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ES-1

EO 12866_111(b) New-Mods 2060-AQ91 RIA Final_20150520

EXECUTIVE SUMMARY

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

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

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

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

ES.1 Background and Context of Final Rule

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

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

reconstructed fossil fuel-fired electricity generating units (EGUs). This rulemaking will apply to 

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

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

CO2 is 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 (CAA) (74 FR 66518) and

summarized in Chapter 3 of this RIA, the anthropogenic buildup of GHGs in the atmosphere is 

the cause of most of the observed global warming over the last 50 years.

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

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

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

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

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

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

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

2014). 

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

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

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

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

February 26, 2014). 
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On June 2, 2014, Administrator McCarthy signed proposed standards of performance, 

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

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

34959, June 18, 2014).

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

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

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

section 111(b), these standards reflect the degree of emission limitation achievable through the 

application of the best system of emission reduction (BSER) that the EPA has determined has 

been adequately demonstrated for each type of unit.

ES.2 Summary of the Final Rule

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

partial carbon capture and storage (CCS) technology to meet an emission limitation of 1,400 lb 

CO2/MWh-gross. The standard for modified steam generating units that conduct modifications 

resulting in a potential hourly increase in CO2 emissions (mass per hour) of more than 10 

percent1is a unit-specific emission limitation consistent with each modified unit’s best one-year 

historical performance (during the years from 2002 to the time of the modification). For 

reconstructed steam generating units, the BSER is the most efficient demonstrated generating 

technology for these types of units (i.e., meeting a standard of performance consistent with a 

reconstructed boiler using most efficient steam conditions available, even if the boiler was not 

originally designed to do so).

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

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

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

to meet an emission standard of 1,000 lb CO2/MWh-gross output (or 1,080 lb CO2/MWh of net 

energy output).

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

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

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

met on a 12-operating month rolling average basis. 

 

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

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

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

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

projected impacts within the current eight-year NSPS timeframe.

2 As explained in detail in this 

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

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

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

The base case modeling the EPA performed for this rule (as well as modeling that the

EPA has performed for other recent air rules) projects that, even in the absence of this action, 

new fossil-fuel fired capacity constructed through 2022 and the years following will most likely 

be NGCC capacity that complies with the final standards. Analyses performed both by the EPA 

and the Energy Information Administration (EIA) project that new compliant natural gas-fired

units and renewable sources are likely to be the technologies of choice for new generating 

capacity due to current and projected economic market conditions.

3

 

2

In some cases, conditions in the analysis year of 2022 are represented by results of power sector modeling for the 

year 2020. An analysis year of 2023 (8 years from finalization) would not substantively alter the overall 

conclusions of this RIA.

3

 See the EIA’s 2009 to 2014 Annual Energy Outlooks (AEO).
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Table ES-1. Summary of BSER and Final Standards for Affected Sources

Affected Source BSER Standard

Newly Constructed Fossil Fuel-Fired 

Steam Generating Units

Partial CCS 1,400 lb CO2/MWh-gross

Modified Fossil Fuel-Fired Steam 

Generating Units

Most efficient generation at the 

affected source achievable 

through a combination of best 

operating practices and 

equipment upgrades

Sources making modifications

resulting in an increase in CO2

hourly emissions of more than 10 

percent are required to meet a 

unit-specific emission limit 

determined by the unit’s best 

historical annual CO2 emission rate 

(from 2002 to the date of the 

modification); the emission limit 

will be no more stringent than:

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

sources with heat input > 2,000 

MMBtu/h.

OR

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

sources with heat input ≤ 2,000 

MMBtu/h.

Reconstructed Fossil Fuel-Fired Steam 

Generating Units

Most efficient generating 

technology at the affected source.

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

sources with heat input > 2,000 

MMBtu/h.

OR

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

sources with heat input ≤ 2,000 

MMBtu/h.

Newly Constructed, Modified, and 

Reconstructed Natural Gas-Fired 

Stationary Combustion Turbines

Efficient Natural Gas Combined 

Cycle (NGCC) Technology

1. 1,000 lb CO2/MWh-gross

 OR

2. 1,080 lb CO2/MWh-net

Historically, the EPA has been notified of very few EGU NSPS modifications (for criteria 

pollutants) or reconstructions. As such, the EPA anticipates few covered units will trigger the 

reconstruction or modification provisions in the period of analysis. 

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

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

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

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

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

While the primary conclusion of the analysis presented in this RIA is that the standards 

for newly constructed EGUs will result in negligible costs and benefits, the EPA has also 
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performed several illustrative analyses, in Chapter 5, that show the potential impacts of the 

rule if certain key assumptions were to change, or if idiosyncratic circumstances suggest in the 

absence of this rule a unit that does not comply with these standards may be constructed. This 

analysis finds that under the unlikely conditions in which the EPA’s conclusions regarding the 

future economic competitiveness of new noncompliant coal-fired units with respect to other 

new generation technologies shifts, that the benefits of the standards to society likely outweigh 

the costs. 

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

power plant must limit CO2 emissions through implementation of partial CCS or other 

technologies such as natural gas co-firing. The final standards reduce regulatory uncertainty by 

defining the requirements to limit emissions of CO2 from new, modified, and reconstructed

fossil fuel-fired steam generating sources. 

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

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

these technologies’ performance and consequent reductions in their cost. Identifying partial 

CCS technology as the best system of emission reductions (BSER) for coal-fired power plants 

promotes further development and encourages continued research of CCS, 4,5 which is 

important for long-term CO2 emission reductions. 

The final standards also provide regulatory certainty for stationary combustion turbines 

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

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

turbines must be well-designed, well-maintained, and well-operated and final applicability 

criteria clearly exclude combustion turbines that are intended to serve peak power demand 

rather than intermediate and base load. 

 

4

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

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

5

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

Management Program. http://www.nrcce.wvu.edu/cleanenergy/docs/Friedmann.pdf. 
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CHAPTER 1

INTRODUCTION AND BACKGROUND

1.1 Introduction

In this action, the U.S. Environmental Protection Agency (EPA) seeks to finalize emission 

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

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

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

Chapter 4, expected economic conditions will lead electricity generators to choose fuels and 

technologies that will meet the final standards for new sources without the need for additional 

control, even in the absence of the rule. As a result, the final new source standards are 

expected to have no, or negligible, costs or monetized benefits associated with them. EPA has 

reached a similar conclusion for the final reconstruction and modification provisions. Based on 

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

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

not anticipate any significant costs or benefits associated with those standards. This chapter 

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

1.1.1 Statutory Requirement

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

emissions from categories of stationary sources that may reasonably contribute to the 

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 finalizing this rule to regulate these emissions from new, 

modified and reconstructed EGU sources under section 111 of the CAA. 

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

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

address carbon pollution from new power plants by September 30, 2013, and to issue 
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“standards, regulations, or guidelines, as appropriate, which address carbon pollution from 

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

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

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

2014). 

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

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

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

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

February 26, 2014). 

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

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

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

34959, June 18, 2014).

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

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

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

section 111(b), these standards reflect the degree of emission limitation achievable through the 

application of the best system of emission reduction (BSER) that the EPA has determined has 

been adequately demonstrated for each type of unit.

1.1.2 Regulatory Analysis 

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

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

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

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

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

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

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

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

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

potential impacts of this rule, consistent with requirements of the Executive Orders.
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This RIA addresses the potential costs and benefits of the new, modified and 

reconstructed source emission limits that are the focus of this action. The EPA does not 

anticipate that any costs or quantified benefits will result from the new source standards if

utilities and project developers make the types of choices related to new generation sources 

that is predicted by EPA’s and EIA’s modeling and that many publicly available utility integrated 

resource plans (IRPs) indicate they are likely to make. However, in the unlikely event that a 

utility or project developer finds it economical to construct a new uncontrolled coal-fired unit 

absent this rule, there could be some compliance costs. In these cases, the EPA expects the rule 

will result in net societal benefits under a range of assumptions.

For new sources, the EPA and other energy modeling groups, such as EIA1, project that 

new fossil-fired electric utility steam generating units and natural gas-fired stationary 

combustion turbines, which meet the applicability criteria, will meet their respective standards 

under this rule, even in the absence of this rule. These modeling analyses also do not forecast 

the construction of any new coal-fired units that exceed the applicable standards under this 

rule, even in the absence of this rule. Some limited new coal-fired units with federallysupported carbon capture and storage (CCS) are forecast to be constructed, though these units 

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

does not change these forecasts, it is expected to have no, or negligible, costs2or quantified 

benefits.

New non-compliant coal-fired units are not expected to be constructed, independent of 

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

the cost of new coal-fired units, relatively low forecast growth in electricity demand and an 

expectation that the growth in end-use energy efficiency and renewable energy resources will 

continue. The expectation that no new non-compliant coal-fired units will be constructed 

absent this rule holds under a range of sensitivity analyses. Chapter 5 complements and 

extends the analysis at the sector level by examining conditions (e.g., significantly high natural 

gas prices, location specific conditions) in which these conclusions regarding the future 

economic competitiveness of new non-compliant coal-fired units with respect to other new 

 

1

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

2

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

already be required to monitor and report their CO2 emissions under the information collection requirements 

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

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

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

affirmative defense. See Chapter 6 for more details on monitoring and reporting costs.
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generation technologies may differ. The analysis evaluates the cost and benefits of adopting 

different competing generating technologies to serve base load demand at an individual facility 

level. When considering a wide range of natural gas price assumptions, along with information 

on historical and projected gas prices, this illustrative facility-level analysis supports the 

conclusion that these final standards are highly likely to have no costs or monetized benefits. 

Furthermore, the analysis finds that in the unlikely case where there might be impacts to a 

specific facility-level investment the rule is expected to have net benefits for society. 

New non-compliant natural gas-fired combustion turbine units intended to serve as 

intermediate and base load generators are not expected to be constructed, independent of this 

rule, due in part to the cost effectiveness of constructing and operating new combined cycle 

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

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

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

analysis finds that in the unlikely case where there might be impacts to a specific facility-level 

investment the rule is expected to have net benefits for society. 

Chapter 5 also analyzes the construction of an illustrative compliant coal-fired unit that 

meets the standard using either partial CCS or by co-firing natural gas, in place of an illustrative 

non-compliant unit. 

EPA has reached a similar conclusion for the reconstruction and modification provisions. 

The EPA has, historically, been notified of few NSPS modifications or reconstructions and, as 

such, the EPA anticipates few covered units will trigger the reconstruction or modification 

provisions in the period of analysis. As a result, we do not anticipate any significant costs or 

benefits associated with this rule.

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

Standards

1.2.1 Baseline and Years of Analysis

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

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

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

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

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

discussed in Chapter 4 of this RIA. 
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All analyses are presented for compliance through the year 20223and all estimates are 

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

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

the current eight-year NSPS timeframe. EPA’s finding of no new non-compliant units (and 

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

2030) in both EPA’s Base Case and the EIA’s Annual Energy Outlook 2014 Reference Case 

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

range of alternative potential market, technical, and regulatory scenarios that influence power 

sector investment decisions evaluated by EIA.4 Chapter 5 complements and extends the 

analysis at the sector level by examining conditions (e.g., significantly high natural gas prices, 

location specific conditions) in which these conclusions regarding the future economic 

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

technologies may differ. The analysis evaluates the cost and benefits of adopting different 

competing generating technologies to serve base load demand at an individual facility level.

Benefits and costs presented in this RIA represent annualized estimates from emission 

reductions under the finalized standards in a particular year. The latent and/or ongoing 

damages associated with pollution from these sources in a particular analysis year are 

discounted to the analysis year. 5The benefits and costs presented do not represent the net 

present value of a stream of benefits and costs due to emission reductions over time.

 

3

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

4

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

construction of new coal capacity, the operation of new non-compliant coal capacity is not forecast by the 

model until 2027. The No GHG Concern case in the 2014 AEO forecasts limited amounts of new non-compliant 

coal capacity commencing operation starting in 2023; however that sensitivity case is unlikely to be reflected in 

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

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

multi-decade life of the plant. 

5

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. EPA relied on a national-average benefit per-ton method 

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

monetize as many of the co-benefits of reducing emissions from electricity generating sources as possible, not 

all known health and non-health co-benefits are accounted for in this assessment. See Chapter 3 for details.
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1.2.2 Definition of Affected Sources

1.2.2.1 New Sources

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

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

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

after January 8, 2014. 

1.2.2.2 Modified Sources

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

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

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

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

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

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

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

expects that most of the actions EGUs are likely to take 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.

1.2.2.3 Reconstructed Sources

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

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

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

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

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

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

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

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

reconstruction. The final standards for reconstructed fossil fuel-fired EGUs apply to those 

sources that reconstruct on or after June 18, 2014.

1.2.3 Regulated Pollutant

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

finalizing 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 
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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 setting 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 setting standards for these pollutants.

1.2.4 Emission Limits

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

partial CCS technology to meet a final emission limitation of 1,400 lb CO2/MWh-gross. The 

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

hourly increase in CO2 emissions (mass per hour) of more than 10 percent6is a unit-specific 

emission limitation consistent with each modified unit’s best one-year historical performance 

(during the years from 2002 to the time of the modification). For reconstructed steam 

generating units, the BSER is the most efficient demonstrated generating technology for these 

types of units (i.e., meeting a standard of performance consistent with a reconstructed boiler 

using most efficient steam conditions available, even if the boiler was not originally designed to 

do so). 

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

turbines expected to serve intermediate and base load is the use of well-designed, wellmaintained, and well-operated natural gas combined cycle (NGCC) technology. 

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

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

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

affected source expected to operate in intermediate or base load capacity are shown in Table 

1-1.

 

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

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

Affected Source BSER Standard

Newly Constructed Fossil Fuel-Fired 

Steam Generating Units

Partial CCS 1,400 lb CO2/MWh-gross

Modified Fossil Fuel-Fired Steam 

Generating Units

Most efficient generation at the 

affected source achievable 

through a combination of best 

operating practices and 

equipment upgrades

Sources making modifications

resulting in an increase in CO2

hourly emissions of more than 10 

percent are required to meet a 

unit-specific emission limit 

determined by the unit’s best 

historical annual CO2 emission rate 

(from 2002 to the date of the 

modification); the emission limit 

will be no more stringent than:

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

sources with heat input > 2,000 

MMBtu/h.

OR

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

sources with heat input ≤ 2,000 

MMBtu/h.

Reconstructed Fossil Fuel-Fired Steam 

Generating Units

Most efficient generating 

technology at the affected source.

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

sources with heat input > 2,000 

MMBtu/h.

OR

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

sources with heat input ≤ 2,000 

MMBtu/h.

Newly Constructed, Modified, and 

Reconstructed Natural Gas-Fired 

Stationary Combustion Turbines

Efficient NGCC Technology 1. 1,000 lb CO2/MWh-gross

 OR

2. 1,080 lb CO2/MWh-net

1.2.5 Emission Reductions

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

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

in GHGemissions over the analysis period. 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. Based on historical precedent, the EPA 

anticipates few covered units will trigger the reconstruction or modification provisions in the 

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

associated with this rule.
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1.3 Organization of the Regulatory Impact Analysis

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

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

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

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

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

emissions on climate and health and provides background information to support 

the benefits analysis.

 Chapter 4, Costs, Economic, and Energy Impacts, describes impacts of the rule.

 Chapter 5, Analysis of Illustrative Cost-Benefit Scenarios, describes additional 

analyses examining potential impacts under a range of scenarios.

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

the standards for modified and reconstructed sources.

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

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

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

requirements.
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CHAPTER 2

ELECTRIC POWER SECTOR PROFILE

2.1 Introduction

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

New Source GHG Standards, including the types of power-sector sources affected by the 

regulation, and provides background on the power sector and EGUs. In addition, this chapter 

provides some historical background on trends in the past decade in the power sector, as well 

as about existing EPA regulation of the power sector.

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

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

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

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

intensity of the US economy, growth and regional changes in the US population, technological 

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

and availability of different fuels, and substantial growth in electricity generation by renewable 

and unconventional methods. Many of these trends will continue to contribute to the evolution 

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

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

being utilized as base load energy in addition to supplying electricity during peak load. This 

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

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

more detail in Chapter 4 of this RIA.

2.2 Power Sector Overview

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

segments: generation, transmission, and distribution. 

2.2.1 Generation

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

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

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

hour, typically measured in megawatts (MW) or gigawatts (1 GW = 1000 MW). Electricity 

Generation refers to the amount of electricity actually produced by EGUs, measured in 

kilowatt-hours (kWh) or gigawatt-hours (GWh = 1 million kWh). In addition to producing 
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electricity for sale to the grid, generators perform other services important to reliable 

electricity supply, such as providing backup generating capacity in the event of unexpected 

changes in demand or unexpected changes in the availability of other generating markets. 

Other important services provided by generators include facilitating the regulation of the 

voltage of supplied generation.

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

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

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

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

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

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

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

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

of EGU in a given season or year. 

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

pressure steam that is released to rotate turbines which, in turn, create electricity. Other units 

generate electricity by using water or wind to rotate turbines, and a variety of other methods 

also make up a small, but growing, share of the overall electricity supply. The generating 

capacity includes fossil-fuel-fired units, nuclear units, and hydroelectric and other renewable 

sources (see Table 2-1). Table 2-1 also shows the comparison between the generating capacity 

in 2002 and 2012.

In 2012 the power sector consists of over 19,000 generating units with a total capacity1

of 1,168 GW, an increase of 188 GW (or 19 percent) from the capacity in 2002 (989 GW). The 

188 GW increase consisted primarily of natural gas fired EGUs (134 GW) and wind generators 

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

units. 

 

1

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

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

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

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

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

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

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

winter capacity) can use a variety of definitions and specified conditions.
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Table 2-1. Existing Electricity Generating Capacity by Energy Source, 2002 and 2012

2002 2012 Change Between '02 and '12

Energy Source

Generator 

Nameplate 

Capacity 

(MW)

% Total 

Capacity

Generator 

Nameplate 

Capacity 

(MW)

% Total 

Capacity

% 

Increase

Nameplate 

Capacity 

Change 

(MW)

% of Total 

Capacity 

Increase

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

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

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

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

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

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

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

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

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

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

Source: U.S. EIA Electric Power Annual, 2012. Downloaded from EIA Electricity Data Browser, Electric Power Plants 

Generating Capacity By Source, 2000 – 2012. Available at http://www.eia.gov/electricity/data.cfm#gencapacity. 

Accessed 12/19/2014

1

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

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

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

percent), and miscellaneous (< 1 percent).

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

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

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

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

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

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

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

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

partially offset by gas retirements (29,859 MW). Wind capacity was the second largest type of 
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new builds (55,583 MW), augmented by 2,807 MW of solar.2 The overall mix of newly built and 

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

Figure 2-1. New Build and Retired Capacity (MW) by Fuel Type, 2002-2012

Source: EIA Form 860

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

In 2012, electric generating sources produced a net 4,058 billion kWh to meet electricity 

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

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

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

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

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

that period. Coal generation declined by 18 percent and petroleum generation by 63 percent, 

while natural gas generation increased by 61 percent. This reflects both the increase in natural 

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

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

total in 2002 to 4.1 percent of the 2012 total.

 

2

Partially offset by 87 MW retired wind or solar capacity. 

-50,000

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

New Build Retirement Net Change

Change in Capacity (M

W)

Coal Nat Gas Wind & Solar Oil & Other
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Table 2-2. Net Generation in 2002 and 2012 (Trillion kWh = TWh)

2002 2012 Change Between '02 and '12

Net 

Generation 

(TWh)

Fuel 

Source 

Share

Net 

Generation 

(TWh)

Fuel 

Source 

Share

Net 

Generation 

Change 

(TWh)

% Change in 

Net 

Generation

Coal 1,933.1 50% 1,586.0 39% -347.1 -18.0%

Natural Gas 702.5 18% 1,125.9 28% 423.5 60.3%

Nuclear 780.1 20% 789.0 19% 9.0 1.1%

Hydro 255.6 7% 264.7 7% 9.1 3.6%

Petroleum 94.6 2.5% 26.9 0.7% -67.7 -71.6%

Wind 10.4 0.3% 167.7 4.1% 157.3 1519.3%

Other Renewable 68.8 1.8% 85.7 2.1% 16.9 24.6%

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

Total 3,858 100% 4,058 100% 200 5%

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

Available at http://www.eia.gov/totalenergy/data/monthly/. Accessed 12/19/2014

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

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

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

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

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

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

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

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

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

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

demand for electricity is reduced. 

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

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

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

of the gas fleet is between 50 and 500 MW per unit. Many of the largest gas units are gas-fired 

steam-generating EGUs. 
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Table 2-3. Coal and Natural Gas Generating Units, by Size, Age, Capacity, 

and Thermal Efficiency (Heat Rate)

Unit Size 

Grouping 

(MW)

No. 

Units

% of All 

Units

Avg. 

Age

Avg. Net 

Summer 

Capacity 

(MW)

Total Net 

Summer 

Capacity 

(MW)

% Total 

Capacity

Avg. Heat 

Rate 

(Btu/kWh)

COAL

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

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

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

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

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

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

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

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

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

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

NATURAL GAS

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

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

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

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

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

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

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

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

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

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

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

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

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

with planned retirements in 2014 or 2015.

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

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

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

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

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

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

Generation, by Age

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

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

years old for clarity. Figure is limited to coal-steam units in NEEDS v.5.14 in operation in 2013 or earlier (excludes 

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

retirements in 2014 or2015.

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

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

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

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

fossil capacity on-line by the end of 2015. This includes planned new builds already under construction and planned 

retirements. In areas with a dense concentration of facilities, some facilities may be obscured. 

2.2.2 Transmission

Transmission is the term used to describe the 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,3each operating synchronously. Within each of these 

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

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

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

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

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

 

3

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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2.2.3 Distribution

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

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

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

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

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

residences and businesses.

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 

deliver power to consumers. In many states, such efforts have also included separating 

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

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

of service.

2.3 Sales, Expenses and Prices

These electric generating sources provide electricity for commercial, industrial and 

residential ultimate customers. Each of the three major ultimate categories consume roughly a 

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

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

while others are relatively constant, such as industrial processes that operate 24 hours a day.

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

 

4

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

accounts less than one percent of electricity consumption.
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Table 2-4. Total U.S. Electric Power Industry Retail Sales in 2012 (billion kWh)

Source: Table 2.2, EIA Electric Power Annual, 2013

Notes: 

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

and loss of electricity that occurs through transmission and distribution.

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

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

2.3.1 Electricity Prices

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

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

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

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

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

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

that generating stations are increasingly located relatively far from population centers (which 

increase transmission costs). Industrial customers generally pay the lowest average prices, 

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

receive electricity at higher voltages (which makes transmission more efficient and less 

expensive). Industrial customers frequently pay variable prices for electricity, varying by the 

season and time of day, while residential and commercial prices historically have been less 

variable. Overall industrial customer prices are usually considerable closer to the wholesale 

marginal cost of generating electricity than residential and commercial prices.

Sales/Direct Use

(Billion kWh)

Share of Total End 

Use

Sales/Direct 

Use (Billion 

kWh) Share of Total End Use

Residential 1,265 35% 1,375 36%

Commercial 1,104 30% 1,327 35%

Industrial 990 27% 986 26%

Transportation NA 7 0%

Other 106 3% NA

Total 3,465 95% 3,695 96%

166 5% 138 4%

3,632 100% 3,832 100%

2002 2012

Sales

Direct Use

Total End Use
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On a state-by-state basis, all retail electricity prices vary considerably. The Northeast, 

California and Alaska have average retail prices that can be as much as double those of other 

states (see Figure 2-4), and Hawaii has electricity.

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

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

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

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

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

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

Source: EIA AEO 2012, Table 2.4

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

through this period, measured by either the GDP implicit price deflator (23.5 percent) or the 

consumer price index (CPI-U, which increased by 27.7 percent)5. Most of these electricity price 

increases occurred between 2002 and 2008; since 2008 nominal electricity prices have been 

relatively stable while overall inflation continued to increase. The increase in nominal 

electricity prices for the major end use categories, as well as increases in the GDP price and CPIU indices for comparison, are shown in Figure 2-6.

 

5

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

.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Electricity Price (Cent/kWh, nominal $)

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

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

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

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

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

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

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

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

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

 

6

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

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

Categories

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

0

2

4

6

8

10

12

14

16

18

1960 1970 1980 1990 2000 2010

Real Electricity Prices (2011$, ¢ /kWh)

Real Electricity Prices, 1960-2014 (including taxes)

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

Major End-Use Categories

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

2.3.2 Prices of Fossil Fuels Used for Generating Electricity

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

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

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

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

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

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

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

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

all 3 fossil fuels between 2002 and 2012.

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

40%

50%

60%

1960 1970 1980 1990 2000 2010

Change in Real Electricity Prices

Relative Change in Electricity Prices,

1960-2014 (including taxes)

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

Average Real Price per MBtu Delivered to EGU

Source: EIA AEO 2012, Table 9.9

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

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

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

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

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

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

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

Sectors). U.S. Census. 

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

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

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

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

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

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

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

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

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

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

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

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

Since 2002

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

Sectors). U.S. Census

2.4 Deregulation and Restructuring

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

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

management between companies, restructuring sought a functional unbundling of the 

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

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

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

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

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

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

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

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

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

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

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

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

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

the formation of organized wholesale spot energy markets with economic mechanisms for the 
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2-19

rationing of scarce transmission resources during periods of peak demand, the introduction of 

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

coordination.

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

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

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

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

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

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

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

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

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

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

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

activity since that time.

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

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

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

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

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

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

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

state government agencies (e.g., Public Utility Commissions). Deregulation and restructuring 

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

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

a mix of ownership affiliates of traditional utility ownership and some generation owned and 

operated by competitive companies known as Independent Power Producers (IPP). The 

resulting generating sector differed by state or region, as the power sector adapted to the 

restructuring and deregulation requirements in each state. 

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

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

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

35 percent owned by IPPs7, and 3 percent owned by commercial and industrial producers. The 

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

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

commercial/industrial, respectively.

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

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

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

The mix of capacity and generation for each of the ownership types is shown in Figures 

2-13 (capacity) and 2-14 (generation). The capacity and generation data for commercial and 

industrial owners are not shown on these figures due to the small magnitude of those 

ownership types. Figures 2-13 and 2-14 present the mixes in 2002 and 2012. A portion of the 

shift of capacity and generation is due to sales and transfers of generation assets from 

traditional utilities to IPPs, rather than strictly the result of newly built units.

 

7

IPP data presented in this section include both combined and non-combined heat and power plants.
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Figures 2-23 & 2-14. Capacity and Generation Mix by Ownership Type, 2002 & 2012

The mix of capacity by fuel types that have been built and retired between 2002 and 

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

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

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

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

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

natural gas capacity than the utilities retired. The retired gas capacity was primary (60%) steam 

and combustion turbines.

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

2002-

Utility

2012-

Utility

2002-IPP 2012-IPP

Capacity (M

W)

Capacity Mix, 2002 & 2012

Nuclear Coal Gas Hydro Wind All Other

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

2002-

Utility

2012-

Utility

2002-IPP 2012-IPP

Generation (G

W)

Generation Mix, 2002 & 2012

Nuclear Coal Gas Hydro Wind All Other
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Figure 2-15. Domestic Emissions of Greenhouse Gases from Major Sectors, 2002 and 2012

(million metric tonnes of CO2 equivalent)

Source: EPA, 2014 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012”, Table 2-12

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2002 2012

G

H

G Emissions (Million Tonnes)

Electric Power Industry Transportation Industry

Agriculture Commercial Residential
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Figures 2-35 & 2-16. Generation Capacity Built and Retired Between 2002 and 2012 by 

Ownership Type

2.5 Emissions of Greenhouse Gases from Electric Utilities

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

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

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

In 2012, the electricity generation accounted for 38 percent of national CO2 emissions. 

Including both generation and transmission (a source of SF6) and generation, the power sector 

accounted for 31 percent of total nationwide greenhouse gas emissions, measured in CO2

equivalent. Table 2-5 and Figure 2-17 show the CO2 emissions from the power sector relative to 

other major economic sectors. Table 2-6 shows the contributions of CO2 and other GHGs from 

the power and other major emitting economic sectors. 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

Utility IPP

Retired Capacity (M

W) Capacity Retirements 2002-2012

by Ownership Type

Coal Gas Wind & Solar Other

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

Utility IPP

New

Capacity (M

W)

Capacity Built 2002-2012

by Ownership Type

Coal Gas Wind & Solar Other
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Table 2-5. Domestic Emissions of Greenhouse Gases, by Economic Sector (million metric 

tonnes of CO2 equivalent)

2002 2012 Change Between '02 and '12

Sector/Source

GHG 

Emissions

% Total 

GHG 

Emissions

GHG 

Emissions

% Total 

GHG 

Emissions

Change in 

Emissions

% Change 

in 

Emissions

% of Total 

Change in 

Emissions

Electric Power 

Industry 2,313 33% 2,064 32% -249 -11% 48%

Transportation 1,958 28% 1,837 28% -121 -6% 23%

Industry 1,419 20% 1,278 20% -140 -10% 27%

Agriculture 561 8% 614 9% 53 10% -10%

Commercial 365 5% 353 5% -12 -3% 2%

Residential 374 5% 321 5% -53 -14% 10%

US Territories 52 1% 58 1% 6 11% -1%

Total Emissions 7,041 100% 6,526 100% -516 -7% 100%

Sinks and Reductions -885 -979 -94 11%

Net Emissions 6,156 5,546 -610 -10%

Source: EPA, 2014 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012”, Table 2-12. Includes CO2, 

CH4, N2O and SF6 emissions.

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

carbon content and heating value of the fuel used. The CO2 emission factors used in IPM v5.14 

(same as used in v5.13) are shown in Table 2-7. Coal has higher carbon content than oil or 

natural gas, and thus releases more CO2 during combustion. Coal emits around 1.7 times as 

much carbon per unit of energy when burned as natural gas (EPA 2013).
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Table 2-6. Greenhouse Gas Emissions from the Electricity Sector (Generation, 

Transmission and Distribution), 2002 and 2012 (million metric tonnes of CO2 equivalent)

2002 2012

Change Between '02 and '12

Gas/Fuel Type or Source GHG 

Emissions

% of Total 

GHG 

Emissions 

from Power 

Sector

GHG 

Emissions

% of Total 

GHG 

Emissions 

from Power 

Sector

Change in 

Emissions

% Change in 

Emissions

CO2 2,287 98.9% 2,039 98.8% -248 -11%

Fossil Fuel Combustion 2,273 98.2% 2,023 98.0% -250 -11%

Coal 1,890 81.7% 1,511 73.2% -379 -20%

Natural Gas 306 13.22% 492 23.85% 187 61%

Petroleum 76.8 3.32% 18.8 0.91% -58.0 -76%

Geothermal 0.4 0.02% 0.4 0.02% 0.0 0%

Incineration of Waste 11.8 0.51% 12.2 0.59% 0.4 3%

Other Process Uses of 

Carbonates

2.6 0.11% 4.0 0.19% 1.4 54%

CH4 0.4 0.02% 0.5 0.02% 0.1 25%

Stationary 

Combustion*

0.4 0.02% 0.5 0.02% 0.1 25%

Incineration of Waste + + 

N2O 12.4 0.54% 18.6 0.90% 6.2 50%

Stationary 

Combustion*

12.0 0.52% 18.3 0.89% 6.3 53%

Incineration of Waste 0.4 0.02% 0.4 0.02% 0.0 0%

SF6 13.3 0.57% 6.0 0.29% -7.3 -55%

Electrical Transmission 

and Distribution

13.3 0.57% 6.0 0.29% -7.3 -55%

Total GHG Emissions 2,313 2,064 -249 -11%

Source: EPA, 2014 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012”, Table 2-13

* 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.
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Table 2-7. Fossil Fuel Emission Factors in EPA Base Case 5.14 IPM Power Sector Modeling 

Application

Fuel Type Carbon Dioxide (lbs/MMBtu)

Coal 

Bituminous 202.8 – 209.6

Subbituminous 209.2 – 215.8

Lignite 212.6 – 219.

Natural Gas 117.1

Fuel Oil 

Distillate 161.4

Residual 161.4 – 173.9

Biomass 195

Waste Fuels 

Waste Coal 204.7

Petroleum Coke 225.1

Fossil Waste 321.1

Non-Fossil Waste 0

Tires 189.5

Municipal Solid Waste 91.9

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

identical to the emission factors in IPM Base Case 5.13.

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

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

source).

2.6 Carbon Dioxide Control Technologies

In the power sector, current approaches available for significantly reducing the CO2

emissions of new fossil fuel combustion sources intended for intermediate and base load 

operations include the use of: carbon capture and storage (CCS), higher-efficiency designs (e.g., 

supercritical or ultra-supercritical steam units, integrated gasification combined cycle (IGCC), or 

combined cycle combustion turbine/steam-turbine units), and/or lower-emitting fuels (e.g. 

natural gas rather than coal).

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

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

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

started and loaded quickly, and can follow rapid demand changes. Full-load efficiencies of large 
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current technology CTs are typically 30-33 percent but can be has high as 40 percent or more

(high heating value basis), as compared to efficiencies of 50 percent or more for new combinedcycle units that recover and use the exhaust heat otherwise wasted from a CT. A simple-cycle 

CT’s lower efficiency causes it to burn much more fuel to produce a MWh of electricity than a 

combined-cycle unit. Thus, when burning natural gas its CO2 emission rate per MWh could be 

40-60 percent higher than a more efficient NGCC unit. 

Base load electricity demand can be met with NGCC generation, coal and other fossilfired steam generation, and IGCC technology, as well as generation from sources that do not 

emit CO2, such as nuclear and hydro. IGCC employs the use of a gasifier to transform fossil fuels 

into synthesis gas (“syngas”) and heat. The syngas is used to fuel a combined cycle generator, 

and the heat from the syngas conversion can produce steam for the steam turbine portion of 

the combined cycle generator. Electricity can be generated through this IGCC process 

somewhat more efficiently than through conventional boiler-steam generators. Additionally, 

with gasification, some of the syngas can be converted into other marketable products such as 

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

2.6.1 Carbon Capture and Storage

CCS can be achieved through either pre-combustion or post-combustion capture of CO2

from a gas stream associated with the fuel combusted. Furthermore, CCS can be designed and 

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

capture (below 90 percent). 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 is heated to regenerate 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 2-18. For 

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

capture process.
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Figure 2-18. Post-Combustion CO2 Capture for a Pulverized Coal Power Plant

Source: Interagency Task Force on Carbon Capture and Storage 2010

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

converted into gaseous components (“syngas”) under heat and pressure and 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 2-19. Application of post-combustion CCS with IGCC can be designed to use 

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

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

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

detail on CCS technology, see the “Report of the Interagency Task Force on Carbon Capture and 

Storage” (2010).8

 

8

For more information on the cost and performance of CCS, see http://www.netl.doe.gov/energyanalyses/baseline_studies.html.
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Figure 2-19. Pre-Combustion CO2 Capture for an IGCC Power Plant

Source: Interagency Task Force on Carbon Capture and Storage 2010

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

scale industrial facilities and more recently in a number of demonstration phase projects 

worldwide for power sector applications. In October 2014 the first industrial-scale coal-fired

capture and storage demonstration project for electricity generation began operation at the 

Boundary Dam Power Station in Saskatchewan, Canada. The Boundary Dam Station is owned by 

the Province of Saskatchewan, and operated by SaskPower, a provincially owned corporation 

that is the primary electric utility in the Province. The demonstration project retrofit Unit 3 (a 

130 MW, coal fired built in 1970, and rebuilt in 2013) at a total cost of approximately $1.5 

billion (Canadian, or about $1.2 billion US), including a partial subsidy of $240 million 

(Canadian) by the Canadian federal government. The carbon capture system is a postcombustion process designed to capture 90 percent of the CO2 emitted by Unit #3. Retrofitting 

the carbon capture system reduced the capacity of the unit to 110 MW. The majority of the 

captured CO2 is used for an EOR project in southern Saskatchewan. The portion of the CO2 is 

being stored in a nearby research and monitoring geological storage facility, where the 

captured CO2 will be injected 3.4 kilometers underground into a sandstone formation located 
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below the major coal field supplying lignite to Unit # 3. The remaining captured CO2 will be 

injected into deep saline formations.

In the United States the Kemper County Carbon Dioxide Capture and Storage Project in 

Mississippi. Construction began in 2010, and the startup is currently scheduled for May, 2016. 

The Kemper County CCS project is constructing a new 524 MW lignite unit as well as a 58 MW 

natural gas unit. Mississippi Power (a division of Southern Power) is building and will operate 

the Kemper County project. The control system is designed to capture 65 percent of the CO2

generated by the plant, and is projected to capture 3.5 million tons of CO2 per year. The 

resulting CO2 emission rate is expected to be ~800 pounds per MWh produced. The current 

total cost estimate is $5.6 billion, a substantial increase from the original $2.4 billion estimate. 

The construction has received a $270 million grant from the US Department of Energy, and 

$133 million in investment tax credits from the Internal Revenue Service. The captured CO2 will 

be transported via a 60 mile pipeline and used for EOR projects in mature Mississippi oil fields.9

The only other industrial-scale electricity power sector CCS project currently under 

construction is the W.A. Parish Petra Nova CCS Project near Houston, Texas. The Parish Petra 

project is a 50/50 partnership between NRG Energy (an integrated electricity company 

generating and supplying electricity to 1.6 million customers in Texas) and the Nippon Oil and 

Gas Exploration Company. The Parish project will retrofit a post-combustion CCS system on a 

portion of the flue gas from the existing 610 MW coal fired Unit # 8. The CCS system will treat a 

240 MW slipstream of the flue gas, and is designed to capture 90 percent of the CO2 in the 

treated flue gas. The capacity rating of Unit # 8 will not be reduced due to the CCS project 

because an 85 MW custom-built natural gas fired combustion turbine co-generation unit is 

being built on-site to provide both electricity and steam to the CCS unit. The total cost of the 

CCS project is estimated to be $1 billion (including a $167 million grant from the US Department 

of Energy), and is expected to extract 1.4 – 1.6 million tons of CO2 per year. The construction 

contract was awarded in July, 2014, and operation is expected to begin in early 2016. The CO2

will be piped 85 miles to a reservoir for EOR in the West Ranch Oil Field.10

 

9

Carbon Capture and Sequestration Technologies Program at MIT. Accessed 1/23/2015. 

https://sequestration.mit.edu/tools/projects/kemper.html

10 US DOE (2010) “Recovery Act: W.A. Parish Post-Combustion CO2 Capture and Sequestration Project”. 

http://www.netl.doe.gov/research/proj?k=FE0003311 Accessed 1/23/2015
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2.7 Geologic and Geographic Considerations for Geologic Sequestration

Geologic sequestration (GS) (i.e., long-term containment of a CO2 stream in subsurface 

geologic formations) is technically feasible and available throughout most of the United States. 

GS is feasible in different types of geologic formations including deep saline formations 

(formations with high salinity formation fluids) or in oil and gas formations, such as where 

injected CO2 increases oil production efficiency through a process referred to as enhanced oil 

recovery (EOR). CO2 may also be used for other types of enhanced recovery, such as for natural 

gas production. Reservoirs, such as unmineable coal seams, also offer the potential for geologic 

storage. The geographic availability of deep saline formations, EOR, and unmineable coal seams 

is shown in Figure 2-20. Estimates of CO2 storage resources by state compiled by the DOE’s 

National Carbon Sequestration Database and Geographic Information System (NATCARB) and 

published in a Carbon Utilization and Storage Atlas (discussed below) are provided in Table 2-8.
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Figure 2-20 Geologic Sequestration in the Continental United States

Sources: EPA Greenhouse Gas Reporting Program; Department of Energy, NATCARB; Department of 

Transportation, National Pipeline Management System.
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Table 2-8. Total CO2 Storage Resource (DOE-NETL)

11

Million Metric Tons*

State Low Estimate High Estimate

ALABAMA 122,490 694,380

ALASKA 8,640 19,750

ARIZONA 130 1,170

ARKANSAS 6,180 63,670

CALIFORNIA 33,890 420,630

COLORADO 37,610 357,190

CONNECTICUT not assessed by DOE-NETL not assessed by DOE-NETL

DELAWARE 40 40

DISTRICT OF COLUMBIA not assessed by DOE-NETL not assessed by DOE-NETL

FLORIDA 102,740 555,010

GEORGIA 145,340 159,050

HAWAII not assessed by DOE-NETL not assessed by DOE-NETL

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 not assessed by DOE-NETL not assessed by DOE-NETL

MARYLAND 1,860 1,930

MASSACHUSETTS not assessed by DOE-NETL not assessed by DOE-NETL

 

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

Fossil Energy, National Energy Technology Laboratory (NETL).
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Table 2-8. Total CO2 Storage Resource (DOE-NETL), cont.

Million Metric Tons*

State Low Estimate High Estimate

MICHIGAN 19,050 47,210

MINNESOTA not assessed by DOE-NETL not assessed by DOE-NETL

MISSISSIPPI 145,010 1,185,030

MISSOURI 10 170

MONTANA 84,580 912,720

NEBRASKA 23,770 113,240

NEVADA not assessed by DOE-NETL not assessed by DOE-NETL

NEW HAMPSHIRE not assessed by DOE-NETL not assessed by DOE-NETL

NEW JERSEY 0 0

NEW MEXICO 42,760 359,090

NEW YORK 4,640 4,640

NORTH CAROLINA 1,340 18,390

NORTH DAKOTA 67,090 147,480

Offshore Federal Only 489,840 6,440,090

OHIO 13,460 13,460

OKLAHOMA 56,950 244,550

OREGON 6,810 93,700

PENNSYLVANIA 22,100 22,100

RHODE ISLAND not assessed by DOE-NETL not assessed by DOE-NETL

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 not assessed by DOE-NETL not assessed by DOE-NETL

VIRGINIA 440 2,910

WASHINGTON 36,620 496,730

WEST VIRGINIA 16,650 16,650

WISCONSIN 0 0

WYOMING 72,690 684,850

U.S. Total 2,296,680 20,092,180

* States with a “zero” value represent estimates of minimal CO2 storage resource. States that 

have not yet been assessed by DOE-NETL have been identified.
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2.7.2 Availability of geologic sequestration in deep saline formations

DOE and the United States Geological Survey (USGS) have independently conducted 

preliminary analyses of the availability and potential CO2 sequestration capacity of deep saline 

formations in the United States. DOE estimates are compiled by the DOE’s National Carbon 

Sequestration Database and Geographic Information System (NATCARB) using volumetric 

models and published in a Carbon Utilization and Storage Atlas.

12 DOE estimates that areas of 

the United States with appropriate geology have a sequestration potential of at least 2,035 

billion metric tons of CO2 in deep saline formations. According to DOE and at least 39 states 

have geologic characteristics that are amenable to deep saline GS in either onshore or offshore 

locations. In 2013, the USGS completed its evaluation of the technically accessible GS resources 

for CO2 in U.S. onshore areas and state waters using probabilistic assessment.13 The USGS 

estimates a mean of 3,000 billion metric tons of subsurface CO2 sequestration potential, 

including saline and oil and gas reservoirs, across the basins studied in the United States. As 

shown in Figure 2-20, there are 39 states for which onshore and offshore deep saline formation 

storage capacity has been identified.

14

 

2.7.3 Availability of CO2 storage via enhanced oil recovery (EOR)

Although the regulatory impact analysis for this rule relies on GS in deep saline 

formations, the EPA also recognizes the potential for securely sequestering CO2 via EOR. EOR 

has been successfully used at numerous production fields throughout the United States to 

increase oil recovery. The oil industry in the United States has over 40 years of experience with 

EOR. An oil industry study in 2014 identified more than 125 EOR projects in 98 fields in the 

United States.15 More than half of the projects evaluated in the study have been in operation 

for more than 10 years, and many have been in operation for more than 30 years. This 

experience provides a strong foundation for demonstrating successful CO2 injection and 

monitoring technologies, which are needed for safe and secure GS that can be used for 

deployment of CCS across geographically diverse areas.

 

12 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).

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

of geologic carbon dioxide storage resources—Results: U.S. Geological Survey Circular 1386, p. 41, 

http://pubs.usgs.gov/circ/1386/.

14 Alaska is not shown in the figure; it has deep saline formation storage capacity, geology amenable to EOR 

operations, and potential GS capacity in unmineable coal.

15 Koottungal, Leena, 2014, 2014 Worldwide EOR Survey, Oil & Gas Journal, Volume 112, Issue 4, April 7, 2014 

(corrected tables appear in Volume 112, Issue 5, May 5, 2014).
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Currently, 12 states have active EOR operations and most have developed an extensive 

CO2 infrastructure, including pipelines, to support the continued operation and growth of EOR. 

An additional 23 states are within 150 miles of current EOR operations. See Figure 2-20. The 

vast majority of EOR is conducted in oil reservoirs in the Permian Basin, which extends through 

southwest Texas and southeast New Mexico. States where EOR is utilized include Alabama, 

Colorado, Louisiana, Michigan, Mississippi, New Mexico, Oklahoma, Texas, Utah, and Wyoming. 

At the project level, the volume of CO2 already injected for EOR and the duration of 

operations are of similar magnitude to the duration and volume of CO2 expected to be captured 

from fossil fuel-fired EGUs. The volume of CO2 used in EOR operations can be large (e.g., 55 

million tons of CO2 were stored in the SACROC unit in the Permian Basin over 35 years), and 

operations at a single oil field may last for decades, injecting into multiple parts of the field.16 

According to data reported to the EPA’s Greenhouse Gas Reporting Program (GHGRP), 

approximately 60 million metric tons of CO2 were supplied to EOR in the United States in 

2013.17 Approximately 70 percent of this total CO2 supplied was produced from natural 

(geologic) CO2 sources, and approximately 30 percent was captured from anthropogenic 

sources.18

A DOE-sponsored study has analyzed the geographic availability of applying EOR in 11 

major oil producing regions of the United States and found that there is an opportunity to 

significantly increase the application of EOR to areas outside of current operations.19 DOEsponsored geologic and engineering analyses show that expanding EOR operations into areas 

additional to the capacity already identified and applying new methods and techniques over the 

next 20 years could utilize 18 billion metric tons of anthropogenic CO2 and increase total oil 

production by 67 billion barrels. The availability of anthropogenic CO2 in areas outside of 

current sources could drive new EOR projects by making more CO2 locally available.

 

16 Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F P. “Evaluation of CO2 trapping mechanisms at the 

SACROC northern platform, Permian basin, Texas, site of 35 years of CO2 injection.” American Journal of 

Science 310. (2010): 282-324.

17 Greenhouse Gas Reporting Program, data reported as of August 18, 2014.

18 Greenhouse Gas Reporting Program, data reported as of August 18, 2014.

19 “Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil 

Recovery”, Advanced Resources International, Inc. (ARI), 2011. Available at: 

http://www.netl.doe.gov/research/energy-analysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-

04a505a19185.
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2.8 GHG and Clean Energy Regulation in the Power Sector

2.8.1 State Policies

Several states have also established emission performance standards or other measures 

to limit emissions of GHGs from new EGUs that are comparable to this rulemaking. 

In 2003, then-Governor George Pataki sent a letter to his counterparts in the Northeast 

and Mid-Atlantic inviting them to participate in the development of a regional cap-and-trade 

program addressing power plant CO2 emissions. This program, known as the Regional 

Greenhouse Gas Initiative (RGGI), began in 2009 and sets a regional CO2 cap for participating 

states. The currently participating states include: Connecticut, Delaware, Maine, Maryland, 

Massachusetts, New Hampshire, New York, Rhode Island, and Vermont. The cap covers CO2

emissions from all fossil-fired EGUs greater than 25 MW in participating states, and limits total 

emissions to 91 million short tons in 2014. The 2014 emissions cap is a 51 percent reduction 

below the initial cap in 2009 to 2011 of 188 million tons. This emissions budget is reduced 2.5

percent annually from 2015 to 2020. RGGI CO2 allowances are sold in a quarterly auction. RGGI 

conducted their 27th quarterly allowance auction in March, 2015 the market clearing price was 

$5.41 per ton of CO2 for current allowances, which was a record high price (the February ’15 

price of $5.21 was the previous record). A total of allowances for 15.3 million tons were sold in 

the March ’15 auction, well below the record of 38.7 million tons sold in June ’13 for $3.21

In September 2006, California Governor Schwarzenegger signed into law Senate Bill 

1368. The law limits long-term investments in baseload generation by the state's utilities to 

power plants that meet an emissions performance standard jointly established by the California 

Energy Commission and the California Public Utilities Commission. The Energy Commission has 

designed regulations that establish a standard for new and existing baseload generation owned 

by, or under long-term contract to publicly owned utilities, of 1,100 lb CO2/MWh.

In 2006 Governor Schwarzenegger also signed into law Assembly Bill 32, the Global 

Warming Solutions Act of 2006. This act includes a multi-sector GHG cap-and-trade program 

which covers approximately 85 percent 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. The AB32 cap and trade 

program began functioning in 2011, and functioning market is now operating on the NYMEX 

futures commodity market. The final 2014 market price for 2014 carbon allowances was 
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$12.38/tonne of carbon. On April 17, 2015 the 2015 allowance futures price was $12.65/tonne, 

and the spot price was $12.46/tonne.

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: base load 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.20 These programs vary widely in structure, enforcement, and scope. 

2.8.2 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 

 

20 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 (best 

available control technology) limit in light of the ‘subject to regulation’ definition under the 

CAA.” The remand was based in part on EAB’s finding that there was not an established EPA 

interpretation of the regulatory phrase “subject to regulation.” 

In December 2008, the Administrator issued a memo indicating that the PSD Permitting 

Program would apply to pollutants that are subject to either a provision in the CAA or a 

regulation adopted by the EPA under the CAA that requires actual control of emissions of that 

pollutant. The memo further explained that pollutants for which the EPA regulations only 

require monitoring or reporting, such as the provisions for CO2 in the Acid Rain Program, are 

not subject to PSD permitting. Fifteen organizations petitioned the EPA for reconsideration, 

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

EPA affirmed the position that PSD permitting is not triggered for a pollutant such as GHGs until 

a final nationwide rule requires actual control of emissions of the pollutant. For GHGs, this 

meant January 2011 when the first national rule limiting GHG emissions for cars and light trucks 

was scheduled to take effect. Therefore, a permit issued after January 2, 2011, would have to 

address GHG emissions.
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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 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 a proposed settlement agreement in December 2010 to issue rules 

that will address greenhouse gas emissions from fossil fuel-fired power plants. On March 27, 

2012, EPA proposed NSPS for CO2 emissions from new source natural gas, coal, and other solid 
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fossil-fired EGUs. After consideration of information provided in more than 2.7 million 

comments on the March 27, 2012 proposal, as well as consideration of continuing changes in 

the electricity sector, the EPA determined that revisions in its initially proposed approach were 

warranted. EPA replaced that prior proposal with a new proposal for NSPS for CO2 emissions 

from EGUs on September 20, 2013; this action finalizes that rulemaking. Existing source 

standards are not addressed in this action. Details of the settlement agreement can be found 

on the EPA website.21

2.9 Revenues and Expenses

Due to lower retail electricity sales, total utility operating revenues declined in 2012 to 

$271 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008 

levels in 2012, operating expenses were appreciably lower and as a result, net income also rose 

in comparison to 2008 (see Table 2-9). Recent economic events have put downward pressure 

on electricity demand, thus dampening electricity prices and consumption (utility revenues), 

but have also reduced the price and cost of fossil fuels and other expenses. In 2012 electricity 

generation was 1.28 percent below the generation in 2011, and has declined in 4 of the past 5 

years.

Table 2-9 shows that investor-owned utilities (IOUs) earned income of about 13.0 

percent compared to total revenues in 2012. The 2012 return on revenue was the third highest 

year for the period 2002 to 2012 (average: 11.9 percent range: 10.6 percent to 13.32 percent).

 

21 http://www.epa.gov/airquality/ghgsettlement.html
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Table 2-9. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities 

for 2010 (nominal $millions) 

2002 2008 2012

Utility Operating Revenues 219,609 298,962 270,912

Electric Utility 200,360 266,124 249,166

Other Utility 19,250 32,838 21,745

Utility Operating Expenses 189,062 267,263 235,694

Electric Utility 171,604 236,572 220,722

Operation 116,660 175,887 152,379

Production 90,715 140,974 111,714

Cost of Fuel 24,149 47,337 38,998

Purchased Power 58,810 84,724 54,570

Other 7,776 8,937 18,146

Transmission 3,560 6,950 7,183

Distribution 3,117 3,997 4,181

Customer Accounts 4,168 5,286 5,086

Customer Service 1,820 3,567 5,640

Sales 264 225 221

Admin. and 

General

13,018 14,718 18,353

Maintenance 10,861 14,192 15,489

Depreciation 16,199 19,049 23,677

Taxes and Other 26,716 26,202 29,177

 Other Utility 17,457 30,692 14,972

Net Utility Operating Income 30,548 31,699 35,218

Source: Table 8.3, EIA Electric Power Annual, 2012

Note: This data does not include information for public utilities, nor for Independent Power Producers (IPPs).

2.10 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, can undergo major price swings 

during short-lived weather events (such as cold snaps leading to short-run spikes in heating 

demand), and has seen a dramatic shift since 2008 due increased production from shale 

formations . Over the last decade, the annual average nominal price of gas delivered to the 

power sector peaked in 2008 at $9.02/mmBtu and has since fallen dramatically to a low of 
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$3.42/mmBtu in 2012. During that time, the daily price22 of natural gas reached as high as 

$18.48/mmBtu and as low as $2.03. Adjusting for inflation using the GDP implicit price 

deflator, in $2011 the annual average price of natural gas delivered to the power sector ranged 

peaked at $9.38/mmBtu in 2008 and have fallen dramatically to a low of $3.36 in 2012. The 

annual natural gas prices in both nominal and real (2011$) terms are in Figure 2-21. A 

comparison of the trends in the real price of natural gas with the real price of delivered coal 

and oil are shown in Figure 2-22. Figure 16 shows that while the real price of coal and oil 

increased from 2002 to 2012 (+54 percent and +203 percent respectively), the real price of 

natural gas declined by 22 percent in the same period. Most of the decline in real natural gas 

prices occurred between 2008 (the peak price year) and 2012, during which real gas prices 

declined by 64 percent while coal and oil prices both increased by 9 percent. The sharp decline 

in natural gas prices from 2008 to 2012 was primarily caused by the rapid increase in natural 

gas production from shale formations.

Figure 2-21. Nominal and Real (2011$) Prices of Natural Gas Delivered to the Power Sector 

($/mmBtu)

Source: http://www.eia.gov/totalenergy/data/monthly/#prices. Downloaded 2/15/2015.

 

22 Henry Hub daily prices. Henry Hub is a major gas distribution hub in Louisiana; Henry Hub prices are generally 

seen as the primary metric for national gas prices for all end uses. 

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

2002 2004 2006 2008 2010 2012

Natural Gas Prices ($/m

mBT

U)

Nominal Price Real Price
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Figure 2-22. Relative Change in Real (2011$) Prices of Fossil Fuels Delivered to the Power 

Sector ($/mmBtu)

Source: http://www.eia.gov/totalenergy/data/monthly/#prices. Downloaded 2/15/2015.

Current and projected natural gas prices are considerably lower than the prices 

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

drilling techniques that have opened up new shale gas resources and substantially increased 

the supply of economically recoverable natural gas. According to AEO 2012 (EIA 2012):

Shale gas refers to natural gas that is trapped within shale formations. Shales are finegrained sedimentary rocks that can be rich sources of petroleum and natural gas. Over 

the past decade, the combination of horizontal drilling and hydraulic fracturing has 

allowed access to large volumes of shale gas that were previously uneconomical to 

produce. The production of natural gas from shale formations has rejuvenated the 

natural gas industry in the United States.

The U.S. Energy Information Administration's Annual Energy Outlook 2014 estimates 

that the United States possessed 2,266 trillion cubic feet (Tcf) of technically recoverable dry 

natural gas resources as of January 1, 2012. Proven reserves make up 15 percent of the 

technically recoverable total estimate, with the remaining 85 percent from unproven reserves. 

-50%

0%

50%

100%

150%

200%

250%

2002 2004 2006 2008 2010 2012

Coal Oil Gas Average
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Natural gas from proven and unproven shale resources accounts for 611 Tcf of this resource 

estimate. 

Many shale formations, especially the Marcellus23, are so large that only small portions 

of the entire formations have been intensively production-tested. Furthermore, estimates from 

the Marcellus and other emerging fields with few wells already drilled are likely to shift 

significantly over time as new geological and production information becomes available. 

Consequently, the estimate of technically recoverable resources is highly uncertain, and is 

regularly updated as more information is gained through drilling and production. 

At the 2012 rate of U.S. consumption (about 25.6 Tcf per year), 2,266 Tcf of natural gas 

is enough to supply nearly 90 years of use. The AEO 2014 estimate of the shale gas resource 

base is modestly higher than the AEO 2012 estimate (2,214 Tcf) shale gas production estimates, 

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

EIA’s projections of natural gas conditions did not change substantially in AEO 2014 

from either the AEO 2012 or 2013, 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 2014 being the highest year on record25 for domestic natural gas production.26

 

23 The Marcellus formation, underlying most of Pennsylvania and West Virginia, along with portions of New York 

and Ohio, in 2014 produced 36% of the U.S. total natural gas extracted from shale formations.

24 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

25 The total dry gas production in 2012 from the lower 48 states, including both onshore and offshore production, 

was 23.97 Tcf, a 1.5% increase from 2013 and a 7.9% total increase from 2011

26 http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2014&subject=8-AEO2014&table=72-

AEO2014®ion=0-0&cases=ref2014-d102413a
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2.11 References

Advanced Resources International. Improving Domestic Energy Security and Lowering CO2

Emissions with “Next Generation” CO2-Enhanced Oil Recovery (CO2-EOR). 2011. Available 

online at: http://www.netl.doe.gov/research/energyanalysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-04a505a19185.

Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F P. Evaluation of CO2 trapping 

mechanisms at the SACROC northern platform, Permian basin, Texas, site of 35 years of 

CO2 injection. American Journal of Science 310. (2010): 282-324.

Interagency Task Force on Carbon Capture and Storage. Report of the Interagency Task Force on 

Carbon Capture and Storage. August 2010. Available online at: 

http://www.epa.gov/climatechange/downloads/CCS-Task-Force-Report-2010.pdf. 

Intergovernmental Panel on Climate Change. Climate Change 2001: The Scientific Basis. 2001. 

Available online at: 

http://www.grida.no/publications/other/ipcc_tar/?src=/climate/ipcc_tar/wg1/218.htm. 

International Energy Agency (IEA). Tracking Clean Energy Progress 2013. Input to the Clean 

Energy Ministerial. 2013. Available online at: http://www.iea.org/etp/tracking/.

Koottungal, Leena. 2014 Worldwide EOR Survey, Oil & Gas Journal, Volume 112, Issue 4, April 7, 

2014 (corrected tables appear in Volume 112, Issue 5, May 5, 2014).

National Energy Technology Laboratory (NETL). Reducing CO2 Emissions by Improving the 

Efficiency of Existing Coal-fired Power Plant Fleet. July 2008. Available online at: 

http://www.netl.doe.gov/energy-analyses/pubs/CFPP%20Efficiency-FINAL.pdf.

National Energy Technology Laboratory (NETL). The United States 2012 Carbon Utilization and 

Storage Atlas, Fourth Edition. 2012. Available online at: 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlasIV/.

National Energy Technology Laboratory (NETL). Energy Analyses: Cost and Performance

Baselines for Fossil Energy Plants. 2013. Available online at: 

http://www.netl.doe.gov/energy-analyses/baseline_studies.html.

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.
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2-47

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

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

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

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

U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2011. 2013. Available 

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

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

2010a. Available online at: 

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

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

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

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

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

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

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

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

online at: http://www.eia.gov/forecasts/archive/aeo11/. 

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2012 (Early Release). 

2012. Available online at: http://www.eia.gov/forecasts/aeo/.

U.S. Energy Information Administration (U.S. EIA). Today in Energy: Most states have 

Renewable Portfolio Standards. 2012a. Available online at: 

http://www.eia.gov/todayinenergy/detail.cfm?id=4850.

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available 

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

U.S. Energy Information Administration (U.S. EIA). Monthly Energy Review, April 2015. 2015. 

Available online at: http://www.eia.gov/totalenergy/data/monthly/.

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

and Sinks: 1990–2011. April 2013. Available online at: 

http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-

Main-Text.pdf.

U.S. Geological Survey (USGS) Carbon Dioxide Storage Resources Assessment Team. National 

assessment of geologic carbon dioxide storage resources – Results: U.S. Geological Survey 

Circular 1386. Available online at: http://pubs.usgs.gov/circ/1386/.
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3-1

CHAPTER 3

BENEFITS OF REDUCING GREENHOUSE GAS EMISSIONS AND OTHER POLLUTANTS

This rule is designed to set emission limits for carbon dioxide (CO2),thereby limiting 

potential increases in future emissions and CO2 concentrations. This will reduce the risk of some 

adverse effects of climate change. As discussed in Chapter 5, the U.S. Environmental Protection 

Agency (EPA) does not anticipate any notable CO2 emission changes resulting from the rule. 

Rather, by clarifying that in the future new coal-fired power plants will be required to meet a 

particular performance standard, this rulemaking reduces uncertainty and may enhance the 

prospects for the deployment of carbon capture and storage (CCS). 

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. A 

discussion of climate science findings from newer assessments can be found in the Preamble. 

This chapter also provides a general discussion about how the climate-related and human 

health benefits of emissions reductions are estimated. These valuation approaches are used in 

Chapter 5 to assess the relative differences in emissions between newly built electric 

generating technologies.

3.1 Overview of Climate Change Impacts from GHG Emissions

Through the implementation of CAA regulations, the EPA addresses the negative 

externalities caused by air pollution. 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. The preamble summarizes the public 

health and public welfare impacts that were detailed in the 2009 Endangerment Finding. For 

health, these include the increased likelihood of heat waves, negative impacts on air quality, 

more intense hurricanes, more frequent and intense storms and heavy precipitation, and 

impacts on infectious and waterborne diseases. For welfare, these include reduced water 

supplies in some regions, increased water pollution, increased occurrences of floods and 

 

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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3-2

droughts, rising sea levels and damage to coastal infrastructure, increased peak electricity 

demand, changes in ecosystems, and impacts on indigenous communities. 

The preamble also summarizes new scientific assessments and recent climatic 

observations. Major scientific assessments released since the 2009 Endangerment Finding have 

improved scientific understanding of the climate, and provide even more evidence that GHG 

emissions endanger public health and welfare for current and future generations. The National 

Climate Assessment (NCA3), in particular, assessed the impacts of climate change on human 

health in the United States, finding that, Americans will be impacted by “increased extreme 

weather events, wildfire, decreased air quality, threats to mental health, and illnesses 

transmitted by food, water, and disease-carriers such as mosquitoes and ticks.” These 

assessments also detail the risks to vulnerable groups such as children, the elderly and low 

income households. Furthermore, the assessments present an improved understanding of the 

impacts of climate change on public welfare, higher projections of future sea level rise than had 

been previously estimated, a better understanding of how the warmth in the next century may 

reach levels that would be unprecedented relative to the preceding millions of years of history, 

and new assessments of the impacts of climate change on permafrost and ocean acidification. 

The impacts of GHG emissions will be realized worldwide, independent upon their location of 

origin, and impacts outside of the United States will produce consequences relevant to the 

United States. 

3.2 Social Cost of Carbon

The social cost of carbon (SC-CO2) is a metric that estimates the monetary value of 

impacts associated with marginal changes in CO2 emissions in a given year. It includes a wide 

range of anticipated climate impacts, such as net changes in agricultural productivity and 

human health, property damage from increased flood risk, and changes in energy system costs,

such as reduced costs for heating and increased costs for air conditioning. It is typically used to 

assess the avoided damages as a result of regulatory actions (i.e., benefits of rulemakings that 

lead to an incremental reduction in cumulative global CO2 emissions). This section discusses the 

development of the SC-CO2 estimates and the Chapter 5 analysis applies the SC-CO2 estimates 

to illustrate the value to society of the difference in CO2 emissions among different generation 

technologies. 

The SC-CO2 estimates used in this analysis were developed over many years, using the 

best science available, and with input from the public. Specifically, an interagency working 

group (IWG) that included the EPA and other executive branch agencies and offices used three 
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3-3

integrated assessment models (IAMs) to develop the SC-CO2 estimates and recommended four 

global values for use in regulatory analyses. The SC-CO2 estimates were first released in 

February 2010 and updated in 2013 using new versions of each IAM. These estimates were 

published in the 2013 Technical Support Document: Technical Update of the Social Cost of 

Carbon for Regulatory Impact Analysis Under Executive Order 12866 (2013 SC-CO2 TSD) and 

henceforth we refer to them as the “SC-CO2 estimates.” 

The SC-CO2 estimates were developed using an ensemble of the three most widely cited 

integrated assessment models in the economics literature with the ability to estimate the SCCO2. A key objective of the IWG was to draw from the insights of the three models while 

respecting the different approaches to linking GHG emissions and monetized damages taken by 

modelers in the published literature. After conducting an extensive literature review, the 

interagency group selected three sets of input parameters (climate sensitivity, socioeconomic 

and emissions trajectories, and discount rates) to use consistently in each model. All other 

model features were left unchanged, relying on the model developers’ best estimates and 

judgments, as informed by the literature. Specifically, a common probability distribution for the 

equilibrium climate sensitivity parameter, which informs the strength of climate’s response to 

atmospheric GHG concentrations, was used across all three models. In addition, a common 

range of scenarios for the socioeconomic parameters and emissions forecasts were used in all 

three models. Finally, the marginal damage estimates from the three models were estimated 

using a consistent range of discount rates, 2.5, 3.0, and 5.0 percent. See the 2010 SC-CO2 TSD 

for a complete discussion of the methods used to develop the estimates and the key 

uncertainties, and the 2013 SC-CO2 TSD for the updated estimates. 

The SC-CO2 estimates represent global measures because of the distinctive nature of the 

climate change, which is highly unusual in at least three respects. First, emissions of most GHGs 

contribute to damages around the world independent of the country in which they are emitted. 

The SC-CO2 must therefore incorporate the full (global) damages caused by GHG emissions to 

address the global nature of the problem. Second, the U.S. operates in a global and highly 

interconnected economy, such that impacts on the other side of the world can affect our 

economy. Damages from climate change in other countries can affect U.S. companies and 

citizens, and conflict exacerbated by climate change can require military expenditures by the 

U.S. This means that the true costs of climate change to the U.S. are larger than the direct 

impacts that simply occur within the U.S. Third, climate change represents a classic public goods

problem, but one that the United States cannot solve alone. A global estimate of the SC-CO2 is 
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therefore the economically appropriate reference point for collective actions to reduce climate 

change.

With the release of the 2010 SC-CO2 estimates the IWG noted that there remained a 

number of limitations to the analysis and committed to updating the estimates as the science 

and economic understanding of climate change and its impacts on society improves over time. 

In particular, a goal was set to revisit the SC-CO2 estimates “within two years or at such time as 

substantially updated models become available.” Subsequent to the release of the 2010 TSD, all 

three of the models used in the development of the SC-CO2 estimates were updated by their 

(academic) developers, in part, to reflect more recent information on the potential impacts of 

climate change. Therefore, in 2013 the IWG released an update to the SC-CO2 estimates that 

maintained the same methodology underpinning the previous estimates, but applied the most 

current versions of the three IAMs. The 2013 process did not revisit the 2010 interagency 

modeling decisions (e.g., with regard to the discount rate, reference case socioeconomic and 

emission scenarios or equilibrium climate sensitivity). Rather, improvements in the way 

damages are modeled are confined to those that have been incorporated into the latest 

versions of the models by the developers themselves and used in peer-reviewed publications. 

The model updates reflected in the 2013 SC-CO2 estimates include: an explicit 

representation of sea level rise damages in the DICE and 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 FUND model. The 2013 SC-CO2 TSD 

provides additional detail on the specific model improvements and the updated estimates. 

When attempting to assess the incremental economic impacts of CO2 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. As a result, any effort to quantify and monetize the harms associated with climate 

change will raise serious questions of science, economics, and ethics and should be viewed as 

provisional. 
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The 2010 SC-CO2 TSD noted a number of limitations to the SC-CO2 analysis, including the 

incomplete way in which the integrated assessment models capture catastrophic and noncatastrophic impacts, their incomplete treatment of adaptation and technological change, 

uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding 

risk aversion. Current integrated assessment models do not assign value to all of the important 

physical, ecological, and economic impacts of climate change recognized in the climate change 

literature due to a lack of precise information on the nature of damages and because the 

science incorporated into these models understandably lags behind the most recent research. 

The limited amount of research linking climate impacts to economic damages makes the 

modeling exercise even more difficult. These individual limitations do not all work in the same 

direction in terms of their influence on the SC-CO2 estimates, though taken together they 

suggest that the SC-CO2 estimates are likely conservative. In particular, the IPCC Fourth 

Assessment Report (2007), which was the most current IPCC assessment available at the time 

of the IWG’s 2009-2010 review, concluded that “It is very likely that [SC-CO2 estimates] 

underestimate the damage costs because they cannot include many non-quantifiable impacts.” 

Since then, the peer-reviewed literature has continued to support this conclusion. For example, 

the IPCC Fifth Assessment report observed that SCC estimates continue to omit various impacts 

that would likely increase damages. The 95th percentile estimate was included in the 

recommended range for regulatory impact analysis to address these concerns.

Nonetheless, these estimates and the discussion of their limitations represent the best 

available information about the social benefits of CO2 reductions to inform benefit-cost 

analysis. The new versions of the models used to estimate the values presented below offer 

some improvements in these areas, although 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. The EPA and other 

federal agencies have considered the extensive public comments on ways to improve SC-CO2 

estimation received via the notice and comment periods that were part of numerous 

rulemakings. In addition, OMB’s Office of Information and Regulatory Affairs sought public 

comment on the approach used to develop the SC-CO2 estimates. The comment period ended 

on February 26, 2014, and OMB is reviewing the comments received.
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The four SC-CO2 estimates, updated in 2013, are as follows: $14, $47, $70, and $140 per 

metric ton of CO2 emissions in the year 2022 (2011$).2 The first three values are based on the 

average SC-CO2 from the three IAMs, at discount rates of 5, 3, and 2.5 percent, respectively. SCCO2 estimates for several discount rates are included because the literature shows that the SCCO2 is quite sensitive to assumptions about the discount rate, and because no consensus exists 

on the appropriate rate to use in an intergenerational context (where costs and benefits are 

incurred by different generations). The fourth value is the 95th percentile of the SC-CO2 from all 

three models at a 3 percent discount rate. It is included to represent higher-than-expected 

impacts from temperature change further out in the tails of the SC-CO2 distribution 

(representing less likely, but potentially catastrophic, outcomes).

Table 3-1 presents the updated global SC-CO2 estimates for the years 2015 to 2050. In 

order to calculate the dollar value for emission reductions, the SC-CO2 estimate for each 

emissions year would be applied to changes in CO2 emissions for that year, and then discounted 

back to the analysis year using the same discount rate used to estimate the SC-CO2. The SC-CO2

increases over time because future emissions are expected to produce larger incremental 

damages as physical and economic systems become more stressed in response to greater 

climate change. Note that the interagency group estimated the growth rate of the SC-CO2

directly using the three integrated assessment models rather than assuming a constant annual 

growth rate. This helps to ensure that the estimates are internally consistent with other 

modeling assumptions. 

 

2

The SC-CO2 values have been rounded to two significant digits. Unrounded numbers from the 2013 SC-CO2 TSD 

were adjusted to 2011$ and used in the Chapter 5 illustrative analysis.
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Table 3-1. Global Social Cost of CO2, 2015-2050a(in 2011$)

Year

Discount Rate and Statistic

5% Average 3% Average 2.5% Average 3%

95th percentile

2015 $12 $39 $61 $120

2020 $13 $46 $68 $140

2022 $14 $47 $70 $140

2025 $15 $50 $74 $150

2030 $17 $55 $80 $170

2035 $20 $60 $85 $190

2040 $22 $65 $92 $200

2045 $26 $70 $98 $220

2050 $28 $76 $100 $230

a

The SC-CO2 values vary depending on the year of CO2 emissions and are defined in real terms. These SC-CO2

values are stated in $/metric ton. Unrounded numbers from the 2013 SC-CO2 TSD were adjusted to 2011$ and 

used in the illustrative analysis in Chapter 5.

3.3 Health Co-Benefits of SO2 and NOx Reductions 

The EPA anticipates that this rule will result in negligible emission changes by 2022.

However, if CO2 emissions are reduced from new EGUs under this rule, then emissions of other 

pollutants from the power sector would also likely be reduced. For example, reducing CO2

emissions through the adoption of CCS from coal-fired boilers may also yield sulfur dioxide 

(SO2) and nitrogen oxide (NOX) emission reductions, which in turn would yield health benefits 

(we refer to these additional benefits as “co-benefits”). 

SO2 is a precursor for fine particulate matter formation, which is particulate matter 2.5 

micrometers in diameter and smaller (PM2.5), while NOX is a precursor for PM2.5 and groundlevel ozone formation. As such, reductions of SO2 and NOX would in turn lower overall ambient 

concentrations of PM2.5 and ozone. Reducing exposure to PM2.5 and ozone is associated with 

human health benefits including avoided mortality and morbidity. Researchers have associated 

PM2.5 and ozone exposure with adverse health effects in numerous toxicological, clinical, and 

epidemiological studies (U.S. EPA, 2009; U.S. EPA, 2013a). Health effects associated with 

exposure to PM2.5 include premature mortality for adults and infants, cardiovascular morbidity 

such as heart attacks and hospital admissions, and respiratory morbidity such as asthma 

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 
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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). 

The avoided incidences of health effects and monetized value of health or non-health 

improvements that result from SO2 and NOx emissions reductions depend on the location of 

those reductions. For a full discussion of the human health, ecosystem and other benefits of 

reducing SO2 and NOX emissions from power sector sources, please refer to the Regulatory 

Impact Analysis for the Final Carbon Pollution Guidelines for Existing Power Plants (U.S. EPA, 

2015).

The EPA anticipates that this rule will result in negligible emission changes by 2022. As a 

result we did not perform a full health co-benefit impact assessment for a specific modeled 

compliance scenario. In Chapter 5, EPA presents results for several illustrative analyses that 

show the potential impacts of the rule if certain key assumptions were to change. When 

assessing the co-benefits of differences in emissions from different generation technologies in 

Chapter 5, the EPA does not assert a specific location for the illustrative new unit.3Instead, the 

EPA relied on a national-average benefit per-ton (BPT) method to estimate PM2.5-related health 

impacts of SO2 and NOX emissions. The BPT approach provides an estimate of the total 

monetized human health benefits (the sum of premature mortality and morbidity) of reducing 

one ton of PM2.5 precursor (i.e., NOX and SO2) from the sector. To develop the BPT estimates

used in this analysis the EPA utilized detailed air quality modeling of the entire power sector 

SO2 and NOX emissions along with the BenMAP model4to estimate the benefits of air quality 

improvements using projected 2020 population, baseline incidence rates, and economic 

factors.

 

3

If the EPA conjectured a location for a particular new unit it may be possible to perform a full health impact 

assessment of different technology options for generating electricity at that location. Doing so for a number of 

locations is beyond the scope of this analysis and would be better captured in sector-wide modeling. 

4

Available at http://www.epa.gov/air/benmap. 
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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, 2013b). These BPT values are estimated in a methodologically consistent manner 

with those reported in Fann et al. (2012). They differ from those reported in Fann et al. (2012) 

as they reflect the health impact studies and population data updated in the benefits analysis of 

the final PM NAAQS RIA (U.S. EPA, 2012). The recalculation of the Fann et al. (2012) BPT values 

based on the updated data from the PM NAAQS RIA (U.S. EPA, 2012) is described in the TSD 

(U.S. EPA, 2013b). The BPT values are for the entire electricity sector and are not differentiated 

by fuel or generator type. 

The methods used for this analysis are consistent with those used to estimate the health 

co-benefits from secondary PM2.5 formation for the Regulatory Impact Analysis for the Final

Carbon Pollution Guidelines for Existing Power Plants (U.S. EPA, 2015). One notable difference 

between the BPT values used in the two analyses is that this analysis utilizes national-average 

BPT estimates because EPA does not assert a specific location for the illustrative new unit, 

whereas the BPT estimates used in the RIA for the final existing source guidelines differ by 

region.5Chapter 5 discusses how the analysis may be affected when considering regional 

differences in the damages associated with these pollutants. 

Despite our attempts to quantify and monetize as many of the co-benefits of reducing 

emissions from electricity generating sources as possible, not all known health and non-health

co-benefits from reducing SO2 and NOx are accounted for in this assessment. For more 

information about unquantified health and non-health co-benefits of SO2 and NOx please refer 

to tables 5-2 and 6-2 of the PM NAAQS RIA (U.S. EPA, 2012), respectively. Furthermore, the 

analysis that follows does not account for known differences in other air and water pollutants 

between the different generating technologies, including, for example, ozone and directlyemitted PM and ozone. The reason and implications for limiting our consideration of cobenefits to pollutants that cause secondary PM2.5 is discussed in Chapter 5. 

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 the uncertainties described in the PM NAAQS RIA, the 

 

5

Separate BPT values are generated for California, the Eastern U.S., and the Western U.S. excluding California. For 

further information, see EPA 2015, 
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use of BPT estimates come with additional uncertainty. Specifically, these national-average BPT

estimates reflect a specific geographic distribution of SO2 and NOX reductions resulting in a 

specific reduction in PM2.5 exposure and may not fully reflect local or regional variability in 

population density, meteorology, exposure, baseline health incidence rates, timing of 

emissions, or other factors that might lead to an over-estimate or under-estimate of the actual 

benefits associated with PM2.5 precursors in a specific location. These estimates are illustrative 

as the EPA does not assert a specific location for the illustrative electricity generation 

technologies and is therefore unable to specifically determine the population that would be 

affected by their emissions. Therefore, the benefits for any specific unit can be different than 

the estimates shown here.

Notwithstanding these limitations, reducing one thousand tons of annual SO2 from U.S. 

power sector sources has been estimated to yield between 4 and 9 incidences of premature 

mortality avoided and monetized PM2.5-related health benefits (including these incidences of 

premature mortality avoided) between $38 million and $85 million in 2020 (2011$) using a 3% 

discount rate or between $34 million and $76 million (2011$) using a 7% discount rate. 

Additionally, reducing one thousand tons of annual NOX from U.S. EGUs has been estimated to 

yield up to 1 incidence of premature mortality avoided and monetized PM2.5-related health 

benefits (including these incidences of premature mortality avoided) of between $5.5 million 

and $12 million in 2020 (2011$) using a 3% discount rate or between $5.0 million and $11 

million (2011$) using a 7% discount rate. For each pollutant, the range of estimated benefits for 

each discount rate is due to the EPA’s use of two alternative primary estimates of PM2.5-related 

mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a higher primary 

estimate based on Lepeule et al. (2012). The benefit per ton values are reported in Table 3-2. 

Table 3-2. Monetized Health Benefits Per Ton of PM2.5 Precursor Reductions in 2020a(in 

2011$)

PM2.5 Precursor

SO2 NOX

3% Discount Rate

Krewski et al. (2009) $38,000 $5,500

Lepeule et al. (2012) $85,000 $12,000

7% Discount Rate

Krewski et al. (2009) $34,000 $5,000

Lepeule et al. (2012) $76,000 $11,000

a

These estimates are from U.S. EPA, 2013a (electricity generating units) and are adjusted to 2011$ using the Gross 

Domestic Product implicit price deflator reported by the Department of Commerce.
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3.4 References

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

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

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

Regulations.

Fann, N., K.R. Baker, C.M. Fulcher. 2012. Characterizing the PM2.5-related health benefits of 

emission reductions for 17 industrial, area and mobile emission sectors across the U.S. 

Environment International, Volume 49, 15 November 2012, Pages 141-151, ISSN 0160-

4120, http://dx.doi.org/10.1016/j.envint.2012.08.017.

Interagency Working Group (IWG) on Social Cost of Carbon (SC-CO2). 2010. Technical Support 

Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866. Docket ID EPA-HQ-OAR-2009-0472-114577. Participation by Council of Economic 

Advisers, Council on Environmental Quality, Department of Agriculture, Department of 

Commerce, Department of Energy, Department of Transportation, Environmental 

Protection Agency, National Economic Council, Office of Energy and Climate Change, 

Office of Management and Budget, Office of Science and Technology Policy, and 

Department of Treasury. 

<http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Costof-Carbon-for-RIA.pdf> Accessed March 31, 2015.

Interagency Working Group (IWG) on Social Cost of Carbon (SC-CO2). 2013. Technical Support 

Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 

12866. Docket ID EPA-HQ-OAR-2013-0495. Participation by Council of Economic 

Advisers, Council on Environmental Quality, Department of Agriculture, Department of 

Commerce, Department of Energy, Department of Transportation, Domestic Policy 

Council, Environmental Protection Agency, National Economic Council, Office of 

Management and Budget, Office of Science and Technology Policy, and Department of 

Treasury. 

<http://www.whitehouse.gov/sites/default/files/omb/assets/inforeg/technical-updatesocial-cost-of-carbon-for-regulator-impact-analysis.pdf> Accessed March 31, 2015.

Intergovernmental Panel on Climate Change (IPCC). 2007. Climate Change 2007: Synthesis 

Report. Contribution of Working Groups I, II and III to the Fourth Assessment Report of 

the Intergovernmental Panel on Climate Change (AR4) [Core Writing Team, Pachauri, 

R.K and Reisinger, A. (eds.)]. IPCC, Geneva, Switzerland, 104 pp. 

<http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_rep

ort_synthesis_report.htm>. Accessed March 30, 2015.

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.

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

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

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

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

Energy Production and Use. National Academies Press. Washington, DC.

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

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

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

December. Available on the Internet at 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485.

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

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

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

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

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

Mercury and Air Toxics Standards. Office of Air Quality Planning and Standards, 

Research Triangle Park, NC. December. Available on the Internet at 

http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the 

Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. 

Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. 

Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2013a. Integrated Science Assessment for 

Ozone and Related Photochemical Oxidants. EPA/600/R-10/076F. Research Triangle 

Park, NC: U.S. EPA. February. Available on the Internet at 

http://oaspub.epa.gov/eims/eimscomm.getfile?p_download_id=511347.

U.S. Environmental Protection Agency (U.S. EPA). 2013b. Technical Support Document 

Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of 

Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on 

the Internet at http://www2.epa.gov/sites/production/files/2014-

10/documents/sourceapportionmentbpttsd.pdf
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U.S. Environmental Protection Agency (U.S. EPA). 2015. Regulatory Impact Analysis for the Final

Carbon Pollution Guidelines for Existing Power Plants. [UPDATE LOCATION WHEN 

AVAILABLE]

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

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

University Press, 2009.
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4-1

CHAPTER 4

COSTS, ECONOMIC, AND ENERGY IMPACTS

4.1 Synopsis

This chapter reports the central compliance cost, economic, and energy impact analyses

performed for the proposed EGU New Source GHG Standards. The EPA analyzed and assessed a 

wide range of potential scenarios and outcomes, using a detailed power sector model, other 

government projections for the power sector, and additional economic assessments and 

analyses to determine the potential impacts of this action. 

The primary finding of this assessment is that in the absence of this proposed rule, all 

projected unplanned1capacity additions affected by this proposal during the analysis period 

would already be compliant with the rule’s requirements (e.g., natural gas combined cycle 

units, low capacity factor natural gas combustion turbines, and small amounts of coal-fired 

units with CCS supported by Federal and State funding). The analysis period is defined as 

through 20222to reflect that CAA Section 111(b) requires that the NSPS be reviewed every 

eight years. The EPA’s conclusion was based on:

 EIA power sector modeling projections,

 EPA power sector modeling projections,

 Electric utility integrated resource planning (IRP) documents,

 Projected new EGUs reported by industry to EIA.

The EPA’s finding of no new conventional coal-fired capacity is robust beyond the 

analysis period (past 2030 in both EIA and EPA baseline modeling projections) and across a wide 

range of alternative potential market, technical, and regulatory scenarios that influence power 

sector investment decisions. As a result, the EGU New Source GHG Standards are not expected

to change GHG emissions for newly constructed EGUs, and are anticipated to yield no 

monetized benefits and impose negligible costs, economic impacts, or energy impacts on the 

electricity sector or society. While the EPA does not project any new coal-fired EGUs without 

CCS to be built in the absence of this rule, this chapter presents an analysis of the project-level 

 

1

Unplanned capacity represents projected capacity additions that are not under construction.

2

IPM output for subsequent years has been made available in the docket and is discussed where appropriate 

throughout the document.
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costs of building new coal-fired capacity with and without CCS to demonstrate that a 

requirement of partial CCS would not preclude new coal construction. An additional illustrative 

analysis, presented at the end of this chapter, shows that even in the unlikely event that new, 

noncompliant EGU capacity would be built in the absence of this rule the proposed EGU New 

Source GHG Standards would provide net social benefits under a range of assumptions.

4.2 Requirements of the Final GHG EGU NSPS

In this action, the EPA is finalizing standards of performance for two basic categories of 

new units that have not commenced construction by January 8, 2014: (i) fossil fuel-fired electric 

utility steam generating units (boilers and IGCC units), including new units and existing units 

that undergo a major modification or reconstruction; and (ii) natural gas-fired stationary 

combustion turbines that generate electricity for sale and meet certain size and operational 

criteria.

The EPA is finalizing standards of performance for affected sources within the following

two categories: (1) all fossil fuel-fired steam generating units (steam generating units, boilers 

and IGCC units), and (2) all natural gas-fired stationary combustion turbines, regardless of the 

size of the stationary turbine unit. All affected new fossil fuel-fired EGUs would be required to 

meet an output-based emission rate of a specific mass of CO2 per MWh of electricity generated 

energy output on a gross basis.

New fossil fuel-fired steam generating units (boilers and IGCC units) would be required 

to meet an emission standard of 1,400 lb CO2/MWh of gross energy output. This is a less 

stringent standard than the proposed limitation (1,100 lb CO2/MWh) in the 2013 proposed rule. 

Existing fossil fuel-fires steam generating units that are making modifications that will result in 

an increase of more than 10% of that unit’s historic CO2/MWh emission rate, or are being 

reconstructed, will be required to meet an emission standard determined by the size of the 

heat input of the unit. Such modified units with a heat input greater than 2,000 MMBtu/hour 

will have an emission limit of 1,800 lb CO2/MWh of gross energy output. Modified units with a 

heat input rate less than or equal to 2,000 MMBtu/hour will have an emission limit of 2,000 lb 

CO2/MWh of gross energy output.

Newly constructed, modified or reconstructed natural gas-fired stationary combustion 

turbines will be required to meet a standard of 1,000 lb CO2/MWh of gross energy output (or 

1,080 lb CO2/MWh of net energy output). This emission limit applies to all affected natural gasfired stationary combustion units regardless of size. The natural gas combustion turbine 

standard, however, will only apply to units that will exceed a sales threshold on the amount of 

electricity generated that is sold to the electric grid. The purpose of the sales threshold criterion 
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4-3

is to permit gas-fired combustion turbines that will operate as a combined heat and power 

(CHP) unit and only sell a small portion of the gross electricity generated to the grid to not have 

to meet the same emission standard as a combustion turbine unit designed primarily to 

generate electricity to be sold to the grid.

Please refer to the preamble for additional detail concerning affected sources and 

standards of performance.

4.3 Power Sector Modeling Framework

4.3.1 Modeling Overview

Over the last decade, the EPA has conducted extensive analyses of regulatory actions 

impacting the power sector. These efforts support the Agency’s understanding of key policy 

variables and provide the framework for how the Agency estimates the costs and benefits 

associated with its actions that impact the power sector. Current forecasts for the utilization of

new and existing generating capacity are a key input into evaluating the impact of this rule. 

Given excess capacity within the existing fleet and relatively low forecasts of electricity demand 

growth, there is limited new capacity - of any type - expected to be constructed over the next 

decade. A small number of new coal-fired power plants have been completed and brought 

online in recent years; however, the EPA does not expect the construction of any new noncompliant coal-fired capacity through the analysis period. The EPA also does not expect any 

new non-compliant natural gas-fired stationary combustion turbines meeting the applicability 

criteria to be built. This conclusion is based in part on the Agency’s own power sector modeling 

utilizing IPM as well as EIA’s Annual Energy Outlook 2014 (AEO 2014) projections.

IPM, developed by ICF International, Inc, is a state-of-the-art, peer reviewed, dynamic 

linear programming model that can be used to project power sector behavior under future 

business as usual conditions and examine prospective air pollution control policies throughout 

the United States for the entire electric power system. The EPA used IPM to project likely future

electricity market conditions with and without this rule. In addition to using IPM, the EPA has 

closely examined the AEO 2014 from the EIA.

To produce the AEO, EIA employs the National Energy Modeling System (NEMS), an 

energy-economy modeling system of the United States. According to EIA:3

 

3

http://www.eia.gov/oiaf/aeo/overview/
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“NEMS projects the production, imports, conversion, consumption, and prices of 

energy, subject to assumptions on macroeconomic and financial factors, world energy markets, 

resource availability and costs, behavioral and technological choice criteria, cost and 

performance characteristics of energy technologies, and demographics.”

The Electricity Market Module of NEMS produces projections of power sector behavior 

that minimize the cost of meeting electricity demand subject to the sector’s inherent 

constraints, including the availability of existing generation capacity, transmission capacity and 

cost, cost of utility and nonutility technologies, expected load shapes, fuel markets, regulations, 

and other factors. EIA’s AEO projections independently support the EPA’s conclusions in that it 

projects no new generation capacity being constructed through the analysis period that would 

not already meet the level of the standard even in the absence of the standard. Both sets of 

modeling results are presented in Section 4.4.

4.3.2 The Integrated Planning Model

IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. 

electric power sector. It provides forecasts of least cost capacity expansion, electricity dispatch, 

and emission control strategies while meeting energy demand and environmental, 

transmission, dispatch, and reliability constraints. The EPA has used IPM for over two decades

to better understand power sector behavior under future business as usual conditions and 

evaluate the economic and emission impacts of prospective environmental policies. The model 

is designed to reflect electricity markets as accurately as possible. 4 The EPA uses the best 

available information from utilities, industry experts, gas and coal market experts, financial 

institutions, and government statistics as the basis for the detailed power sector modeling in 

IPM. The model documentation provides additional information on the assumptions discussed 

here as well as all other model assumptions and inputs.5,6

Although the Agency typically focuses on broad system effects when assessing the 

economic impacts of a particular policy, the EPA’s application of IPM includes a detailed and 

sophisticated regional representation of key power sector variables and its organization. When 

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

the relative economics of various technologies based on a wide spectrum of current and future 

considerations, including capital costs, operation and maintenance costs, fuel costs, utility 

 

4

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

5

http://www.epa.gov/airmarkets/programs/ipm/psmodel.html

6

http://www.epa.gov/airmarkets/documents/ipm/EPA_Base_Case_v514_Incremental_Documentation.pdf
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sector regulations, and emission profiles. The capital costs for new units account for regional 

differences in labor, material, and construction costs. These regional cost differentiation factors 

are based on assumptions used in the EIA’s AEO.

As part of IPM’s assessment of the relative economic value of building a new power 

plant, the model incorporates a detailed representation of the fossil-fuel supply system that is 

used to forecast equilibrium fuel prices, a key component of new power plant economics. The 

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

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

American gas market. This module consists of 118 supply, demand, and storage nodes, 15

liquefied natural gas regasification facility locations and 3 LNG export facility locations that are 

tied together by a series of linkages (i.e., pipelines) that represent the North American natural 

gas transmission and distribution network.

IPM also endogenously models the coal supply and demand system throughout the 

continental U.S., and reflects non-power sector demand and imports/exports. IPM reflects 36 

coal supply regions, 465 coal supply curves for each of 9 years, 14 coal sulfur grades, and the 

coal transport network, which consists of 4,947 linkages representing the costs of transporting 

coal via rail, barge, and truck and conveyer linkages connecting 41 regions with 575 individual 

coal-fired generating stations. The coal supply curves and the transport network costs used in 

IPM are publicly available7, 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. 

The 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, 

 

7

The IPM coal supply curves are presented in detail in Appendix 9-24 of the IPM Base Case documentation, which 

is available at http://www.epa.gov/airmarkets/programs/ipm/psmodel.html. The coal transport network costs 

are in Appendix 9-23, available at that same link.
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emission changes, and power sector impacts for the Clean Air Interstate Rule (CAIR), CrossState Air Pollution Rule (CSAPR), and the Mercury and Air Toxics Standards (MATS).8

 

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

panels for both the model itself and the EPA’s key modeling input assumptions.9The 

rulemaking process also provides opportunity for expert review and comment by stakeholders, 

including owners and operators of the electricity sector that is represented by the model, public 

interest groups, and other developers of U.S. electricity sector models. EPA is required to 

respond to significant comments submitted regarding the inputs used in IPM, its structure, and 

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

assumptions, model representation, and modeling results. IPM has received extensive review 

by energy and environmental modeling experts in a variety of contexts. For example, from the 

mid-1990s through 2011 the Science Advisory Board reviewed IPM as part of the CAA

Amendments Section 812 studies of the Clean Air Act costs and benefits that are periodically 

conducted.10 The model has also undergone considerable interagency scrutiny when it has 

been used to conduct over one dozen legislative analyses (performed at Congress’ request) 

over the past decade. In addition, Regional Planning Organizations throughout the U.S. have 

extensively examined IPM as a key element in the state implementation plan (SIP) process for 

achieving the National Ambient Air Quality Standards. The Agency has also used the model in a 

number of comparative modeling exercises sponsored by Stanford University’s Energy 

Modeling Forum over the past 15 years.

IPM has also been employed by states (e.g., for RGGI, the Western Regional Air 

Partnership, Ozone Transport Assessment Group), other Federal and State agencies, 

environmental groups, and industry, all of whom subject the model to their own review 

procedures. States have also used the model extensively to inform issues related to ozone in 

the northeastern U.S. This groundbreaking work set the stage for the NOx SIP call, which has 

helped reduce summer NOx emissions and the formation of ozone in densely populated areas in 

the northeast. 

 

8

All of the IPM projections conducted for this rulemaking are available at EPA’s website and in the public docket.

9

http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html

10 http://www.epa.gov/air/sect812/index.html
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4.4 Analyses of Future Generating Capacity

4.4.1 Base Case Power Sector Modeling Projections

EPA conducted analysis and modeling in support of the April 2012 EGU GHG New Source 

Standards proposal, and concluded that new unplanned noncompliant base load power plants 

are not expected to be economic both during, and well beyond, the analysis period. The EPA 

conducted an analysis of the economic impacts by modeling a base case scenario of future 

electricity market conditions. The EPA’s IPM modeling for the 2012 proposal utilized the IPM v. 

4.10 base case, and relied on the AEO 2010 for the electric demand forecast for the U.S. and 

employed a set of the EPA’s assumptions regarding fuel supplies, the performance and cost of 

electric generation technologies, pollution controls, and numerous other parameters.

11

After considering public comments received on the 2012 proposal, the EPA issued a new 

proposal for carbon emissions from new power plants in September, 2013. The EPA’s IPM 

modeling of the 2013 111(b) proposal relied on the AEO 2013 electric demand forecast, and 

was analyzed using the IPM v. 5.13 base case. 

For the analysis of the final 111(b) rule, the EPA used the IPM v. 5.14 base case, which 

relied on the electric demand forecast in AEO 2014. The v. 5.14 base case updated v. 5.13 unit 

level specifications (including control configurations) based on comments received and 

environmental regulations. The base case accounts for the effects of the finalized MATS and 

CSAPR rules, New Source Review settlements and state rules through 2014 impacting sulfur 

dioxide (SO2), NOx, directly emitted particulate matter and CO2, and final actions the EPA has 

taken to implement the Regional Haze Rule. The EPA’s IPM base case also includes two federal 

non-air rules effecting EGUs: the Cooling Water Intakes (316(b)) Rule and the Disposal of Coal 

Combustion Residuals from Electric Utilities Rule (CCR). 

The EPA’s IPM base case forecast finds that new generation capacity is expected to be 

compliant with the standards, even in the absence of this rule. Some new coal-fired units with 

federally-supported carbon capture and storage (CCS) are forecast to be constructed, though 

these units are expected to be compliant with their standards under this rule. New capacity is 

forecast to be predominately stationary combustion turbines and renewables. New simplecycle combustion turbines (CTs) constructed in the EPA’s IPM base case are assumed to operate 

at an emissions rate above the standard. Mirroring real world behavior, relatively low levels of 

CT generation are projected in the base case. In the base case new CTs are forecast to operate, 

 

11 http://www.epa.gov/airmarkt/progsregs/epa-ipm/proposedEGU_GHG_NSPS.html
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on average in each domestic model region, at capacity factors well below the applicability 

requirements of this rule. In the base case the maximum average capacity factor for individual 

new CTs is 14% or less across all domestic regions and all simulation years. The emission rate of

new natural gas combined cycle (NGCC) units in the EPA’s IPM base case emit below the

emissions rate standard of this final rule by assumption. However, a modeled emissions rate for 

new NGCC units below the standard is consistent with the detailed emissions rate analysis 

described in the preamble for this rule, which carefully considered emissions rate data on newly 

constructed NGCC units and GHG limitations in recently issued construction permits for NGCC 

facilities. 

The EIA projections that are reflected in AEO 2014 are summarized in the following 

tables alongside the EPA base case projections. New coal-fired capacity through 2030 in the 

AEO 2014 reference case is entirely CCS-equipped and would be in compliance with this 

proposal (300 MW). 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 2014 –

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 coal-fired additions are robust under a range of sensitivity cases examined in the AEO 2013 

and AEO 2014. Sensitivity cases that EIA conducted in those AEOs separately examine higher 

economic growth, lower coal prices, no risk premium for greenhouse gas emissions liability 

from conventional coal, and lower oil and natural gas resources also forecast zero unplanned 

additions of coal-fired capacity without CCS in the analysis period. This has been a consistent 

finding in the AEO, which led EIA to conclude that “the low capital expense, technical maturity, 

and dispatchability of natural gas generation are likely to dominate investment decisions under 

current policies and projected prices."14 

 

 

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. 
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Table 4-1. Reference Case Unplanned Cumulative Capacity Additions (GW)

EPA AEO 2014 Reference Case

Capacity Type 2020 2020 2025 2030

Conventional Coal 0 0 0 0

Coal with CCS 0.3 0.3 0.3 0.3

Natural Gas CC 6.9 9.8 28.8 95.7

Natural Gas CT 2.6 14.1 34.5 49.2

Nuclear 0 0 0 0

Renewables15 15.9 17.4 19.3 22.5

Distributed Generation 0 1.6 3.3 4.6

Total 25.8 43.2 86.3 141.4

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

nameplate capacity, AEO capacity data is net summer generating capacity.

Source: EPA 2020 projection from IPM v. 5.14 base case; EIA 2020-2030 projection from EIA Annual Energy Outlook 2014, Table 

A9.

The capacity projections of EIA and the EPA represent a continuation of current trends, 

where natural gas-fired capacity has been the technology of choice for base load and 

intermediate load power generation over the last few years (see Figure 4-1), due in large part 

to its significant levelized cost of electricity16 (LCOE) advantage over coal-fired generating 

technologies. A greater discussion of the relative LCOE of different generating technologies is 

provided beginning in Section 4.4.

 

15 Renewable projections in 2020 are larger in the AEO 2014 reference case than in EPA’s IPM v 5.14 base case 

primarily due to differences in modeling assumptions regarding the amount of ‘planned’ renewable capacity 

additions and ‘unplanned’ additions in the AEO forecast. The overall amount of total renewable capacity in use 

by 2020 is largely similar in the two forecasts.

16The levelized cost of electricity is an economic assessment of the cost of electricity from a new generating unit or 

plant, including all the costs over its lifetime: initial investment, operations and maintenance, cost of fuel, and 

cost of capital.
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Figure 4-1. Historical U.S. Power Plant Capacity Additions, by Technology, 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 2014, and reflect the most costeffective dispatch and investment decisions modeled, given a variety of variables and 

constraints. Even without the deployment of new conventional coal-fired capacity, U.S. 

electricity demand will continue to be met by a diverse mix of electricity generation sources 

with coal projected to continue to provide the largest share of electricity (36% of total 2020 

generation in AEO 2014 and 37% in the EPA’s projections), as displayed in Table 4-2. 
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Table 4-2. 2012 U.S. Electricity Net Generation and Projections for 2020, 2025, and 2030

(Billion kWh)

Historical EPA AEO 2014 Reference Case

2012 2020 2020 2025 2030

Coal 1,512 1,534 1,646 1,689 1,692

Oil 23 47 18 19 19

Natural Gas 1,228 1,156 1,286 1,410 1,552

Nuclear 769 815 779 711 782

Hydroelectric 274 282 288 291 294

Wind 142 251 218 218 219

Other Renewables 48 121 102 133 154

Other 71 -7 65 151 103

Total 4,067 4,199 4,402 4,622 4,815

Source: Historical data from Form EIA-860, 2012. EPA 2020 projection from IPM 5.14 base case; EIA 2020-2030 projection from 

EIA Annual Energy Outlook 2014, Tables A8 and A16

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

include biomass, geothermal, waste and solar electric generation capacity. “Other” includes pumped storage (net loss, nonbiogenic waste, batteries, hydrogen, and other misc. generation and storage technologies. Negative value reflects net energy 

loss from pumped storage.

It has been previously noted that since the time of the original 2012 proposed new 

source rule, projections for key market variables are now even less favorable to the 

development of coal-fired capacity. State and regional regulations have necessarily evolved 

since the AEO 2010 and the EPA’s modeling projections for the 2012 proposal, most notably 

regulations of GHG emissions from the power sector and state renewable portfolio standards 

(RPS):

 State regulations addressing CO2 emissions – Several states have adopted 

measures to address emissions of CO2 from the power sector. These approaches 

include flexible market-based programs like California’s Assembly Bill 32 and the 

RGGI in the Northeast, and specific GHG performance standards for new power 

plants in California, Oregon, New York, and Washington.

 State Renewable Portfolio Standards (RPS) – According to EIA, 30 states and the 

District of Columbia have an enforceable RPS, or similar laws.17 There are eight 

other States that have voluntary goals.18 These measures, in conjunction with 

 

17 http://www.eia.gov/forecasts/aeo/legs_regs_all.cfm#state

18 http://www.dsireusa.org/rpsdata/index.cfm
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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 

state requirements, allow regulators and utilities to consider a broader array of 

measures to meet future electric demand most cost effectively. IRPs also help 

electric planners to consider key strategic and policy goals like electric reliability, 

environmental impacts, and the economic efficiency of power sector 

investments.19 In general, these plans confirm the expectation that utilities 

anticipate that any new sources of generation will be from renewables, in 

response to state and federal regulations and incentives, and natural gas prices. 

Furthermore, these plans reflect an expectation of relatively low demand growth 

due, in part, to policies and regulations to reduce the electricity consumption 

such as energy efficiency regulations and policies, evolution of the Smart Grid, 

and demand response measures. 

4.4.2 Alternative Scenarios from AEO 2014

In addition to EPA’s own analysis, EPA reviewed EIA’s recent forecasts of new capacity in 

the electricity sector for the AEO 2014, which uses the National Energy Market System (NEMS) 

model. The AEO 2014 reference case forecasts no new coal that would not comply with the 

final new source standards. Furthermore, the reference case projects a capacity factor for CTs 

of less than 20% in all regions and in all years. Furthermore, power sector modeling by EIA 

projects no new 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 31 scenarios contained in the AEO 2014, none 

project new coal-fired capacity in the analysis period, including the four scenarios that may be 

considered most favorable to the development of coal-fired capacity displayed in Table 4-3.20

 

19 E.g., http://www.pacificpower.net/about/irp.html

20 AEO 2014 scenario definitions: High Economic Growth increases annual real GDP growth by 2.8%/year through 

2040; Low Coal Cost assumes 2.4% greater regional coal mining productivity growth than in the reference case, 

and lower wages, equipment, and declining transportation costs for the coal industry than in the reference 

case, falling to 25% below the reference case by 2040; Low Oil and Gas Resource reduces the ultimate 

estimated recovery of shale gas, tight gas, and tight oil by 50%; No GHG Concern removes the perceived risk of 

incurring costs under a future GHG policy from market investment decisions.
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Table 4-3. AEO 2014 Reference and Alternative Scenario Forecasts of Unplanned 

Cumulative Capacity Additions by 2020, GW 

Capacity Type Reference

High 

Growth

Low Coal 

Cost

Low Gas 

& Oil 

Resource

No GHG 

Concern

Conventional Coal 0 0 0 0 0

Coal with CCS 0.3 0.3 0.3 0.3 0.3

Natural Gas 23.9 34.4 19.8 16.3 22.7

Nuclear 0 0 0.0 2.5 0.0

Non-Hydro Renewables 17.4 19.7 17.6 23.7 17.5

Other 1.6 2.0 1.5 0.8 1.6

Total 43.2 56.5 39.3 43.6 42.1

4.4.3 Power Sector Fuel Price Dynamics and Trends

As mature technologies, the cost and performance characteristics of conventional coalfired capacity and NGCC are projected by EPA to be relatively stable over time in comparison to 

emerging generation technologies.21 Therefore, expectations of future fuel prices play a key 

role in determining the overall cost competitiveness of conventional coal-fired units versus 

NGCC units.

Current and projected natural gas prices are considerably lower than observed 

prices over the past decade. This is largely due to advances in hydraulic fracturing and 

horizontal drilling techniques that have opened up new shale gas resources and 

substantially increased the supply of economically recoverable natural gas. According to 

EIA:

Shale gas refers to natural gas that is trapped within shale formations. 

Shales are fine-grained sedimentary rocks that can be rich sources of petroleum

and natural gas. Over the past decade, the combination of horizontal drilling and 

hydraulic fracturing has allowed access to large volumes of shale gas that were 

previously uneconomical to produce. The production of natural gas from shale 

formations has rejuvenated the natural gas industry in the United States.

 

21 http://www.epa.gov/airmarkt/progsregs/epa-ipm/docs/v410/Chapter4.pdf
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Of the natural gas consumed in the United States in 2011, about 95% was 

produced domestically; thus, the supply of natural gas is not as dependent on foreign 

producers as is the supply of crude oil, and the delivery system is less subject to 

interruption. The availability of large quantities of shale gas should enable the United 

States to consume a predominantly domestic supply of gas for many years and produce 

more natural gas than it consumes.

The AEO 2014 projects U.S. natural gas production will increase by 13.3 trillion cubic 

feet (Tcf), a 55% increase (from 24.3 Tcf in 2014 to 37.5 Tcf in 2040). Over 75% of this 

forecasted increase in domestic natural gas production is due the projected doubling of shale 

gas production, which is forecast to increase by 10.2 TCF (from 9.6 TCF in 2014 to 19.8 TCF in 

2040).

22

Recent historical data reported to EIA is also consistent with these trends, with 2014 

being the highest year on record for domestic natural gas production.23 Gas production in 2014 

was 6.3% above production in 2013, which is the largest annual growth rate since 1984. The 

average real (2011$) delivered natural gas price delivered to the power sector was $4.39 per 

MMBtu in 2014, an increase from $4.25/MMBtu in 2013.24 

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.25,26 Modeling by the EPA and EIA 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 2014), but also in current capacity planning 

by utilities and electricity producers across the country. The North American Electric Reliability 

Corporation’s (NERC) Long Term Reliability Assessment, which is based on utility plans for new 

 

22 AEO 2014, Appendix A, Table A14. Oil and Gas Supply

23 http://www.eia.gov/dnav/ng/hist/n9010us2a.htm

24 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)

25

 National Petroleum Council. 2011. Prudent Development: Realizing the Potential of North America's Abundant 

Natural Gas and Oil Resources. http://www.npc.org/reports/rd.html (see Figure 1.2 on p. 47).

26 EIA. 2013. U.S. Crude Oil and Natural Gas Proved Reserves, 2011. 

http://www.eia.gov/naturalgas/crudeoilreserves/pdf/uscrudeoil.pdf
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4-15

capacity over a 10-year period, reinforces this consensus by stating that “gas-fired generation 

[is] the primary choice for new capacity.”

27

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-tomonth, or even year-to year, variations in fuel prices. Shorter-term prices will affect how units 

are dispatched, but these potential dispatch impacts are considered with other factors over a 

longer time horizon and factored into the choice of which type of plant to build. In contrast, 

the uncertainty surrounding long-term fuel prices will exert significantly greater influence on 

the technology selected for new capacity additions. In a modeling context with perfect 

foresight, this longer term uncertainty may be evaluated by the scenario testing presented 

throughout this analysis.

In addition to major changes in the gas supply outlook, there have been notable changes

in the coal supply outlook. Coal costs have generally increased over the past few years due 

primarily to increased production costs. These costs have increased as the most accessible and 

economically viable mines are depleted, requiring movement into coal reserves that are more 

costly to mine. The basic trends in coal supply are not expected to change for the foreseeable 

future.28

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.29

 

27 NERC, Long-Term Reliability Assessments for 2012. New capacity includes both planned and conceptual 

resources as defined by NERC.

28 http://www.eia.gov/forecasts/aeo/assumptions/pdf/coal.pdf

29 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.” 
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4.4.4 Power Sector Fuel Projections

 To examine the potential impacts of uncertainty inherent in natural gas and coal 

markets, the EIA used scenario analysis to generate the 2020 fuel price projections in Table 4-4.

Table 4-4. National Delivered 2020 Fuel Prices by AEO 2014 Scenario (2011$/MMBtu)

Scenario30 Natural Gas Coal

Reference 4.99 2.57

High Growth 5.28 2.59

Low Growth 4.97 2.55

High Coal Cost 5.13 2.90

Low Coal Cost 4.88 2.27

High Gas/Oil Resource 4.30 2.45

Low Gas/Oil Resource 5.63 2.63

However, given that power plants are long-lived assets, capacity planning decisions are 

necessarily undertaken with a forward view of expected market and regulatory conditions. In 

producing the AEO 2014, EIA capacity expansion projections are informed by a lifecycle cost 

analysis over a 30-year period in which the expectations of future prices are consistent with the 

projections realized in the model (i.e. the model executes decisions with perfect foresight of 

future market, technical, and regulatory conditions). Therefore, the fuel prices that inform 

capacity expansion decisions in 2020 is not only the prices that year, but the entire future fuel 

price stream. For example, Figure 4-2 displays EIA’s natural gas price projections for the 

Reference Case and several key scenarios through 2040.

 

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.

30 AEO 2014 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%; No GHG Concern has no GHG policy enacted and market decisions are not altered in anticipating of a GHG 

policy.
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Figure 4-2. National Real Price of Natural Gas Delivered to EGUs for Select AEO 2014 

Scenarios (2011$/MMBtu)

Note: The AEO gas price forecasts go through 2040. The AEO forecasted prices are interpolated to 2040 by 

applying the average annual rate of price increase from 2035 to 2040 in each AEO scenario to all 

subsequent years from 2041 through 2049.

Natural gas prices are expected to increase after 2020 in all scenarios31; however, rising 

natural gas prices through 2040 – including in EIA’s low gas/oil resource scenario - are still not 

sufficient to support new, non-compliant coal-fired generation 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 non-compliant coal-fired 

capacity through the analysis period is compelling, the scenario projections cannot fully 

illustrate the extent of the economic advantage that NGCC maintains over conventional coal –

only that the advantage remains intact across a broad range of market and technical scenarios. 

To identify potential market conditions that could fully erode the private cost advantages of 

 

31 Coal prices are also expected to rise in all scenarios.

$4

$5

$6

$7

$8

$9

$10

$11

$12

$13

$14

Delivered Gas Price (2011$/M

M

Btu)

Reference

High growth

Low growth

High coal cost

Low coal cost

High resource

Low resource

No GHG concern
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NGCC over coal-fired technologies during the analysis period, the following section adopts a 

static, engineering cost analysis.

4.5 Levelized Cost of Electricity Analysis 

New capacity projections from the EPA and EIA reviewed in the previous section

indicate that the NSPS is not projected to require changes in the design or construction of new 

EGUs from what would be expected in the absence of the rule. Thus, under both the baseline 

projections and alternative scenarios analyzed in AEO 2014, the proposed EGU New Source 

GHG Standards are not projected to result in any emission reductions, monetized benefits, or

costs.

To further examine the robustness of these conclusions the EPA conducted additional 

analysis using the levelized cost of electricity (LCOE) for different types of new generation 

technologies. The LCOE is a widely used metric that represents the cost, in dollars per output, 

of building and operating a generating facility over the entirety of its economic life. Evaluating 

competitiveness on the basis of the LCOE is particularly useful in establishing cost comparisons 

between generation types with similar operating characteristics but with different cost and 

financial characteristics. The typical cost components associated with the LCOE include capital, 

fixed operating and maintenance (FOM), variable operating and maintenance (VOM), and fuel.

4.5.1 Overview of the Concept of Levelized Cost of Electricity

The levelized capital and FOM costs may be calculated by taking the annualized capital 

and FOM (expressed in $/kW-yr) costs and spreading the expense over the annual generation 

of the facility using the expected average annual capacity factor (the percent of full load at 

which a unit would produce its actual annual generation if it operated for 8760 hours). The 

annualized capital cost (expressed in $/kw-yr) is the product of the $/kW capital cost and the 

capital recovery factor (CRF). A CRF may be calculated using the project’s interest rate (i) and 

book life (n).32

The VOM cost, which is already expressed in terms of cost per unit output, may be 

presented with or without the fuel expense. The fuel expense is typically the largest 

component of VOM costs (non-fuel components to VOM include start-up fuel, consumables, 

 

32 The interest rate assumed for NGCC projects is 9.06%; the interest rate assumed for coal-fired projects is 9.57%. 

Both types of projects are assumed to have a 30-year book life, resulting in a capital recovery factor of 9.78% 

for NGCC projects and 10.23% for coal-fired projects.
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inspections, etc.) and for certain capacity types – such as NGCC – fuel expense may represent 

the majority of the LCOE. 

Because levelized costs consider the entire lifecycle of the facility, fuel expenses are 

represented by the levelized fuel price which captures the forecast of annual delivered fuel 

prices over the economic life of the facility at a given discount rate.33 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 the LCOE that 

impact power plant investment decisions. New power plant developers must consider the 

particular demand characteristics in any particular region, the existing mix of generators, 

operational flexibility of different types of generation, prevailing and expected electricity prices, 

other potential revenue opportunities (e.g., the capacity value of a particular unit, where 

certain power markets have mechanisms to compensate units for availability to maintain 

reliability, sale of co-products, etc.), and the varying financial risks associated with different 

generation technologies. Broader system-wide power sector modeling – such as the analyses 

conducted by the EPA and EIA – is able to more effectively capture some of these 

considerations.

4.5.2 Cost and Performance of Technologies 

The NGCC and coal-fired generation technology cost and performance assumptions that 

form the basis for the LCOE analysis in this chapter are from the DOE’s National Energy 

Technology Laboratory (NETL).34 NETL cost and performance characteristics were selected for 

coal-fired technologies because the NETL estimates were unique in the detail of their cost and 

performance estimates for a range of CO2 capture levels for both new super critical pulverized 

coal (SCPC) and integrated gasification combined cycle (IGCC) facilities.

35,36 The CO2 capture 

 

33 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. The EPA utilized a 5% discount rate to calculate levelized 

fuel prices, a value consistent with the discount rate embedded in IPM.

34 http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf

35 All potential build types are compliant with all current environmental regulations, including the EPA’s Mercury 

and Air Toxics Standards (MATS).

36 For an emerging technology like CCS, costs can be estimated for a “first-of-a-kind” (FOAK) plant or an “nth

-of-akind” (NOAK) plant, the latter has lower costs due to the “learning by doing” and risk reduction benefits that 

result from serial deployments, as well as from continuing research, development and demonstration projects. 

The estimates provided in Table 4-5 for a new NGCC unit and for a SCPC plant without CO2 capture are based 
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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. The 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 – was based on a single, internally consistent framework. For 

technologies where NETL cost and performance estimates were not available or sufficiently 

recent – such as for nuclear and simple cycle CT – EPA adopted EIA’s AEO 2014 estimates of the 

LCOE.

To represent a new SCPC facility, NETL assumed a new boiler with a combination of lowNOx burners with overfire air and a selective catalytic reduction system for NOx control. The 

plant was assumed to have a fabric filter and a wet limestone flue gas desulfurization scrubber 

for particulate matter and SO2 control, respectively. For configurations including CCS, the plant 

was assumed to have a sodium hydroxide polishing scrubber to ensure that the flue gas 

entering the CO2 capture system has a SO2 concentration of 10 ppmv or less. The SCPC with CCS

plant configurations were assumed to be 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 

 

on mature technologies and are thus NOAK costs. For plants that utilize technologies that are not yet fully 

mature, such as IGCC or any plant that includes CO2 capture, the cost estimates in Table 4-5 represent a plant 

that is somewhere between FOAK and NOAK, sometimes referred to as “next-of-a-kind”. Because there are a 

number of projects currently under development, the EPA believes it is reasonable to focus on the next-of-akind costs provided in Table 4-5. See the preamble for additional discussion.

.
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cooling system.

37 The “slip stream” approach – which leads to lower capital and operating costs

– was therefore adopted by the EPA for cost and performance estimates under partial capture.

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 and CO2) but no water-gas shift 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 water-gas shift reaction with bypass and the twostage acid gas (SelexolTM) scrubbing system. 38 In summary, the technology cost and 

performance characteristics utilized by the EPA in developing the LCOE estimates discussed in 

this chapter and Chapter 5 are listed below in Table 4-5.

Table 4-5. Technology Cost and Performance Specifications (2011$) 

Capacity Type Total Overnight 

Capital Cost ($/kw)

Fixed Operations 

& Maintenance 

($/kw-yr)

Variable 

Operations & 

Maintenance 

($/MWh)

Levelized Fuel 

Cost 

($/MMBtu)

Net Plant 

HHV 

Efficiency 

(%)

NGCC 891 31.4 1.8 6.07 51.1

SCPC 2,452 83.0 7.7 2.80 39.3

SCPC w/ Partial CCS 

(1,400 lbs/MWh 

gross)

2,876 94.9 8.9 2.80 36.9

IGCC 2,969 81.8 9.3 2.80 39.0

IGCC w/ Partial CCS 

(1,400 lbs/MWh 

gross)

3,419 112.5 9.4 2.80 38.8

 

37 NETL based this determination primarily upon a review of the literature. See page 2 of 

http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf

38 For additional detail and discussion on the specific technology configurations selected for this analysis, please 

refer to the preamble.
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4-22

Notes: The coal assumed is a bituminous coal with a sulfur content of 2.8% (dry) at a real (2011$) price of $2.80/MMBtu, 

consistent with AEO 2014 Reference Case forecast levelized delivered coal (all types) price. The natural gas price is the EIA AEO 

2014 forecast levelized real (2011$) delivered gas price from EIA’s AEO 2014 Reference Case. NETL (2013) explains that there 

are a range of future potential costs that are up to 15% below, or 30% above their central estimate, consistent with a 

“feasibility study” level of design engineering applied to the various cases in this study. The value of the studies lie not in the 

absolute accuracy of the individual case results but in the fact that all cases were evaluated under the same set of technical and 

economic assumptions. This consistency of approach allows meaningful comparisons among the cases evaluated.

4.5.3 Levelized Cost of Electricity of New Generation Technologies

To support and provide context for the sectoral modeling results presented above, this section 

presents two LCOE comparisons39: 

1. NGCC to Uncontrolled Coal – to demonstrate the cost advantages of NGCC across a 

range of natural gas prices and regional market conditions.

2. NGCC to CT – to demonstrate the low likelihood of a new combustion turbine being 

built with the expectation of meeting the applicability criteria based on utilization

and thus being covered by this proposal.

The illustrative unit cost and performance characteristics used in this section assume 

representative costs associated with spatially dependent components, such as connecting to 

existing fuel delivery infrastructure and the transmission grid. In practice units may experience 

higher or lower costs for these components depending on where they are located. It should be 

noted that the LCOE comparisons presented in this section only represent the cost to the 

generator and do not reflect the additional social costs that are associated with emissions of 

greenhouse gases or other air pollutants. A broader consideration of the health and welfare 

impacts of emissions from these technologies is considered in Chapter 5.

It is also important to note that both the 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 

 

39 As the sectoral modeling may not capture all considerations, particularly local ones, under which a noncompliant coal unit may be built, Section 5.5 provides a comparison the cost of a non-compliant coal unit to a 

compliant coal unit, either with partial CCS or natural gas cofiring. The analysis demonstrates that the standard

could be accommodated and would not, based on the cost increment of constructing and operating a CCS, 

preclude new coal construction. The section also demonstrates how the cost to a non-compliant coal unit of 

complying the final standard is mitigated by the emission reduction benefits of controlling their emissions. 
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4-23

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 GHGintensive projects in a context of climate uncertainty. When comparing ex-ante private 

investment costs, the EPA believes the inclusion of the CUA in LCOE estimates is consistent with 

the industry’s current planning and evaluation framework for future projects (demonstrable 

through IRPs and public utility commission orders) and is therefore necessary to adopt in 

evaluating potential investment behavior in light of 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 GHGintensive projects to account for the possibility they may eventually have to purchase 

allowances or invest in other GHG emission-reducing projects that offset their emissions.”42

Therefore, the EPA recognizes the application of the CUA is context dependent – as a part of 

the planning process it is appropriately applied in an evaluative sense to prospective projects, 

and then removed once a project transitions from planning to execution. While omitting the 

CUA is inconsistent with an analysis considering how project characteristics and market 

conditions would lead a developer or utility to select a certain project, as is the purpose of this 

section, for transparency the 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, to represent the reduced CO2 liability associated with such 

technologies.

4.5.4 Levelized Cost of Electricity of NGCC and Uncontrolled Coal

The EPA’s base LCOE estimates for NGCC, SCPC, and IGCC are displayed in Figure 4-3 by 

cost component (capital, FOM, VOM, TS&M and fuel) and assume a construction date of 2020. 

Although the EPA believes that this cost data is broadly representative of the economics 

between new coal and new natural gas facilities, this analysis assumes representative new units 

 

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 estimating CO2 emissions liability in 

their integrated resource planning. http://www.synapse-energy.com/Downloads/SynapsePaper.2011-

02.0.2011-Carbon-Paper.A0029.pdf. In addition to utilities, several state commissions have mandated the 

inclusion of potential financial liabilities associated with CO2 emissions in long-term planning (e.g., Minnesota 

utilities must adopt a price beginning in 2017).

42 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
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4-24

and does not reflect the full array of new generating sources that could potentially be built. To 

the extent that other types of new units that would be affected by this rule are built, they may 

exhibit different costs than those presented here. For example, new conventional coal facilities 

of a size smaller than what is assumed in the base estimate would tend to exhibit a relatively 

higher LCOE, while some technologies could potentially display a lower LCOE if – all else equal -

fuel could be obtained at a lower price than that assumed in this analysis (such as may be the 

case for petroleum coke or waste coal facilities). These potential differences do not 

fundamentally change the analysis presented in this chapter.

On a levelized cost basis, NGCC is significantly cheaper than all of the uncontrolled coalfired options. 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.

Figure 4-3. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation 

Technologies by Cost Component

Notes: 

(1) The coal assumed is a bituminous coal with a sulfur content of 2.8% (dry) and a real delivered price of 

$2.80/MMBtu. $2.80/MMBtu is the levelized real (2011$) delivered average coal price from the AEO 2014 

reference case for all coals during the 20 year forecast period 2020-2039. The $2.80/MMBtu coal price is 
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4-25

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. 

(2) The levelized delivered price of natural gas is $6.07/MMBtu (2011$).This price is the levelized real (2011$) 

delivered gas price from the AEO 2014 reference during the 20 year forecast period 2020-2039.

(3) A 3% climate uncertainty adder (CUA) is added to the SCPC without any CCS control. The CUA is not added to the 

SCPC with partial control, nor to the two IGCC alternatives.

(4) The cost of CO2transport, storage and monitoring (TS&M) is included as part of LCOE for the two alternatives 

capturing CO2. 

(5) The gross CO2 emission rates for these illustrative new generation technologies are: NGCC = 778 lbs/MMBtu; 

SCPC (no CCS) = 1,677 lbs/MMBtu; SCPC with CCS on 22% of emission stream = 1,400 lbs/MMBtu; IGCC (no CCS) 

= 1,434 lbs/MMBtu; IGCC with CCS on 2.8% of emission stream = 1,400 lbs/MMBtu.

(6) A capacity factor of 85 percent is assumed across all technologies.

(7) 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.43 The levelized costs 

presented above are based on NETL assumptions and will necessarily differ from AEO 2014 levelized costs for a 

variety of reasons, including cost and performance characteristics, financial assumptions, and fuel input prices. 

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 (with no CO2 control) 

are included as well.44

 

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

44 Some new units could be designed to combust waste coal or petroleum coke (pet coke), which may be affected

by this rule. These technologies could exhibit different local economics, particularly in the delivered price of 

fuel. From a capital and operating perspective, the EPA believes the cost and performance of these units are 

broadly similar and therefore well represented by new, conventional coal-fired facilities (e.g. SCPC).
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Figure 4-4. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation 

Technologies Across Select Natural Gas Prices

It is only when natural gas prices exceed $10/MMBtu on a levelized basis (in 2011$) that 

new coal-fired generation without CCS approaches parity with NGCC in terms of the LCOE (none 

of the EPA sensitivities or AEO 2014 scenarios described in this chapter project national average 

natural gas prices near that level).

45

 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 4-6 report the levelized natural gas prices 

(initial year of 2020) for both a 20-year period (to accommodate the end of EIA’s modeling 

projections in 2040) and 30-year period (calculated by continuing the projected level of price 

increases through 2050).

 

45 As noted earlier in this chapter, investment decisions require consideration of fuel price projections over long 

periods of time; similarly, the power sector modeling cited here make fuel price projections over long periods 

of time. Neither these modeling projections nor these LCOE calculations are meant to suggest that the gas 

price could not reach as high as $10/MMBtu at any given point in time; the point is that these analyses do not 

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.
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Table 4-6. Levelized Natural Gas Prices by Select AEO 2014 Scenario (2011$/MMBtu)

Scenario

20-Year AEO 

Projection

(2020-2039)

30-Year AEO-Based 

Projection

(2020-2049)

Reference 6.07 6.53

High Growth 6.32 6.96

Low Growth 5.78 6.20

High Coal Cost 6.19 6.69

Low Coal Cost 6.03 6.47

High Gas/Oil Resource 4.80 4.85

Low Gas/Oil Resource 7.70 8.45

Note: Discount rate of 5%, consistent with IPM assumptions. The 30-year natural gas 

price is calculated by applying the average annual rate of price increase from 2035 to 

2040 in all subsequent years from 2041 through 2049.

One potential price path that would achieve a $10/MMBtu on a 20-year levelized basis 

in 2020 is a natural gas price path 30% higher than EIA’s low resource scenario in all years; see 

Figure 4-5 below. This illustrative price path to achieve a $10/MMBtu levelized price would 

result in a $11.02/MMBtu annual real price in 2030 and a $13.81/MMBtu real price in 2040.
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Figure 4-5. Projected Real National Delivered Natural Gas Price for Select AEO 2014 

Scenarios and Illustrative Path for > $10/MMBtu Levelized Cost

It is important to note that the LCOE calculations are based on assumptions regarding 

the average national cost of generation at new facilities. It is known that there is significant 

spatial variation in the costs of new generation due to design differences, labor productivity 

and wage differences, and delivered fuel prices, among other potential factors.46 

 

46 http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf

$6.07

$4.80

$7.70

$10.00

$0

$2

$4

$6

$8

$10

$12

$14

2015 2020 2025 2030 2035 2040

Gas Price Delivered to EG

Us (2011$/M

MBtu)

Reference Low Gas & Oil Resources

High Gas & Oil Resources Illustrative Path to $10 Gas

Levelized Price
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4-29

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 2014 for SCPC, IGCC, and NGCC build options are presented below in Table 4-7:47

Table 4-7. AEO 2014 Regional Capital Cost Scalars by Capacity Type

Capacity Type Minimum Capital 

Cost Scalar

Maximum Capital Cost 

Scalar

SCPC 0.885 1.152

IGCC 0.908 1.136

NGCC 0.893 1.205

Applying the regional capital cost scalars displayed above to the base LCOE estimates 

developed earlier in this section produces only a small change in the relative competitiveness of 

the technologies as seen in Table 4-8.

Table 4-8. LCOE Estimates with Minimum and Maximum AEO 2014 Regional Capital Cost 

Scalars (2011$/MWh)

Capacity Type Reference 

LCOE

Minimum Capital 

Cost Scalar

Maximum Capital 

Cost Scalar

SCPC (no CCS, with CUA) 91 81 105

IGCC (no CCS, without CUA) 96 87 109

NGCC 59 53 71

The LCOE of SCPC in the lowest capital cost region still results in an LCOE that is 13% 

higher than an NGCC located in the most expensive capital cost region. The IGCC LCOE is 22% 

above NGCC in the most expensive region. 

The other primary driver in determining the regional impact on competitiveness of new 

build options is delivered fuel prices. As part of the AEO, EIA releases electric power 

projections – including fuel prices – for each of the 22 Electricity Market Module (EMM) 

regions. The two regions with the highest projected 2020 natural gas prices in the AEO 2014 

are the Western Electricity Coordinating Council/Southwest (‘Southwest’) and the Florida 

Reliability Coordinating Council (FRCC). The 20-year levelized natural gas and coal price 

forecasts (2020-2039) in the AEO 2014 reference case are displayed in Figure 4-6 for both 

regions.

 

47 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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Figure 4-6. Levelized Regional Fuel Price from AEO 2014 Reference Case, 2020-2039 

(2011$/MMBtu)48 

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 the SCPC, IGCC, and NGCC technologies without 

CCS is reported in Table 4-9 for both sets of fuel prices, as well as the national average for 

comparison. 

Table 4-9. LCOE Estimates For Minimum and Maximum AEO 2014 Regional Capital Cost 

Scalars (2011$/MWh)

Capacity Type National Average

Fuel Prices FRCC Fuel Prices Southwest Fuel Prices

SCPC (w/ 3% CUA) 91 98 88

IGCC (No CUA) 96 104 93

NGCC 59 87 70

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 $28/MWh over SCPC (compared 

with a $32 advantage with national fuel prices) and $23/MWh over IGCC (compared with a $37 

advantage with national fuel prices.

 

48 Assuming 5% discount rate.

$10.12 

$7.61 

$3.67 

$2.46 

$0

$2

$4

$6

$8

$10

$12

FRCC WECC-Southwest

Levelized Cost of Delivered Fuels

(2011$/M

MBtu)

Gas Coal
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4-31

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.

4.5.7 Levelized Cost of Simple Cycle Combustion Turbine and Natural Gas Combined Cycle

Simple Cycle Combustion Turbines (CTs) fulfill a fundamentally different function in 

power sector operations than that of NGCC and fossil-fired steam facilities. CTs are designed to 

start quickly in order to meet demand for electricity during peak operating periods and are 

generally less expensive to build (on a capital cost basis) but are also less fuel efficient than 

combined cycle technology, (which employs heat recovery systems). Due to lower fuel 

efficiencies, CTs produce a significantly higher cost of electricity (cost per kWh) at higher 

capacity factors and consequently are typically utilized at levels below the applicability 

requirements for sources affected by the EGU New Source GHG Standards. Specifically, the 

final emission standards do not apply to stationary combustion turbines subject to a federally 

enforceable permit condition limiting annual electric sales to the specific design efficiency of 

the combustion turbine multiplied by the unit’s potential electric output or less. New CTs are 

expected to most often be built to ensure reserve margins are met during peak periods 

(typically in the summer), and in some instances be able to generate additional revenues by 

selling capacity into power markets. Thus, in practice, EPA expects that potential CT units 

would not meet the applicability requirements finalized in this rule and would therefore, not be 

subject to the standards of performance.

To illustrate the economic incentives of utilizing combustion turbines in an intermediate 

and base load mode of operation, Figure 4-7 presents the LCOE estimates for a new CT, 

Advanced CT and NGCC at increasing capacity factors. The estimates utilize the AEO 2014

Reference Case levelized natural gas price for 2020.
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Figure 4-7. Levelized Cost of Electricity Across a Range of Capacity Factors, CT and NGCC 

(2011$/MWh at $6.07/MMBtu Levelized Natural Gas Price)

In the LCOE figure above, utilizing a CT for generation is less expensive than an NGCC 

unit only at capacity factors of less than 20%.49 If expected utilization is greater than 20%, it can 

reasonably be expected that a utility or developer would seek to deploy NGCC over CT for a 

host of economic, environmental, and technical reasons. Furthermore, the design net 

efficiencies for currently available potentially impacted aeroderivative simple cycle combustion 

turbines range from approximately 32 percent for smaller designs to 39 percent for the largest 

intercooled designs. The efficiencies of industrial frame units range from 30 percent for smaller 

designs to 36 percent for the largest units.50 The EPA therefore does not expect new CT units to 

be constructed, which would meet the applicability requirements. 

4.8 Macroeconomic and Employment Impacts

These final EGU New Source GHG Standards are not anticipated to change GHG 

emissions for newly constructed electric generating units, and are anticipated to impose 

negligible costs or monetized benefits. EPA typically impacts on employment or labor markets 

associated with 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 

 

49 CT cost, performance, and financial assumptions from AEO 2013.

50 These efficiency values follow the methodology the EPA has historically used and are based on the higher 

heating value (HHV) of the fuel.

$0

$50

$100

$150

$200

$250

$300

$350

0% 20% 40% 60% 80% 100%

LC

OE (2011$/M

Wh)

Capacity Factor

NGCC Conventional CT Advanced CT
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4-33

behavior relative to the baseline in response to this rule, there are no notable macroeconomic 

or employment impacts expected as a result of this rule. 

4.9 References

Dixit, Avinash and Pindyck, Robert. Investment Under Uncertainty. 1994. Princeton University 

Press.

Fann, N., K.R. Baker, C.M. Fulcher. 2012. Characterizing the PM2.5-related health benefits of 

emission reductions for 17 industrial, area and mobile emission sectors across the U.S.

Environment International, Volume 49, 15 November 2012, Pages 141-151, ISSN 0160-

4120, http://dx.doi.org/10.1016/j.envint.2012.08.017.

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

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

10-013.

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

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

Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz, 

and W.H. White. 2009. “Reanalysis of the Harvard Six Cities Study and the American 

Cancer Society Study of Particulate Air Pollution and Mortality.” Special Report to the 

Health Effects Institute. Cambridge, MA. July.

Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. “Chronic Exposure to Fine Particles and 

Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.

Malik, N.S. 2010, November 1. NextEra CEO sees clean energy standards replacing recent 

climate proposals [Radio transcript]. Dow Jones News [Online]. Available: Dow Jones 

Interactive Directory: Publications Library.

Mufson, S. 2011, January 2. Coal’s burnout. The Washington Post. Retrieved from 

http://www.washingtonpost.com/newssearch. 

Muller, N.Z., R. Mendelsohn, and W. Nordhaus. 2011. Environmental Accounting for Pollution in 

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

National Energy Technology Laboratory (NETL). Cost and Performance of PC and IGCC Plants for

a Range of Carbon Dioxide Capture. Revised Sept. 16, 2013. Available online at:

http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf. 

Rosenberg, M. 2011, September/October. “The Reign of Cheap Gas.” EnergyBiz Magazine. 

Retrieved from http://www.energybiz.com/magazine/article/234577/reign-cheap-gas.
***E.O. 12866 Review – Do Not Cite, Quote, or Release During Review***

4-34

Tong, S. 2010, November 1. Placing Bets on Clean Energy. [Radio transcript]. American Public 

Media: Marketplace [Online]. Available: Marketplace Programs on Demand.

National Petroleum Council. 2011. Prudent Development: Realizing the Potential of North 

America's Abundant Natural Gas and Oil Resources. Available online at: 

http://www.npc.org/reports/rd.html.

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

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

Trigeorgis, Lenos. Real Options: Managerial Flexibility and Strategy in Resource Allocation.

1996. The MIT Press.

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

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

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available 

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

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

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

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

December. Available on the Internet at 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485. 

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

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

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

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

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

Mercury and Air Toxics Standards. Office of Air Quality Planning and Standards, 

Research Triangle Park, NC. December. Available on the Internet at 

http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the 

Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. 

Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. 

Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2013a. Technical Support Document 

Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of 

Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on 

the Internet at: 

http://www.epa.gov/airquality/benmap/models/Source_Apportionment_BPT_TSD_1_3

1_13.pdf.
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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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5-1

CHAPTER 5

ANALYSIS OF ILLUSTRATIVE COST-BENEFIT SCENARIOS

5.1 Synopsis

The previous chapter of this regulatory impact analysis (RIA) presents the U.S. 

Environmental Protection Agency’s (EPA) analysis and projections from the U.S. Energy 

Information Administration (EIA) that support the conclusion that the EGU New, Modified and 

Reconstructed Source Standards will result in negligible costs and benefits in the period of 

analysis. The EPA recognizes that this conclusion is based on underlying expected economic 

conditions (e.g., fuel prices) and assumptions about considerations investors would weigh in 

deciding whether to build new uncontrolled coal-fired power plants. Therefore, this chapter 

presents the results of several illustrative analyses that show, under a range of alternative 

conditions, the potential costs and benefits of these standards for individual investments that 

provide base load dispatchable generation. We evaluate conditions under which different 

generator types are constructed in lieu of a non-compliant supercritical coal unit and estimate 

the social benefit of adopting the investment that is compliant with the standards. This also 

allows us to consider idiosyncratic circumstances under which a unit that does not comply with 

these standards may be constructed. 

While the analysis in Chapter 4 focuses on national level conditions, the analysis in this 

chapter explores the potential impacts to individual investments. The analysis in this chapter 

finds that under unlikely conditions, in which the EPA’s conclusions regarding the future 

economic competitiveness of new non-compliant coal-fired units with respect to other new 

generation technologies shifts, or that idiosyncratic situations exist that favor the construction 

of units that would not comply with these standards, that the benefits of the standards to 

society outweigh the costs.

5.2 Comparison of Emissions from Generation Technologies

As discussed in Chapter 4, natural gas combined cycle (NGCC) units are on average 

expected to be more economical to build and operate than new coal units (See section 4.5).

Therefore, as our point of departure for comparing the costs and benefits of an individual 

investment decision, we evaluate the private and social cost of a new NGCC unit that is 

compliant with the finalized standards with a non-compliant conventional supercritical 
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5-2

pulverized coal (SCPC) coal-fired unit.1 When evaluating the costs and benefits associated with 

these standards, it is also important to understand the difference in emissions associated with 

these units. In addition to being more economical, new NGCC units also have lower emission

profiles for CO2 and criteria air pollutants than new coal units. For example, a typical new SCPC 

facility that burns bituminous coal in compliance with current utility regulations (e.g., the 

Mercury and Air Toxics Standards (MATS)) would have considerably greater CO2, sulfur dioxide 

(SO2), nitrogen dioxide (NOx), toxic metals, acid gases, and particulate emissions than a 

comparable NGCC facility. 

Table 5-1 shows, emissions from a typical new NGCC unit are significantly lower than 

those from a new coal-fired unit.2 The emission characteristics are based on, and thus 

consistent with, the cost and performance assumptions of the illustrative units described in 

LCOE analysis in section 4.5. That is, these are base load units of the same net capacity 

operating at an 85 percent capacity factor, the coal unit is assumed to be using bituminous coal 

with a sulfur content of 2.8% dry, they are in compliance with current utility regulations (e.g., 

the MATS), etc. The typical new NGCC unit would emit about 2.3 fewer million metric tons of 

CO2 per year than the typical new SCPC unit, as well as roughly 1,700 fewer short tons of SO2

and about 1,200 fewer short tons of NOx per year than the SCPC unit. Table 5-1 also provides

information for a representative integrated gasification combined cycle (IGCC) unit providing 

the same amount of electricity and using the same coal for comparison. The new IGCC unit 

would emit less CO2, SO2 and NOx than a typical coal-fired SCPC unit, but has higher emissions 

than a new NGCC unit. Reductions in SO2 emissions are a particularly significant driver for 

monetized health benefits, as SO2 is a precursor to the formation of particulates in the 

atmosphere, and particulates are associated with premature death and other serious health 

effects. Further information on these pollutants’ health and non-health effects is described in 

Chapter 3. 

 

1

As discussed in section [XX], we expect new NGCC capacity built in the period of analysis will be compliant with 

the standard even in the absence of the standard. As a result, there are no compliance costs anticipated for 

NGCC units.

2

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, amongst 

others.
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5-3

Table 5-1. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired 

Generating Units

Natural Gas CC SCPC SCPC+ Partial 

CCS (1,400 

lbs/MWh Gross)

IGCC IGCC+ Partial CCS 

(1,400 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 1,400 0.62 23 0.011 24 0.011

NOx 130 0.060 1,400 0.61 1,400 0.65 1,200 0.52 1,200 0.52

CO2

1.7 

million 800 4.0 million 1,800 3.4 million 1,500 3.8 million 1,700 3.7 million 1,700

Notes: SO2 and NOxin short tons, CO2in 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 in 

section 4.5 (i.e., these are base load units running at 85 percent capacity factor, all coal units are assumed to be using 

bituminous coal with a sulfur content of 2.8% dry, etc.). The tons of emissions are estimated for a coal-fired facility that 

achieves the gross-output standard of 1,400 lbs/MWh and presented in this table on a net output basis. For the postcombustion CCS system assumed in the SCPC case, acidic gases (e.g., SO2, HCl) need to be scrubbed to very low levels prior to

going to the CCS system to avoid degredation of the solvent. Therefore, SO2 emissions are lower in the case of the SCPC unit 

with partial CCS. See preamble for discussion about the format of the standard. Here we further assume all units are of the 

same capacity (600 MW net). 

5.3 Comparison of Health and Climate Impacts from Generation Technologies

As discussed in the previous section, the emissions of GHGs and other pollutants 

associated with new sources of electricity generation are greater for coal-fired units than for 

NGCC units. Reducing the emissions associated with electricity generation results in climate, 

human health and non-health benefits. 

To consider the health and climate benefits associated with the adoption of lower 

emitting new generation technologies, we apply the 2022 social benefit values discussed in 

Chapter 3 to the differences in illustrative emission profiles between the technologies in Table 

5-1. Specifically, we multiply the difference in CO2 emissions between two technologies by the 

estimates of the social cost of carbon dioxide (SC-CO2) (Table 3-1), multiply the difference in

sulfur dioxide (SO2) and nitrogen dioxide (NOX) emissions by the PM2.5-related SO2 and NOX

benefit per ton (BPT) estimates (Table 3-2), and add those values to get a measure of the 2022 

social benefits attributable to differences in emissions of adopting the lower emitting new 

generation technology. We subsequently divide by the number of MWh underlying the annual 

emissions estimates to derive the social benefits attributable to the differences in emissions per 

unit of generation. 
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5-4

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 

upstream greenhouse gas emissions (in particular, methane) from different technologies but 

those were not quantified for this assessment.

Table 5-2 reports the 2022 incremental climate and health benefits associated with an 

illustrative new NGCC unit relative to illustrative new coal-fired SCPC and IGCC units, given 

different mortality risk studies and assumptions about the discount rate.3The benefits

presented in Table 5-2 are estimated on an output basis to enable easier comparisons to the 

potential costs of investing in a new non-compliant coal-fired unit relative to a new NGCC unit. 

These incremental benefits should be relatively invariant across natural gas prices and other 

economic factors. Depending on the discount rate and mortality risk study used, 2022 

incremental benefits associated with generation from a representative new NGCC unit relative 

to a new coal-fired SCPC or IGCC unit are $7.0 to $97 per MWh (2011$).4

The precise health and welfare benefits associated with reduced CO2 emissions, which 

are the focus of this rule, depend on the specific fuels. However, the benefits of reduced CO2

emissions do not depend on the location of generation because the location of CO2 emissions 

does not influence their impact on the evolution of global climate conditions. As with the 

relative investment costs of a new coal-fired unit and a new NGCC unit, the precise incremental 

health co-benefits will be location specific and depend on the specific fuels used. However, 

these factors will not change the qualitative conclusion. There will be incremental 

 

3

The benefits estimated in this section are based on a single year (2022) of emissions from different generating 

technologies. Due to data limitations, we are not able to estimate annualized benefits from the stream of 

emissions over the lifetime of the generating technologies. Because the benefit per-ton of emission reductions 

increases over time, due in part to population growth, the single year estimate results in a conservative 

comparison of benefits to costs where LCOE represents annualized lifetime costs of generating technologies.

4

Different discount rates are applied to SC-CO2 than to the other benefit estimates because CO2 emissions are 

long-lived and subsequent damages occur over many years. Moreover, several rates are applied to SC-CO2

because the literature shows that it is sensitive to assumptions about discount rate and because no consensus 

exists on the appropriate rate to use in an intergenerational context. The SC-CO2 interagency working group 

centered its attention on the 3 percent discount rate but emphasized the importance of considering all four SCCO2 estimates. See the 2010 SC-CO2 TSD. Docket ID EPA-HQ-OAR-2009-0472-114577 or 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf for 

details.
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Table 5-2. 2022 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Illustrative 

New Natural Gas Combined Cycle Generation Relative to New Non-Compliant SCPC or 

IGCC Coal Generation1

SCPC IGCC

CO2-Related Benefits using SC-CO2

5% Discount Rate $6.1 $5.8

3% Discount Rate $21 $20

2.5% Discount Rate $31 $29

3% Discount Rate (95th percentile) $63 $60

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)

SC-CO2 Discount Rate 3% 7% 3% 7%

5% Discount Rate $22 to $41 $20 to $37 $7.2 to $8.9 $7.0 to $8.6

3% Discount Rate $36 to $55 $35 to $52 $21 to $23 $21 to $22

2.5% Discount Rate $46 to $66 $45 to $62 $31 to $32 $31 to $32

3% Discount Rate (95th percentile) $78 to $97 $77 to $94 $61 to $63 $61 to $62

Notes: The emission rates and operating characteristics of the units being compared in this table are reported in Table 5.1. Benefits are 

estimated for a 2022 analysis year. The range of benefits within each SC-CO2 value and discount rate for PM2.5-related benefits pairing 

reflects the use of two core estimates of PM2.5-related premature mortality.2The EPA has evaluated the range of potential impacts per 

MWh by combining all SC-CO2 values with health benefits values at the 3 percent and 7 percent discount rates. Combining the 3 percent 

SC-CO2 values with the 3 percent health benefit values assumes that there is no difference in discount rates between intragenerational 

and intergenerational impacts. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor 

reductions (Table 3-2), which are representative of 2022.

 

1

This analysis assumes representative new units and does not reflect the full array of new generating sources that could 

potentially be built (e.g., a comparison of a small new conventional coal-fired unit with a small natural gas-fired unit, or 

a comparison of a waste coal or petroleum coke-fired unit to a natural gas-fired unit of a comparable size and capacity 

factor). However, the incremental damages associated with other units that could be built, and which would be subject 

to this rule, would not change noticeably (i.e., these new facilities would be subject to emissions standards for other 

pollutants and would emit similar levels of SO2, NOX, and CO2, on an output basis) except for differences in location, as 

discussed previously.

2

The range of estimated benefits for each discount rate is due to the EPA’s use of two alternative primary estimates of 

PM2.5-related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a higher primary estimate 

based on Lepeule et al. (2012).
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5-1

climate and human health benefits associated with a new NGCC unit relative to a new coal-fired 

unit, independent of the location. 

The conclusion from this analysis is that there are significant environmental and health 

benefits associated with electricity generation from a representative new NGCC unit relative to 

a new conventional coal-fired unit. Other studies of the social costs of coal and natural gas-fired 

generation provide similar findings (Muller et. al., 2011; NRC, 2009).1

As explained previously, the power sector has moved away from the construction of 

coal-fired power plants in favor of 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 would be constructed during the analysis period. In these circumstances, units built with 

CCS in place of conventional coal-fired units would result in relative climate and human health 

and non-health benefits. Table 5-3 reports the 2022 incremental benefits associated with an 

illustrative new coal-fired unit with CCS relative to illustrative new SCPC and IGCC coal-fired 

units, 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, 2022 

incremental benefits associated with generation from a representative new coal-fired unit with 

CCS relative to a new coal-fired unit without CCS are $0.46 to $22 per MWh (2011$).2These 

incremental benefits will be referenced in the analyses presented in subsequent sections. 

 

1 Muller et al. 2011 conclude that, “coal-fired power plants have air pollution damages larger than their value 

added”, while the same is not true for natural gas plants (see Table 5). 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 NGCC units. Despite these caveats, the finding of these 

two studies are consistent with the findings in this section. 

2

Different discount rates are applied to SC-CO2 than to the other benefit estimates because CO2 emissions are 

long-lived and subsequent damages occur over many years. Moreover, several rates are applied to SC-CO2

because the literature shows that it is sensitive to assumptions about discount rate and because no consensus 

exists on the appropriate rate to use in an intergenerational context. The SC-CO2 interagency group centered its 

attention on the 3 percent discount rate but emphasized the importance of considering all four SC-CO2

estimates. See the 2010 SC-CO2 TSD for details. Docket ID EPA-HQ-OAR-2009-0472-114577 or 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf.
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Table 5-3. 2022 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from 

Compliant Coal- Fired Generation with CCS meeting 1,400 lbs/MWh Relative to 

New Non-Compliant Coal-Fired Generation 

SCPC IGCC 

CO2-Related Benefits using SC-CO2

5% Discount Rate $1.6 $0.46

3% Discount Rate $5.4 $1.6

2.5% Discount Rate $8.2 $2.3

3% Discount Rate (95th percentile) $17 $4.7

PM2.5-Related Benefits from SO2 and NOX Reductions

3% discount rate

Krewski et al. (2009) $2.2 *

Lepeule et al. (2012) $4.9 *

7% discount rate

Krewski et al. (2009) $2.0 *

Lepeule et al. (2012) $4.5 *

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%

5% Discount Rate $3.8 to $6.5 $3.6 to $6.1 $0.46

3% Discount Rate $7.6 to $10 $7.4 to $10 $1.6

2.5% Discount Rate $10 to $13 $10 to $13 $2.3

3% Discount Rate (95th percentile) $19 to $22 $19 to $21 $4.7

*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 (one cent or less per MWh) associated with these emissions increases. 

Notes: Benefits are estimated for a 2022 analysis year. The range of benefits within each SC-CO2 value and discount rate for 

PM2.5-related benefits pairing reflects the use of two core estimates of PM2.5-related premature mortality.3The EPA has 

evaluated the range of potential impacts per MWh by combining all SC-CO2 values with health benefits values at the 3 percent 

and 7 percent discount rates. Combining the 3 percent SC-CO2 values with the 3 percent health benefit values assumes that 

there is no difference in discount rates between intragenerational and intergenerational impacts. PM2.5-related co-benefits are 

estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 

2022.

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

Gas Prices

As the analysis in Chapter 4 demonstrated, under a wide range of likely electricity 

market conditions – including the EPA base case and EIA reference case scenarios as well as 

multiple alternative scenarios – it is expected that the industry will choose to construct new 

 

3

The range of estimated benefits for each discount rate is due to the EPA’s use of two alternative primary 

estimates of PM2.5-related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a 

higher primary estimate based on Lepeule et al. (2012).
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5-3

units that already meet the standards of this rulemaking, even in its absence. In this section, we 

consider the potential impacts of the regulation if key assumptions regarding natural gas prices 

were to change during the analysis period. The analysis in this section indicates that in this 

scenario, the standards for new sources would result in costs to the illustrative investor, but 

would also lead to climate and human health benefits, and is highly likely to provide net 

benefits to society as a whole. 4

Furthermore, this section demonstrates that local fuel prices must be significantly 

different than regional differences already captured in IPM and EIA’s modeling for private 

investment costs to favor a new uncontrolled coal-fired unit relative to a new NGCC unit serving

a particular load. Section 4.5.4 describes how regional conditions and other factors may 

influence the LCOE comparison, and how these regional differences are already captured in the 

electricity sector modeling in support of this rule. The 64 different regions in IPM are reflect the 

administrative structure of regional transmission organizations (RTOs) and independent system 

operators (ISOs).5 However, within those regions there may be local conditions which differ 

meaningfully from the broader regional conditions. The analysis in this section examines how 

substantially divergent those local conditions must be from representative conditions for noncompliant coal generation to be the technology of choice to serve demand. 

The starting point for this analysis is the illustrative comparison (presented in Section 

4.5) of the relative levelized cost of electricity (LCOE) of representative new coal-fired SCPC and 

IGCC EGUs and representative NGCC units.

6

This comparison demonstrates a significant 

difference in the LCOE between the coal-fired and natural gas-fired generating technologies. 

The estimated LCOE for a representative NGCC unit is roughly $32 and $37 per MWh less than 

 

4

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.

5

Further disaggregation of the NERC assessment regions and RTOs allows a more accurate characterization of the 

operation of the US power markets by providing the ability to represent transmission bottlenecks across RTOs 

and ISOs, as well as key transmission limits within them.

6

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

the form of electricity generating services. We assume in the discussion that the benefit of electricity 

production to consumers outweighs the private and social investment cost. However, a caveat of our 

comparison is that at particularly high fuel prices this might not be the case (that is, at high costs for both 

technologies, it may not be worthwhile to construct either). 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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for a representative new coal-fired SCPC or IGCC unit, respectively (see Figure 4-3).7This is 

consistent with the EPA’s expectation that the new source standards for steam units are not 

projected to impose any non-negligible costs or quantified benefits under current and likely 

future market conditions, as discussed in Chapter 4. The emissions associated with these 

technologies, and the benefits in terms of reduced damages of constructing and operating the 

illustrative NGCC unit in lieu of the illustrative non-compliant coal unit, are reported in the 

previous section.

To supplement this determination, this section presents an analysis of three relevant 

ranges within the distribution of future natural gas prices that can be classified as likely gas 

prices, unexpectedly high natural gas prices, and unprecedented natural gas prices. Because the 

cost of natural gas is a significant share of the LCOE for NGCC units, we evaluate how changes in 

natural gas prices affect differences in the relative private and social costs of new technologies.

We identify the natural gas price when the private costs, which are inclusive of the CUA, 

suggest that a new non-compliant coal may be adopted by an investor in lieu of a new NGCC 

unit. We then compare the social costs of these technologies, which is inclusive of both the 

private costs of these technologies and the damages from these technologies but exclusive of 

the CUA, at this natural gas price.8 We then identify the natural gas price when the social cost of 

investing in the illustrative new non-compliant coal unit is plausibly less than the social cost of 

the new illustrative NGCC unit. 

In general, this analysis shows that there would likely be a net social benefit, even under 

scenarios with higher than expected gas prices, if new compliant units were built in place of 

new non-compliant coal-fired units as a result of this rule.9 Under some conditions, higher

natural gas prices may result in a net social cost of constructing and operating new natural gas 

in lieu of non-compliant coal, holding all other parameters constant and disregarding social 

 

7

The reported decrease in the LCOE from adopting NGCC are relative to the SCPC with 3% CUA and IGCC without 

3% CUA.

8 When forecasting the behavior of private actors in choosing between different technologies based on expected 

future costs, we account for a climate uncertainty adder (CUA), but when comparing the difference in costs of 

illustrative new units after construction, such as in the analysis of the social costs of these technologies (i.e., the 

private cost plus the cost associated with their emissions), the CUA is not included. The CUA is described in 

section 4.5.3.

9

The benefits estimated in this section are based on a single year (2022) of emissions from different generating 

technologies. Due to data limitations, we are not able to estimate annualized benefits from the stream of 

emissions over the lifetime of the generating technologies. This results in a conservative comparison of 

benefits to costs where LCOE represents annualized lifetime costs of generating technologies.
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5-5

benefits that we are unable to monetize.

10 However, even under these unlikely conditions the 

social benefits of these finalized standards may yield social net benefits as there may be other 

technologies that would have a lower social cost than a new non-compliant coal unit. 

5.4.1 Likely Natural Gas Prices 

As shown in Chapter 4, it is only when natural gas prices exceed $10/MMBtu on a 

levelized basis (in 2011 dollars) that the representative new coal-fired SCPC unit without CCS 

likely becomes competitive in terms of its cost of electricity produced. None of the sensitivities

presented in Chapter 4 or the AEO2014 scenarios approach this natural gas price level on either 

a forward looking 20-year levelized price basis or on an average annual price basis at any point 

during the analysis period.

11

5.4.2 Unexpectedly High Natural Gas Prices

At natural gas prices above $10/mmBtu, the private levelized cost of electricity for a 

representative new coal-fired SCPC unit falls below that of a new NGCC unit. 12 Therefore, in the 

event of such unexpectedly high levelized fuel prices, some new coal-fired SCPC units might be 

constructed in the absence of this proposed rulemaking, provided that coal price do not rise at 

the same time, there is sufficient demand for electricity, and new non-compliant coal-fired 

SCPC units are competitive with other new and existing generating technologies other than 

NGCC units. In this scenario, there would be some compliance costs if a new NGCC unit or a 

compliant coal-fired unit were built as a result of the new fossil steam standard. However, 

generation from a new NGCC unit would also have incremental environmental and health 

benefits as it has less CO2 and PM2.5 (as a result of SO2 and NOx emissions) emissions than

 

10 As described below, an outcome where there are net social costs is unlikely to occur over our analysis period and 

for a significant period beyond. Even a situation where natural gas prices are significantly higher, such as very 

high economic growth, would increase both natural gas and coal prices at the same time - making it harder to 

alter the underlying cost advantage of NGCC generation. Furthermore, even in the situation where we report 

net social costs, it is important to recall that the analysis is limited in the types of benefits and costs considered, 

given that it does not account for the emissions associated with the production and delivery of natural gas and 

coal, the limitations of current SC-CO2 estimates, and the limited accounting of non-CO2 emissions benefits. As 

previously discussed, the current SC-CO2 estimates do not capture all important all of the physical, ecological, 

and economic impacts of climate change recognized in the climate change literature. Despite our attempts to 

quantify and monetize as many of the co-benefits as possible, the health and welfare co-benefits are not fully 

quantified or monetized in this assessment. For more information about unquantified health and welfare cobenefits please refer to tables 5-2 and 6-2 of the PM NAAQS RIA (U.S. EPA, 2012), respectively.

11 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.

12 The private levelized cost of the noncompliant SCPC unit is inclusive of the CUA. 
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generation from a new non-compliant coal-fired SCPC unit (as would a coal-fired unit that is 

compliant with the new standards; see Section 5.5).

For levelized natural gas prices of $10/mmBtu and somewhat higher, the resulting 

emission reduction benefits of building an NGCC unit, in place of a coal-fired SCPC unit, will 

outweigh the costs of constructing and operating an NGCC unit in lieu of a coal-fired SCPC unit. 

This observation indicates that the standard for new fossil steam sources would yield net 

benefits in the analysis year. For example, at a levelized gas price of $11/MMBtu, the 

illustrative NGCC unit would generate electricity for approximately $13/MWh more than the

coal-fired SCPC unit on a levelized basis,13 and result in incremental benefits from emissions 

reductions of $20 to $97/MWh (see analysis of 2022 relative benefits of NGCC: Table 5-2). The 

net benefit of this scenario would be $7.1 to $84/MWh.

For context, a natural gas price of $10/MMBtu (in 2011 dollars) is higher than any 

average annual natural gas price faced by the electric power sector since at least 1996, when 

the EIA historic data series begins.

14 The continued development of unconventional natural gas 

resources in the U.S. suggests that gas prices may actually tend to be towards the lower end of 

the historical range. In addition, the highest projected average levelized natural gas price during 

the analysis period of any of the AEO2014 scenarios cited in Chapter 4 is $8.45MMBtu (2012 $), 

which occurs in the Low Oil and Gas Resource scenario (see Table 4.6). As discussed in Chapter 

4, none of the EIA sensitivity cases (which account for future fuel prices for both gas and coal) 

show scenarios where non-compliant coal-fired units become more economic than NGCC units 

in the period of analysis.

5.4.3 Unprecedented Natural Gas Prices

At extremely high natural gas prices, the LCOE for a non-compliant coal-fired SCPC unit

could be sufficiently lower than the cost of a new NGCC unit, such that the net benefit of the 

standard in a given year could be negative (i.e., a net cost), at least under some ranges of 

benefit estimates. For example, at a levelized gas price of $14/MMBtu, the illustrative NGCC

unit would generate electricity for roughly $33/MWh more than the illustrative coal-fired SCPC, 

respectively, but result in social benefits from lower emissions of $20 to $97/MWh relative to 

the coal-fired SCPC unit (see analysis of 2022 relative benefits of NGCC: Table 5-2). If the 

 

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

prices. 

14 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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5-7

illustrative NGCC unit were built in lieu of the illustrative SCPC as a result of the new fossil

steam standard, the impact would range from a net social cost of $13/MWh to a net social 

benefit of $64/MWh relative to the illustrative SCPC.

As noted in the previous subsection, natural gas prices at these levels would be 

unprecedented. As a result, the EPA believes that the probability of levelized natural gas prices 

reaching levels at which this standard would generate net social costs 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 gas prices, we project 

that the new fossil steam 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. Furthermore, 

these results, complemented by the analysis in Chapter 4 on regional differences in levelized 

costs of these technologies, indicate that local differences in the cost of these technologies 

must be significantly different from representative conditions for non-compliant coal 

generation to be the technology of choice to serve demand. The probability that this proposed 

standard would result in net social costs is exceedingly low.

5.5 Illustrative Analysis – Benefits and Costs of Uncontrolled Coal and Compliant Coal 

As discussed in detail in the previous section and in Chapter 4, it is unlikely that a new 

non-compliant coal-fired unit would be constructed in the analysis period. The power sector 

continues to move away from the construction of coal-fired power plants in favor of natural 

gas-fired power plants due, in part, to the significant LCOE differential explored in the previous 

section. Even so, 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 need

for CCS could be accommodated and would not, based on the incremental cost of the CCS 

portion of the new unit, preclude the construction of the new coal-fired facility.15 One factor in 

 

15 The preamble provides a summary of existing sources that have demonstrated CCS as well as new coal-fired 

facilities that will utilize CCS and are very near to completion.
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determining that needing CCS would not preclude the construction of the new facility is the 

availability of Enhanced Oil Recovery (EOR) opportunities for new coal-fired facilities.16

This section evaluates the impacts that might occur if an investor, who otherwise 

wanted to construct a new non-compliant coal unit, chose to instead construct a new compliant 

coal-fired unit in response to the new fossil steam standard. In this scenario, this decision 

would result in some costs in order to build a unit with partial CCS or co-fire with natural gas. 17

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, the EPA analyzed the cost and 2022 

emission impacts of meeting the new source standards. While partial CCS is considered the best 

system of emission reductions (BSER) for these units, it would also be possible to meet the 

standard without CCS through co-firing natural gas, which is also analyzed. Consistent with the 

LCOE estimates provided in Table 4-5 (in Chapter 4), the partial capture CCS and cofiring natural 

gas scenarios achieve the proposed emissions rate of 1,400 lb CO2/MWh gross output.

The cost of CCS used to support this rule assumes that the geologic sequestration of CO2

will be in deep saline formations and accounts for the cost of doing so, but the EPA also 

recognizes the potential for sequestering CO2 for EOR and allows a source to provide CO2 for 

EOR (as well as enhanced gas recovery) as a compliance option. 

EOR refers to the injection of gases and/or fluids into a reservoir to increase oil 

production efficiency.18 CO2-EOR has been successfully used at many production fields 

throughout the United States. The oil and natural gas industry in the United States has over 40 

years of experience in injection and monitoring of CO2. This experience provides a strong 

foundation for the technologies used in the deployment of CCS on coal-fired electric generating 

units. Although deep saline formations provide the most CO2 storage opportunity (2,102 to 

 

16 The potential availability of EOR was not used in EPA’s evaluating the reasonableness of cost in determining the 

best system of emissions reduction. 

17 In this section we do not include a CUA for the illustrative new non-compliant SCPC and IGCC units as we are 

assuming that the investor will install construct and operate a new coal fired plant regardless. Furthermore, as 

in the previous section, when comparing the difference in costs of illustrative new units after construction, such 

as in the analysis of the social costs of these technologies (i.e., the private cost plus the cost associated with 

their emissions), the CUA is not included.

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

Storage Atlas, Fourth Edition.
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20,043 billion metric tons), oil and gas reservoirs are estimated to have 226 billion metric tons 

of CO2 storage resource.

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 in operation (e.g., Boundary Dam Energy Project, 

Saskatchewan, Canada) or under construction or at an advanced stage of planning, 70% intend 

to use captured CO2 to improve recovery of oil in mature fields, including Mississippi Power’s 

Kemper County Energy Facility, NRG Energy’s W.A. Parish Petra Nova CCS Project, Summit 

Power’s Texas Clean Energy Project, and the Hydrogen Energy California Project. The Texas 

Clean Energy project is planning to capture 90% of the CO2 and sell it for EOR.19

Therefore, in the near term, new coal-fired EGUs with CCS may be located in areas 

amenable to using the captured CO2 in EOR operations because these formations have been 

previously well characterized for hydrocarbon recovery, likely already have suitable 

infrastructure (e.g., wells, pipelines, etc.), and have an associated economic benefit of 

increasing oil well productivity. Furthermore, EPA believes the opportunity to engage in EOR 

opportunities is not significantly limited by the location of those opportunities or the current 

CO2 pipeline infrastructure (12 states currently have existing or under construction CO2

pipelines). Provision of electric power does not require coal-fired facilities to be co-located 

with the demand it is intended to serve. Please refer to Chapter 2 for a more detailed 

discussion of EOR, including its geographic availability, expected future growth, and overall 

impact on the economics of CCS.

There are two EOR opportunities evaluated in this section – ‘High’ and ‘Low.’ The high 

EOR opportunity assumes a CO2 sale price of $40 per metric ton; the low EOR opportunity 

assumes a CO2 sale price of $20 per metric ton based on assumptions used by NETL in 

evaluating potential EOR opportunities. 20 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

 

19 http://www.texascleanenergyproject.com/

20 The High and Low CO2 sale prices utilized by EPA are consistent with NETL’s Base Case and Low Case sale prices, 

respectively (http://www.netl.doe.gov/energy-analyses/pubs/storing%20co2%20w%20eor_final.pdf). In 

addition, this range is broadly consistent with the CO2 sale price data collected by the Department of Interior 

for projects located on federal lands (http://statistics.onrr.gov/ReportTool.aspx). Prices are expressed in 2011$ 

and the price is expected to be static over time.
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the practice.21 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.22 

Figure 5-1 compares the LCOE for an illustrative uncontrolled coal to coal with partial 

CCS both with and without EOR. It also provides the LCOE of an illustrative uncontrolled coal 

unit to the cost of a controlled unit cofiring natural gas. With the exception of the LCOE costs 

accounting for EOR, these costs were provided in Table 4-5. We see in Figure 5-1 that if a 

limited number of non-compliant coal-fired power plants would have be constructed in the 

analysis period, that the adoption of CCS could be accommodated and would not, based on the 

incremental cost of the CCS portion of the new unit, preclude the construction of the new coalfired facility. Furthermore, it shows that if it was not possible for a unit to provide CO2 for EOR, 

it may lower its costs by cofiring natural gas and still generate a substantial share of its 

production from coal. 

 

21 For EOR applications the point of sale is typically the facility fence line, in which case the coal facility operator 

will avoid the TSM cost. Consequently, the economic benefit of EOR to the investor in the coal plant may be 

greater than simply the price paid for CO2. 

22 This range is broadly consistent with estimates provided by NETL (http://www.netl.doe.gov/energyanalyses/pubs/QGESS_CO2T%26S_Rev2_20130408.pdf ) and the Global CCS Institute 

(http://www.globalccsinstitute.com/publications/economic-assessment-carbon-capture-and-storagetechnologies-2011-update). 
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Figure 5-1. Levelized Cost of Electricity, Uncontrolled Coal and Coal with Partial 

CCS (1,400 lbs/MWh gross). 2011$ 

Notes: 

(1) EIA estimated LCOE under AEO 2014 assumptions for uncontrolled SCPC is $116 (2011$). AEO 2014 

does not provide LCOE estimates for IGCC, or for full or partial CCS capture technologies.

23

(2) Uncontrolled SCPC requires NG cofiring to provide 43% of total heat input to achieve a 1,400 

lbs/MMBtu CO2 emission rate. Uncontrolled IGCC requires 6% NG cofiring.

(3) The partial control alternatives that achieve 1,400 #/MMBtu using carbon capture include the cost of 

transportion, storage and monitoring (TS&M).

Tables 5-4 and 5-5 show the costs and 2022 net benefits per MWh of each of adopting 

compliant coal in lieu of non-compliant coal. The EPA estimates of the benefits associated with 

avoided CO2, SO2, and NOX emissions using the methods described in Table 5-3. The cost 

estimates used are reported in Figure 5-1. While the levelized cost comparison in Figure 5-1 

focuses on the cost to the individual investor, the comparison of the uncontrolled coal unit to a 

scenario where the source sells CO2 for EOR includes the cost of TSM for CCS when monetizing 

the net benefits of this approach. This is because TSM will require real resources regardless of 

who pays for it. As before, it is important to note that these comparisons omit additional 

benefits that may be associated with the abatement of greenhouse gas emissions and other 

benefits associated with reducing SO2 and NOX emissions.

 

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

$0

$20

$40

$60

$80

$100

$120

SCPC IGCC

LC

OE ($/M

Wh, 2011$)

Uncontrolled (w/o CUA) Uncontrolled (w CUA) Partial CCS (1400#) no EOR

Partial CCS (1400#) $20 EOR Partial CCS (1400#) $40 EOR No CCS, 1400# via NG Cofiring
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Table 5-4. Illustrative 2022 Social Costs and Benefits for Compliant SCPC with Partial 

Capture or with Co-Firing Natural Gas Relative to Non-Compliant SCPC (per 

MWh 2011$)

Partial CCS

Co-Firing

Natural Gas

Additional LCOE a$16 $11

Revenue from EOR (Low - High EOR) $3.4 to $6.7 *

Additional LCOE, net of EOR $8.9 to $12 *

Value of Monetized Benefits for 2022 Emissions

SCC 5% with Krewski 3% to SCC 3% (95th) with Lepeule 3%b$3.8 to $22 $1.6 to $19

Net Monetized Benefits

Without EOR Revenue -$12 to $5.9 -$9.6 to $7.6

With EOR Revenuec-$8.4 to $13 *

a

For this comparison the LCOE of the representative SCPC without CCS does not include 3% CUA. 

b Table 5-3 reports these values for the comparison to the compliant unit with partial CCS. Benefits are estimated for 

a 2022 analysis year. Values shown are calculated using different discount rates. Four estimates of the SC-CO2 in the 

year 2022 were used: $14, $47, and $70 per metric ton (average SC-CO2 at discount rates of 5, 3, and 2.5 percent, 

respectively) and $140 per metric ton (95th percentile SC-CO2 at 3 percent). The average SC-CO2 at 5 percent 

produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate. See 

section 3.2 for complete discussion of these estimates. PM2.5-related co-benefits are estimated using 2020 

monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022.

C The cost of TSM is not included in this comparison even though this is an opportunity cost borne by society. 
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Table 5-5. Illustrative 2022 Social Costs and Benefits for Compliant IGCC with Partial 

Capture or with Co-Firing Natural Gas Relative to Non-Compliant IGCC (per MWh 

2011$)

Partial CCS

Co-Firing 

Natural Gas

Additional LCOEa$3.5 $1.7

Revenue from EOR (Low - High EOR)

$0.39 to

$0.78 *

Additional LCOE, net of EOR $2.7 to $3.1 *

Value of Monetized Benefits for 2022 Emissions

SCC 5% with Krewski 3% to SCC 3% (95th) with Lepeule 3%b$0.45 to $4.7 $0.27 to $2.8

Net Monetized Benefits 

Without EOR Revenue -$3 to $1.3 $1.4 to $1.1

With EOR Revenue -$2.6 to $2.1 *

a

For this comparison the LCOE of the representative IGCC without CCS does not include 3% CUA.

b

Table 5-3 reports these values for the comparison to the compliant unit with partial CCS. Benefits are estimated for a 

2022 analysis year. Values shown are calculated using different discount rates. Four estimates of the SC-CO2 in the year 

2022 were used: $14, $47, and $70 per metric ton (average SC-CO2 at discount rates of 5, 3, and 2.5 percent, 

respectively) and $142 per metric ton (95th percentile SC-CO2 at 3 percent). The average SC-CO2 at 5 percent produced 

the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate. See Section 3.2 for 

complete discussion of these estimates. PM2.5-related co-benefits are estimated using 2020 monetized health benefitsper-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022.

C The cost of TSM is not included in this comparison even though this is an opportunity cost borne by society. 

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

Consistent with EPA’s practice in evaluating the benefits and costs of significant rules, 

Chapter 4 uses detailed electricity sector modeling of expected market conditions to 

demonstrate that new EGUs expected to be built in the period of analysis would be in 

compliance with this proposed rule, even in the absence of this rule. As a result, the 

quantifiable benefits and costs of the standards, as measured in those deterministic settings, 

are expected to be negligible in the analysis period. That analysis is extended in this chapter to 

acknowledge unexpected conditions that could occur during the period of analysis in which the 

construction of a new non-compliant EGUs would be desirable from the perspective of an 

individual firm and evaluates the social costs and benefits of constructing a generating 

technology that complies with the proposed rule instead. This section further extends, and 

draws on, those analyses to discuss, qualitatively, the potential social benefits and costs of the 

standards from the perspective of an uncertain future. 

Firms operating in the power sector have a set of options available to address increases 

in electricity demand, such as increasing the utilization of existing generating capacity, 
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5-14

implementing energy efficiency programs to mitigate demand growth, or investing in new 

generating capacity. Within the category of investing in new generating capacity they are able 

to select amongst a set of generating technologies and energy sources. Uncertainty about 

future conditions that could impact the profitability of these different investment options 

means that retaining flexibility to react to future conditions and choose the most profitable 

investments has value to firms. The value associated with retaining flexibility and being able to 

select the most profitable investments in the future is referred to as “option value.”24 This rule 

does not impose a direct cost on firms by requiring them to take a specific action, instead the 

cost of this rule for firms is the lost option value associated with losing the ability to build a new 

fossil steam or combustion turbine EGU with an emissions rate above their respective 

standards. 

This option value is determined, in part, by the likelihood that the restricted choices 

would have been exercised in the future absent the policy and the cost of available substitutes. 

Since the analysis in Chapter 4 estimates that new natural gas combustion turbines forecast in 

the baseline, which meet the applicability criteria, will already meet the standards this 

discussion focuses on new fossil steam EGUs. As discussed in Chapter 4, it is highly unlikely that 

over the analysis period there will be enough expansion in relative fuel prices (e.g., natural gas 

prices relative to coal) to make a typical new fossil steam EGU cost competitive with available 

substitutes (e.g., NGCC, investing in energy efficiency program). Even in the unlikely event that 

this occurs, the incremental cost of constructing a compliant fossil steam EGU with partial CCS 

or an alternative compliance pathway will represent an upper bound on the costs to the firm 

due to the availability of substitute generation sources which might be able to provide a similar 

service at a lower cost. Given both of these reasons, the low likelihood of the restricted options 

being exercised in the baseline and availability of cost effective substitutes, on average the lost 

option value for firms is likely to be minimal.

Furthermore, as shown in the preceding sections, even when conditions arise where it is 

known with certainty that an outlying firm would find it most profitable to invest in a new noncompliant unit EGU over available alternatives in the baseline, the social benefits of restricting 

the choice set likely outweighs the costs to the firm. Therefore it will also be the case that 

expected social benefits from preventing new EGUs with an emissions rate above their 

respective standards, will likely outweigh the lost option value. 

 

24 We refer the interested reader to Dixit and Pindyck (1994) and Trigeorgis (1996) for more information on the 

concept of option value in the context of firms’ investment choices.
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A similar perspective may be applied to assessing the social costs of this rule. There are 

at least two notable differences when assessing the lost option value from society’s perspective

relative to the firm’s perspective. First, from society’s perspective the available substitution 

possibilities are greater as they are not bound by the conditions of a single firm but activities 

that may be pursued by electricity producers and consumers at large. Second, the benefits of 

adding a single new EGU for the purpose of diversifying the generation fleet across fuels to 

hedge against uncertainty in fuel markets, will likely be lower for society at large than for a 

single firm with a more limited generating fleet. 25 Both of these differences suggest that the 

lost option value from a social perspective is lower than what is already likely to a minimal lost 

option value for the average firm. 

It is difficult to precisely estimate the lost option value associated with this final rule 

given the numerous sources of uncertainty that influence investment decisions in the electricity 

sector and the existing modeling tools. However, the analysis reported in this chapter and the 

previous chapter has considered important variables that influence investment decisions in the 

electricity sector and found that across a wide range of potential outcomes this rule would have 

no quantifiable costs. Furthermore, considering the additional analysis in this chapter and the 

discussion above, the cost of the lost option value of the rule is concluded to be small. 

Additionally, if conditions arise that would have led to the construction of non-compliant EGUs 

absent the proposed rule, the quantifiable monetized social benefits of limiting the 

construction of those units likely exceeds the cost (even though not all social benefits are 

captured). However, as discussed throughout this RIA, when considering the most likely 

outcomes, the new source standards are anticipated to yield no monetized benefits and impose 

negligible costs over the analysis period. 

5.8 References

Dixit, Avinash and Pindyck, Robert. Investment Under Uncertainty. 1994. Princeton University 

Press.

 

25

 The option value associated with constructing a new EGU associated with a specific fuel source as part of a 

portfolio to hedge against uncertainty in future relative fuel prices will be conditional upon the current 

composition of the firm’s generation portfolio. If the current stock was constructed in expectation of relative 

fuel prices that more strongly favored higher emitting fuels, then the composition of the generating fleet may

already be too heavily weighted toward the ability to use those fuels, given the current expected distribution of 

relative fuel prices. Furthermore, the possibility to hedge against changes in fuel prices may be pursued by 

other means, such as risk contracts, and thus is not limited to the construction of generation sources with 

particular fuel sources. 
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5-16

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

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

10-013.

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

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

Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz, 

and W.H. White. 2009. “Reanalysis of the Harvard Six Cities Study and the American 

Cancer Society Study of Particulate Air Pollution and Mortality.” Special Report to the 

Health Effects Institute. Cambridge, MA. July.

Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. “Chronic Exposure to Fine Particles and 

Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.

Muller, N.Z., R. Mendelsohn, and W. Nordhaus. 2011. Environmental Accounting for Pollution in 

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

National Energy Technology Laboratory (NETL). Cost and Performance of PC and IGCC Plants for

a Range of Carbon Dioxide Capture. Revised Sept. 16, 2013. Available online at:

http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf. 

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

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

Trigeorgis, Lenos. Real Options: Managerial Flexibility and Strategy in Resource Allocation.

1996. The MIT Press.

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

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

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available 

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

U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the 

Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. 

Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. 

Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.
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CHAPTER 6 

MODIFIED AND RECONSTRUCTED SOURCE IMPACTS

6.1 Introduction

In addition to the standards for new sources analyzed in Chapter 4 and Chapter 5, this 

action also sets standards under Clean Air Act Section 111(b) for units that modify or 

reconstruct. For the reasons discussed in this chapter, the EPA also believes that the standards 

for modified and reconstructed fossil fuel-fired EGUs will result in minimal compliance costs, 

because we expect few modified or reconstructed EGUs in the period of analysis (through 

2022).

6.2 Reconstructed Sources

The new source performance standard (NSPS) provisions (40 CFR part 60, subpart A) 

define a “reconstruction” as the replacement of components of an existing facility to an extent 

that (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital 

cost that would be required to construct a comparable entirely new facility, and (2) it is 

technologically and economically feasible to meet the applicable standards. Historically, we are 

only aware of one EGU that has notified the EPA that it has reconstructed under the 

reconstruction provision of section 111(b). As a result, we anticipate that few EGUs will 

undertake reconstruction in the period of analysis. For this reason, the standards will not result 

in any significant emission reductions, costs, or quantified benefits in the period of analysis. 

Likewise, the Agency does not anticipate any impacts on the price of electricity or energy 

supply. The rule is not expected to raise any resource adequacy concerns, since reserve margins 

will not be impacted and the rule does not impose any additional requirements on existing 

facilities not triggering the reconstruction provision. There are no macroeconomic or

employment impacts expected as a result of these standards.

Due to the extremely limited data available on reconstructions, it is not possible to 

conduct a representative illustrative analysis of what costs and benefits might result from this 

rule in the unlikely case that a unit were to reconstruct.

6.3 Modified Sources

Historically, few EGUs have notified the EPA that they have modified under the 

modification provision of section 111(b). The EPA’s current regulations define an NSPS

“modification” as a physical or operational change that increases the source’s maximum 
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achievable hourly rate of emissions, but specifically exempt from that definition projects that 

entail the installation of pollution control equipment or systems. 

The EPA expects that most of the actions EGUs are likely to take in the foreseeable 

future that could be classified as “modifications” would qualify as pollution control projects. In 

many cases, those projects are likely to involve the installation of add-on control equipment 

needed to meet CAA requirements for criteria and air toxics air pollutants. Any associated CO2

emissions increases would likely be small and would occur as a chemical byproduct of the 

operation of the control equipment. In other cases, those projects would involve equipment 

changes to improve fuel efficiency to meet state requirements for implementation of the CAA 

section 111(d) rulemaking for existing sources and would have the effect of increasing a 

source’s maximum achievable hourly emission rate (lb CO2/hr), even while decreasing its actual 

output based emission rate (lb CO2/MWh). Because all of these actions would be treated as 

pollution control projects under the EPA’s current NSPS regulations, they would be specifically 

exempted from the definition of modification.

Given the limited information that we have about past modifications, the EPA has 

concluded that it lacks sufficient information to establish standards of performance for all types 

of modifications at steam generating units at this time. Instead, the EPA has determined that it 

is appropriate to establish standards of performance at this time for large-scale modifications

of steam generating units, such as major facility upgrades involving the reconstruction or 

replacement of steam turbines and other equipment upgrades that result in substantial 

increases in a unit’s potential hourly CO2 emissions rate. The EPA does not have sufficient 

information at this time to predict the full array of actions that existing steam generating units 

may undertake, including those in response to applicable requirements under an approved CAA 

section 111(d) plan. Additionally, it is not possible to predict which, if any, of these actions may 

result in increases in potential CO2 hourly emissions. Nevertheless, EPA expects that, to the 

extent actions are undertaken by existing steam generating units, the magnitude of the 

increases in potential hourly CO2 emissions associated with the vast majority of such changes

would generally be small and therefore would generally not be subject to the standards of 

performance for modified steam generating units finalized in this action.

Similar to the case of the steam generating units, the EPA also expect few existing 

stationary combustion turbines to modify during the period of analysis and become subject to 

the standards of performance the EPA is finalizing for such units in this action. Therefore, the 

EPA expects the standards associated with modified stationary combustion turbines to result in 

minimal, if any, compliance costs during the period of analysis.
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Based on this information, we anticipate that few EGUs will take actions that would be 

considered modifications and subject to the standards of performance finalized in this action 

during the period of analysis. For this reason, the standards will result in minimal emission 

reductions, costs, or quantified benefits in the period of analysis. Likewise, the Agency does not 

anticipate any impacts on the price of electricity or energy supplies. This rule is not expected to 

raise any resource adequacy concerns, since reserve margins will not be impacted and the rule 

does not impose any additional requirements on existing facilities not triggering the 

modification provision. There are no macroeconomic or employment impacts expected as a 

result of these standards.

Due to the limited data available on past modifications and the diversity of existing units 

that could potentially modify, it is not possible to conduct a representative illustrative analysis 

of what costs and benefits might result from this rule in the unlikely case that a unit were to 

take an action that would be classified as a modification.
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CHAPTER 7

STATUTORY AND EXECUTIVE ORDER REVIEWS

7.1 Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, 

Improving Regulation and Regulatory Review

This final action is a significant regulatory action that was submitted to the Office of 

Management and Budget (OMB) for review. It is a significant regulatory action because it raises 

novel legal or policy issues arising out of legal mandates. Any changes made in response to 

OMB recommendations have been documented in the established dockets for this action under 

Docket ID No. EPA-HQ-OAR-2013-0495 (Standards of Performance for Greenhouse Gas 

Emissions from New Stationary Sources: Electric Utility Generating Units) and Docket ID No. 

EPA-HQ-OAR-2013-0603 (Carbon Pollution Standards for Modified and Reconstructed 

Stationary Sources: Electric Utility Generating Units). This RIA includes an economic analysis of 

the potential costs and benefits associated with this action. 

The EPA does not anticipate that this final action will result in any notable compliance 

costs. Specifically, we believe that the standards for newly constructed fossil fuel-fired EGUs 

(electric utility steam generating units and natural gas-fired stationary combustion turbines) will 

have negligible costs associated with it over a range of likely sensitivity conditions because 

electric power companies will choose to build new EGUs that comply with the regulatory 

requirements of this action even in the absence of the action, because of existing and expected 

market conditions. (See Chapter 5 for further discussion of sensitivities). The EPA does not 

project any new coal-fired steam generating units without CCS to be built in the absence of this 

action. However, because some companies may choose to construct coal or other fossil fuelfired EGUs, the RIA also analyzes project-level costs of a unit with and without CCS, to quantify 

the potential cost for a fossil fuel-fired EGU with CCS.

The EPA also believes that the standards for modified and reconstructed fossil fuel-fired 

EGUs will result in minimal compliance costs, because, as previously stated, the EPA expects 

few modified or reconstructed EGUs in the period of analysis (through 2022). In Chapter 6, we 

discuss factors that limit our ability to quantify the costs and benefits of the standards for 

modified and reconstructed sources.

7.2 Paperwork Reduction Act (PRA)

The information collection activities in this final action have been submitted for 

approval to OMB under the PRA. The Information Collection Request (ICR) document that the 

EPA prepared has been assigned EPA ICR number [XX]. Separate ICR documents were prepared 
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and submitted to OMB for the proposed standards for newly constructed EGUs (EPA ICR 

number 2465.02) and the proposed standards for modified and reconstructed EGUs (EPA ICR 

number 2506.03). Because the CO2 standards for newly constructed, modified, and 

reconstructed EGUs will be included in the same new subpart (40 CFR part 60, subpart TTTT) 

and are being finalized in the same action, the ICR document for this action includes estimates 

of the information collection burden on owners and operators of newly constructed, modified, 

and reconstructed EGUs. Estimated cost burden is based on 2013 Bureau of Labor Statistics 

(BLS) labor cost data. Thus, all burden estimates are in 2013 dollars. Burden is defined at 5 CFR 

1320.3(b). You can find a copy of the ICR in the dockets for this action (Docket ID Numbers EPAHQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), and it is briefly summarized here. The 

information collection requirements are not enforceable until OMB approves them.

The recordkeeping and reporting requirements in this final action are specifically 

authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant 

to the recordkeeping and reporting requirements for which a claim of confidentiality is made is 

safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B.

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. When OMB 

approves this ICR, the Agency will announce that approval in the Federal Register and publish a 

technical amendment to 40 CFR part 9 to display the OMB control number for the approved 

information collection activities contained in this final action.

7.2.1 Newly constructed EGUs

This final action will impose minimal new information collection burden on owners and 

operators of affected newly constructed fossil fuel-fired EGUs (steam generating units and 

natural gas-fired stationary combustion turbines) beyond what those sources would already be 

subject to under the authorities of CAA parts 75 and 98. OMB has previously approved the 

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

CFR part 75 and 40 CFR part 98) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. and has assigned OMB control numbers 2060-0626 and 2060-0629, respectively. 

Apart from certain reporting costs 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 the standards for newly constructed EGUs is already collected and 
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reported by other regulatory programs.

The EPA believes that electric power companies will choose to build new EGUs that 

comply with the regulatory requirements of the rule because of existing and expected market 

conditions. The EPA does not project any newly constructed coal-fired steam generating units 

that commenced construction after proposal (January 8, 2014) to commence operation over 

the 3-year period covered by this ICR. We estimate that 17 affected newly constructed natural 

gas-fired stationary combustion turbines will commence operation during that time period. As a 

result of this final action, owners or operators of those newly constructed units will be required 

to prepare a summary report, which includes reporting of emissions and downtime, every 3 

months.

7.2.2 Modified and Reconstructed EGUs

This final action is not expected to impose an information collection burden under the 

provisions of the PRA on owners and operators of affected modified and reconstructed fossil 

fuel-fired EGUs (steam generating units and natural gas-fired stationary combustion turbines). 

As previously stated, the EPA expects few modified or reconstructed EGUs in the period of 

analysis. Specifically, the EPA believes it unlikely that fossil fuel-fired electric utility steam 

generating units or natural gas-fired stationary combustion turbines will take actions that 

would constitute modifications or reconstructions as defined under the EPA’s NSPS regulations. 

Accordingly, the standards for modified and reconstructed EGUs are not anticipated to impose 

any information collection burden over the 3-year period covered by this ICR. We have 

estimated, however, the information collection burden that would be imposed on an affected 

EGU if it was modified or reconstructed.

Although not anticipated, if an EGU were to modify or reconstruct, this final action 

would impose minimal information collection burden on those affected sources beyond what 

they would already be subject to under the authorities of CAA 40 CFR parts 75 and 98. As 

described above, the OMB has previously approved the information collection requirements 

contained in the existing part 75 and 98 regulations. Apart from certain reporting costs, which 

are mandatory for all owners/operators subject to CAA section 111 national emission 

standards, there would be no new information collection costs, as the information required by 

the final rule is already collected and reported by other regulatory programs.

As stated above, although the EPA expects few sources will trigger either the NSPS 

modification or reconstruction provisions, if an EGU were to modify or reconstruct during the 3-

year period covered by this ICR, the owner or operator of the EGU will be required to prepare a 
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summary report, which includes reporting of emissions and downtime, every 3 months. The 

annual reporting burden for such a unit is estimated to be $2,665 and 32 labor hours. There are 

no annualized capital costs or O&M costs associated with burden for modified or reconstructed 

EGUs.

7.2.3 Information Collection Burden

The annual information collection burden for newly constructed, modified, and 

reconstructed EGUs consists only of reporting burden as explained above. The annual reporting 

burden for this collection (averaged over the first 3 years after the effective date of the 

standards) is estimated to be $32,886 and 395 labor hours. There are no annualized capital 

costs or O&M costs associated with burden for newly constructed EGUs. Average burden hours 

per response are estimated to be 8 hours. The total number of respondents over the 3-year ICR 

period is estimated to be 37.

7.3 Regulatory Flexibility Act (RFA)

EPA certifies that this final action will not have a significant economic impact on a 

substantial number of small entities under the RFA. In making this determination, the impact of 

concern is any significant adverse economic impact on small entities. An agency may certify 

that a rule will not have a significant economic impact on a substantial number of small entities 

if the rule relieves regulatory burden, has no net burden or otherwise has a positive economic 

effect on the small entities subject to the rule.

7.3.1 Newly constructed EGUs

The EPA believes that electric power companies will choose to build new fossil fuel-fired 

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

comply with the regulatory requirements of the final rule because of existing and expected 

market conditions. The EPA does not project any new coal-fired steam generating units without 

CCS to be built. We expect that any newly constructed natural gas-fired stationary combustion 

turbines will meet the standards. We do not include an analysis of the illustrative impacts on 

small entities that may result from implementation of the final rule because we anticipate 

negligible compliance costs over a range of likely sensitivity conditions as a result of the 

standards for newly constructed EGUs. Thus the cost-to-sales ratios for any affected small 

entity would be zero costs as compared to annual sales revenue for the entity. Accordingly, 

there are no anticipated economic impacts as a result of the standards for newly constructed 

EGUs. We have therefore concluded that this final action will have no net regulatory burden for 

all directly regulated small entities.
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7.3.2 Modified and Reconstructed EGUs

The EPA expects few modified fossil fuel-fired electric utility steam generating units or 

natural gas-fired stationary combustion turbines in the period of analysis. An NSPS modification 

is defined as a physical or operational change that increases the source’s maximum achievable 

hourly rate of emissions. The EPA does not believe that there are likely to be EGUs that will take 

actions that would constitute modifications as defined under the EPA’s NSPS regulations.

In addition, the EPA expects few reconstructed fossil fuel-fired electric utility steam 

generating units or natural gas-fired stationary combustion turbines in the period of analysis. 

Reconstruction occurs when a single project replaces components or equipment in an existing 

facility and exceeds 50 percent of the fixed capital cost that would be required to construct a 

comparable entirely new facility.

In Chapter 6, we discuss factors that limit our ability to quantify the costs and benefits 

of the standards for modified and reconstructed sources. However, we do not anticipate that 

the rule would impose significant costs on those sources, including any that are owned by small 

entities.

7.4 Unfunded Mandates Reform Act (UMRA)

This final action does not contain an unfunded mandate of $100 million or more as 

described in UMRA, 2 U.S.C. 1531–1538, and does not significantly or uniquely affect small 

governments.

The EPA believes the final rule will have negligible compliance costs on owners and 

operators of newly constructed EGUs over a range of likely sensitivity conditions because 

electric power companies will choose to build new fossil fuel-fired electric utility steam 

generating units or natural gas-fired stationary combustion turbines that comply with the 

regulatory requirements of the rule because of existing and expected market conditions. The 

EPA does not project any new coal-fired steam generating units without CCS to be built and 

expects that any newly constructed natural gas-fired stationary combustion turbines will 

meet the standards.

As previously stated, the EPA expects few modified or reconstructed fossil fuel-fired 

electric utility steam generating units or natural gas-fired stationary combustion turbines in 

the period of analysis. In Chapter 6, we discuss factors that limit our ability to quantify the 

costs and benefits of the standards for modified and reconstructed sources. However, we do 

not anticipate that the rule would impose significant costs on those sources.
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We have therefore concluded that the standards for newly constructed, modified, and 

reconstructed EGUs do not impose enforceable duties on any state, local or tribal governments, 

or the private sector, that may result in expenditures by state, local and tribal governments, in 

the aggregate, or to the private sector, of $100 million or more in any one year. We have also 

concluded that this action does not have regulatory requirements that might significantly or 

uniquely affect small governments. The threshold amount established for determining whether 

regulatory requirements could significantly affect small governments is $100 million annually 

and, as stated above, we have concluded that the final action will not result in expenditures of 

$100 million or more in any one year. Specifically, the EPA does not project any new coal-fired 

steam generating units without CCS to be built and expects that any newly constructed natural 

gas-fired stationary combustion turbines will meet the standards. Further, the EPA expects few 

modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gasfired stationary combustion turbines in the period of analysis.

7.5 Executive Order 13132, Federalism

This final action does not have federalism implications. It will not have substantial direct 

effects on the states, on the relationship between the national government and the states, or 

on the distribution of power and responsibilities among the various levels of government. The 

EPA believes that electric power companies will choose to build new fossil fuel-fired electric 

utility steam generating units or natural gas-fired stationary combustion turbines that comply 

with the regulatory requirements of the final rule because of existing and expected market 

conditions. In addition, as previously stated, the EPA expects few modified or reconstructed 

fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion 

turbines in the period of analysis. We, therefore, anticipate that the final rule will impose 

minimal compliance costs.

7.6 Executive Order 13175, Consultation and Coordination with Indian Tribal 

Governments

This final action does not have tribal implications as specified in Executive Order 13175. 

The final rule will impose requirements on owners and operators of newly constructed, 

modified, and reconstructed EGUs. The EPA is aware of three facilities with coal-fired steam 

generating units, as well as one facility with natural gas-fired stationary combustion turbines, 

located in Indian Country, but is not aware of any EGUs owned or operated by tribal entities. 

We note that because the rule addresses CO2 emissions from newly constructed, modified, and 

reconstructed EGUs, it will affect existing EGUs such as those located at the four facilities in 

Indian Country only if those EGUs were to take actions constituting modifications or 
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reconstructions as defined under the EPA’s NSPS regulations. As previously stated, the EPA 

expects few modified or reconstructed EGUs in the period of analysis. Thus, the rule will neither 

impose substantial direct compliance costs on tribal governments nor preempt Tribal law. 

Accordingly, Executive Order 13175 does not apply to this action.

Nevertheless, because the EPA is aware of Tribal interest in carbon pollution standards 

for the power sector and, consistent with the EPA Policy on Consultation and Coordination with 

Indian Tribes, the EPA offered consultation with tribal officials during development of this rule. 

Prior to the April 13, 2012 proposal (77 FR 22392), the EPA sent consultation letters to the 

leaders of all federally recognized tribes. Although only newly constructed, modified, and 

reconstructed EGUs will be affected by this action, the EPA’s consultation regarded planned 

actions for new and existing sources. The letters provided information regarding the EPA’s 

development of NSPS and emission guidelines for EGUs and offered consultation. A 

consultation/outreach meeting was held on May 23, 2011, with the Forest County Potawatomi 

Community, the Fond du Lac Band of Lake Superior Chippewa Reservation, and the Leech Lake 

Band of Ojibwe. A description of that consultation is included in the preamble to the proposed 

standards for new EGUs (79 FR 1501, January 8, 2014).

The EPA also offered consultation to the leaders of all federally recognized tribes after 

the proposed action for newly constructed EGUs was signed on September, 20, 2013. On 

November 1, 2013, the EPA sent letters to tribal leaders that provided information regarding 

the EPA’s development of carbon pollution standards for new, modified, reconstructed and 

existing EGUs and offered consultation. No tribes requested consultation regarding the 

standards for newly constructed EGUs.

In addition to offering consultation, the EPA also conducted outreach to tribes during 

development of this rule. The EPA held a series of listening sessions prior to proposal of GHG 

standards for newly constructed EGUs. Tribes participated in a session on February 17, 2011, 

with the state agencies, as well as in a separate session with tribes on April 20, 2011. The EPA 

also held a series of listening sessions prior to proposal of GHG standards for modified and 

reconstructed EGUs and GHG emission guidelines for existing EGUs. Tribes participated in a 

session on September 9, 2013, together with the state agencies, as well as in a separate tribeonly session on September 26, 2013. In addition, an outreach meeting was held on September 

9, 2013, with tribal representatives from some of the federally recognized tribes. The EPA also 

met with tribal environmental staff with the National Tribal Air Association, by teleconference, 

on July 25, 2013, and December 19, 2013. Additional detail regarding this stakeholder outreach 
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is included in the preamble to the proposed emission guidelines for existing EGUs (79 FR 34830, 

June 18, 2014).

7.7 Executive Order 13045, Protection of Children from Environmental Health Risks and 

Safety Risks

This action is not subject to Executive Order 13045 because it is not economically 

significant as defined in Executive Order 12866. While the action is not subject to Executive 

Order 13045, the EPA believes that the environmental health or safety risk addressed by this 

action has a disproportionate effect on children. Accordingly, the agency has evaluated the 

environmental health and welfare effects of climate change on children. 

CO2 is a potent greenhouse gas that contributes to climate change and is emitted in 

significant quantities by fossil fuel-fired power plants. The EPA believes that the CO2 emission 

reductions resulting from implementation of these final guidelines, as well as substantial ozone 

and PM2.5 emission reductions as a co-benefit, will further improve children’s health. 

The assessment literature cited in the EPA’s 2009 Endangerment Finding concluded that 

certain populations and lifestages, including children, the elderly, and the poor, are most 

vulnerable to climate-related health effects. The assessment literature since 2009 strengthens 

these conclusions by providing more detailed findings regarding these groups’ vulnerabilities 

and the projected impacts they may experience.

These assessments describe how children’s unique physiological and developmental 

factors contribute to making them particularly vulnerable to climate change. Impacts to 

children are expected from heat waves, air pollution, infectious and waterborne illnesses, and 

mental health effects resulting from extreme weather events. In addition, children are among 

those especially susceptible to most allergic diseases, as well as health effects associated with 

heat waves, storms, and floods. Additional health concerns may arise in low income 

households, especially those with children, if climate change reduces food availability and 

increases prices, leading to food insecurity within households.

More detailed information on the impacts of climate change to human health and 

welfare is provided in Section II.A of the preamble.

7.8 Executive Order 13211, Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use

This final action is not a “significant energy action” because it is not likely to have a 

significant adverse effect on the supply, distribution, or use of energy. The EPA believes that 
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electric power companies will choose to build new fossil fuel-fired electric utility steam 

generating units or natural gas-fired stationary combustion turbines that comply with the 

regulatory requirements of the final rule because of existing and expected market conditions. In 

addition, as previously stated, the EPA expects few modified or reconstructed fossil fuel-fired 

electric utility steam generating units or natural gas-fired stationary combustion turbines in the 

period of analysis. Thus, this action is not anticipated to have notable impacts on emissions, 

costs or energy supply decisions for the affected electric utility industry.

7.9 National Technology Transfer and Advancement Act

This final action involves technical standards. The following voluntary consensus 

standards are used in the final rule: American Society for Testing and Materials (ASTM) 

Methods D388-12 (Standard Classification of Coals by Rank), D396-13c (Standard Specification 

for Fuel Oils), D975-14 (Standard Specification for Diesel Fuel Oils), D3699-13b (Standard 

Specification for Kerosene), D6751-12 (Standard Specification for Biodiesel Fuel Blend Stock 

(B100) for Middle Distillate Fuels), D7467-13 (Standard Specification for Diesel Fuel Oil, 

Biodiesel Blend (B6 to B20)), and American National Standards Institute (ANSI) Standard C12.20 

(American National Standard for Electricity Meters - 0.2 and 0.5 Accuracy Classes). The rule also 

requires use of Appendices A, B, D, F and G to 40 CFR part 75; these Appendices contain 

standards that have already been reviewed under the NTTAA.

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

Populations and Low-Income Populations

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

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

extent practicable and permitted by law, to make environmental justice part of their mission by 

identifying and addressing, as appropriate, disproportionately high and adverse human health 

or environmental effects of their programs, policies and activities on minority populations and 

low-income populations in the U.S. The EPA defines environmental justice as the fair treatment 

and meaningful involvement of all people regardless of race, color, national origin, or income 

with respect to the development, implementation, and enforcement of environmental laws, 

regulations, and policies. The EPA has this goal for all communities and persons across this 

Nation. It will be achieved when everyone enjoys the same degree of protection from 

environmental and health hazards and equal access to the decision-making process to have a 

healthy environment in which to live, learn, and work.
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Leading up to this rulemaking the EPA summarized the public health and welfare effects 

of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment Finding, the

Administrator considered climate change risks to minority or low-income populations, finding 

that certain parts of the population may be especially vulnerable based on their circumstances. 

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. See 

Sections F and G, above, where EPA discusses Consultation and Coordination with Tribal 

Governments and Protection of Children. The Administrator placed weight on the fact that 

certain groups, including children, the elderly, and the poor, are most vulnerable to climaterelated health effects.

Strong scientific evidence that the potential impacts of climate change raise 

environmental justice issues is found in the major assessment reports by the U.S. Global 

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

and the National Research Council (NRC) of the National Academies, summarized in the record 

for the Endangerment Finding. Their conclusions include that poor communities can be 

especially vulnerable to climate change impacts because they tend to have more limited 

adaptive capacities and are more dependent on climate-sensitive resources such as local water 

and food supplies. In addition, Native American tribal communities possess unique 

vulnerabilities to climate change, particularly those on established reservations that are 

restricted to reservation boundaries and therefore have limited relocation options. Tribal 

communities whose health, economic well-being, and cultural traditions depend upon the 

natural environment will likely be affected by the degradation of ecosystem goods and services 

associated with climate change. 

Southwest native cultures are especially vulnerable to water quality and availability 

impacts. Native Alaskan communities are likely to experience disruptive impacts, including 

coastal erosion and shifts in the range or abundance of wild species crucial to their livelihoods 

and well-being. The most recent assessments continue to strengthen scientific understanding 

of climate change risks to minority and low-income populations in the United States.1The new 

 

1 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United 

States: The Third National Climate Assessment. U.S. Global Change Research Program, 841 pp.

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects.

Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate 

Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. 
***E.O. 12866 Review – Do Not Cite, Quote, or Release During Review***

7-11

assessment literature provides more detailed findings regarding these populations’ 

vulnerabilities and projected impacts they may experience. In addition, the most recent 

assessment literature provides new information on how some communities of color may be 

uniquely vulnerable to climate change health impacts in the United States. These studies find 

that certain climate change related impacts—including heat waves, degraded air quality, and 

extreme weather events—have disproportionate effects on low-income and some communities 

of color, raising environmental justice concerns. Existing health disparities and other inequities 

in these communities increase their vulnerability to the health effects of climate change. In 

addition, the studies also find that climate change poses particular threats to health, wellbeing, 

and ways of life of indigenous peoples in the United States.

As the scientific literature presented above and in the Endangerment Finding illustrates, 

low income communities and communities of color are especially vulnerable to the health and 

other adverse impacts of climate change.

The EPA believes the human health or environmental risk addressed by this final action 

will not have potential disproportionately high and adverse human health or environmental 

effects on minority, low-income or indigenous populations. The final rule limits GHG emissions 

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

generating units and natural gas-fired stationary combustion turbines by establishing national 

emission standards for CO2.

The EPA has determined that the final rule will not result in disproportionately high and 

adverse human health or environmental effects on minority, low-income or indigenous 

populations because the rule is not anticipated to notably affect the level of protection 

provided to human health or the environment. The EPA believes that electric power companies 

will choose to build new fossil fuel-fired electric utility steam generating units and natural gasfired stationary combustion turbines that comply with the regulatory requirements of the final 

rule because of existing and expected market conditions. The EPA does not project any new 

 

Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, 1132 pp.

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects. 

Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate 

Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. 

Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, 688 pp.
***E.O. 12866 Review – Do Not Cite, Quote, or Release During Review***

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coal-fired steam generating units without CCS to be built and expects that any newly built 

natural gas-fired stationary combustion turbines will meet the standards. In addition, as 

previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility 

steam generating units or natural gas-fired stationary combustion turbines in the period of 

analysis. This final rule will ensure that, to whatever extent there are newly constructed, 

modified, and reconstructed EGUs, they will use the best performing technologies to limit 

emissions of CO2.

7.11 Congressional Review Act (CRA)

This final action is subject to the CRA, and the EPA will submit a rule report to each 

House of the Congress and to the Comptroller General of the United States. This action is not a 

“major rule” as defined by 5 U.S.C. 804(2).