other Utility 26,822 25,393 24,946

Utility Operating Expenses 244,243 253,022 247,118

Electric Utility 219,544 234,173 228,873

Operation 154,925 166,922 161,460

Production 118,816 128,831 122,520

Cost of Fuel 40,242 44,138 42,779

Purchased Power 67,630 67,284 61,447

Other 10,970 17,409 18,294

Transmission 6,742 6,948 6,876

Distribution 3,947 4,007 4,044

Customer Accounts 5,203 5,091 5,180

Customer Service 3,857 4,741 5,311

0

2

4

6

8

10

12

14

1960 1970 1980 1990 2000 2010

cents/KWh (2011$)
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Sales 178 185 185

Admin. and  

General 15,991 17,120 17,343

Maintenance 14,092 14,957 15,772

Depreciation 20,095 20,951 22,555

Taxes and Other 29,081 31,343 29,086

Other Utility 24,698 18,849 18,245

Net Utility Operating Income 31,881 32,490 33,402

Source: Table 8.3, EIA Electric Power Annual, 2011

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

Table 4‐109. Projected Revenues by Service Category in 2015 for Public Power and Investor‐

Owned Utilities (billions)

Generation $207

Transmission $40

Distribution $111

Total $359

Source: EIA 2013

Note: Data are derived by taking either total electricity use (for generation) or sales (transmission and

distribution) and multiplying by forecasted prices by service category from Table 8 of EIA AEO 2013

(Electricity Supply, Disposition, Prices, and Emissions).
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Figure 4‐7. National Average Retail Electricity Price (1960 – 2011)

Source: EIA 2013

On a state‐by‐state basis, retail electricity prices vary considerably. The Northeast and

California have average retail prices that can be as much as double those of other states (see

Figure 4‐108).

0

2

4

6

8

10

12

14

1960 1970 1980 1990 2000 2010

cents/KWh (2011$)
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Figure 4‐108.  Average Retail Electricity Price by State (cents/kWh), 2011

Source: EIA 2012

4.9   Natural Gas Market

The natural gas market in the United States has historically experienced significant price

volatility from year to year, between seasons within a year, and can undergo major price swings

during short‐lived weather events (such as cold snaps leading to short‐run spikes in heating

demand). Over the last decade, gas prices (both Henry Hub prices and delivered prices to the

power sector) have ranged from below $3 to nearly $10/mmBtu on an annual average basis

(see Figure 4‐119). During that time, the daily price of natural gas reached as high as

$15/mmBtu. Recent forecasts of natural gas availability have also experienced considerable

revision as new sources of gas have been discovered and have come to market, although there

continues to be some uncertainty surrounding the precise quantity of the resource base.
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Current and projected natural gas prices are considerably lower than the prices

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

drilling techniques that have opened up new shale gas resources and substantially increased

the supply of economically recoverable natural gas. According to AEO 2012 (EIA 2012):

Shale gas refers to natural gas that is trapped within shale formations. Shales are

fine‐grained sedimentary rocks that can be rich sources of petroleum and natural

gas. Over the past decade, the combination of horizontal drilling and hydraulic

fracturing has allowed access to large volumes of shale gas that were previously

uneconomical to produce. The production of natural gas from shale formations

has rejuvenated the natural gas industry in the United States.

The U.S. Energy Information Administration's Annual Energy Outlook 2012 (Early

Release) estimates that the United States possessed 2,214 trillion cubic feet (Tcf) of

technically recoverable natural gas resources as of January 1, 2010. Natural gas from

proven and unproven shale resources accounts for 542 Tcf of this resource estimate.

Many shale formations, especially the Marcellus, are so large that only small portions of

the entire formations have been intensively production‐tested. Consequently, the

estimate of technically recoverable resources is highly uncertain, and is regularly

updated as more information is gained through drilling and production. At the 2010 rate

of U.S. consumption (about 24.1 Tcf per year), 2,214 Tcf of natural gas is enough to

supply over 90 years of use. Although the estimate of the shale gas resource base is

lower than in the prior edition of the Outlook, shale gas production estimates increased

between the 2011 and 2012 Outlooks, driven by lower drilling costs and continued

drilling in shale plays with high concentrations of natural gas liquids and crude oil, which

have a higher value in energy equivalent terms than dry natural gas.21

EIA’s projections of natural gas conditions did not change substantially in AEO 2013

from the AEO 2012, and EIA is still forecasting abundant reserves consistent with the above

findings.  Recent historical data reported to EIA is also consistent with these trends, with 2012

being the highest year on record for domestic natural gas production.22 The average delivered

                                                      

21 For more information, see: http://www.eia.gov/forecasts/archive/aeo11/IF_all.cfm#prospectshale;

http://www.eia.gov/energy_in_brief/about_shale_gas.cfm   22 http://www.eia.gov/dnav/ng/hist/n9010us2a.htm
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natural gas price to the power sector was $3.44 per MMBtu in 2012, down from $4.78/MMBtu

in 2011.23   

EIA projections of future natural gas prices assume trends that are consistent with

historical and current market behavior, technological and demographic changes, and current

laws and regulations.24 Depending on actual conditions, there may be significant variation from

the price projected in the reference case and the price observed. To address this uncertainty,

EIA issues a range of alternative cases, including cases with higher and lower economic growth,

which address many of the uncertainties inherent in the long‐term projections. The EPA

describes the AEO 2013 reference case and a number of relevant alternative cases in the

analyses in Chapter 5.

                                                      

23 http://www.eia.gov/dnav/ng/hist/n3045us3A.htm; Assumes that 1 TCF = 1.023 MMBtu natural gas

(http://www.eia.gov/tools/faqs/faq.cfm?id=45&t=8) 24 EIA 2010c.

0

2

4

6

8

10

12

1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040

2011 dollars per million Btu

Natural Gas Spot Price, Annual Average (Henry Hub)

EIA Historical

EIA Projected (AEO 2011)

EIA Projected (AEO 2012)

EIA Projected (AEO 2013)
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Figure 4‐119. Natural Gas Spot Price, Annual Average (Henry Hub)

Source: EIA 2010d, EIA 2011, EIA 2012, EIA 2013

4.10 Electricity Demand and Demand Response

Electricity performs a vital and high‐value function in the economy. Historically, growth

in electricity consumption has been closely aligned with economic growth. Overall, the U.S.

economy has become more efficient over time, producing more output (gross domestic

product – GDPGDP) per unit of energy input, with per capita energy use fairly constant over the

past 30 years (EIA, 2010e). The growth rate of electricity demanded has also been in overall

decline for the past sixty years (see Figure 4‐1210), 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.25 Second, companies have strong financial incentives to

reduce expenditures, including those for energy. Third, companies are responding to the

marketplace and continually develop and bring to market new technologies that reduce energy

consumption. Fourth, other policies, such as energy efficiency standards at the state and

Federal level, have helped address certain market failures. These broader changes have altered

the outlook for future electricity growth (see Figure 4‐10).  

                                                      

25 EIA 2013
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Figure 4‐7120.Electricity Growth Rate (3 Year Rolling Average) and Projections from the

Annual Energy Outlook 2013

Source: EIA 2009, EIA 2013

Energy efficiency initiatives have become more common, and investments in energy

efficiency are projected to continue to increase for the next 5 to 10 years, driven in part by the

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

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

incentives to reduce electricity consumption and peak load. According to EIA, demand‐side

management provided actual peak load reductions of 33.3 GW in 2010. For context, the current

coal fleet is roughly 314 GW of capacity.

Demand for electricity, especially in the short run, is not very sensitive to changes in

prices and is considered relatively price inelastic, although some demand reduction does occur

in response to price. With that in mind, the EPA modeling does not typically incorporate a

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

prices typically projected for EPA rulemakings. Electricity demand is considered to be constant

in EPA modeling applications and the reduction in production costs that would result from

lower demand is not considered in the primary analytical scenario that is modeled. This leads to

some overstatement in the private compliance costs that the EPA estimates for rules where

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

create compliance costs for projected new EGU sources

.  

4.110   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.  
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Pacific Northwest National Laboratory (PNNL). An Assessment of the Commercial Availability of

Carbon Dioxide Capture and Storage Technologies as of June 2009. June 2009. Available

online at: http://www.pnl.gov/science/pdf/PNNL‐18520_Status_of_CCS_062009.pdf.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

online at: http://www.eia.gov/forecasts/archive/aeo11/.  

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2012 (Early Release).

2012. Available online at: http://www.eia.gov/forecasts/aeo/.

U.S. Energy Information Administration (U.S. EIA). Today in Energy: s Most states have

Renewable Portfolio Standards.  2012a. Available online at:

http://www.eia.gov/todayinenergy/detail.cfm?id=4850.

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available

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

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

and Sinks: 1990–2011. April 2013. Available online at:

http://www.epa.gov/climatechange/Downloads/ghgemissions/US‐GHG‐Inventory‐2013‐

Main‐Text.pdf.

  
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CHAPTER 5

COSTS, BENEFITS, ECONOMIC, AND ENERGY IMPACTS

5.1 Synopsis

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

analysesanalysis performed for the proposed EGU New Source GHG NSPSStandards. EPA

analyzed and assessed a wide range of potential scenarios and outcomes, using a detailed

power sector model, other government projections for the power sector, and additional

economic assessments and analysis to determine the potential impacts of this action.   

The primary finding of this assessment is that in the absence of this proposed rule, all

projected unplanned1 capacity additions affected by this proposal during the analysis period

would already be compliant with the rule’s requirements (e.g., combined cycle natural gas, low

capacity factor natural gas combustion turbine, and small amounts of coal with CCS supported

largely by Federal and State funding). The analysis period is defined as through 20222 to reflect

that CAA Section 111(b) requires that the NSPS be reviewed every eight years.  EPA’s conclusion

was based onthe result of:

 Energy Information Administration (EIA) power sector modeling projections

 EPA power sector modeling projections

 Electric utility integrated resource planning (IRP) documents

 Projected new electric generating units (EGUs) reported by industry to EIA

EPA’s finding of no new, unplanned conventional coal‐fired capacity is robust beyond

the analysis period (past 2030 in both EIA and EPA baseline modeling projections) and across a

wide range of alternative potential market, technical, and regulatory scenarios that influence

power sector investment decisions.  As a result, thisthe proposed EGU New Source GHG NSPS

isStandards are not expected to change GHG emissions for newly constructed EGUs, and it isare

anticipated to yield no monetized benefits and impose negligible costs, economic impacts, or

energy impacts on the electricity sector or society.  While EPA does not project any new coal‐

fired EGUs without CCS to be built in the absence of this proposal, this chapter presents an

analysis of the project‐level costs of building new coal‐fired capacity with and without CCS to

                                                      

1 Unplanned capacity represents projected capacity additions that are not under construction. 2 Information for other years has been made available in the docket and is discussed where appropriate

throughout the document.
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demonstrate that a requirement of partial CCS would not preclude new coal construction.  An

additional illustrative analysis, presented at the end of this chapter, shows that even in the

unlikely event that new, noncompliant EGU capacity would be built in the absence of this rule

the proposed EGU New Source GHG NSPSStandards would likely provide net social benefits

under a range of assumptions.

5.2 Requirements of the Proposed GHG EGU NSPS

In this action, the EPA is proposing separate standards of performance for two basic

categories of new units that have not commenced construction: (i) coal‐fired and other solid

fossil fuel‐fired electric utility steam generating units (boilers and integrated gasification

combined cycle (IGCC) units); and (ii) natural gas‐fired stationary combustion turbines that

generate electricity for sale and meet certain size and operational criteria.

The EPA is proposing to create subcategories within the EGU category and is proposing

standards of performance for affected sources within those the following subcategories. The

subcategories are: (1) natural gas‐fired stationary combustion turbines with a heat input rating

to the turbine engine that is greater than 850 MMBtu/hr; (2) natural gas‐fired stationary

combustion turbines with a heat input rating to the turbine engine that is less than or equal to

850 MMBtu/hr; and (3) all solid fossil fuel‐fired boilers and IGCC units.  All affected new fossil

fuel‐fired EGUs would be required to meet an output‐based emission rate of a specific mass of

CO2 per MWh of electricity generated energy output on a gross basis.  New natural gas‐fired

stationary combustion turbines with a heat input rating greater than 850 MMBtu/hr would be

required to meet a standard of 1,000 lb CO2/MWh of gross energy output.  New natural gas‐

fired stationary combustion turbines with a heat input rating less than or equal to 850

MMBtu/hr would be required to meet a standard of 1,100 lb CO2/MWh of gross energy output.

New solid fossil fuel‐fired boilers and IGCC units would be required to meet a standard of 1,100

lb CO2/MWh of gross energy output.  These standards would be met on a 12‐operating month

rolling average basis.  An alternative emission limit, available only to new solid fossil‐fired

EGUsboilers and IGCC units, can be met over a 60‐operating month rolling average basis.  The

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

  

The proposed action applies to sources based on electric sales.  More specifically, a

facility is covered if it sells more than 1/3 of its potential electric output and more than 219,000

MWh net electric output to the grid.  The proposed definition does not explicitly exclude simple

cycle combustion turbines, but as a practical matter, it is generally expected not to apply as

most simple cycle combustion turbines sell less than 1/3 of their potential electric output.  For

potential combustion turbines that anticipate selling more than 1/3 of their potential electric
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5‐3

output, there are more cost effective and lower emitting technologies that could be

constructed consistent with the proposed standards as will be demonstrated later in thise

Cchapter.  Please refer to the preamble for additional detail concerning affected sources and

standards of performance.

5.3 Power Sector Modeling Framework

5.3.1 Modeling Overview

Over the last decade, EPA has conducted extensive analyses of regulatory actions

impacting the power sector.  These efforts support the Agency’s understanding of key policy

variables and provide the framework for how the Agency estimates the costs and benefits

associated with its actions.  Current forecasts for the utilization of new and existing generating

capacity are a key input into informing the design of EPA’s proposal.  Given excess capacity

within the existing fleet and relatively low forecasts of electricity demand growth, there is

limited new capacity ‐ of any type ‐ expected to be constructed over the next decade.  A small

number of new coal‐fired power plants have been built in recent years; however, EPA does not

expect the construction of any new, unplanned, conventional coal‐fired capacity through the

analysis period. This conclusion is based in part on the Agency’s own power sector modeling

utilizing the Integrated Planning Model (IPM) as well as EIA’s Annual Energy Outlook 2013 (AEO

2013) projections.  

IPM, developed by ICF Consulting, is a state‐of‐the‐art, peer reviewed, dynamic linear

programming model that can be used to project power sector behavior under future business

as usual conditions and examine prospective air pollution control policies throughout the

United States for the entire electric power system. EPA used IPM to project likely future

electricity market conditions with and without the proposed rule.  In addition to IPM, EPA has

closely examined the Annual Energy Outlook 2013 (AEO 2013) from the EIA.

To produce the AEO, EIA employs the National Energy Modeling System (NEMS), an

energy‐economy modeling system of the United States.  According to EIA:3

“NEMS projects the production, imports, conversion, consumption, and prices of

energy, subject to assumptions on macroeconomic and financial factors, world energy

markets, resource availability and costs, behavioral and technological choice criteria,

cost and performance characteristics of energy technologies, and demographics.”

                                                      

3 http://www.eia.gov/oiaf/aeo/overview/
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The Electricity Market Module of NEMS produces projections of power sector behavior

that minimizeoptimize the cost of meeting electricity demand subject to the sector’s inherent

constraints, including the availability of existing generation capacityresources, transmission

capacity and cost, cost of utility and nonutility technologies, expected load shapes, fuel

markets, regulations, and other factors. EIA’s AEO projections independently support EPA’s

conclusions in that it projects no unplanned, conventional coal‐fired new generation capacity

being constructed through the analysis period that would not already meet the level of the

standard even in the absence of the standard.  Both sets of modeling results are presented in

Section 5.4.

5.3.2 The Integrated Planning Model

IPM is a multi‐regional, dynamic, deterministic linear programming model of the U.S.

electric power sector. It provides forecasts of least cost capacity expansion, electricity dispatch,

and emission control strategies while meeting energy demand and environmental,

transmission, dispatch, and reliability constraints. EPA has used IPM for over two decades to

better understand power sector behavior under future business as usual conditions and

evaluate the economic and emission impacts of prospective environmental policies. The model

is designed to reflect electricity markets as accurately as possible. 4

  EPA uses the best available

information from utilities, industry experts, gas and coal market experts, financial institutions,

and government statistics as the basis for the detailed power sector modeling in IPM.  The

model documentation provides additional information on the assumptions discussed here as

well as all other model assumptions and inputs.5

Although the Agency typically focuses on broad system effects when assessing the

economic impacts of a particular policy, EPA’s application of IPM includes a detailed and

sophisticated regional representation of key power sector variables and its organization.  When

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

the relative economics of various technologies based on a wide spectrum of current and future

considerations, including capital costs, operation and maintenance costs, fuel costs, utility

sector regulations, and emission profiles.  The capital costs for new units account for regional

differences in labor, material, and construction costs. These regional cost differentiation factors

are based on assumptions used in the EIA’s AEO.

                                                      

4 http://www.epa.gov/airmarkt/progsregs/epa‐ipm/index.html 5 http://www.epa.gov/airmarkt/progsregs/epa‐ipm/BaseCasev410.html#documentation
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As part of IPM’s assessment of the relative economic value of building a new power

plant, the model incorporates a detailed representation of the fossil‐fuel supply system that is

used to forecast equilibrium fuel prices, a key component of new power plant economics.  The

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

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

American gas market.  This module consists of 114 supply, demand, and storage nodes and 14

liquefied natural gas regasification facility locations that are tied together by a series of linkages

(i.e., pipelines) that represent the North American natural gas transmission and distribution

network.

IPM also endogenously models the coal supply and demand system throughout the

continental U.S., and reflects non‐power sector demand and imports/exports.  IPM reflects 84

coal supply curves, 12 coal sulfur grades, and the coal transport network, which consists of

1,230 linkages representing rail, barge, and truck and conveyer linkages.  The coal supply curves

in IPM, which are publicly available6

, were developed during a thorough bottom‐up, mine‐by‐

mine approach that depicts the coal choices and associated supply costs that power plants will

face over the modeling time horizon.  The IPM documentation outlines the methods and data

used to quantify the economically recoverable coal reserves, characterize their cost, and build

the 84 coal supply curves.  The coal supply curves were developed in consultation with Wood

Mackenzie, one of the leading energy consulting firms and specialists in coal supply.  These

curves have been independently reviewed by industry experts and have been made available

for public review on several occasions over the past two years during other rulemaking

processes.   

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

power sector emissions. Recently, the model has been used to forecast the costs, emission

changes, and power sector impacts for the Clean Air Interstate Rule, Cross‐State Air Polluton

Rule (CSAPR), and the Mercury and Air Toxics Standards (MATS).7

   

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

panels for both the model itself and EPA’s key modeling input assumptions.8 The rulemaking

process also provides opportunity for expert review and comment by a variety of stakeholders,

including owners and operators of the electricity sector that is represented by the model, public

                                                      

6 v4.10 of the coal supply curves may be found in Appendix 9‐4 of http://www.epa.gov/airmarkt/progsregs/epa‐

ipm/BaseCasev410.html#documentation 7 All of the IPM projections conducted for this rulemaking are available at EPA’s website and in the public docket.. 8 http://www.epa.gov/airmarkets/progsregs/epa‐ipm/past‐modeling.html
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interest groups, and other developers of U.S. electricity sector models.  EPA is required to

respond to significant comments submitted regarding the inputs used in IPM, its structure, and

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

input assumptions, model representation, and modeling results. IPM has received extensive

review by energy and environmental modeling experts in a variety of contexts.  For example, in

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

Section 812 prospective studies that are periodically conducted.9

  The model has also

undergone considerable interagency scrutiny when it has been used to conduct over one dozen

legislative analyses (performed at Congress’ request) over the past decade.  In addition,

Regional Planning Organizations throughout the U.S. have extensively examined IPM as a key

element in the state implementation plan (SIP) process for achieving the National Ambient Air

Quality Standards.  The Agency has also used the model in a number of comparative modeling

exercises sponsored by Stanford University’s Energy Modeling Forum over the past 15 years.

IPM has also been employed by states (e.g., for RGGIRegional 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. States have used the model extensively to inform issues related to ozone in

the northeastern U.S.  This groundbreaking work set the stage for the NOx SIP call, which has

helped reduce summer NOx emissions and the formation of ozone in densely populated areas in

the northeast.   

5.4 Analyses of Future Generating Capacity

5.4.1 Base Case Power Sector Modeling Projections

EPA conducted analysis and modeling in support of the April 2012 EGU GHG New Source

StandardsGHG EGU NSPS proposal, and concluded that new unplanned non‐compliant base

load power plants are not expected to be economic well beyond the analysis period. EPA

conducted an analysis of the economic impacts by modeling a base case scenario of future

electricity market conditions. EPA’s IPM modeling relied on the AEO 2010 for the electric

demand forecast for the U.S. and employed a set of EPA assumptions regarding fuel supplies,

the performance and cost of electric generation technologies, pollution controls, and numerous

other parameters.10 The base case accounts for the effects of the finalized MATS and CSAPR

                                                      

9 http://www.epa.gov/air/sect812/

10 http://www.epa.gov/airmarkt/progsregs/epa‐ipm/proposedEGU_GHG_NSPS.html
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rules, and New Source Review settlements and state rules through December 2010 impacting

sulfur dioxide (SO2), nitrogen oxides (NOx), directly emitted particulate matter and CO2.

11

The most current EIA projections are reflected in AEO 2013 and are summarized in the

following tables alongside the EPA projections.  New coal‐fired capacity through 2030 in the

AEO 2013 reference case is entirely CCS‐equipped and would be in compliance with this

proposal (0.3 GW).  The projected CCS‐equipped capacity is assumed to occur in response to

existing Federal, State, and local incentives for the technology.12 According to the AEO 2013 –

which represents existing policies and regulations influencing the power sector ‐ the vast

majority of new, unplanned generating capacity is forecast to be either natural gas‐fired or

renewable.13  The economics favoring new natural gas combined cycle (NGCC) additions instead

of conventional coal are robust under a range of sensitivity cases examined in the AEO 2013.  

Sensitivity cases that separately examine higher economic growth, lower coal prices, no risk

premium for greenhouse gas emissions liability from conventional coal, and lower oil and

natural gas resources also forecast zero unplanned additions of non‐compliant coal capacity in

the analysis period.  Recent previous versions of the AEO came to similar conclusions. Based on

these previous AEO analyses, DOE concluded that “the low capital expense, technical maturity,

and dispatchability of natural gas generation are likely to dominate investment decisions under

current policies and projected prices."14   

In comparing the EPA and EIA modeling projections reported here, the most important

variables influencing the choice of technology for new generating capacity are more favorable

to new coal‐fired capacity in the EPA analysis.  For example, electric demand in 2020 was

assumed to be 4,305 billion kWh (taken from AEO 2010) in EPA’s modeling projections, which is

over 4% higher than electric demand in AEO 2013. 15  Projected fuel prices for natural gas and

coal are also more favorable to new coal‐fired capacity relative to new NGCC capacity in the

EPA analysis than in the AEO 2013 projections.   

                                                      

11 The legal status of CSAPR and CAIR has no impact on this proposal’s evaluation, as neither CSAPR nor CAIR

significantly influences the type of new capacity additions projected to be economic. 12 These programs include the Emergency Economic Stabilization Act of 2008, the American Reinvestment and

Recovery Act of 2009 (which assisted in funding for such programs as the Clean Coal Power Initiative through

DOE  and tax credits for Clean Energy Manufactures through DOE and the Treasury Department), as well as

loans provided by USDA for CO2 capture projects. 13 http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm   14 Department of Energy (2011). Report on the First Quadrennial Technology Review. Available at

http://energy.gov/sites/prod/files/QTR_report.pdf. 15 In a long‐term power sector modeling framework, calendar years are typically grouped into model run years.  In

EPA’s IPM projections reported in this chapter, 2020 is the run year that is representative of results from

calendar years 2017‐2024.  Consequently, the chapter often presents 2020 projections and results from EPA

and EIA as opposed to projections for the last year of the analysis period (2022).
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Table 5‐1. Reference Case Unplanned Cumulative Capacity Additions (GW)

EPA AEO 2013

Capacity Type 2020 2020 2025 2030

Conventional Coal 0 0 0 0

Coal with CCS 2 0.3 0.3 0.3

Natural Gas CC 7.0 3.1 17.4 48.2

Natural Gas CT 3.0 15.4 28.0 43.3

Nuclear 0 0 0 0

Renewables16 26.9 3.7 6.4 10.5

Distributed Generation 0 0.9 1.9 3.1

Total 38.9 23.4 54.1 105.4

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

Source: EPA 2020 projection from IPM run by EPA, 2011; EIA 2020‐2030 projection from EIA Annual Energy Outlook 2013

The capacity projections of EIA and EPA represent a continuation of current trends,

where natural gas‐fired capacity has been the technology of choice for base load and

intermediate load power generation over the last few years (see Figure 5‐2), due in large part

to its significant levelized cost of electricity17 (LCOE) advantage over coal‐fired generating

technologies.  A greater discussion of the relative LCOE of different generating technologies is

provided beginning in Section 5.5.

                                                      

16 Renewable projections are higher in the EPA reference case due largely to EPA’s 2011 modeling projections

predating  AEO 2013 projections; therefore, all renewable builds that occurred in the interim would be

accounted for in AEO 2013 as ‘planned’ capacity and are omitted from the table above. The overall amount of

total renewable capacity by 2020 is largely similar. 17The levelized cost of electricity is an economic assessment of the cost of electricity from a new generating unit or

plant, including all the costs over its lifetime: initial investment, operations and maintenance, cost of fuel, and

cost of capital.
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Figure 5‐21 Historical   U.S. Power Plant Capacity Additions, by Technology, 1940‐2011

Source: Form EIA‐860 (2011)  

Note: Renewables include hydro, geothermal, biomass, solar, and wind energy technologies.    

In addition to new builds, increased electricity demand is expected to be partially

fulfilled by increased utilization of existing generating capacity.  Generation projections are the

result of least‐cost economic modeling both in IPM and AEO 2013, and reflect the most cost‐

effective dispatch and investment decisions modeled, given a variety of variables and

constraints.  Even without the deployment of unplanned conventional coal‐fired capacity, U.S.

electricity demand will continue to be met by a diverse mix of electricity generation sources

with coal projected to continue to provide the largest share of electricity (39% of total 2020

generation in AEO2013 andto 469% in EPA’s projections2020), as displayed in Table 5‐2.:.   

Table 5‐32. 2011 U.S. Electricity Net Generation and Projections for 2020, 2025, and 2030

(Billion kWh)

   Historical EPA AEO 2013

   2011 2020 2020 2025 2030

Coal 1,718 1,976 1,640 1,707 1,745

Oil 15 Negligible 15 16 16

Natural Gas 926 869 1,078 1,127 1,221
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Nuclear 790 840 885 912 908

Hydroelectric 318 286 289 291 292

Non‐Hydro Renewables 164 289 270 295 310

Other 18 45 5 9 13

Total 3,949 4,305 4,182 4,356 4,506

Source: Historical data from Form EIA‐860, 2011.  EPA 2020 projection from IPM run by EPA, 2011; EIA 2020‐2030 projection

from EIA Annual Energy Outlook 2013Notes: Net summer generating capacity.  The sum of the table values in each column may

not match the total figure due to rounding.  “Non‐Hydro Renewables” include biomass, geothermal, solar, and wind electric

generation capacity.  The capacity of a generating unit that is co‐firing gas in a coal boiler is split in this table between

“pulverized coal” and “Oil/Gas Steam” proportionally by fuel use.

It has been previously noted that since the time of the IPM Base Case analysis,

projections for key market variables are now less favorable to the development of coal‐fired

capacity.  It should also be noted that the most recentlatest developments in federal and state

rules, regulations and subsidies are not fully captured in EPA’s modeling and may impact the

viability of new coal‐fired development:

 State regulations addressing CO2 emissions – Several Sstates have adopted

measures to address emissions of CO2 from the power sector.  These approaches

include flexible market‐based programs like California’s Assembly Bill 32 and the

Regional Greenhouse Gas Initiative (RGGI) in the Northeast, and specific GHG

performance standards for new power plants in California, Oregon, New York,

and Washington.

 State Renewable Portfolio Standards (RPS) – According to EIA, 30 Sstates and the

District of Columbia have an enforceable RPS, or similar laws.18  There are eight

other States that have voluntary goals.19  These measures, in conjunction with

Federal financial incentives, are key drivers of the significant growth in new

renewable energy seen over the past few years and expected over the next

decade.  

 State and Utility IRPs – IRPs, which are usually adopted by utilities in response to

Sstate requirements, allow regulators and utilities to consider a broader array of

measures to meet future electric demand most cost effectively.  IRPs also help

electric planners to consider key strategic and policy goals like electric reliability,

environmental impacts, and the economic efficiency of power sector

investments.20 In general, these plans confirm the expectation that utilities

                                                      

18 http://www.eia.gov/forecasts/aeo/legs_regs_all.cfm#state 19 http://www.dsireusa.org/rpsdata/index.cfm 20 E.g., http://www.pacificpower.net/about/irp.html
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anticipate that any new sources of generation will be from renewables, in

response to state and federal regulations and incentives, and natural gas.  

Furthermore, these plans reflect an expectation of relatively low demand growth

due, in part, to policies and regulations to reduce the electricity consumption

such as energy efficiency regulations and policies, evolution of the Smart Grid,

and demand response measures.  

5.4.2 Alternative Scenarios from AEO 2013  

Power sector modeling that projects no new, unplanned, conventional coal‐fired

capacity in the analysis period have been demonstrated to be robust under a range of

alternative assumptions that influence the industry’s decisions to build new power plants.  For

example, EIA typically supplements the AEO with scenarios that explore key market, technical,

and regulatory issues.  Of the 26 scenarios contained in the AEO 2013, none projected

unplanned, conventional coal capacity in the analysis period, including the four scenarios that

may be considered most favorable to the development of coal‐fired capacity displayed below:21

Table 5‐43. AEO 2013 Unplanned Cumulative Capacity Additions, GW (202022)

Capacity Type Reference High

Growth

Low Coal

Cost

Low Gas

Resource

No GHG

Concern

Conventional Coal 0 0 0 0 0

Coal with CCS 0.3 0.3 0.3 0.3 0.3

Natural Gas 18.5 19.5 17.6 13.7 17.8

Nuclear 0 0 0 0 0

Non‐Hydro Renewables 3.7 13.5 5.0 5.2 4.1

Other 0.9 0.6 0.8 0.2 0.8

Total 23.4 33.9 23.8 19.3 23.1

  

5.4.3 Power Sector Fuel Price Dynamics and Trends

As mature technologies, the cost and performance characteristics of conventional coal‐

fired capacity and NGCC are projected by EPA to be relatively stable over time in comparison to

                                                      

21 AEO 2013 scenario definitions: High Economic Growth increases annual real GDP growth by 0.4%; Low Coal Cost

assumes greater regional productivity growth rates and lower wages, equipment, and transportation costs for

the coal industry; Low Oil and Gas Resource reduces the ultimate estimated recovery of shale gas, tight gas,

and tight oil by 50%; No GHG Concern removes the perceived risk of incurring costs under a future GHG policy

from market investment decisions. 22 The 2020 run year represents conditions out through 2022, consistent with the eight year NSPS review cycle.
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emerging generation technologies.23  Therefore, expectations of future fuel prices play a key

role in determining the overall cost competitiveness of conventional coal versus NGCC.

Current and projected natural gas prices are considerably lower than observed

prices over the past decade.  This is largely due to advances in hydraulic fracturing and

horizontal drilling techniques that have opened up new shale gas resources and

substantially increased the supply of economically recoverable natural gas. According to

EIA’s AEO 2012:

Shale gas refers to natural gas that is trapped within shale formations.

Shales are fine‐grained sedimentary rocks that can be rich sources of petroleum

and natural gas. Over the past decade, the combination of horizontal drilling and

hydraulic fracturing has allowed access to large volumes of shale gas that were

previously uneconomical to produce. The production of natural gas from shale

formations has rejuvenated the natural gas industry in the United States.

The U.S. Energy Information Administration's Annual Energy Outlook 2012 (Early

Release) estimates that the United States possessed 2,214 trillion cubic feet (Tcf) of

technically recoverable natural gas resources as of January 1, 2010. Natural gas from

proven and unproven shale resources accounts for 542 Tcf of this resource estimate.

Many shale formations, especially the Marcellus, are so large that only small portions of

the entire formations have been intensively production‐tested. Consequently, the

estimate of technically recoverable resources is highly uncertain, and is regularly

updated as more information is gained through drilling and production. At the 2010 rate

of U.S. consumption (about 24.1 Tcf per year), 2,214 Tcf of natural gas is enough to

supply over 90 years of use. Although the estimate of the shale gas resource base is

lower than in the prior edition of the Outlook, shale gas production estimates increased

between the 2011 and 2012 Outlooks, driven by lower drilling costs and continued

drilling in shale plays with high concentrations of natural gas liquids and crude oil, which

have a higher value in energy equivalent terms than dry natural gas.24

Recent historical data reported to EIA is also consistent with these trends, with 2012

being the highest year on record for domestic natural gas production.25 The average delivered

                                                      

23 http://www.epa.gov/airmarkt/progsregs/epa‐ipm/docs/v410/Chapter4.pdf

25 http://www.eia.gov/dnav/ng/hist/n9010us2a.htm
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natural gas price to the power sector was $3.44 per MMBtu in 2012, down from $4.78/MMBtu

in 2011.26   

Increases in the natural gas resource base have led to fundamental changes in the

outlook for natural gas.  While sources may disagree on the absolute level of increases from

shale resources, there is general agreement that recoverable natural gas resources will be

substantially higher for the foreseeable future than previously anticipated, exerting downward

pressure on natural gas prices.27  EPA and EIA modeling incorporates the impact of these

additional resources on the forecasts of the price of natural gas used by electric generating

units.  The increases in the natural gas resource base are reflected not only in current natural

gas prices and projections (e.g., AEO 2013), but also in current capacity planning by utilities and

electricity producers across the country.  The North American Electric Reliability Corporation’s

(NERC) Long Term Reliability Assessment, which is based on utility plans for new capacity over a

10‐year period,28 reinforces this consensus by stating that “gas‐fired generation [is] the primary

choice for new capacity.”

EPA’s and EIA’s modeling frameworks are designed to reflect the longer term,

fundamentals‐based perspective that electric utilities and developers employ in evaluating

capital investments, while utilizing scenario testing to account for broader fuel market

uncertainties.  Short‐term fuel price volatility is not the most relevant factor in this context

because new power plants have asset lives measured in decades, not in months or years, and

new capacity investment decisions are based on long‐run expected prices, not month‐to‐

month, or even year‐to year, variations in fuel prices.  Shorter‐term prices will affect how units

are dispatched, but these potential dispatch impacts are considered with other factors over a

longer time horizon and factored into the choice of which type of plant to build.  In contrast,

the uncertainty surrounding long‐term fuel prices will exert significantly greater influence on

the technology selected for new capacity additions. In a modeling context with perfect

foresight, this longer term uncertainty may be evaluated by the scenario testing presented

throughout this analysis.

In addition to major changes in the gas supply outlook, there have been notable changes

in the coal supply outlook.  Coal costs have generally increased over the past few years due

                                                      

26 http://www.eia.gov/dnav/ng/hist/n3045us3A.htm; Assumes that 1 TCF = 1.023 MMBtu natural gas

(http://www.eia.gov/tools/faqs/faq.cfm?id=45&t=8) 27 http://www.eia.gov/forecasts/aeo/IF_all.cfm 28 NERC, Long‐Term Reliability Assessments for 2009 (Table 5) and 2012 (Figure 51).  Capacity includes both

planned and conceptual resources as defined by NERC.
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primarily to increased production costs.  These costs have increased as the most accessible and

economically viable mines are depleted, requiring movement into coal reserves that are more

costly to mine.  The basic trends in coal supply are not expected to change for the foreseeable

future.29

Taken together, current and expected natural gas and coal market trends are

contributing to a fundamental shift in the economic conditions for new power plant

development that utilities and developers have recognized and responded to in planning.30

5.4.4 Power Sector Fuel Projections

  ToThrough scenario analysis to examine the potential impacts of uncertainty inherent

in natural gas and coal markets, the EIA used scenario analysis to generatedeveloped the 2020

fuel price projections in table 5‐5.below:

Table 5‐54. National Delivered 2020 Fuel Prices by AEO 2013 Scenario (2011$/MMBtu)

Scenario31 Natural Gas Coal

Reference 5.00 2.52

High Growth 5.45 2.57

Low Growth 4.64 2.47

High Coal Cost 5.26 2.93

Low Coal Cost 4.85 2.17

High Gas/Oil Resource 3.60 2.47

Low Gas/Oil Resource 6.18 2.78

                                                      

29 http://www.eia.gov/forecasts/aeo/assumptions/pdf/coal.pdf 30 For example: "We don’t have any plans to build new coal plants.  So the rules won’t have much of an impact.  

Any additional generation plants we’d build for the next generation will be natural gas." American Electric

Power, 3/26/2012, National Journal; “As we look out over the next two decades, we do not plan to build

another coal plant. ...  As the evidence is coming in, [shale gas] is proving to be the real deal. If we have no

plans, as one of the largest utilities and largest users of coal in this country, no plans to build a new coal plant

for two decades, the regulations are not relevant.” Jim Rogers (Duke), 3/27/2012, NPR All Things Considered..;

“If you actually look at the economics today, you would be burning gas, not coal,” Jack Fusco, Calpine,

12/1/2010, Marketplace; “Coal’s most ardent defenders are in no hurry to build new ones in this environment.”

John Rowe, Exelon, 9/2011, EnergyBiz; “With low gas prices, gas‐fired generation kind of snowplows everything

else” Lew Hay, NextEra, 11/1/2010, Dow Jones. 31 AEO 2013 scenario definitions: High Economic Growth increases annual real GDP growth by 0.4%; Low Economic

Growth decreases real GDP growth by 0.6%; High Coal Cost assumes lower regional productivity growth rates

and higher wages, equipment, and transportation costs for the coal industry; Low Coal Cost assumes greater

regional productivity growth rates and lower wages, equipment, and transportation costs for the coal industry;

High Oil and Gas Resource expands the ultimate estimated recovery of shale gas, tight gas, and tight oil by

100%; Low Oil and Gas Resource reduces the ultimate estimated recovery of shale gas, tight gas, and tight oil by

50%.
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However, given that power plants are long‐lived assets, capacity planning decisions are

necessarily undertaken with a forward view of expected market and regulatory conditions.  In

producing the AEO 2013, EIA capacity expansion projections are informed by a lifecycle cost

analysis over a 30‐year period in which the expectations of future prices are consistent with the

projections realized in the model (i.e. the model executes decisions with perfect foresight of

future market, technical, and regulatory conditions).  Therefore, the fuel price that informs

capacity expansion decisions in 2020 is not the 2020 price, but the entire future fuel price

stream.  For example, Figure 5‐6 displays EIA’s natural gas price projections for the Reference

Case and several scenarios through 2040.:

Figure 5‐62. National Delivered Natural Gas Prices by Select AEO 2013 Scenario

(2011$/MMBtu)

0

2

4

6

8

10

12

2015 2020 2025 2030 2035 2040

Reference

High growth

Low growth

High coal cost

Low coal cost

High resource

Low resource

No GHG concern

Formatted: Font: Bold
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   Natural gas prices are expected to increase after 2020 in all scenarios32; however, rising

natural gas prices through 2040 – including in EIA’s low gas/oil resource scenario ‐ are still not

sufficient to support new, conventional coal‐fired generation in the analysis period (i.e.,

through 2022), demonstrating that natural gas prices at currently low levels are not required to

persist for NGCC to maintain its economic advantage over coal‐fired technologies.

While the uniformity of EIA scenarios in projecting no new, unplanned, conventional

coal‐fired capacity through the analysis period is compelling, the scenario projections cannot

fully illustrate the extent of the economic advantage that NGCC maintains over conventional

coal – only that the advantage remains intact across a broad range of market and technical

scenarios.  To identify potential market conditions that could fully erode the private cost

advantages of NGCC over conventional coal during the analysis period the following section

adopts a static, engineering cost analysis.

5.5 Levelized Cost of Energy Analysis

5.5.1 Overview of the Concept of Levelized Cost of Energy

New capacity projections from the EPA and EIA reviewed in the previous section

indicate that the NSPS is not projected to require changes in the design or construction of new

EGUs from what would be expected in the absence of the rule.  Thus, under both the baseline

                                                      

32 Coal prices are also expected to rise in all scenarios.

0

2

4

6

8

10

12

2015 2020 2025 2030 2035 2040

Reference

High growth

Low growth

High coal cost

Low coal cost

High resource

Low resource

No GHG concern

Formatted: Font: Bold
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projections as well as alternative AEO 2013 scenarios, the proposed EGU New Source GHG

NSPSStandards areis not projected to result in any emission reductions, monetized benefits, or

costs.

Despite this conclusion, it is important to supplement the power sector modeling

projections to quantify the robustness of the economic advantage of new NGCC relative to new

conventional coal.  To achieve this task, EPA will rely on the concept of levelized cost of energy

(LCOE).  LCOE is a widely used metric that represents the cost, in dollars per output, of building

and operating a generating facility over the entirety of its economic life.  Evaluating

competitiveness on the basis of LCOE is particularly useful in establishing cost comparisons

between generation types with different cost, operating, and financial characteristics.   The

typical cost components associated with LCOE include capital, fixed operating and maintenance

(FOM), variable operating and maintenance (VOM), and fuel.

The levelized capital cost is the result of the annualized capital cost spread over the

annual output of the generation facility.  The annualized capital cost (expressed in $/kw‐yr) is

the product of the $/kW capital cost and the capital recovery factor (CRF).  A simplified CRF may

be calculated using only the project’s interest rate (i) and book life (n).

33:

ܥܴܨ ൌ ݅ሺ1 ൅ ݅ሻ௡/ሾሺ1 ൅ ݅ሻ௡ିଵሿ

The levelized capital and FOM costs may be calculated by taking the annualized capital

and FOM (expressed in $/kW‐yr) and spreading the expense over the annual generation of the

facility using the expected average annual capacity factor (the percent of full load at which a

unit would produce its actual annual generation if it operated for 8760 hours).

The VOM, which is already expressed in terms of cost per unit output, may be presented

with or without fuel expense.  The fuel expense is typically the largest component of VOM (non‐

fuel components to VOM include start‐up fuel, consumables, inspections, etc.) and for certain

capacity types – such as NGCC – fuel expense may represent the majority of the LCOE.  To

calculate a levelized fuel cost, it is necessary to introduce the concept of a levelized fuel price.   

Because levelized costs are constant over the life of the facility, the levelized fuel price

calculates the single value payments necessary to reflect the stream of annual delivered fuel

                                                      

33 The interest rate assumed for natural‐gas fired combined cycleNGCC projects is 9.068%; the interest rate

assumed for coal‐fired projects is 910.572%.  Both types of projects are assumed to have a 30‐year book life,

resulting in a capital recovery factor of 9.78% for NGCC projects and 10.23% for coal‐fired projects..
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prices over the economic life of the facility at a given discount rate.34  Levelizing fuel prices

recognizes the necessity to consider the trajectory of fuel costs over the facility’s entire

economic life.

It should be noted that there are other important considerations beyond LCOE that

impact power plant investment decisions.  New power plant developers must consider the

particular demand characteristics in any particular region, the existing mix of generators,

operational flexibility of different types of generation, prevailing and expected electricity prices,

and other potential revenue opportunities (e.g., the capacity value of a particular unit, where

certain power markets have mechanisms to compensate units for availability to maintain

reliability, sale of co‐products, etc.).  Broader system‐wide power sector modeling – such as the

analyses conducted by EPA and scenarios conducted by EIA – is able to more effectively capture

these considerations.

5.5.2 Cost and Performance of Technologies  

The NGCC and coal‐fired generation technology cost and performance assumptions that

form the basis for the LCOE analysis in this chapter are sourced from the DOE’s Department of

Energy’s National Energy Technology Laboratory (NETL).

35  NETL cost and performance

characteristics were selected for coal‐fired technologies because the NETL estimates were

unique in the detail of theirits cost and performance estimates for a range of CO2 capture levels

for both new super critical pulverized coal (SCPC) and IGCC facilities.36 The CO2 capture

sensitivity analysis included an evaluation of the cost, performance, and environmental profile

of these facilities under different configurations that were tailored to achieve a specific level of

carbon capture.  EPA selected NETL cost and performance characteristics for NGCC to ensure

that the cost comparisons between NGCC and coal‐fired technologies – the primary comparison

made in this chapter – represented a single, internally consistent framework.  For technologies

where NETL cost and performance estimates were not available or sufficiently recent – such as

for nuclear and simple cycle combustion turbine (CT) – EPA adopted EIA’s AEO 2013 estimates

of LCOE.

                                                      

34 As an illustration of applying a discount rate to a stream of future fuel prices, the levelized fuel price will be less

than the mean fuel price if prices are increasing; equal to the mean if fuel prices are constant; and greater than

the mean if fuel prices are declining. The weighting of nearer‐term prices through the application of a discount

rate is consistent with modeling economic behavior.  EPA utilized a 5% discount rate to calculate levelized fuel

prices, a value consistent with the discount rate embedded in IPM. 35 http://www.netl.doe.gov/energy‐analyses/pubs/Gerdes‐08022011.pdf 36 All potential build types are compliant with all current environmental regulations, including EPA’s Mercury and

Air Toxics Standards (MATS).
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To represent a new SCPC facility, NETL assumed a new boiler with a combination of low‐

NOx burners (LNB) with overfire air (OFA) and a selective catalytic reduction (SCR) system for

NOx control. The plant was assumed to have a fabric filter and a wet limestone flue gas

desulfurization (FGD) scrubber for particulate matter and sulfur dioxide (SO22) control,

respectively. For configurations including CCS, the plant was assumed to have a sodium

hydroxide (NaOH) polishing scrubber to ensure that the flue gas entering the CO2 capture

system has a SO2 concentration of 10 ppmv or less. The SCPC w/ CCS plant configurations were

equipped with Fluor’s Econamine FG PlusSM process for post‐combustion CO2 capture via

temperature swing absorption with a monoethanolamine (MEA) solution as the chemical

solvent.

Specific to the partial capture configurations for SCPC, the NETL study identified two

options. The first option identified was to process the entire flue gas stream through the MEA

capture system, but at reduced solvent circulation rates. The second option was to maintain the

same high solvent circulation rate and stripping steam requirement as would be used for full

capture, but only treat a portion of the total flue gas stream. The NETL report determined that

this “slip stream” approach was the most economical because a reduction in flue gas flow rate

will: (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce the size of

the CO2 absorption columns; and (3) trim the cooling water requirement of the direct contact

cooling system37. The “slip stream” approach – which leads to lower capital and operating costs

– was adopted by EPA for cost and performance estimates under partial capture.

For a new IGCC EGU, the NETL study evaluated a number of IGCC plant configurations.

EPA adopted the configurations presented as the most viable – from both an economic and

technological perspective – for the no capture, partial capture, and full capture cases. The no

CO2 capture case employed an IGCC that used the two‐stage acid gas (SelexolTM) process for

acid gas control (i.e., hydrogen sulfide (H2S) and CO2) but no WGS reactor. The 25 percent CO2

capture case utilized the same two‐stage SelexolTM unit to maximize CO2 capture from the

unshifted syngas.  To achieve higher CO2 capture levels – including full capture ‐ the IGCC was

assumed to be configured with a two‐stage WGR with bypass and the two‐stage acid gas

(SelexolTM) scrubbing system. 38

                                                      

37 NETL based this determination primarily upon literature review.  Please refer to page 2 of

http://www.netl.doe.gov/energy‐analyses/pubs/Gerdes‐08022011.pdf 38 For additional detail and discussion on the specific technology configurations selected for this analysis, please

refer to the preamble.
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In summary, the technology cost and performance characteristics utilized by EPA in

developing the LCOE estimates provided in this chapter are listed below in Table 5‐7:

Table 5‐75 Technology Cost and Performance (2011$)

Capacity Type Total Overnight

Capital Cost ($/kw)

Fixed Operations

& Maintenance

($/kw‐yr)

Variable

Operations &

Maintenance

($/MWh)

2020 Fuel

Cost

($/MMBtu)

Net Plant

HHV

Efficiency

(%)

NGCC 891 26.7 1.8 5.00 50.2

SCPC 2,452 70.6 7.7 2.94 39.3

SCPC w/ Partial CCS  

(1,100 lbs/MWh) 3,301 90.7 10.5 2.94 34.5

SCPC w/Full CCS

(200 lbs/MWh) 4,391 116.6 14.1 2.94 28.4

IGCC 2,969 94.8 9.3 2.94 39.0

IGCC w/ Partial CCS  

(1,100 lbs/MWh) 3,274 103.2 10.1 2.94 37.3

IGCC w/ Full CCS

(150 lbs/MWh) 4,086 125.6 12.1 2.94 32.6

Notes: The coal assumed is a bituminous coal with a sulfur content of 2.8% (dry) at a price of $2.94/MMBtu, consistent with the

NETL analysis from which technology cost and performance was sourced39. The natural gas price is the 2020 price from EIA’s

AEO 2013 Reference Case.  The NETL study cost estimates for coal‐fired CCS have an expected accuracy range of ‐15%/+30%.

5.5.3 Levelized Cost of Energy of New Generation Technologies

This section presents four LCOE comparisons:  

1. NGCC to Uncontrolled Coal – to demonstrate the cost advantages of NGCC over a

range of natural gas prices and regional market conditions.

2. Uncontrolled Coal to Coal with partial CCS – to demonstrate that any requirement

for CCS could be accommodated and would not, based on the cost increment of

constructing and operating the CCS portion, preclude new coal construction.

                                                      

39 http://www.netl.doe.gov/energy‐analyses/pubs/Gerdes‐08022011.pdf http://www.netl.doe.gov/energy‐

analyses/pubs/BaselineCostUpdate.pdf
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3. Coal with CCS to Nuclear – to demonstrate that the overall cost of building coal with

CCS is not fundamentally different than the overall cost of constructing a nuclear

facility.

4. NGCC to CT – to demonstrate the unlikelihood of a new combustion turbine being

built with the expectation of exceeding a 33% annual capacity factor and thus being

covered by this proposal.

It should be noted that the LCOE comparisons presented in this section only represent

the cost to the generator and do not reflect the additional social costs that are associated with

emissions of greenhouse gases or other air pollutants.  A broader consideration of the health

and welfare impacts is considered beginning in Section 5.7.   

Additionally, it is important to note that both EIA and EPA apply a climate uncertainty

adder (CUA) ‐ represented by a three percent increase to the weighted average cost of capital –

to new, conventional coal‐fired capacity types.  EIA developed the CUA to address differences in

how investments in new capacity are evaluated in power sector models as compared to

resource planning exercises commonly conducted by the industry.  While baseline power sector

modeling scenarios may not specify potential future GHG regulatory requirements, investors in

the industry typically incorporate some expectation of a future cost to limit CO2 emissions in

resource planning evaluations that influence investment decisions. 40  Therefore, the CUA

reflects the additional risk typically assigned by project developers and utilities to GHG‐

intensive projects in a context of climate uncertainty.  When comparing private investment

costs, EPA believes the inclusion of the CUA in LCOE estimates is consistent with the industry’s

current planning and evaluation framework for future projects (demonstrable through IRPs and

public utility commissionPUC orders) and is therefore necessary to adopt in evaluating the

behavioral response to the cost competitiveness of alternative generating technologies.41   

In defining the CUA, EIA states that “the adjustment should not be seen as an increase in

the actual cost of financing, but rather as representing the implicit hurdle being added to GHG‐

intensive projects to account for the possibility they may eventually have to purchase

allowances or invest in other GHG emission‐reducing projects that offset their emissions.”42

                                                      

40 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm 41 For example, a 2011 Synapse Report lists 15 utilities that adopted a value for CO2 in their integrated resource

planning.  http://www.synapse‐energy.com/Downloads/SynapsePaper.2011‐02.0.2011‐Carbon‐

Paper.A0029.pdf.  In addition to utilities, several state commissions have mandated the inclusion of a cost of

CO2 in long‐term planning (e.g., Minnesota utilities must adopt a price beginning in 2017). 42 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
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Therefore, EPA recognizes the application of the CUA is context dependent – as a part of the

planning costprocess it is appropriately applied in an evaluative sense to prospective projects,

and then removed once a project transitions from planning to execution.  Although a

perspective that omits the CUA is inconsistent with the purposes of the analysis contained in

this section (i.e., EPA is seeking to analyzinge the project characteristics and market conditions

that would lead a developer or utility to select a certain project, not determine what the actual

project costs would be once that project selection is made), LCOE estimates for uncontrolled

coal‐fired projects are presented both with and without the CUA.  All LCOE estimates of coal‐

fired facilities with CCS (partial or full) are presented without the CUA.

5.5.4 Levelized Cost of Electricity of NGCC and Uncontrolled Coal

EPA’s base LCOE estimates for NGCC, SCPC, and IGCC are displayed below by cost

component (capital, FOM, VOM, fuel) and assume a construction date of 2020:

Figure 5‐83. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation

Technologies by Cost Component, EPA43

                                                      

43 Although EPA believes that this cost data is broadly representative of the economics between new coal and new

natural gas facilities, this analysis assumes representative new units and does not reflect the full array of new

generating sources that could potentially be built.  To the extent that other types of new units that would be

affected by this rule could beare built, they couldmay exhibit different costs than those presented here.  For

example, smaller new conventional coal facilities whichof a size smaller than what is assumed in the base

estimate would be more expensive on a $/kw basis and havetend to exhibit a relatively higher LCOE, andwhile

some technologies could potentially havedisplay a lower LCOE if – all else equal ‐ fuel could be obtained

cheaply and capital costs remained similar, or at a lower than, a new base load conventional coal plant price

than that assumed in this analysis (such as may be the case for petroleum coke or waste coal facilities).  These

potential differences do not fundamentally change the analysis presented in this chapter.
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52

92

81

112

97

‐

20

40

60

80

100

120

NGCC SCPC (w/ 3%

Adder)

SCPC (w/o 3%

Adder)

IGCC (w/ 3%

Adder)

IGCC (w/o 3%

Adder)

2011$/MWh

Fuel

VO&M

FO&M

Capital

59

92

81

112

97

‐

20

40

60

80

100

120

NGCC SCPC (w/ 3%

Adder)

SCPC (w/o 3%

Adder)

IGCC (w/ 3%

Adder)

IGCC (w/o 3%

Adder)

2011$/MWh

Fuel

VO&M

FO&M

Capital
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Notes: The coal assumed is a bituminous coal with a sulfur content of 2.8% (dry) at a price of $2.94/MMBtu,

consistent with the NETL analysis from which technology cost and performance was sourced44. The $2.94/MMBtu

delivered coal price is assumed for all years; therefore, the price serves as both the 2020 fuel cost as well as the

levelized fuel cost over any future period of time.  This assumption produces a 20‐year levelized coal price consistent

with the AEO2013 Reference Case’s $2.79/MMBtu projection.  A capacity factor of 85 percent is assumed across all

technologies.  For comparison, EIA estimates levelized costs under AEO 2013 assumptions for SCPC and IGCC are

$99/MWh and $122/MWh, respectively, including a 3% CUA and excluding transmission investment costs.45 The

levelized costs presented above are based on NETL assumptions and will necessarily differ from AEO 2013 levelized

costs for a variety of reasons, including cost and performance characteristics, financial assumptions, and fuel input

prices.

On a levelized cost basis, NGCC is significantly cheaper than all of the uncontrolled coal‐

fired options, including those options that assume no CUA.  In addition to the disparity in LCOE

totals, the cost composition exhibits fundamental differences between natural gas‐ and coal‐

fired facilities, with NGCC dominated by fuel expense and the levelized cost of coal‐fired

technologies driven by capital expense.  Consequently, this section will explore the impact of

changes in natural gas price and the capital costs of coal‐fired facilities to better quantify the

magnitude of the relative cost advantage NGCC exhibits over coal‐fired alternatives.

The figure below presents the LCOE of an NGCC facility at three levelized natural gas

price levels.  For reference, the base LCOE estimates for SCPC and IGCC are included as well.46

                                                      

44 http://www.netl.doe.gov/energy‐analyses/pubs/Gerdes‐08022011.pdf 45 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm 46 Some new units could be designed to combust waste coal or petroleum coke (pet coke), which may be affected

by this rule.  These technologies could exhibit different local economics, particularly in the delivered price of fuel.  

From a capital and operating perspective, EPA believes the cost and performance of these units are broadly similar

and therefore well represented by new, conventional coal‐fired facilities (i.e. SCPC).
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5‐25

Figure 5‐94. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation

Technologies Across Select Natural Gas Prices, EPA

It is only when natural gas prices exceed $10/MMBtu on a levelized basis (in 2011

dollars) that new coal‐fired generation without CCS approaches parity with NGCC in terms of

LCOE (none of the EPA sensitivities or AEO 2013 scenarios described in this chapter project

52

69

86

92

112

0

20

40

60

80

100

120

NGCC

($5/MMBtu)

NGCC

($7.5/MMBtu)

NGCC

($10/MMBtu)

SCPC (w/ 3%

Adder)

IGCC (w/ 3%

Adder)

2011$/MWh

59

69

86

92

112

0

20

40

60

80

100

120

NGCC

($5/MMBtu)

NGCC

($7.5/MMBtu)

NGCC

($10/MMBtu)

SCPC (w/ 3%

Adder)

IGCC (w/ 3%

Adder)

2011$/MWh
***E.O. 12866 Review –Do Not Cite, Quote, or Release During Review***

5‐26

national average natural gas prices near that level). 47  To achieve a $10/MMBtu levelized price

in 2020 would require a significantly more pessimistic natural gas outlook than what is

contained in AEO’s low natural gas resource scenario.  To illustrate, Table 5‐6 reportbelow are

the levelized natural gas prices (initial year of 2020) for both a 20‐year period (to accommodate

the end of EIA’s modeling projections in 2040) and 30‐year period (calculated by continuing the

projected level of price increases through 2050).

48

Table 5‐106. Levelized Natural Gas Prices by Select AEO 2013 Scenario (2011$/MMBtu)

Scenario

20‐Year AEO

Projection

(2020‐2039)

30‐Year AEO‐Based

Projection

(2020‐2049)

Reference 6.11 6.79

High Growth 6.69 7.30

Low Growth 5.64 6.32

High Coal Cost 6.51 7.28

Low Coal Cost 6.00 6.74

High Gas/Oil Resource 4.09 4.40

Low Gas/Oil Resource 7.63 8.50

Note: Discount rate of 5%, consistent with IPM assumptions.  

To achieve a price that exceeds $10/MMBtu on a 20‐year levelized basis in 2020 would

require a natural gas price projection more than 30% higher than EIA’s low resource scenario in

all years – see Figure 5‐511 below.  This elevated natural gas price would result in a

$10.15/MMBtu average annual price in 2030 ($16.23/MMBtu nominal49) and a $13.66/MMBtu

price in 2039 ($27.27/MMBtu nominal). 50

                                                      

47 As noted earlier in this chapter, investment decisions require consideration of fuel price projections over long

periods of time; similarly, the power sector modeling cited here make fuel price projections over long periods

of time.  Neither these modeling projections nor these LCOE calculations are meant to suggest that the gas

price wcould not reach as high as $10/MMBtu at any given point in time; the point is that these analyses do not

expect such a price level to be sustained over a period of time that would influence an economic assessment of

which type of new capacity offers a better investment. 48 Assuming a 5% discount rate,, consistent with IPM assumptions.  The 30‐year natural gas price is calculated by

applying the price increase from 2039 to 2040 in all subsequent years through 2049. 49 Assuming annual inflation of 2.5% 50 Nominal prices assuming an annual inflation rate of 2.5%.
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5‐27

Figure 5‐115. Projected Real National Delivered Natural Gas Price for Select AEO 2013

Scenarios and Illustrative Path for > $10/MMBtu Levelized Cost

To conclude the comparison of NGCC with uncontrolled coal‐fired alternatives, it is

important to note that the LCOE calculations are based on assumptions regarding the average

national cost of generation at new facilities.  It is known that there is significant spatial variation

0

2

4

6

8

10

12

14

16

2011$/MMBtu

Required Natural Gas Price

for >$10/MMBtu Levelized

on a 20‐Year Basis

Low resource

Reference

High resource

0

2

4

6

8

10

12

14

16

2011$/MMBtu

Required Natural Gas Price

for >$10/MMBtu Levelized

on a 20‐Year Basis

Low resource

Reference

High resource
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5‐28

in the costs of new generation due to design differences, labor wage and productivity

differences, and delivered fuel prices among other potential factors.51   

For example, EIA utilizes capital cost scalars to capture regional differences in labor,

material, and construction costs.  The minimum and maximum capital cost scalars across all

regions in AEO 2013 for SCPC, IGCC, and NGCC build options are presented below in Table 5‐

7Figure 5‐12:

52

Table 5‐127. AEO 2013 Regional Capital Cost Scalars by Capacity Type

Capacity Type Minimum Capital

Cost Scalar

Maximum Capital Cost

Scalar

SCPC 0.885 1.152

IGCC 0.908 1.136

NGCC 0.893 1.205

Applying the regional capital cost scalars displayed above to the base LCOE estimates

developed earlier in this section produces only a smallmild change in the relative

competitiveness of the technologies as seen in Table 5‐8.:

Table 5‐138 LCOE Estimates For Minimum and Maximum AEO 2013 Regional Capital Cost

Scalars (2011$/MWh)

Capacity Type Reference (w/ 3%

CUAAdder)

Minimum Capital

Cost Scalar

Maximum Capital

Cost Scalar

SCPC 92 86 100

IGCC 112 106 120

NGCC 5259 5158 5462

The LCOE of SCPC in the lowest capital cost region still results in an LCOE that is ~6040%

higher than an NGCC located in the most expensive capital cost region.  IGCC remains almost

100more than 70% higher under a similar adjustment.  In addition to the relatively mild

changes in LCOE displayed above, the relative movement in LCOE that can be attributed to

regional variations in capital cost is further muted by the fact that a high or low capital cost

region for coal‐fired build types is projected to be a high or low capital cost region for gas‐fired

                                                      

51 http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf 52 Excluding the New York City and Long Island areas, as well as those areas of the country that prohibit the

development of new, uncontrolled coal‐fired facilities.
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5‐29

build types. Due to its capital‐intensive nature, the most favorable regions for development of

new coal‐fired capacity over NGCC are the lowest cost areas – an assumption that only narrows

NGCC’s LCOE advantage by $5/MWh for both SCPC and IGCC.  To completely negate the base

$4033/MWh LCOE advantage of NGCC over SCPC solely with a reduction in coal‐fired capital

costs, overnight capital costs for SCPC would have to be reduced from $2,452/kW to less than

$500~$800/kW; IGCC overnight capital costs would have to be reduced tofall below

$200~$500/kW.

The other primary driver in determining the regional impact on competitiveness of new

build options is delivered fuel prices.  As part of the AEO, EIA releases electric power

projections – including fuel prices – for each of the 22 Electricity Market Module (EMM)

regions.  The two regions with the highest projected 2020 natural gas prices in the AEO 2013

are the Western Electricity Coordinating Council/Southwest (‘Southwest’) and the Florida

Reliability Coordinating Council (‘FRCC’).  The 20‐year levelized natural gas and coal price

forecasts (2020‐2039) in the AEO 2013 reference case are displayed in Figure 5‐6below for both

regions.:

Figure 5‐146 Levelized Regional Fuel Price from AEO 2013 Reference Case, 2020‐2039

(2011$/MMBtu)53

                                                      

53 Assuming 5% discount rate.

6.95

6.43

3.51

2.6

0

1

2

3

4

5

6

7

8

FRCC WECC‐Southwest

20‐Year Levelized Fuel Price (2011$/MMBtu)

Natural Gas Coal

Formatted: Font color: Black
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5‐30

While the FRCC region experiences the highest overall natural gas prices, the Southwest

region realizes a greater $/MMBtu differential between coal and natural gas prices under the

AEO projections; the impact on the LCOE of SCPC, IGCC, and NGCC is reported in Table 5‐

9.calculated below for both sets of fuel prices:  

Table 5‐159. LCOE Estimates For Minimum and Maximum AEO 2013 Regional Capital Cost

Scalars (2011$/MWh)

Capacity Type

Reference (w/ 3%

CUA)EPA Base

Estimates

FRCC Fuel Prices Southwest Fuel

Prices

SCPC (w/ 3% CUAAdder) 92 97 89

IGCC (w/ 3% CUAAdder) 112 117 109

NGCC 5259 65 62

Due to the greater fuel price differential, the more favorable region for the

development of coal‐fired facilities from an LCOE perspective is the Southwest, where the

regional fuel prices reduce the LCOE advantage of NGCC to $27/MWh over SCPC and $47/MWh

over IGCC.  Even combined with the potential $5/MWh cost advantage coal‐fired facilities may

realize from building capacity in the lowest capital cost region, the regional variations

6.95

6.43

3.51

2.6

0

1

2

3

4

5

6

7

8

FRCC WECC‐Southwest

20‐Year Levelized Fuel Price (2011$/MMBtu)

Natural Gas Coal

Formatted: Font color: Black
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5‐31

In conclusion, even the most favorable combination of regional variability in capital

costs and delivered fuel prices represented by EIA are insufficient to support new, unplanned,

conventional coal‐fired capacity in the analysis period.

5.5.5 Levelized Cost of Electricity of Uncontrolled Coal and Coal with Carbon Capture and

Storage (CCS)

The power sector continues to move away from the construction of coal‐fired power

plants in favor of natural gas‐fired power plants due, in part, to the significant LCOE differential

explored in the previous section. Even so, it is possible that a limited number of conventional

coal‐fired power plants might be constructed in the analysis period. In these circumstances, EPA

believes that any requirement for CCS could be accommodated and would not, based on the

incremental cost of the CCS portion of the new unit, render the construction of the new coal‐

fired facility to be cost‐prohibitive.54

A key factor in this determination is the availability of enhanced recovery (ER)

opportunities for new coal‐fired facilities.  ER, which includes both enhanced oil recovery (EOR)

and enhanced gas recovery (EGR), refers to the injection of fluids into a reservoir to increase oil

and/or gas production efficiency. CO2‐EOR has been successfully used at many production fields

throughout the United States. The oil and natural gas industry in the United States has over 40

years of experience in injection and monitoring of CO2. This experience provides a strong

foundation for the technologies used in thethat will be needed for successful deployment of

CCS from on coal‐fired electric generating units.  Although deep saline formations provide the

most CO2 storage opportunity (2,102 to 20,043 billion metric tons), oil and gas reservoirs are

estimated to have 226 billion metric tons of CO2 storage resource.55   

The use of CO2 for EOR can significantly lower the cost of implementing CCS. The

opportunity to sell the captured CO2 rather than paying directly for its long‐term storage,

greatly improves the economics of the new generating unit. According to the International

Energy Agency, of the CCS projects under construction or at an advanced stage of planning,

70% intend to use captured CO2 to improve recovery of oil in mature fields (enhanced oil

recovery, CO2‐EOR).  , including Southern Company’s Kemper County Energy Facility, Summit

Power’s Texas Clean Energy Project, and the Hydrogen Energy California Project.

                                                      

54 The preamble provides a complete list of existing sources that have demonstrated CCS as well as new coal‐fired

facilities that will utilize CCS and are very near to completion. 55 U.S. Department of Energy National Energy Technology Laboratory (2012). United States Carbon Utilization and

Storage Atlas, Fourth Edition.
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There are two EOR opportunities presented in Figure 5‐16 – ‘High’ and ‘Low.’  The high

EOR opportunity assumes a CO2 sale price of $40 per metric ton; the low EOR opportunity

assumes a CO2 sale price of $20 per metric ton.56  For either opportunity, it is assumed that the

facility is only responsible for the costs of transmitting the captured CO2 to the fence line, as is

currently the practice.57  Costs for the transportation, storage, and monitoring (TSM) of CO2 are

included in this analysis. For non‐EOR applications, TSM costs of ~$5‐$15 dollars per ton of CO2

are applied based on the level of capture.58 Although this proposal has determined partial CCS is

BSER for affected coal‐fired facilities, the LCOE associated with full capture is presented as well

for illustrative purposes:

Figure 5‐167 Levelized Cost of Energy, Uncontrolled Coal and Coal with Full and Partial CCS

(1,100 lbs/MWh gross)

                                                      

56 The High and Low CO2 sale prices utilized by EPA are consistent with NETL’s Base Case and Low Case sale prices,

respectively (http://www.netl.doe.gov/energy‐analyses/pubs/storing%20co2%20w%20eor_final.pdf).  In

addition, this range is broadly consistent with the CO2 sale price data collected by the Department of Interior

for projects located on federal lands.  Prices are expressed in 2011$ and the price is expected to be static over

time. 57 Costs for the transportation, storage, and monitoring (TS&M) of CO2 are included in this analysis. For non‐EOR

applications, TS&M costs of ~$5‐$15 dollars per ton of CO2 are applied based on the level of capture.  This

range is broadly consistent with estimates provided by NETL (http://www.netl.doe.gov/energy‐

analyses/pubs/QGESS_CO2T%26S_Rev2_20130408.pdf ), the Global CCS Institute

(http://www.globalccsinstitute.com/publications/economic‐assessment‐carbon‐capture‐and‐storage‐

technologies‐2011‐update) and others.  For EOR applications the point of sale is typically the facility fence line,

in which case the coal facility operator will avoid the TS&MTSM cost.  Consequently, the economic benefit of

EOR may be greater than simply the price paid for CO2. 58 This range is broadly consistent with estimates provided by NETL (http://www.netl.doe.gov/energy‐

analyses/pubs/QGESS_CO2T%26S_Rev2_20130408.pdf ) and the Global CCS Institute

(http://www.globalccsinstitute.com/publications/economic‐assessment‐carbon‐capture‐and‐storage‐

technologies‐2011‐update).  
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NOTE: EIA estimated levelized costsLCOE under AEO 2013 assumptions for full capture SCPC+CCS is

estimated at a LCOE of $134 without EOR.  No estimate is provided for IGCC+CCS or partial capture

technologies.59

EPA believes the opportunity to engage in EOR opportunities is not significantly limited

by the location of those opportunities or the current CO2 pipeline infrastructure (12 states

                                                      

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

0

20

40

60

80

100

120

140

160

SCPC IGCC

LCOE (2011$/MWh)

Uncontrolled (w/ 3% Adder)

Uncontrolled (w/o 3% Adder)

Partial CCS

Partial CCS ‐ Low EOR

Partial CCS ‐ High EOR

Full CCS

Full CCS ‐ Low EOR

Full CCS ‐ High EOR

0

20

40

60

80

100

120

140

160

SCPC IGCC

LCOE (2011$/MWh)

Uncontrolled (w/ 3% Adder)

Uncontrolled (w/o 3% Adder)

Partial CCS

Partial CCS ‐ Low EOR

Partial CCS ‐ High EOR

Full CCS

Full CCS ‐ Low EOR

Full CCS ‐ High EOR

Formatted: Font: Bold

Formatted: Font: Bold
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currently have existing or under construction CO2 pipelines).  Provision of electric power does

not require coal‐fired facilities to be co‐located with the demand it is intended to serve.   Please

refer to Chapter 4 for a more detailed discussion of ER, including its geographic availability,

expected future growth, and overall impact on the economics of CCS.

5.5.7 6 Levelized Cost of Electricity of Coal with Carbon Capture and Storage and Nuclear

There are five nuclear units currently under construction in the United States – Vogtle

Units 3 and 4, Summer Units 2 and 3, and Watts Bar 2 – as well as nine active applications

under U.S. Nuclear Regulatory Commission (NRC) review covering an additional 14 potential

units.  The addition of Units 3 and 4 at Georgia Power’s Plant Vogtle will be the first new

nuclear units built in the United States in 30 years.  Although it is unlikely that all of the

proposed nuclear projects will be built, the renewed interest in new nuclear facilities – despite

persistently high capital costs – is driven by a host of factors, including climate and air quality

concern, the value attached to fuel diversity, regional or local base load capacity needs, and

supportive regulatory environments.   

As shown in Figure 5‐8. Oon an LCOE basis, the cost of new nuclear is similar to the cost

of new coal with partial CCS without the benefit of any EOR opportunities.  Factoring in the

revenues associated with the low EOR opportunity ($20 per ton of CO2 and no transportation

storage and monitoring – TSM –  [TSM] obligation) reduces the cost of coal with CCS to levels

that are 6‐10% lower than new nuclear; assuming a high EOR opportunity ($40 per ton of CO2

and no TSM obligation) reduces the cost of SCPC with CCS and IGCC with CCS to 18% and 9%

below new nuclear, respectively.  The current activity related to new nuclear development at a

cost that is broadly similar to coal with CCS is a demonstration of the industry’s willingness to

develop higher cost projects that produce low‐emitting base load capacity that contributes to

fuel diversity.

Figure 5‐178. Levelized Cost of Energy, Nuclear and Coal with Partial CCS (1,100 lbs/MWh

gross)
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5.5.8 7 Levelized Cost of Simple Cycle Combustion Turbine and Natural Gas Combined Cycle

Combustion turbines (CTs) fulfill a fundamentally different function in power sector

operations than that of NGCC and coal‐fired facilities.  CTs are designed to start quickly in order

107 110

96

88

109

101

97

0

20

40

60

80

100

120

Nuclear SCPC+CCS SCPC+CCS

(Low EOR)

SCPC+CCS

(High EOR)

IGCC+CCS IGCC+CCS

(Low EOR)

IGCC+CCS

(High EOR)

LCOE (2011$MWh)

107 110

96

88

109

101

97

0

20

40

60

80

100

120

Nuclear SCPC+CCS SCPC+CCS

(Low EOR)

SCPC+CCS

(High EOR)

IGCC+CCS IGCC+CCS

(Low EOR)

IGCC+CCS

(High EOR)

LCOE (2011$MWh)
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to meet demand for electricity during peak operating periods and are generally less expensive

to build (on a capital cost basis) but are also less fuel efficient than combined cycle technology,

(which employs heat recovery systems).  Due to lower fuel efficiencies, CTs produce a

significantly higher cost of electricity (cost per kWh) at higher capacity factors and consequently

are typically utilized at levels well below the proposed threshold for affected sources affected

by the proposed EGU New Source GHG Standards (1/3 of potential electric output).  Instead,

these units are most often built to ensure reserve margins are met during peak periods

(typically in the summer), and in some instances are able to generate additional revenues by

selling capacity into power markets.  Thus, in practice, EPA does not expects that potential CT

units to would not meet the applicability threshold in this proposed action and would not be

subject to any standard.

Mirroring real world behavior, relatively low levels of CT generation are projected in

both EPA and EIA modeling frameworks. AEO 2013 projects a capacity factor for CTs of less than

20% in all regions and in all years.  EPA’s IPM modeling projects a capacity factor for individual

new CTs of 8.5% or less in all simulation years.  Thus, these potential new units do not meet the

applicability threshold for this proposal, and there is no projected cost or emissions impact on

new CT units...

To illustrate the economic impracticality of utilizing combustion turbines in an

intermediate and base load mode of operation, below areFigure 5‐18 displays the LCOE

estimates for a CT and NGCC at increasing capacity factors:.  The estimates utilize the AEO2013

Reference Case natural gas price for 2014 (representative of the lowest – and therefore most

favorable to the relative levelized cost of a CT – natural gas price during the analysis period):

Figure 5‐189. Levelized Cost of Energy Across a Range of Capacity Factors, CT and NGCC

($2011/MWh at $53.84/MMBtu Levelized Natural Gas Price)
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In the LCOE figure above, utilizing a CT for generation is less expensive than an NGCC

only at capacity factors of 22% and less than 20%60.  If expected utilization is greater than

2220%, it can reasonably be expected that a utility or developer would seek to deploy NGCC

over CT for a host of economic, environmental, and technical reasons.  Unanticipated short

                                                      

60 CT cost and, performance characteristics, and financial assumptions from AEO 2013.

‐

50

100

150

200

250

300

350

5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85%

LCOE (2011$/MWh)

Capacity Factor

NGCC CT

‐

50

100

150

200

250

300

350

5% 10% 15% 20% 25% 30% 35% 40% 45% 50%

LCOE (2011$/MWh)

Capacity Factor

NGCC CT
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term utilization of CTs above a 33% capacity factor would not be expected to alter this dynamic

as a 3 ‐year averaging period is used to determine utilization.

5.6 Comparison of Emissions from Generation Technologies

As discussed earlier in this chapter, NGCC units are on average expected to be more

economical to build and operate than new coal units.  These natural gas units also have lower

emission profiles for CO2 and criteria air pollutants than new coal units. While the proposed

EGU New Source GHG NSPSStandards is anticipated to have negligible costs or quantified

benefits under a range of likely market conditions, it is instructive to consider the differences in

emissions of CO2 and other air pollutants between the two types of units.     

As Table 5‐19 below shows, emissions from a typical new NGCC unit are significantly

lower than those from a new coal unit.61  For example, a typical new supercritical pulverized

coal facility that burns bituminous coal in compliance with new utility regulations (e.g., MATS)

would have considerably greater CO2, sulfur dioxide (SO2), nitrogen oxides (NOx), toxic metals,

acid gases, and particulate emissions than a comparable natural gas combined cycle facility.  A

typical natural gas combined cycle unit emits two million metric tons less CO2 per year than a

typical new conventional coal unit, as well as 2,000 fewer short tons SO2 and about 1,200 fewer

short tons of NOx each year.  Importantly, these differences in emissions assume a new coal

unit that complies with all applicable final regulations, including MATS. Reductions in SO2

emissions are a particularly significant driver for monetized health benefits, as SO2 is a

precursor to the formation of particulates in the atmosphere, and particulates are associated

with premature death and other serious health effects.   Further information on these

pollutants’ health effects is included in the next subsection.

                                                      

61 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.
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Table 5‐1910.  Illustrative Emissions Profiles, New Coal and Natural Gas‐Fired Generating

Units

Natural Gas CC SCPC SCPC+CCS (1,100

lbs/MWh Gross)

IGCC IGCC+CCS (1,100

lbs/MWh Gross)

Emissions

(tons/

year)

Emission

Rate

(lbs/

MWh

net)

Emissions

(tons/

year)

Emission

Rate

(lbs/

MWh

net)

Emissions

(tons/

year)

Emission

Rate

(lbs/

MWh

net)

Emissions

(tons/

year)

Emission

Rate

(lbs/

MWh

net)

Emissions

(tons/year)

Emission

Rate

(lbs/

MWh

net)

SO2 10 0.0041 1,700 0.74 1,100 0.48 23 0.010 30 0.013

NOx 130 0.060 1,400 0.61 1,500 0.69 1,200 0.52 1,200 0.52

CO2

1.7

million 800 4.0million 1,800 2.7million 1,200 3.8million 1,700 3.0 million 1,400

Notes: SO2 and NOx in short tons, CO2 in metric tons. Values rounded to two significant digits.  Emission characteristics are

based on, and thus consistent with the cost and performance assumptions of, the illustrative units described in LCOE analysis

above ((i.e., e.g., these are base load units running at 85 percent capacity factor and all coal units are assumed to be using

bituminous coal with a sulfur content of 2.8% dry). Here we further assume all units are of the same capacity (600 MW net).

Utilizing a consistent net capacity metric across plant types requires a higher gross capacity for those types with greater need

for auxiliary power. The tons of emissions associated with a facility are driven by gross capacity.  The illustrative units represent

relative  emissions for new well controlled 600 MW (net) base load units running at 85 percent capacity factor (reflects

operation of new base load units and does not necessarily reflect historic capacity factors of existing units with specifications

similar to these illustrative units). Utilizing a consistent net capacity metric across plant types requires a higher gross capacity

for those types with greater need for auxiliary power. The tons of emissions associated with a facility are driven by gross

capacity.  In most cases, tons and emission rates are rounded to two significant digits.   All coal units are assumed to be using

bituminous coal with a sulfur content of 2.8% dry and operating with a scrubber and SCR; SCPC and IGCC data are based on

estimated parameters from NETL.

5.7 Benefits of Reducing GHGs and Other Pollutants

Society is not only affected by differences in the private generating costs of different

technologies, it also experiences the benefit or the burden of relative differences in emissions

produced by these generation technologies.  As such, the appropriate social welfare

comparison should also account for the health, ecological and other emissions impacts of

different generation technologies. In particular, emissions of CO2 and other pollutants lead to

additional social costs of these technologies. Any relative differences in these emissions

between newly built electric generating technologies would translate into relative climate‐

related and human health benefits. This section provides a general discussion about how the

climate‐related and human health benefits of emission reductions are estimated. The following

sections provide a comparison of the relative social benefits of different generation

technologies.
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5.7.1 Social Cost of Carbon

The social cost of carbon (SCC) is a metric that estimates the monetary value of impacts

associated with marginal changes in CO2 emissions in a given year. It is intended to include (but

is not limited to) changes in net agricultural productivity, human health, property damages

from increased flood risk, and the value of ecosystem services due to climate change. It is

typically used to assess the avoided damages, i.e. benefits, of rulemakings that achieve

marginal reductions in CO2 emissions. This analysis applies SCC to illustrate the value of the

difference in CO2 emissions among different generation technologies discussed in Section 5.5.    

The federal government typically uses the SCC to estimate the social benefits of CO2

reductions from regulatory actions that impact cumulative global emissions. An interagency

process that included the EPA and other executive branch entities used three integrated

assessment models (IAMs) to develop SCC estimates and selected four global values for use in

regulatory analyses.  Three values are based on the average SCC from the three IAMs, at

discount rates of 5, 3, and 2.5 percent. SCCs at several discount rates are included because the

literature shows that the SCC is quite sensitive to assumptions about the discount rate, and

because no consensus exists on the appropriate rate to use in an intergenerational context

(where costs and benefits are incurred by different generations). The fourth value is the 95th

percentile of the SCC from all three models at a 3 percent discount rate. It is included to

represent higher‐than‐expected impacts from temperature change further out in the tails of the

SCC distribution (representing less likely, but potentially catastrophic, outcomes). The SCC

Technical Support Document (SCC TSD) provides a complete discussion of the methods used to

develop these estimates.62  

The federal governmentinteragency group recently updated these estimates, using new

versions of each integrated assessment model and published them in May 2013. The 2013

interagency process did not revisit the 2010 interagency modeling decisions (e.g., with regard

to the discount rate, reference case socioeconomic and emission scenarios or equilibrium

climate sensitivity). Rather, improvements in the way damages are modeled are confined to

those that have been incorporated into the latest versions of the models by the developers

                                                      

62 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://www.whitehouse.gov/sites/default/files/omb/inforeg/for‐agencies/Social‐Cost‐of‐Carbon‐for‐RIA.pdf  
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themselves and used in the peer‐reviewed publicationsliterature.   The model updates that are

relevant to the SCC estimates include: an explicit representation of sea level rise damages in the

Dynamic Integrated Climate and Economy (DICE) and Policy Analysis of the Greenhouse Effect

(PAGE) models; updated adaptation assumptions, revisions to ensure damages are constrained

by GDP, updated regional scaling of damages, and a revised treatment of potentially abrupt

shifts in climate damages in the PAGE model; an updated carbon cycle in the DICE model; and

updated damage functions for sea level rise impacts, the agricultural sector, and reduced space

heating requirements, as well as changes to the transient response of temperature to the

buildup of GHG concentrations and the inclusion of indirect effects of methane emissions in the

Climate Framework for Uncertainty, Negotiation, and Distribution (FUND) model.63  

The SCC estimates usingfrom the updated versions of the models are higher than those

reported in the 2010 TSD, which were used in the April 2012 EGU New Source GHG

NSPSStandards RIA. By way of comparison, the four 2020 SCC estimates reported in the 2010

TSD and used in the April 2012 EGU New Source GHG NSPSStandards proposal were $7, $28,

$44 and $86 per metric ton (2011$). The corresponding four updated SCC estimates for 2020

are $13, $46, $69, and $138 per metric ton (2011$).64,

65   

When attempting to assess the incremental economic impacts of carbon dioxide

emissions, the analyst faces a number of serious challenges. A report from the National

Academies of Science (NRC 2009) points out that any assessment will suffer from uncertainty,

speculation, and lack of information about (1) future emissions of greenhouse gases, (2) the

effects of past and future emissions on the climate system, (3) the impact of changes in climate

on the physical and biological environment, and (4) the translation of these environmental

impacts into economic damages.66 As a result, any effort to quantify and monetize the harms

                                                      

63 Docket ID EPA‐HQ‐OAR‐2013‐0495....(add reference), Technical Support Document: Technical Update of the

Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, Interagency Working Group

on Social Cost of Carbon, with participation by Council of Economic Advisers, Council on Environmental Quality,

Department of Agriculture, Department of Commerce, Department of Energy, Department of Transportation,

Environmental Protection Agency, National Economic Council, Office of Energy and Climate Change, Office of

Management and Budget, Office of Science and Technology Policy, and Department of Treasury (May 2013).

Also available at

http://www.whitehouse.gov/sites/default/files/omb/inforeg/social_cost_of_carbon_for_ria_2013_update.pdf   64  The 2010 and 2013 TSDs present SCC in $2007.  The estimates were adjusted to $2011 using GDP Implicit Price

Deflator, http://www.gpo.gov/fdsys/pkg/ECONI‐2013‐02/pdf/ECONI‐2013‐02‐Pg3.pdf. 65 The 2010 SCC TSD concluded that a global measure of the benefits from reducing U.S. emissions is preferable.

The development of a domestic SCC is greatly complicated by the relatively few region‐ or country‐specific

estimates of SCC in the literature. See Interagency Working Group on Social Cost of Carbon. 2010. Technical

Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. 66 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.
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associated with climate change will raise serious questions of science, economics, and ethics

and should be viewed as provisional.  

The 2010 SCC TSD noted a number of limitations to the SCC analysis, including the

incomplete way in which the integrated assessment models capture catastrophic and non‐

catastrophic impacts, their incomplete treatment of adaptation and technological change,

uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding

risk aversion. Current integrated assessment models do not assign value to all of the important

physical, ecological, and economic impacts of climate change recognized in the climate change

literature because of a lack of precise information on the nature of damages and because the

science incorporated into these models understandably lags behind the most recent research.

The limited amount of research linking climate impacts to economic damages makes the

interagency modeling exercise even more difficult.  

While the new versions of the models used to estimate the values presented below

offer some improvements in these areas, further work remains warranted. Accordingly, the EPA

and other agencies continue to engage in research on modeling and valuation of climate

impacts with the goal to improve these estimates. Additional details are provided in the SCC

TSDs.

Table 5‐11 presents the updated global SCC estimates for the years 2015 to 2050.  In

order to calculate the dollar value for emission reductions, the SCC estimate for each emissions

year would be applied to changes in CO2 emissions for that year, and then discounted back to

the analysis year using the same discount rate used to estimate the SCC.67 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 climate change.

Note that the interagency group estimated the growth rate of the SCC directly using the three

integrated assessment models rather than assuming a constant annual growth rate. This helps

to ensure that the estimates are internally consistent with other modeling assumptions.

                                                      

67 This analysis considered the climate impacts of only CO2 emission change, as the U.S. Interagency Working

Group on the Social Cost of Carbon has thus far only considered estimates for the social cost of CO2. While CO2

is the dominant GHG emitted by the sector, we recognize the representative facilities within these comparisons

may also have different emission rates for other climate forcers which will serve a minor role in determining

the overall social cost of generation.
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Table 5‐X11.Social Cost of CO2, 2015‐2050a (in 2011$)

Year

Discount Rate and Statistic

5% Average 3% Average 2.5% Average 3%

95th percentile

2015 $13 $41 $62 $116

2020 $13 $46 $69 $138

2025 $15 $51 $75 $154

2030 $17 $55 $81 $170

2035 $20 $61 $86 $188

2040 $22 $66 $93 $205

2045 $26 $70 $98 $220

2050 $29 $76 $105 $236

a The SCC values vary depending on the year of CO2 emissions and are defined in real terms. These SCC values are

stated in $/metric ton.

5.7.2 Health Co‐Benefits of SO2 and NOx Reductions  

Reducing power sector CO2 under this rule would also result in reductions of SO2 and

NOX emissions, which in turn would yield health benefits (we refer to these additional benefits

as “co‐benefits”). SO2 is a precursor for fine particulate matter (PM2.5) formation while NOX is a

precursor for PM2.5 and ground‐level ozone formation. As such, reductions of SO2 and NOX

would in turn lower overall ambient concentrations of PM2.5 and ozone. Reducing exposure to

PM2.5 and ozone is associated with significant human health benefits including avoided

mortality and morbidity. Researchers have associated PM2.5 and ozone exposure with adverse

health effects in numerous toxicological, clinical, and epidemiological studies (U.S. EPA, 2009;

U.S. EPA, 2013b). Health effects associated with exposure to PM2.5 include premature mortality

for adults and infants, cardiovascular morbidity such as heart attacks and hospital admissions,

and respiratory morbidity such as asthma attacks, bronchitis, hospital and emergency room

visits, work loss days, restricted activity days, and respiratory symptoms. Health effects

associated with exposure to ozone include premature mortality and respiratory morbidity such

as hospital admissions, emergency room visits, and school loss days. In addition to human

health co‐benefits associated with PM2.5 and ozone exposure, reducing SO2 and NOX emissions

under this rule would result in reduced health impacts from direct exposure to these pollutants.  

Reducing SO2 and NOX emissions would also result in other human welfare (non‐health)

improvements including improvements in ecosystem services. SO2 and NOX emissions can

adversely impact vegetation and ecosystems through acidic deposition and nutrient

enrichment, and can affect certain manmade materials, visibility, and climate (U.S. EPA, 2009;

U.S. EPA, 2008).  
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For a full discussion of the human health, ecosystem and other benefits of reducing SO2

and NOX emissions from power sector sources, please refer to the RIA for MATS (U.S. EPA,

2011).

The avoided incidences of health effects and monetized value of health or non‐health

improvements that result from SO2 and NOx emissions reductions depend on the location of

those reductions. However, when assessing the co‐benefits of relative differences in emissions

from different generation technologies in the following sections, the EPA does not assert a

specific location for the new unit. As a result, the EPA does not have the data to perform a full

health impact assessment for a specific modeled scenario.68 Instead, the EPA relied on a

national‐average benefit per‐ton (BPT) method to estimate PM2.5‐related health impacts of SO2

and NOX emissions. The BPT approach provides an estimate of the total monetized human

health benefits (the sum of premature mortality and premature morbidity) of reducing one ton

of PM2.5 precursor (i.e., NOX and SO2) from the sector. To develop the BPT estimates used in this

analysis the EPA utilized detailed air quality modeling of power sector SO2 and NOX emissions

along with the BenMAP model69 to estimate the benefits of air quality improvements using

projected 2020 population, baseline incidence rates, and economic factors.

The SO2‐ and NOX‐related BPT estimates utilized in this analysis are derived from the

Technical Support Document (TSD) on estimating the BPT of reducing PM2.5 and its precursors

(U.S. EPA, 2013a). These BPT values are estimated in a methodologically consistent manner

with those reported in Fann et al. (2012). They differ from those reported in Fann et al. (2012)

as they reflect the health impact studies and population data updated in the benefits analysis of

the final PM NAAQS RIA (U.S. EPA, 2012). The recalculation of the Fann et al. (2012) BPT values

based on the updated data from the PM NAAQS RIA (U.S. EPA, 2012) is described in the TSD

(U.S. EPA, 2013a).  

Despite our attempts to quantify and monetize as many of the co‐benefits as possible,

the health and non‐health co‐benefits are not fully quantified or monetized in this assessment.

For more information about unquantified health and non‐health co‐benefits please refer to

tables 5‐2 and 6‐2 of the PM NAAQS RIA (U.S. EPA, 2012), respectively.

                                                      

68 If the EPA conjectured a location for a particular new unit it may be possible to perform a full health impact

assessment of different technologies at that location. Doing so for a number of locations is beyond the scope of

this analysis and would be better captured in sector‐wide modeling. For more information on the EPA’s

methods for conducting health impact assessments, please refer to Chapter 5 of the final PM NAAQS RIA. (U.S.

EPA, 2012) 69 Available at http://www.epa.gov/air/benmap.  
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As we do not conjecture a specific location for the new units being compared, this RIA is

unable to include the type of detailed uncertainty assessment found in the PM NAAQS RIA (U.S.

EPA, 2012). However, the results of the uncertainty analyses presented in the PM NAAQS RIA

can provide some information regarding the uncertainty inherent in the benefits results

presented in this analysis. In addition to these uncertainties, use of BPT estimates come with

additional uncertainty. Specifically, all national‐average BPT estimates reflect a specific

geographic distribution of SO2 and NOX reductions resulting in a specific reduction in PM2.5

exposure and may not fully reflect local or regional variability in population density,

meteorology, exposure, baseline health incidence rates, or other factors that might lead to an

over‐estimate or under‐estimate of the actual benefits associated with PM2.5 precursors in a

specific location. These estimates are purely illustrative as the EPA does not assert a specific

location for the illustrative electricity generation technologies and is therefore unable to

specifically determine the population that would be affected by their emissions. Therefore, the

benefits for any specific unit can be different than the estimates shown here.  

Notwithstanding these limitations, reducing one thousand tons of annual SO2 from U.S.

power sector sources has been estimated to yield between 4 and 9 incidences of premature

mortality avoided and monetized PM2.5‐related health benefits (including these incidences of

premature mortality avoided) between $38 million and $85 million in 2020 (2011$) using a 3%

discount rate or between $34 million and $76 million (2011$) using a 7% discount rate.70

Additionally, reducing one thousand tons of annual NOX from U.S. EGUs has been estimated to

yield up to 1 incidence of premature mortality avoided and monetized PM2.5‐related health

benefits (including these incidences of premature mortality avoided) of between $5.5 million

and $12 million in 2020 (2011$) using a 3% discount rate or between $5.0 million and $11

million (2011$) using a 7% discount rate.71 For each pollutant, the range of estimated benefits

for each discount rate is due to the EPA’s use of two alternative primary estimates of PM2.5‐

related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a higher

primary estimate based on Lepeule et al. (2012).

                                                      

70 The SO2 and NOX BPT values presented here consist of only PM2.5‐related health benefits from reductions in SO2

and NOX (precursors to PM2.5 formation). 71 Ibid.
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Table 5‐12. Monetized Health Co‐Benefits Per Ton of PM2.5 Precursor Reductions in 2020a (in

2011$)

PM2.5 Precursor

SO2 NOX

3% Discount Rate

Krewski et al. (2009) $38,000   $5,5000

Lepeule et al. (2012) $85,000 $12,000

7% Discount Rate

Krewski et al. (2009) $34,000 $5,000

Lepeule et al. (2012) $76,000 $11,000

a As described in Section 5.7.2, the SO2‐ and NOX‐related BPT estimates are from the Technical Support Document

on Estimating the Benefit Per Ton of Reducing PM2.5 from 17 Sectors (U.S. EPA, 2013a) and are adjusted to 2011$.

5.8 Comparison of Health and Welfare Impacts from Generation Technologies

As previously discussed in this chapter, the emissions of GHGs and other pollutants

associated with new sources of electricity generation are greater for coal‐fired units than for

natural gas combined cycle units (even when accounting for compliance with MATSthe Mercury

and Air Toxics Standards). Reducing the emissions associated with electricity generation results

in both climate and human health and non‐health benefits.  

To consider the relative social benefits associated with the adoption of lower emitting

new generation technologies, we value the relative differences in emissions in the illustrative

emission profiles across technologies in Table 5‐X10 using the 2020 social benefit values

discussed in sectionSection 5.7. Specifically, we multiply the relative difference in CO2

emissions between two technologies by the estimates of the SCC, multiply the relative

difference in SO2 and NOX emissions by the PM2.5‐related SO2 and NOX BPT estimates, and add

those values to get a measure of 2020 social benefits of the adoption of lower emitting

generation technology. We subsequently divide by the number of MWh underlying the

emission estimates to derive the social benefits per unit of generation. The relative social

benefits presented in these assessments apply to emission reductions occurring in a single

year—2020.

Only the direct emissions of CO2, SO2, and NOX are considered in this illustrative

exercise. Other air and water pollutants emitted by these technologies and emissions from the

extraction and transport of the fuels used by these technologies are not considered. For

example, coal has higher mercury emissions than natural gas, but the relative benefits from the

difference in mercury emissions are not considered. Furthermore, there may be differences in
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upstream greenhouse gas emissions (in particular, methane) from different technologies but

those were not quantified for this assessment.

Table 5‐X13 reports the 2020 incremental climate and health benefits associated with

an illustrative new natural gas combined cycleNGCC plant relative to illustrative new super

critical pulverized coal (SCPC) and integrated gasification combined cycle (IGCC) coal plants,

given different mortality risk studies and assumptions about the discount rate.  These

incremental benefits should be relatively invariant across natural gas prices and other economic

factors. Depending on the discount rate and mortality risk study used, 2020 incremental

benefits associated with generation from a representative new natural gas combined cycle unit

relative to a new coal unit are $6.6 to $95 per MWh (2011$).72  

The precise social benefits associated with reduced CO2 emissions, which are the focus

of this rule, depend on the specific fuels used but do not depend on the location of generation

because the location of CO2 emissions does not influence their impact on the evolution of

global climate conditions. As with the relative investment costs of a new coal unit and a new

natural gas combined cycle system, the precise incremental health co‐benefits associated with

lower emissions depend on the location under consideration and the specific fuels that would

be used. An ideal benefit‐cost analysis would account for these local circumstances (and

consider alternative sources of generation).   

However, these factors will not change the qualitative conclusion. There will always be

incremental climate and human health benefits associated with a new natural gas combined

cycle unit relative to a new coal unit, independent of the location.

                                                      

72 Different discount rates are applied to SCC than to the other benefit estimates because CO2 emissions are long‐

lived and subsequent damages occur over many years. Moreover, several rates are applied to SCC because the

literature shows that it is sensitive to assumptions about discount rate and because no consensus exists on the

appropriate rate to use in an intergenerational context. The SCC interagency group centered its attention on

the 3 percent discount rate but emphasized the importance of considering all four SCC estimates. See the 2010

SCC TSD. “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 or http://www.whitehouse.gov/sites/default/files/omb/inforeg/for‐

agencies/Social‐Cost‐of‐Carbon‐for‐RIA.pdf. http://www.epa.gov/otaq/climate/regulations/scc‐tsd.pdf for

details.
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Table 5‐X 13. 2020 Incremental Benefits ($/MWh, 2011$) of Emissions in 2020

Emission Reductions from Constructing an Illustrative New Natural Gas

Combined Cycle Generation Relative to Constructing New SCPC andor IGCC Coal

Generation without CCS73

SCPC IGCC

CO2‐Related Benefits using SCC

5% Discount Rate $5.6 $5.4

3% Discount Rate $20 $19

2.5% Discount Rate $31 $29

3% Discount Rate (95th percentile) $61 $58

PM2.5‐Related Co‐Benefits from SO2 and NOX Reductions

3% discount rate

Krewski et al. (2009) $15 $1.4

Lepeule  et al. (2012) $35 $3.1

7% discount rate

Krewski et al. (2009) $14 $1.2

Lepeule et al. (2012) $31 $2.8

Combined CO2‐Related and PM2.5‐Related Benefits  

Discount Rate Applied to PM2.5‐Related Benefits  

(range based on adult mortality function)

SCC Discount Rate 3% 7% 3% 7%

5% Discount Rate $21 ‐to $40 $20 ‐to $37 $6.7 ‐to $8.5 $6.6 ‐to $8.2

3% Discount Rate $36 ‐to $55 $34 ‐to $52 $21 ‐to $22 $20 ‐to $22

2.5% Discount Rate $46 ‐to $65 $44 ‐to $62 $30 ‐to $32 $30 ‐to $32

3% Discount Rate (95th percentile) $76 ‐to $95 $75 ‐to $92 $59 ‐to $61 $59 ‐to $60

                                                      

73 The benefits presented here are estimated on an output basis to enable easier comparisons and to illustrate the

potential impacts of moving from new coal without CCS to new natural gas combined cycle. This analysis

assumes representative new units and does not reflect the full array of new generating sources that could

potentially be built (e.g., a comparison of a small new conventional coal plant with a small natural gas plant, or

a comparison of a waste coal or petroleum coke facility to a natural gas plant of a comparable size and capacity

factor). However, the incremental benefits associated with other facilities that could be built, and which would

be subject to this proposal, would not change noticeably (i.e., these new facilities would be subject to

emissions standards for other pollutants and would emit similar levels of SO2, NOX, and CO2, on an output basis)

except for differences in local conditions, as discussed previously.
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Notes: The emission rates and operating characteristics of the units being compared in this table are reported in Table 5.X and

sections 5.X.10. Benefits are estimated for a 2020 analysis year. The range of costsbenefits within each SCC value and discount

rate for PM2.5‐related benefits pairing reflects the use of two core estimates of PM2.5‐related premature mortality.74 Assumed

coal is high sulfur bituminous with scrubber and SCR. The EPA has evaluated the range of potential impacts per MWh by

combining all SCC values with health benefits values at the 3 percent and 7 percent discount rates. To be consistent with

concepts of intergenerational discounting, values for health benefits, which occur within a generation, would only be combined

with SCC values using a lower discount rate, e.g. the 7 percent health benefit estimates would be combined with 5 percent or

lower SCC values, but the 3 percent health benefit would not be combined with the 5 percent SCC value. While the 5 percent

SCC and 3 percent health benefit estimate falls within the range of values we analyze, this individual estimate should not be

used independently in an analysis, as it is represents a combination of discount rates that is unlikely to occur. Combining the 3

percent SCC values with the 3 percent health benefit values assumes that there is no difference in discount rates between

intragenerational and intergenerational impacts.

The conclusion from this analysis is that there are significant environmental and health

benefits associated with electricity generation from a representative new natural gas combined

cycle unit relative to a new conventional coal unit.75 Other studies of the social costs of coal and

natural gas fired generation provide similar findings (Muller et. al., 2011; NRC, 2009).76  

As explained previously, the power sector continues to move away from the

construction of coal‐fired power plants in favor of natural gas‐fired power plants due, in part, to

the significant cost differential. Even so, it is possible that a limited number of unplanned coal‐

fired power plants will be constructed through 2020.during the analysis period. In these

circumstances, units built with CCS in place of conventional coal‐fired units would result in

relative climate and human health and non‐health benefits. Table 5‐X14 reports the 2020

incremental benefits associated with an illustrative new coal‐fired plant with CCS relative to

illustrative new super critical pulverized coal (SCPC) and integrated gasification combined cycle

(IGCC) coal plants, given different mortality risk studies and assumptions about the discount

rate.  Depending on the coal‐fired generation type, discount rate, and mortality risk study used,

                                                      

74 The range of estimated benefits for each discount rate is due to the EPA’s use of two alternative primary

estimates of PM2.5‐related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a

higher primary estimate based on Lepeule et al. (2012). 75 As previously noted in this section and the previous sections on the costs and damages associated with these

technologies, the 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, though the proportion associated with CO2, which is a well dispersed global pollutant, will not be affected

by location.   76 Muller et al. 2011 conclude that, “coal‐fired power plants have air pollution damages larger than their value

added”, while the same is not true for natural gas plants (see Table 5). However, these comparisons are based

on typical existing coal and natural gas units, including natural gas boilers, and are not sensitive to location

(although the underlying analysis in the study does account for differences in the location of existing units

when estimating damages). The NRC 2009 study shows that only the most polluting natural gas units may cause

greater damages than even the least polluting existing coal plants (compare Tables 2‐9 and 2‐15). However, the

NRC comparison does not compare new units located in the same place, and so some of the natural gas units

with the greatest damages may be attributable to their location, and includes natural gas steam boilers, which

have a higher emission rates per unit of generation than natural gas combined cycle units.  
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2020 incremental benefits associated with generation from a representative new coal‐fired unit

with CCS relative to a new coal unit without CCS are $2.0 to $45 per MWh (2011$).77    

Table 5‐X.14. 2020 Incremental Benefits ($/MWh, 2011$) of Emissions in 2020Emission

Reductions from Coal‐Fired Generation with CCS meeting 1,100 lbs/MWh Relative to

New Coal‐Fired Generation Without CCS

   SCPC   IGCC  

CO2‐Related Benefits using SCC

5% Discount Rate $3.2 $2.1

3% Discount Rate $11 $7.5

2.5% Discount Rate $17 $11

3% Discount Rate (95th percentile) $34 $23

PM2.5‐Related Benefits from SO2 and NOX Reductions

3% discount rate

Krewski et al. (2009) $4.7 *

Lepeule et al. (2012) $11 *

7% discount rate

Krewski et al. (2009) $4.2 *

Lepeule et al. (2012) $9.5 *

Combined CO2‐Related and PM2.5‐Related Benefits  

Discount Rate Applied to PM2.5‐Related Benefits  

(range based on adult mortality function)

SCC Discount Rate 3% 7% 3% 7%

5% Discount Rate $7.9 ‐to $14 $7.4 ‐to $13 $2.0 ‐to $2.0

$2.0 ‐to

$2.01

3% Discount Rate $16 ‐to $22 $16 ‐to $21 $7.4 ‐to $7.5 $7.4 ‐to $7.5

2.5% Discount Rate $22 ‐to $28 $22 ‐to $27 $11 ‐to $11 $11 ‐to $11

3% Discount Rate (95th percentile) $39 ‐to $45 $39 ‐to $44 $22 ‐ $22to $23

$22 ‐ $22to

$23

                                                      

77 Different discount rates are applied to SCC than to the other benefit estimates because CO2 emissions are long‐

lived and subsequent damages occur over many years. Moreover, several rates are applied to SCC because the

literature shows that it is sensitive to assumptions about discount rate and because no consensus exists on the

appropriate rate to use in an intergenerational context. The SCC interagency group centered its attention on

the 3 percent discount rate but emphasized the importance of considering all four SCC estimates. See the 2010

SCC TSD. “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 or and at http://www.whitehouse.gov/sites/default/files/omb/inforeg/for‐

agencies/Social‐Cost‐of‐Carbon‐for‐RIA.pdf. http://www.epa.gov/otaq/climate/regulations/scc‐tsd.pdf for

details.
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*IGCC with CCS results in a small SO2 emissions increase when compared to IGCC without CCS. As a result, there would be a

negligible health disbenefit associated with these emissions increases.  

Notes: Benefits are estimated for a 2020 analysis year. The range of costsbenefits within each SCC value and discount rate for

PM2.5‐related benefits pairing reflects the use of two core estimates of PM2.5‐related premature mortality.78 Assumed coal is

high sulfur bituminous with scrubber and SCR. The EPA has evaluated the range of potential impacts per MWh by combining all

SCC values with health benefits values at the 3 percent and 7 percent discount rates. To be consistent with concepts of

intergenerational discounting, values for health benefits, which occur within a generation, would only be combined with SCC

values using a lower discount rate, e.g. the 7 percent health benefit estimates would be combined with 5 percent or lower SCC

values, but the 3 percent health benefit would not be combined with the 5 percent SCC value. While the 5 percent SCC and 3

percent health benefit estimate falls within the range of values we analyze, this individual estimate should not be used

independently in an analysis, as it is represents a combination of discount rates that is unlikely to occur. Combining the 3

percent SCC values with the 3 percent health benefit values assumes that there is no difference in discount rates between

intragenerational and intergenerational impacts.

5.9 Illustrative Analysis – Benefits and Costs across a Range of Gas Prices

As the analysis in sectionsSections 5.4 and 5.5 demonstrated, under a wide range of

likely electricity market conditions – including the EPA and EIA baseline scenarios as well as

multiple alternative scenarios – the EPA projects that the industry will choose to construct new

units that already meet the standards of this proposed rulemaking, regardless of this proposal.

In this section, we consider the unlikely scenario where construction of new conventional

(advanced, but without CCS) coal capacity occurs during the analysis period in the absence of

the rule. The analysis in this section indicates that in this scenario, which implies that the

proposed EGU New Source GHG NSPSStandards would result in costs to the investor if an

operator chose to construct an NGCC unit in place of a coal‐fired unit, but would also result

inlead to greater climate and human health benefits and is highly likely to provide net benefits

to society as a whole. 79

The starting point for this analysis is the illustrative comparison (presented in Figure 5‐8

above) of the relative LCOE of representative new SCPC and IGCC coal EGUs and representative

NGCC units.80 This comparison shows that, at forecast relative fuel prices, there isdemonstrates

                                                      

78 The range of estimated benefits for each discount rate is due to the EPA’s use of two alternative primary

estimates of PM2.5‐related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a

higher primary estimate based on Lepeule et al. (2012). 79 EO 13563 states that each agency must “propose or adopt a regulation only upon a reasoned determination that

its benefits justify its costs (recognizing that some benefits are hard to quantify).” While the presence of net

social benefits for a given regulatory option is not the only condition necessary for optimal regulatory design, it

does signify that the regulatory option is welfare improving for society.The presence of net benefits for a given

regulatory option is a necessary but not a sufficient condition for optimal regulatory design. It does however

signify that the regulatory option is welfare improving for society. 80 By fixing generation in this comparison, we are assuming that both technologies generate the same benefits in

the form of electricity generating services. We assume in the discussion that the benefit of electricity

production to consumers outweighs the private and social investment cost. However, at particularly high fuel

prices this might not be the case. For a discussion of when comparing the levelized costs of different generating

technologies provides informative results and when it does not see, for example, Joskow 2010 and 2011.  
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a significant difference in the LCOE between the coal‐fired and natural gas‐fired generating

technologies. At current natural gas prices relative to other fuels, theThe estimated LCOE for a

representative NGCC unit is roughly $40 33 and $45 38 per MWh less than for a representative

new SCPC or IGCC coal unit, respectively (see Figure 5‐83).81  This is consistent with the EPA’s

projection, discussed at length abovein this chapter, that the proposed EGU New Source GHG

NSPS isStandards are not projected to impose any costs (or generate quantified net benefits)

under current and likely future market conditions.  

ThisTo supplement this determination, this section presents an analysis of three

relevant ranges within the distribution of future natural gas prices that can be classified as likely

gas prices, unexpectedly high natural gas prices, and unprecedented natural gas prices. Because

the cost of natural gas is a significant share of the LCOE for NGCC, we evaluate how changes in

natural gas prices affect differences in private and social cost of new technologies. In general,

this analysis shows that there would likely be a net social benefit,82 even under scenarios with

much higher than expected gas prices, if new NGCC units were built in place of new coal‐fired

units as a result of this policy. Under some conditions, higher natural gas prices may result in a

net social cost, holding all other parameters constant and disregarding social benefits that we

are unable to monetize.83   IfAdditionally, given certain market conditions result in a situation

where coal is relatively more economic than natural gas, some operators may choose to

construct a new coal‐fired unit with CCS. The relative private costs and social benefits of a new

coal‐fired unit with CCS are discussed in sectionSection 5.910.

5.9.1 Likely Natural Gas Prices  

  As shown earlier, it is only when natural gas prices reachexceed $10.94/MMBtu on a

levelized basis (in 2011 dollars) that new coal‐fired generation without CCS becomes

                                                      

81 LCOE of NGCC relative to SCPC with 3% CUAadder and IGCC without 3% CUAadder. 82 The benefits estimated in this section are based on a single year (2020) of emissions from different generating

technologies.  Due to data limitations, we are not able to estimate annualized benefits from the stream of

emissions over the lifetime of the generating technologies.  This results in a conservative comparison of

benefits to costs where LCOE represents annualized lifetime costs of generating technologies. 83 In reality, the net cost scenario is unlikely to occur over our analysis period and for a significant period beyond.

For example, high economic growth would increase both natural gas and coal prices at the same time ‐ making

it harder to alter the underlying cost advantage of NGCC generation. It is important to note that this analysis is

limited in the types of benefits and costs considered, given that it does not address the life‐cycle pollution

associated with fossil fuels along with the limitations of current SCC estimates. As previously discussed, the

current SCC estimates do not capture all important all of the physical, ecological, and economic impacts of

climate change recognized in the climate change literature. Despite our attempts to quantify and monetize as

many of the co‐benefits as possible, the health and welfare co‐benefits are not fully quantified or monetized in

this assessment. For more information about unquantified health and welfare co‐benefits please refer to tables

5‐2 and 6‐2 of the PM NAAQS RIA (U.S. EPA, 2012), respectively.
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competitive in terms of LCOEits cost of electricity. None of the EPA sensitivities or AEO

2013AEO2013 scenarios approach this natural gas price level).

84 As noted earlier in this chapter,

investment decisions require consideration of fuel on either a forward looking 20‐year

levelized price basisprojections over long periods of time; as such, the power sector modeling

cited here is designed to forecast long‐term fuelor on an average annual price basistrends.

Therefore such analyses are not meant to be interpreted as stating that short‐term natural gas

prices would never reach as high as $10/MMBtu. However, these analyses suggest that such a

high price is not anticipated to be sustained over aat any point during the analysis period of

time long enough that it would influence an economic assessment of which type of new

capacity offers a better investment. .

85  

5.9.2 Unexpectedly High Natural Gas Prices  

In this illustrative analysis, atAt natural gas prices above $10.94/mmBtu, the private

levelized cost of electricity for a representative new SCPC unit falls below that of a new NGCC

unit. Therefore, at anticipated levelized fuel prices above that price level some new SCPC coal

units might be constructed in the absence of the standard of this proposed rulemaking,

provided there is sufficient demand and new coal without CCS is competitive with other

generating technologies.86 In this scenario, there would be some compliance cost associated if a

new NGCC unit were built as a result of the standard. However, generation from either a new

natural gas combined cycleNGCC unit or a coal‐fired unit with CCS would also have incremental

environmental and health benefits relative to a new coal unit by reducing global warming

pollution and particulate matter (as a result of SO2 and NOx emissions).) relative to generation

from a new coal unit.

For a range of average annual natural gas prices above greater than $10.94/mmBtu, the

resulting emission reduction benefits of building NGCC will outweigh the difference in the

compliance costs in this illustrative example of constructing an NGCC unit in lieu of a coal plant

without CCS – indicating that the standard would yield net benefits. for the analysis year. For

                                                      

84 EIA’s projected natural gas price for 2020 in its reference scenario for AEO 2011 is $5.30 (in 2007 dollars).  Even

EIA’s most pessimistic gas sensitivity case (“low shale gas recovery per well”) only projects an electricity sector

gas price of $7.01/mmBtu (in 2007 dollars) in 2020 (the “low shale gas recovery per play” scenario projects a

price of $6.13/mmBtu (in 2007 dollars) in 2020).   85 EIA’s projected natural gas price for 2022 in its reference scenario for AEO2013 is $5.31 (in 2011 dollars).  EIA’s

“Low oil and gas resource” scenario  projects an average delivered electricity sector gas price of $6.64/mmBtu

(in 2011 dollars) in 2022 . 86 See section 5.5 for a discussion of how local conditions and other factors may influenceing the LCOElevelized

cost comparison may influence the natural gas price where the levelized cost of the conventional coal unit and

the NGCC unit are the same.  
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example, at an average annual gas pricesprice of $11/MMBtu, the illustrative NGCC unit would

generate power for approximately $1/MWh more than an SCPC coal unit on a levelized basis,

87

and result in incremental benefits from 2020 emissions of $20 to $95/MWh (see analysis of

2020 relative benefits of NGCC: table 5‐X13).88 The net benefit of this scenario would be $2019

to $95/MWh.89 As illustrated in section 5.10, Iif an SCPC coal unit with CCS were built instead of

an SCPC coal unit without CCS, the CCS equipped unit would result in an incremental cost of

$18/MWh and incremental benefits from 2020 emissions of $7.4 to $45/MWh relative to an

SCPC unit without CCS (see analysis of 2020 relative benefits of CCS: table 5‐X14). The net

impact of this scenario would range from a net cost of $11/MWh to a net benefit of $27/MWh.  

For context, we note that these circumstances are far less likely than the projected zero

cost scenario outlined above. To put this gas price point into historical perspective, $10/MMBtu

is higher than any average annual gas price (in 2011 dollars) observed over the last 10 years.90

Looking forwarda natural gas price level of $10/MMBtu (in 2011 dollars) is higher than  any

annual natural gas price to the electric power sector since at least 1996, when the EIA data

series stops.91 In addition, the highest projected average annual natural gas price during the

analysis period in any of the AEO2013 scenarios cited in this chapter is $6.64/MMBtu in the Low

Oil and Gas Resource scenario.  Further, the continued development of unconventional natural

gas resources in the U.S. suggests that gas prices would actually tend to be towards the lower

end of the historical range. As discussed above, none of the EIA sensitivity cases (which

represent future price trajectories for both gas and coal) show scenarios where non‐compliant

coal becomes more economic than NGCC before 2020.

5.9.3 Unprecedented Natural Gas Prices  

At extremely high natural gas prices, the generating costs of coal without CCS would be

sufficiently lower than the cost of new natural gas that the net benefit of the standard in a

given year could be negative (i.e., a net cost) under some ranges of benefit estimates. For

example, at gas prices of $14/MMBtu, the illustrative NGCC unit would generate power for

                                                      

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

prices.   88 Again, assuming that coal prices do not increase along with natural gas prices as they historically have. See

previous footnote. 89 The higher value of net benefits calculated here is equal to the higher value of incremental benefits due to

rounding. 90 See: http://www.eia.gov/dnav/ng/hist/n3045us3A.htm. EIA reports average annual delivered natural gas prices

to the electricity sector for the past 15 years (since 1996). 91 See: http://www.eia.gov/dnav/ng/hist/n3045us3A.htm. EIA reports average annual delivered natural gas prices

to the electricity sector for the past 16 years (since 1997).
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roughly $21 and $16/MWh more than conventional SCPC and IGCC coal units, respectively but

result in social benefits from lower emissions in 2020 of $20 to $95/MWh and $6.6 to

$61/MWh relative to the SCPC and IGCC coal units, respectively (see analysis of 2020 relative

benefits of NGCC: table 5‐X13). If an NGCC unit were built as a result of the standard, the

resulting net impact would range from a net social cost of $1.5/MWh to a net social benefit of

$74/MWh relative to SCPC and from a net social cost of $9.5/MWh to a net social benefit of

$45/MWh relative to IGCC.

As noted previously, Nnatural gas prices at these levels would be unprecedented.

Average annual natural gas prices delivered to the electricity sector have not exceeded $10.24

/mmBtu (in 2011 dollars) over the last 15 years, and projected prices do not begin to approach

this level in any of EIA’s scenarios.

92,93 As a result, based on historical gas prices as well as

projections, the EPA believes that the probability of natural gas prices reaching (let alone

sustaining) average annual levels at which this standard would generate net social costs under

some ranges of benefit estimates is extremely small.   

We emphasize that differences in generating costs, plant design, local factors, and the

relative differences between fuels costs can all have major impacts on the precise

circumstances under which this standard would be projected to have no costs, net social

benefits or net social costs. However, based on historical and expected average annual gas

prices over the last 15 years, we project that this standard is most likely to have negligible costs,

and, if it does result in costs, it is also likely to produce positive, although modest, net social

benefits. The probability that this proposed standard would result in net social costs is

exceedingly low.

5.10 Illustrative Analysis – Benefits and Costs of CCS Compared with Conventional Coal  

The previous section evaluated the social benefit of an investor constructing a new

NGCC unit in lieu of an uncontrolled unit in response to the proposed rule.  If an operator chose

to construct a new coal unit, this proposed rule would result in some costs in order to build a

unit with partial CCS. However, there would also be climate and other benefits resulting from

reductions in CO2, SO2, and NOX emissions. For each coal‐fired generation type, SCPC and IGCC,

                                                      

92 http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm. EIA reports average annual delivered natural gas

prices to the electricity sector for the past 15 years (since 1996) and reports average monthly delivered natural

gas prices to the electricity sector over the past 10 years (since 2001). 93 Note that while EIA forecasts natural gas prices to rise, it also forecasts coal price to rise as well. An ideal

comparison of levelized costs in future time periods should account for the expected change in both natural gas

and coal prices.
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the EPA analyzed the cost and 2020 emission impacts for the proposed emission limit using

partial capture, plus a more stringent full capture scenario.three scenarios: no capture, partial

capture, and full capture. Consistent with the LCOE estimates provided earlier in this chapter,

Tthe partial capture CCS scenarios achieve the proposed emissions rate of 1,100 lb CO2/MWh

gross output. The full capture CCS scenarios achieve an emissions rate of 200 lb CO2/MWh and

150 lb CO2/MWh for SCPC and IGCC, respectively. Tables 5‐x15 and 5‐x16 show the costs and

2020 net benefits per MWh of each of these scenarios relative to a no capture scenario.    

In the near term, any new coal‐fired EGU with CCS would most likely be located in areas

amenable to using the captured CO2 in 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 project94 is planning to capture 90% of the CO2 and sell it for

enhanced oil recovery. To evaluate the potential revenues from EOR we estimate the revenue

in each scenario if CO2 could be sold for $20 to $40/ton based on assumptions used by NETL in

evaluating the EOR opportunities.95 [update source of estimate]..  

Table 5‐X15 Illustrative Costs and 2020 Social Benefits for SCPC with Partial Capture and Full

Capture CCS Relative to SCPC without CCS (per MWh 2011$)

   Partial CCS Full CCS

Additional LCOE of CCSa $29 $66

Revenue from EOR (Low ‐ High EOR) $14 ‐to $22 $32 ‐to $54

Additional LCOE, net of EOR $15 ‐to $7 $34 ‐to $12

Value of Monetized Benefits for 2020 Emissions

SCC 5% with Krewski 3% ‐to SCC 3%(95th) with Lepeule 3%b $7.9 ‐to $45 $22 ‐to $120

Net Monetized Benefits for 2020 Emissions

Without EOR Revenue  ‐$21 ‐to $16 ‐$44 ‐to $59

With EOR Revenue  ‐$7.1 ‐to $38 ‐$12 ‐to $110 a LCOE of SCPC without CCS does not include 3% CUAadder. b

Benefits are estimated for a 2020 analysis year. Values shown are calculated using different discount rates.  Four

estimates of the SCC in the year 2020 were used:  $13, $46, and $69 per metric ton (average SCC at discount rates of

5, 3, and 2.5 percent, respectively) and $138 per metric ton (95th percentile SCC at 3 percent).  The average SCC at 5

percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate.

See RIA 5.7.1 for complete discussion about these estimates.

                                                      

94 http://www.texascleanenergyproject.com/   95 http://www.netl.doe.gov/energy‐analyses/pubs/storing%20co2%20w%20eor_final.pdf
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Table 5‐X16 Illustrative Costs and 2020 Social Benefits for IGCC with Partial Capture and Full

Capture CCS Relative to IGCC without CCS (per MWh 2011$)

   Partial CCS Full CCS

Additional LCOE of CCS $12 $39

Revenue from EOR (Low ‐ High EOR) $8 ‐to $12 $27 ‐to $45

Additional LCOE, net of EOR $4 ‐to $0 $12 ‐ (‐$to ‐$6)

Value of Monetized Benefits for 2020 Emissions

SCC 5% with Krewski 3% – SCC 3%(95th) with Lepeule 3%a $2 ‐to $22 $8.3 ‐to $94

Net Monetized Benefits for 2020 Emissions

Without EOR Revenue

‐$10 ‐ $10to

$11 ‐$31 ‐to $55

With EOR Revenue

‐$2 ‐ $22to

$23 ‐$3.7 ‐to $100 aa Benefits are estimated for a 2020 analysis year. Values shown are calculated using different discount rates.  Four

estimates of the SCC in the year 2020 were used:  $13, $46, and $69 per metric ton (average SCC at discount rates of

5, 3, and 2.5 percent, respectively) and $138 per metric ton (95th percentile SCC at 3 percent).  The average SCC at 5

percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate.

See RIA 5.7.1 for complete discussion about these estimates.

The CCS 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. The EPA estimated the

benefits associated with avoided CO2, SO2, and NOX emissions using the methods described

previously in this chapter.  

As before, it is important to note that these comparisons omit additional benefits that

may be associated with the abatement of greenhouse gas emissions.

5.11 Summary of Costs, Benefits, and Energy Impacts

Under a wide range of electricity market conditions – including EPA’s baseline scenario

as well as multiple sensitivity analyses – EPA projects that the industry will choose to construct

new units that already meet these standards, regardless of this proposal.  As a result, EPA

anticipates that the proposed EGU New Source GHG NSPSStandards will result in negligible CO2

emission changes, energy impacts, benefits or costs for new units constructed by 2020.  

Likewise, the Agency does not anticipate any notable impacts on the price of electricity or

energy supplies. Additionally, for the reasons described above, the proposed rule is not

expected to raise any reliability concerns, since reserve margins will not be impacted and the

rule does not impose any requirements on existing facilities. 
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5.12 Macroeconomic and Employment Impacts

ThisThese proposed EGU New Source GHG NSPSStandards is not anticipated to change

GHG emissions for newly constructed electric generating units, and is anticipated to impose

negligible costs or monetized benefits.  EPA typically presents the economic impacts to

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

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

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

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

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

employment impacts expected as a result of this proposed rule.   

5.13 References

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

University Press: New York (1988).

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

OECD/IEA.

Dalia Patiño‐Echeverri, Paul Fischbeck, and Elmar Kriegler. Economic and Environmental Costs

of Regulatory Uncertainty for Coal‐Fired Power Plants. Environmental Science &

Technology 2009 43 (3), 578‐584.

Fann, N., K.R. Baker, C.M. Fulcher. 2012. Characterizing the PM2.5‐related health benefits of

emission reductions for 17 industrial, area and mobile emission sectors across the U.S.

Environment International, Volume 49, 15 November 2012, Pages 141‐151, ISSN 0160‐

4120, http://dx.doi.org/10.1016/j.envint.2012.08.017.

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.

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

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

10‐013.

Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz,

and W.H. White. 2009. “Reanalysis of the Harvard Six Cities Study and the American

Cancer Society Study of Particulate Air Pollution and Mortality.” Special Report to the

Health Effects Institute. Cambridge, MA. July.
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Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. “Chronic Exposure to Fine Particles and

Mortality: An Extended Follow‐Up of the Harvard Six Cities Study from 1974 to 2009.”

Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.

Malik, N.S. 2010, November 1. NextEra CEO sees clean energy standards replacing recent

climate proposals [Radio transcript]. Dow Jones News [Online]. Available: Dow Jones

Interactive Directory: Publications Library.

Mufson, S. 2011, January 2. Coal’s burnout. The Washington Post. Retrieved from  

http://www.washingtonpost.com/newssearch.

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

United States Economy. American Economic Review. 101:1649‐1675.

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

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

Rosenberg, M. 2011, September/October. “The Reign of Cheap Gas.” EnergyBiz Magazine.

Retrieved from http://www.energybiz.com/magazine/article/234577/reign‐cheap‐gas.

Teisberg, E.O. An Option Valuation Analysis of Investment Choices by a Regulated Firm.

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

Tong, S. 2010, November 1. Placing Bets on Clean Energy. [Radio transcript]. American Public

Media: Marketplace [Online]. Available: Marketplace Programs on Demand.

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

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

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

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

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

December. Available on the Internet at

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

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

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

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

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
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U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis for the Final

Mercury and Air Toxics Standards. Office of Air Quality Planning and Standards,

Research Triangle Park, NC. December. Available on the Internet at

<http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf>.

U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the

Final Revisions to the National Ambient Air Quality Standards for Particulate Matter.

Office of Air Quality Planning and Standards, Research Triangle Park, NC. December.

Available on the Internet at <http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf>.

U.S. Environmental Protection Agency (U.S. EPA). 2013a. Technical Support Document

Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of

Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on

the Internet at:

<http://www.epa.gov/airquality/benmap/models/Source_Apportionment_BPT_TSD_1_

31_13.pdf>.

U.S. Environmental Protection Agency (U.S. EPA). 2013b. Integrated Science Assessment for

Ozone and Related Photochemical Oxidants. EPA/600/R‐10/076F. Research Triangle

Park, NC: U.S. EPA. February. Available on the Internet at

<http://oaspub.epa.gov/eims/eimscomm.getfile?p_download_id=511347>.
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CHAPTER 6

STATUTORY AND EXECUTIVE ORDER ANALYSES

6.1   Synopsis

This chapter presents discussion and analyses relating to Executive Orders and statutory

requirements relevant to the proposed EGU New Source GHG Standards. We discuss analyses

conducted to meet the requirements of Executive Orders 12866 and 13563, as well as,

potential impacts to affected small entities required by the Regulatory Flexibility Act (RFA), as

amended by the Small Business Regulatory Enforcement Fairness Act (SBREFA). We also discuss

the requirements of the Unfunded Mandates Reform Act of 1995 (UMRA) and assess the

impact of the proposed rule on state, local and tribal governments and the private sector, along

with the analysis conducted to comply with the Paperwork Reduction Act (PRA). In addition, we

address the requirements of Executive Order (EO) 13045: Protection of Children from

Environmental Health and Safety Risks; EO 13132: Federalism; EO 13175: Consultation and

Coordination with Indian Tribal Governments; EO 12898: Federal Actions to Address

Environmental Justice in Minority Populations and Low‐Income Populations; EO 13211: Actions

that Significantly Affect Energy Supply, Distribution, or Use; and the National Technology

Transfer and Advancement Act (NTTAA).   

6.2   Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563,

Improving Regulation and Regulatory Review

Under EO 12866 (58 FR 51,735, October 4, 1993), this action is a “significant regulatory

action” because it “raises novel legal or policy issues arising out of legal mandates.”

Accordingly, the EPA submitted this action to the Office of Management and Budget (OMB) for

review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any

changes made in response to OMB recommendations have been documented in the docket for

this action.  

In addition, the EPA prepared an analysis of the potential costs and benefits associated

with this action. This analysis is contained in this RIA. Based on the analysis presented in

Chapter 5, the EPA believes this rule will have negligible compliance costs associated with it,

over a range of likely sensitivity conditions, because electric power companies would choose to

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

absence of the proposal given existing and expected market conditions. The EPA does not

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

However, because some companies may choose to construct coal or other solid fossil fuel‐fired
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units, this RIA also analyzes project‐level costs of a unit with and without CCS, to quantify the

potential cost for a solid fossil fuel‐fired unit with CCS and estimate the social benefits of

requiring CCS on a new uncontrolled unit.  

6.3   Paperwork Reduction Act

The information collection requirements in this proposed rule have been submitted for

approval to the Office of Management and Budget under the Paperwork Reduction Act, 44

U.S.C. 3501 et seq. The information collection requirements are not enforceable until OMB

approves them. The Information Collection Request (ICR) document prepared by the EPA has

been assigned EPA ICR tracking number 2465.01 and OMB control number 2060‐0685.  

     This proposed action will impose minimal new information collection burden on

affected sources beyond what those sources are already subject to under the authorities of CAA

parts 75 and 98. OMB has previously approved the information collection requirements

contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under

the provisions of the PRA, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060‐

0626 and 2060‐0629, respectively. Apart from certain reporting costs based on requirements in

the NSPS General Provisions (40 CFR part 60, subpart A), which are mandatory for all

owners/operators subject to CAA section 111 national emission standards, there are no new

information collection costs, as the information required by this proposed rule is already

collected and reported by other regulatory programs. The recordkeeping and reporting

requirements are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information

submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a

claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR

part 2, subpart B.     

The EPA believes that electric power companies will choose to build new EGUs that

comply with the regulatory requirements of this proposal because of existing and expected

market conditions. The EPA does not project any new coal‐fired EGUs that commence

construction after this proposal to commence operation over the 3‐year period covered by this

ICR. We estimate that 17 new affected NGCC units will commence operation during that time

period. As a result of this proposal, those units will be required to prepare a summary report,

which includes reporting of excess emissions and downtime every 6 months.

When a malfunction occurs, sources must report them according to the applicable

reporting requirements of 40 CFR part 60, subpart Da or KKKK. An affirmative defense to civil

penalties for exceedances of emission limits that are caused by malfunctions is available to a
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source if it can demonstrate that certain criteria and requirements are satisfied. The criteria

ensure that the affirmative defense is available only where the event that causes an

exceedance of the emission limit meets the narrow definition of malfunction1 and where the

source took necessary actions to minimize emissions. In addition, the source must meet certain

notification and reporting requirements. For example, the source must prepare a written root

cause analysis and submit a written report to the Administrator documenting that it has met

the conditions and requirements for assertion of the affirmative defense.  

To provide the public with an estimate of the relative magnitude of the burden

associated with an assertion of affirmative defense, the EPA has estimated what the

notification, recordkeeping, and reporting requirements associated with the assertion of the

affirmative defense might entail. The EPA’s estimate for the required notification, reports, and

records, including the root cause analysis, associated with a single incident totals approximately

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.

Given the variety of circumstances under which malfunctions could occur, as well as

differences among sources' operation and maintenance practices, we cannot reliably predict

the severity and frequency of malfunction‐related excess emissions events for a particular

source. It is important to note that the EPA has no basis currently for estimating the number of

malfunctions that would qualify for an affirmative defense. Current historical records would be

an inappropriate basis, as this rule applies only to sources built in the future. Of the number of

excess emissions events that may be reported by source operators, only a small number would

be expected to result from a malfunction, and only a subset of excess emissions caused by

malfunctions would result in the source choosing to assert an affirmative defense. Thus, we

believe the number of instances in which source operators might be expected to avail

themselves of the affirmative defense will be extremely small. In fact, we estimate that there

will be no such occurrences for any new sources subject to 40 CFR part 60, subpart Da or KKKK

                                                      

1 Malfunction means any sudden, infrequent, and not reasonably preventable failure of air pollution control and

monitoring equipment, process equipment, or a process to operate in a normal or usual manner which causes,

or has the potential to cause, the emission limitations in an applicable standard to be exceeded. Failures that

are caused in part by poor maintenance or careless operation are not malfunctions.
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over the 3‐year period covered by this ICR. We expect to gather information on such events in

the future, and will revise this estimate as better information becomes available.

The annual information collection burden for this collection consists only of reporting

burden as explained above. The reporting burden for this collection (averaged over the first 3

years after the effective date of the standards) is estimated to be $15,570 and 396 labor hours.

This estimate includes semi‐annual summary reports which include reporting of excess

emissions and downtime. All burden estimates are in 2010 dollars, consistent with the

information collection request. Average burden hours per response are estimated to be 16.5

hours. The total number of respondents over the 3‐year ICR period is estimated to be 36.

Burden is defined at 5 CFR 1320.3(b).

An agency may not conduct or sponsor, and a person is not required to respond to, a

collection of information unless it displays a currently valid OMB control number. The OMB

control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9.

To comment on the Agency's need for this information, the accuracy of the provided

burden estimates, and any suggested methods for minimizing respondent burden, the EPA has

established a public docket for this rule, which includes this ICR, under Docket ID number EPA‐

HQ‐OAR‐2013‐0495. Submit any comments related to the ICR to the EPA and OMB. See

ADDRESSES section at the beginning of this notice for where to submit comments to the EPA.

Send comments to OMB at the Office of Information and Regulatory Affairs, Office of

Management and Budget, 725 17th Street, NW, Washington, DC 20503, Attention: Desk Officer

for EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days

after publication in the Federal Register, a comment to OMB is best assured of having its full

effect if OMB receives it by 30 days after publication in the federal register. The final rule will

respond to any OMB or public comments on the information collection requirements contained

in this proposal.  

6.4.   Regulatory Flexibility Act 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.
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For purposes of assessing the impacts of this rule on small entities, small entity is

defined as:  

(1) A small business that is defined by the Small Business Administration’s regulations at

13 CFR 121.201 (for the electric power generation industry, the small business size standard is

an ultimate parent entity defined as having a total electric output of 4 million MWh or less in

the previous fiscal year. The NAICS codes for the affected industry are in Table 6‐1 below);

(2) A small governmental jurisdiction that is a government of a city, county, town, school

district, or special district with a population of less than 50,000; and  

(3) A small organization that is any not‐for‐profit enterprise which is independently

owned and operated and is not dominant in its field.

Table 6‐1. Potentially Regulated Categories and Entitiesa

Category NAICS Code Examples of Potentially Regulated Entities

Industry 221112 Fossil fuel electric power generating units.

Federal Government 221112b Fossil fuel electric power generating units owned by the federal

government.

State/Local

Government

221112b Fossil fuel electric power generating units owned by municipalities.

Tribal Government 921150 Fossil fuel electric power generating units in Indian Country.

a Include NAICS categories for source categories that own and operate electric power generating units (includes boilers and

stationary combined cycle combustion turbines).

b Federal, state, or local government‐owned and operated establishments are classified according to the activity in which they

are engaged.

After considering the economic impacts of this proposed rule on small entities, the

Administrator of EPA certifies that this action will not have a significant economic impact on a

substantial number of small entities.  

We do not include an analysis of the illustrative impacts on small entities that may result

from implementation of this proposed rule by states because we anticipate negligible

compliance costs over a range of likely scenarios as a result of this proposal. Thus the cost‐to‐

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 proposed rule because of existing
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and expected market conditions. (See the Chapter 5 for further discussion of sensitivities.) The

EPA does not project any new coal‐fired EGUs without CCS to be built. Accordingly, there are no

anticipated economic impacts as a result of this proposed rule.

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 enabled the

EPA to hear directly from these representatives, at a very preliminary stage, about how it

should approach the complex question of how to apply Section 111 of the CAA to the regulation

of GHGs from these source categories. The EPA’s outreach regarded planned actions for new

and existing sources, but only new sources will be affected by this proposed action.

The EPA conducted an initial outreach meeting with small entity representatives on

April 6, 2011. The purpose of the meeting was to provide an overview of recent EPA proposals

impacting the power sector. Specifically, overviews of the Transport Rule, the Mercury and Air

Toxics Standards, and the Clean Water Act 316(b) Rule proposals were presented.

The EPA conducted outreach with representatives from 20 various small entities that

potentially would be affected by this rule. The representatives included small entity

municipalities, cooperatives, and private investors. We distributed outreach materials to the

small entity representatives; these materials included background, an overview of affected

sources and GHG emissions from the power sector, an overview of CAA section 111, an

assessment of CO2 emissions control technologies, potential impacts on small entities, and a

summary of the listening sessions. We met with eight of the small entity representatives, as

well as three participants from organizations representing power producers, on June 17, 2011,

to discuss the outreach materials, potential requirements of the rule, and regulatory areas

where the EPA has discretion and could potentially provide flexibility.

A second outreach meeting was conducted on July 13, 2011. We met with nine of the

small entity representatives, as well as three participants from organizations representing

power producers. During the second outreach meeting, various small entity representatives

and participants from organizations representing power producers presented information

regarding issues of concern with respect to development of standards for GHG emissions.

Specifically, topics suggested by the small entity representatives and discussed included: boilers
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with limited opportunities for efficiency improvements due to New Source Review (NSR)

complications for conventional pollutants; variances per kilowatt‐hour and in heat rates over

monthly and annual operations; significance of plant age; legal issues; importance of future

determination of carbon neutrality of biomass; and differences between municipal government

electric utilities and other utilities.

     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 (UMRA)

This proposed rule does not contain a Federal mandate that may result in expenditures

of $100 million or more for State, local, or tribal governments, in the aggregate, or the private

sector in any one year. The EPA believes this proposed rule will have negligible compliance

costs associated with it over a range of likely sensitivity conditions because electric power

companies will choose to build new EGUs that comply with the regulatory requirements of this

proposed rule because of existing and expected market conditions. (See Chapter 5 for further

discussion of sensitivities.) The EPA does not project any new coal‐fired EGUs without CCS to be

built. Thus, this proposed rule is not subject to the requirements of sections 202 or 205 of

UMRA.

This proposed rule is also not subject to the requirements of section 203 of UMRA

because it contains no regulatory requirements that might significantly or uniquely affect small

governments.

In light of the interest in this rule among governmental entities, the EPA initiated

consultations with governmental entities while formulating the provisions of the proposed

regulation (77 FR 22392, April 13, 2012). The EPA invited the following 10 national

organizations representing state and local elected officials to a meeting held on April 12, 2011,

in Washington DC: 1) National Governors Association; 2) National Conference of State

Legislatures, 3) Council of State Governments, 4) National League of Cities, 5) U.S. Conference

of Mayors, 6) National Association of Counties, 7) International City/County Management

Association, 8) National Association of Towns and Townships, 9) County Executives of America,

and 10) Environmental Council of States. These 10 organizations representing elected state and

local officials have been identified by the EPA as the “Big 10” organizations appropriate to

contact for purposes of consultation with elected officials. The purposes of the consultation

were to provide general background on the proposal, answer questions, and solicit input from
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state/local governments. The EPA’s consultation regarded planned actions for new and existing

sources, but only new sources will be affected by this proposed action.  

During the meeting, officials asked clarifying questions regarding CAA section 111

requirements and efficiency improvements that would reduce CO2 emissions. In addition, they

expressed concern with regard to the potential burden associated with impacts on state and

local entities that own/operate affected utility boilers, as well as on state and local entities with

regard to implementing the rule. Subsequent to the April 12, 2011 meeting, the EPA received a

letter from the National Conference of State Legislatures. In that letter, the National

Conference of State Legislatures urged the EPA to ensure that the choice of regulatory options

maximizes benefit and minimizes implementation and compliance costs on state and local

governments; to pay particular attention to options that would provide states with as much

flexibility as possible; and to take into consideration the constraints of the state legislative

calendars and ensure that sufficient time is allowed for state actions necessary to come into

compliance.

6.6   Executive Order 13132, Federalism

This proposed action does not have federalism implications. It will not have substantial

direct effects on the States, on the relationship between the national government and the

States, or on the distribution of power and responsibilities among the various levels of

government, as specified in EO 13132. This action will not impose substantial direct compliance

costs on state or local governments nor will it preempt state law. Thus, Executive Order 13132

does not apply to this action. The EPA consulted with state and local officials in the process of

developing the proposed rule to permit them to have meaningful and timely input into its

development. The EPA’s consultation regarded planned actions for new and existing sources,

but only new sources will be affected by this action. The UMRA discussion in this chapter

includes a description of the consultation. The EPA met with 10 national organizations

representing state and local elected officials to provide general background on the proposal,

answer questions, and solicit input from state/local governments. The UMRA discussion in this

preamble 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
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Subject to the EO 13175 (65 FR 67249, November 9, 2000) the EPA may not issue a

regulation that has tribal implications, that imposes substantial direct compliance costs, and

that is not required by statute, unless the Federal government provides the funds necessary to

pay the direct compliance costs incurred by tribal governments, or the 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 action will not have tribal implications. It will neither

impose substantial direct compliance costs on tribal governments, nor preempt tribal law. This

proposed rule will 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 proposed rule 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 the proposed regulation to

permit them to have meaningful and timely input into its development. The EPA’s consultation

regarded planned actions for new and existing sources, but only new sources will be affected by

this action.

Consultation letters were sent to 584 tribal leaders. The letters provided information

regarding the EPA’s development of NSPS and emission guidelines for EGUs and offered

consultation. A consultation/outreach meeting was held on May 23, 2011, with the Forest

County Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa Reservation,

and the Leech Lake Band of Ojibwe. Other tribes participated in the call for information

gathering purposes. In this meeting, the EPA provided background information on the GHG

emission standards to be developed and a summary of issues being explored by the agency.

Tribes suggested that the EPA consider expanding coverage of the GHG standards to include

combustion turbines, lowering the 250 MMBtu per hour heat input threshold so as to capture

more EGUs, and including credit for use of renewables. The tribes were also interested in the

scope of the emissions averaging being considered by the agency (e.g., over what time period,

across what units) for a possible existing source standard. In addition, the EPA held a series of

listening sessions on the proposed action. Tribes participated in a session on February 17, 2011

with the state agencies, as well as in a separate session with tribes on April 20, 2011.  
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The EPA will also hold additional meetings with tribal environmental staff to inform

them of the content of this proposal, as well as provide additional consultation with tribal

elected officials where it is appropriate. We specifically solicit additional comment on this

proposed rule from tribal officials.

6.8   Executive Order 13045, Protection of Children from Environmental Health Risks and

Safety Risks

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those

regulatory actions that concern health or safety risks, such that the analysis required under

section 5‐501 of the Order has potential to influence the regulation. This proposed action is not

subject to EO 13045 because it is based solely on technology performance. The proposal is not

expected to produce notable changes in emissions of greenhouse gases or other pollutants but

does encourage the current trend towards cleaner generation, helping to protect air quality and

children's health. The agency recognizes that children are among the groups most vulnerable to

climate change impacts and the public is invited to submit comments or identify peer reviewed

studies relevant to this proposal.

6.9   Executive Order 13211, Actions Concerning Regulations That Significantly Affect

Energy Supply, Distribution, or Use

This proposed action is not a “significant energy action” as defined in Executive Order

13211 (66 FR 28355, May 22, 2001), because it is not likely to have a significant adverse effect

on the supply, distribution, or use of energy. This proposed action is anticipated to have

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

industry.

6.10   National Technology Transfer and Advancement Act  

Section 12(d) of the NTTAA of 1995 (Public Law No. 104‐113; 15 U.S.C. 272 note) directs

the EPA to use Voluntary Census Standards (VCS) in their regulatory and procurement activities

unless to do so would be inconsistent with applicable law or otherwise impractical. VCS are

technical standards (e.g., materials specifications, test methods, sampling procedures, business

practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA

directs the EPA to provide Congress, through annual reports to the OMB, with explanations

when an agency does not use available and applicable VCS.
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This proposed rulemaking involves technical standards. The EPA cites the following

standards in this proposed rule: D5287‐08 (Standard Practice for Automatic Sampling of

Gaseous Fuels), D4057‐06 (Standard Practice for Manual Sampling of Petroleum and Petroleum

Products), and D4177‐95(2010) (Standard Practice for Automatic Sampling of Petroleum and

Petroleum Products). The EPA is proposing use of Appendices B, D, F, and G to 40 CFR part 75;

these Appendices contain standards that have already been reviewed under the NTTAA.

The EPA welcomes comments on this aspect of the proposed rulemaking and,

specifically, invites the public to identify potentially‐applicable VCS and to explain why such

standards should be used in this action.  

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

Populations and Low‐Income Populations

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

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

extent practicable and permitted by law, to make environmental justice part of their mission by

identifying and addressing, as appropriate, disproportionately high and adverse human health

or environmental effects of their programs, policies, and activities on minority populations and

low‐income populations in the U.S.

This proposed rule limits GHG emissions from new fossil fuel‐fired EGUs by establishing

national emission standards for CO2. The EPA has determined that this proposed rule will not

result in disproportionately high and adverse human health or environmental effects on

minority, low‐income, and indigenous populations because it increases the level of

environmental protection for all affected populations without having any disproportionately

high and adverse human health or environmental effects on any population, including any

minority, low‐income, or indigenous populations.  

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