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Agency
Regulatory Impact Analysis for the Proposed Standards of
Performance for Greenhouse Gas Emissions for New Stationary
Sources: Electric Utility Generating Units
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EPA-452/R-12-001
March 2012
Regulatory Impact Analysis for the Proposed Standards of Performance for Greenhouse Gas
Emissions for New Stationary Sources: Electric Utility Generating Units
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Health and Environmental Impacts Division
Research Triangle Park, NC
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CONTACT INFORMATION
This document has been prepared by staff from the Office of Air Quality Planning and
Standards, U.S. Environmental Protection Agency. Questions related to this document should be
addressed to Amanda Curry Brown, U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, C439-02, Research Triangle Park, North Carolina 27711 (email:
CurryBrown.Amanda@epa.gov).
ACKNOWLEDGEMENTS
In addition to EPA staff from the Office of Air Quality Planning and Standards,
personnel from the U.S. EPA Office of Atmospheric Programs and Office of Policy contributed
data and analysis to this document.
in
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ACRONYMS
AEO
BACT
CAA
CCS
CH4
C02
CSAPR
DOE
EAB
ECU
ECU GHG NSPS
EIA
EO
EOR
EPA
FERC
GHG
HFC
HRSG
ICR
IGCC
IOU
IPCC
IPM
kWh
MATS
mmBtu
MW
MWh
N20
NEEDS
NETL
NGCC
Annual Energy Outlook
Best Available Control Technology
Clean Air Act
Carbon Capture and Sequestration or Carbon Capture and Storage
Methane
Carbon Dioxide
Cross State Air Pollution Rule
U.S. Department of Energy
Environmental Appeals Board
Electric Generating Unit
Standards of Performance for Greenhouse Gas Emissions for New
Stationary Sources for Electric Utility Generating Units
U.S. Energy Information Administration
Executive Order
Enhanced Oil Recovery
U.S. Environmental Protection Agency
Federal Energy Regulatory Commission
Greenhouse Gas
Hydrofluorocarbons
Heat Recovery Steam Generator
Information Collection Request
Integrated Gasification Combined Cycle
Investor Owned Utility
Intergovernmental Panel on Climate Change
Integrated Planning Model
Kilowatt-hour
Mercury and Air Toxics Standards
Million British Thermal Units
Megawatt
Megawatt-hour
Nitrous Oxide
National Electric Energy Data System
National Energy Technology Laboratory
Natural Gas Combined Cycle
IV
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NOX
NRC
NSPS
NTTAA
O&M
OMB
PC
PM2.5
PRA
PSD
psi
RFA
RIA
SBA
SBREFA
SCC
SF6
SIP
S02
SPC
Tcf
TSD
UMRA
USGCRP
VCS
Nitrogen Oxide
National Research Council
New Source Performance Standard
National Technology Transfer and Advancement Act
Operations and Maintenance
Office of Management and Budget
Pulverized Coal
Fine Particulate Matter
Paperwork Reduction Act
Prevention of Significant Deterioration
Pounds per Square Inch
Regulatory Flexibility Act
Regulatory Impact Analysis
Small Business Administration
Small Business Regulatory Enforcement Fairness Act
Social Cost of Carbon
Sulfur Hexafluoride
State Implementation Plan
Sulfur Dioxide
Supercritical Pulverized Coal
Trillion Cubic Feet
Technical Support Document
Unfunded Mandates Reform Act
U.S. Global Change Research Program
Voluntary Consensus Standards
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TABLE OF CONTENTS
Executive Summary ES-1
ES.l Background and Context of Proposed Rule ES-1
ES.2 Summary of Proposed Rule ES-2
ES.3 Key Findings of Economic Analysis ES-3
Chapter 1 Introduction and Background 1-1
1.1 Introduction 1-1
1.2 Background 1-1
1.3 Regulatory Analysis 1-1
1.4 Regulated Entities 1-3
1.5 Regulated Pollutant 1-3
1.6 Baseline and Years of Analysis 1-4
1.7 Organization of the Regulatory Impact Analysis 1-4
Chapter 2 Control Strategies 2-1
2.1 Synopsis 2-1
2.2 Definition of Affected Sources 2-1
2.3 Control Strategies 2-4
2.4 Analytical Baseline 2-4
2.5 Emission Reductions 2-4
Appendix 2A Potential Transitional Units 2A-1
VI
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Chapter 3 Defining the Climate Change Problem and Rationale for Rulemaking 3-1
3.1 Overview of Climate Change Impacts from GHG Emissions 3-1
3.2 References 3-10
Chapter 4 Electric Power Sector Profile 4-1
4.1 Introduction 4-1
4.2 Power Sector Overview 4-1
4.3 Deregulation and Restructuring 4-6
4.4 Emissions of Greenhouse Gases from Electric Utilities 4-7
4.5 Pollution Control Technologies 4-11
4.6 GHG Regulation in the Power Sector 4-16
4.7 Revenues, Expenses, and Prices 4-18
4.8 Electricity Demand and Demand Response 4-22
4.9 References 4-24
Chapter 5 Costs, Benefits, Economic, and Energy Impacts 5-1
5.1 Synopsis 5-1
5.2 Background 5-1
5.3 External Review of EPA Applications of IPM 5-6
5.4 IPM is a Detailed Bottom-Up Model 5-7
5.5 Base Case and Sensitivity Analysis of Future Generating Capacity 5-8
5.6 Analysis of Applicability of Proposed ECU GHG NSPS to Projected New
Generating Capacity 5-14
5.7 Costs, Economic, and Energy Impacts of the Proposed Rule for New
Electric Generating Units 5-19
5.8 Comparison of Emissions from Generation Technologies 5-19
5.9 Benefits of Reducing GHGs and Conventional Pollutants 5-21
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5.10 Illustrative Analysis of the Social Costs of New Generating Sources 5-26
5.11 Macroeconomic and Employment Impacts 5-37
5.12 References 5-37
Chapter 6 Statutory and Executive Order Analyses 6-1
6.1 Synopsis 6-1
6.2 Executive Order 12866, Regulatory Planning and Review, and Executive
Order 13563, Improving Regulation and Regulatory Review 6-1
6.3 Paperwork Reduction Act 6-2
6.4. Regulatory Flexibility Act as Amended by the Small Business Regulatory
Enforcement Fairness Act of 1996, 5 U.S.C. et seq 6-4
6.5 Unfunded Mandates Reform Act of 1995 6-7
6.6 Executive Order 13132, Federalism 6-8
6.7 Executive Order 13175, Consultation and Coordination with Indian Tribal
Governments 6-9
6.8 Executive Order 13045, Protection of Children from Environmental Health
Risks and Safety Risks 6-10
6.9 Executive Order 13211, Actions Concerning Regulations That Significantly
Affect Energy Supply, Distribution, or Use 6-10
6.10 National Technology Transfer and Advancement Act 6-11
6.11 Executive Order 12898: Federal Actions to Address Environmental Justice in
Minority Populations and Low-Income Populations 6-11
VIM
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LIST OF TABLES
Table 4-1. Existing Electricity Generating Capacity by Energy Source, 2009 4-2
Table 4-2. Total U.S. Electric Power Industry Retail Sales in 2010 (Billion kWh) 4-2
Table 4-3. Electricity Net Generation in 2010 (Billion kWh) 4-3
Table 4-4. Coal Steam Electricity Generating Units, by Size, Age, Capacity, and Thermal
Efficiency (Heat Rate) 4-4
Table 4-5. Domestic Emissions of Greenhouse Gases, by Economic Sector (million metric
tons of C02 equivalent) 4-8
Table 4-6. Electricity Generation-Related Greenhouse Gas Emissions, 2009 (million metric
tons of C02 equivalent) 4-9
Table 4-7. Fossil Fuel Emission Factors in EPA Modeling Applications 4-10
Table 4-8. Existing Coal-Fired ECU Efficiency Improvements Reported for Actual Efficiency
Improvement Projects 4-14
Table 4-9. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities
for 2010 (Smillions) 4-19
Table 4-10. Projected Revenues by Service Category in 2015 for Public Power and Investor-
Owned Utilities (billions) 4-20
Table 5-1. Total Generation Capacity in 2010 and Projected by 2020 (GW) 5-10
Table 5-2. 2010 U.S. Electricity Net Generation and EPA Base Case Projections for 2020
(Billion kWh) 5-10
Table 5-3. Projected New Capacity in 2020 5-14
Table 5-4. Estimated Levelized Cost of New Generation Resources from EIA, U.S. Average
(2016) 5-18
Table 5-5. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired
Generating Units 5-21
Table 5-6. Social Cost of C02, 2015-2050 (in 2007 dollars) 5-24
Table 5-7. Pollution Damages ($/MWh) from Illustrative New Coal Unit Relative to New
Natural Gas Combined Cycle Unit 5-30
Table 5-8. Illustrative Costs and Benefits for two CCS Scenarios Compared to Conventional
Coal Plant (per MWh 2007$) 5-36
Table 6-1. Potentially Regulated Categories and Entities 6-5
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LIST OF FIGURES
Figure 4-1. Fossil Fuel-Fired Electricity Generating Facilities, by Size 4-5
Figure 4-2. Status of State Electricity Industry Restructuring Activities 4-7
Figure 4-3. Domestic Emissions of Greenhouse Gases, 2009 (million metric tons of C02
equivalent) 4-8
Figure 4-4. GHG Emissions from the Power Sector Relative to Total Domestic GHG Emissions
(2009) 4-10
Figure 4-5. Post-Combustion C02 Capture for a Pulverized Coal Power Plant 4-12
Figure 4-6. Pre-Combustion C02 Capture for an IGCC Power Plant 4-13
Figure 4-7. National Average Retail Electricity Price (1960 - 2009) 4-20
Figure 4-8. Average Retail Electricity Price by State (cents/kWh), 2009 4-21
Figure 4-9. Natural Gas Spot Price, Annual Average (Henry Hub) 4-22
Figure 4-10. Electricity Growth Rate (3 Year Rolling Average) and Projections from the Annual
Energy Outlook 2011 4-23
Figure 5-1. Historical U.S. Power Plant Capacity Additions, by Technology 5-4
Figure 5-2. Projected Levels of Electricity Demand in 2020, EPA and EIA 5-12
Figure 5-3. Projected Natural Gas Prices in 2020, EPA and EIA (Delivered, Power Sector). 5-13
Figure 5-4. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation
Technologies, EPA 5-16
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EXECUTIVE SUMMARY
This Regulatory Impact Analysis (RIA) discusses potential benefits, costs, and economic
impacts of the proposed Standards of Performance for Greenhouse Gas Emissions for New
Stationary Sources for Electric Utility Generating Units (herein referred to as ECU GHG NSPS).
ES.l Background and Context of Proposed Rule
The proposed ECU GHG NSPS will limit greenhouse gas emissions (GHG) from new fossil
fuel fired electric generating units (ECU) constructed in the United States in the future.1 This
rulemaking will apply to carbon dioxide (C02) emissions from new electric generating sources
that exceed 25 megawatts (MW) in capacity. The United States Environmental Protection
Agency (EPA) is proposing requirements for these sources because C02 is a GHG and power
plants are the country's largest stationary source emitters of GHGs. As stated in the EPA's
Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of
the Clean Air Act (74 FR 66,518; Dec. 15, 2009) and summarized in Chapter 3 of this RIA, the
anthropogenic buildup of GHGs in the atmosphere is very likely the cause of most of the
observed global warming over the last 50 years. This action is taken in response to a proposed
settlement agreement entered into on December 23, 2010 to issue rules that will deal with
GHGs from certain fossil fuel-fired EGUs.
The statutory authority for this action is the Clean Air Act (CAA) section lll(b), which
covers the regulation of new, modified, and reconstructed sources. For the purposes of this
rule, a new source is one that commences construction after the publication of the proposed
rule, other than those sources EPA has classified as "transitional" sources described later in this
RIA. A reconstructed source is generally defined as an existing source that conducts extensive
replacement of components and is treated as a new source under CAA section 111. A
modification is any physical change in, or change in the method of operation of, a source that
increases the amount of any air pollutant emitted by the source or results in the emission of
any air pollutant not previously emitted.
EPA is not proposing a standard of performance for a group of sources it is calling
transitional sources as long as they commence construction2 within 12 months from the date of
1 For purposes of this rule, covered EGUs do not include simple cycle combustion turbines. In addition, units
subject to emission requirements under the CAA solid waste combustion provisions (Section 129) would not be
subject to requirements under this proposed rule.
2 EPA's regulations define "commenced construction" as, in general, undertaking a continuous program of
construction or entering into a binding contract to do so (40 CFR 51.165).
ES-1
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this proposal. Transitional sources are affected EGUs that have received approval for their
complete Prevention of Significant Deterioration (PSD) preconstruction permits, but that have
not "commenced construction" by the date of today's proposed rulemaking. EPA is aware of
approximately 15 transitional sources, six of which are expected to utilize carbon capture and
sequestration (CCS) technology.
CAA section lll(d) covers regulation of existing stationary sources that are not
regulated under other parts of the CAA (i.e., pollutants regulated under NAAQS requirements
or NESHAP requirements) and to which a new source performance standard (NSPS) would apply
if such existing source were a new source. This rulemaking affects CAA section lll(b) new
sources of GHG emissions from fossil fuel-fired EGUs but does not address GHG emissions from
existing sources. EPA is currently examining options for developing C02 emission guidelines that
will be used by states to develop plans establishing standards of performance as required by
CAA section lll(d). CAA Section 111 (b) requires that this standard be reviewed every eight
years, thus this regulatory requirement will likely be reviewed and potentially revised after the
2020 timeframe. Therefore, this economic analysis focuses on benefits and costs of this
proposal for the years through 2020.
This proposed rule is consistent with the President's goal to ensure that "by 2035 we
will generate 80 percent of our electricity from a diverse set of clean energy sources - including
renewable energy sources like wind, solar, biomass and hydropower, nuclear power, efficient
natural gas, and clean coal."3 Additionally, this rule demonstrates to other countries that the
United States is taking action to limit GHGs from its largest emissions sources, in line with our
international commitments. The impact of GHGs is global, and U.S. action to reduce GHG
emissions complements ongoing programs and efforts in other countries.
ES.2 Summary of Proposed Rule
This proposal requires that all new fossil-fuel fired units that exceed 25 MW in capacity
be able to meet an emission rate standard of 1,000 pounds of C02 per megawatt hour (Ibs
C02/MWh) calculated over a rolling 12-month period. It also proposes an alternative
compliance option that would allow units to meet the 1,000 Ibs C02/MWh standard using a 30-
year averaging period. These standards could be met either by natural gas combined cycle
(NGCC) generation with no additional GHG control or coal-fired generation using CCS. The base
case modeling EPA performed for this rule (as well as modeling that EPA has performed for
3 "Blueprint for a Secure Energy Future." March 30, 2011. Available online at:
http://www.whitehouse.gov/sites/default/files/blueprint_secure_energy_future.pdf
ES-2
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other recent air rules) project that, even in the absence of this action, new fossil-fuel fired
capacity constructed through 2020 will most likely be natural gas combined cycle capacity.
Alternatively, with available federal funding and appropriate market conditions, coal-fired
capacity with CCS could also be built. Any projected combustion turbine capacity would not be
affected by this rule. Analyses performed both by EPA and the U.S. Energy Information
Administration (EIA)4 project that generation technologies other than coal (including natural gas
and renewable sources) are likely to be the technology of choice for new generating capacity
due to current and projected economic market conditions. This means that technologies
planned for new sources currently envisioned by owners and operators of EGUs will meet the
regulatory requirements of this NSPS or are not covered by the NSPS.
ES.3 Key Findings of Economic Analysis
As explained in detail in this document, energy market data and projections support the
conclusion that, even in the absence of this rule, existing and anticipated economic conditions
in the marketplace will lead electricity generators to choose technologies that meet the
proposed standards. Therefore, based on the analysis presented in Chapter 5, EPA anticipates
that the proposed ECU GHG NSPS will result in negligible C02 emission changes, energy
impacts, quantified benefits, costs, and economic impacts by 2020. Accordingly, EPA also does
not anticipate this rule will have any impacts on the price of electricity, employment or labor
markets, or the US economy. Nonetheless, this rule may have several important beneficial
effects described below.
This NSPS provides legal assurance that any new coal-fired plants must limit C02
emissions. Rather than relying solely on changeable energy market conditions to provide low
emissions from new power plants in the future, this rule prevents the possible construction of
uncontrolled, high-emitting new sources that might continue to emit at high levels for decades,
contributing to accumulation of C02 in the atmosphere. In Chapter 5 of this RIA, we present a
sensitivity analysis indicating that even in the unlikely event that market conditions change
sufficiently to make the construction of new conventional coal-fired units economical from the
perspective of private investors, the level of avoided negative health and environmental effects
expected would imply net social benefits from this proposed rule.
The rule will reduce regulatory uncertainty by defining section lll(b) requirements for
limiting GHG from new ECU sources. In addition, EPA intends this rule to send a clear signal
about the future of CCS technology that, in conjunction with other policies such as Department
4 Annual Energy Outlook (AEO) 2009- 2012.
ES-3
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of Energy (DOE) financial assistance, the agency estimates will support development and
demonstration of CCS technology from coal-fired plants at commercial scale, if that financial
assistance is made available and under the appropriate market conditions.5 Carbon capture
also has the potential to help to improve U.S. energy production through enhanced oil
recovery, as highlighted by a series of regional assessments conducted for DOE.6
5 A number of the sources that EPA has identified as transitional sources have received some form of DOE financial
assistance to demonstrate CCS. Several additional projects have received funding but have not yet received air
permits. Beyond these projects, prospects for additional federal funding are dependent on the overall budget
process.
6 U.S. Department of Energy. DOE web page, "Ten Basin-Oriented CO2-EOR Assessments Examine Strategies for
Increasing Domestic Oil Production.," Available online at:
http://www.fossil.energy.gov/programs/oilgas/eor/Ten_Basin-Oriented_CO2-EOR_Assessments.html.
ES-4
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CHAPTER 1
INTRODUCTION AND BACKGROUND
1.1 Introduction
In this action, EPA seeks to address the climate and health effects of GHGs, specifically
C02, emitted from fossil fuel-fired electricity generating units. This document presents the
expected economic impacts of the proposed ECU GHG NSPS rule through 2020. Based on the
analysis presented in Chapter 5, expected and anticipated economic conditions will lead
electricity generators to choose technologies that meet the standard. As a result, this proposed
rule is expected to have no, or negligible, costs or monetized benefits associated with it. This
chapter contains background information on the rule and an outline of the chapters of the
report.
1.2 Background
Section 111 of the CAA requires performance standards for air pollutant emissions from
categories of stationary sources that may reasonably contribute to endangerment of public
health or welfare. In April 2007, the Supreme Court ruled that GHGs meet the definition of an
"air pollutant" under the CAA. This ruling clarified that the authorities and requirements of the
Act apply to GHGs. As a result, EPA must make decisions about whether to regulate GHGs under
certain provisions of the Act, based on relevant statutory criteria. EPA issued a final
determination that GHG emissions endanger public health and welfare in the Endangerment
and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air
Act (74 FR 66,496; Dec. 15, 2009). Because fossil fuel-fired EGUs contribute significantly to
domestic C02 emissions, EPA is proposing to regulate these emissions from ECU sources under
section 111 of the CAA.
This action responds to a proposed settlement agreement EPA entered into in
December 2010 to issue rules that will address greenhouse gas emissions from fossil fuel-fired
power plants. Details of the settlement agreement can be found on the EPA website.1 This
action addresses standards for new sources but does not address existing sources at this time.
Existing sources will be addressed in a separate action at a later date by the EPA.
1.3 Regulatory Analysis
In accordance with Executive Order 12866, Executive Order 13563, and EPA's Guidelines
for Preparing Economic Analyses, EPA prepared this RIA for this "significant regulatory action."
1 http://www.epa.gov/airquality/ghgsettlement.html
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This proposal is not anticipated to have an annual effect on the economy of $100 million or
more or adversely affect in a material way the economy, a sector of the economy, productivity,
competition, jobs, the environment, public health or safety, or State, local, or tribal
governments or communities and is therefore not an "economically significant rule." However,
under EO 12866 (58 FR 51,735, October 4, 1993), this action is a "significant regulatory action"
because it "raises novel legal or policy issues arising out of legal mandates." As a matter of
policy, however, EPA has attempted to provide a thorough analysis of the potential impacts of
this rule, consistent with requirements of the Executive Orders, and will continue to analyze the
potential impacts of this rule between the proposed and final rule.
This RIA addresses the potential costs and benefits of the new source guidelines that are
the focus of the proposed action. The proposed rule regulates new sources. EPA does not
anticipate that any costs or quantified benefits will result from those parts of the standards.
For new sources, EPA (and other energy modeling groups such as EIA2) does not project that
any new coal capacity without federally-supported CCS will be built in the analysis period. This
is due in part to the low cost of base load NGCC capacity relative to coal capacity, relatively low
growth in electricity demand, and use of energy efficiency and renewable energy resources.
This conclusion holds under a range of sensitivity analyses as well as in EPA's baseline scenario.
Furthermore, absent this rule, any new NGCC that may be built is expected to have an annual
emission rate in compliance with the standard. Because the proposal does not change these
projections, it is expected to have no, or negligible, costs3 or quantified benefits associated with
it. Chapter 5 of this RIA also provides an illustrative analysis of the levelized cost of electricity
and environmental damages associated with representative new conventional coal and natural
gas combined cycle units, under a range of natural gas price assumptions. That analysis, along
with information on historical4 and projected5 gas prices, indicates that this standard is highly
likely to have no costs or benefits; that there is some small probability that the standard
2 AEO 2009-2012.
3 Because of existing and anticipated trends in the marketplace, EPA does not project that any generators expected
to be built within the time frame of our analysis will have to install additional controls to meet the proposed
standard. Additionally, because new generators would already be required to monitor and report their CO2
emissions under the information collection requirements contained in the existing part 75 and 98 regulations
(40 CFR part 75 and 40 CFR part 98), any additional monitoring or reporting costs from this proposal should be
negligible. Costs are only incurred if there has been a violation and a source chooses to take advantage of the
affirmative defense, in which the source can show that the violation was caused by a malfunction and the
source took necessary actions to minimize emissions. See Chapter 6 for more details on monitoring and
reporting costs.
EIA. U.S. Natural Gas Prices. Available online at: http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm.
5AEO 2009-2012.
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produces net benefits; and that the probability that the standard results in net costs to society
is exceedingly low.
1.4 Regulated Entities
This action will directly regulate C02 emissions from EGUs with capacity greater than 25
MW that commence construction after the issuance of this proposal.6
As described in the preamble, EPA does not have enough information on potential
reconstructions in order to issue a standard at this time. As a result, in today's action, the EPA is
not including a proposal for reconstructions. Instead, we solicit comment on how we should
approach reconstructions and, depending on the information we receive, we may propose and
finalize a standard for reconstructions at a later time. Additionally, EPA does not have
information indicating that affected EGUs would undertake modifications, and is thus not
proposing any standards for modifications. EPA is taking comment on this and in the future may
choose to set a standard for modifications that is different than that for existing sources.
Finally, EPA is not proposing a standard of performance for transitional sources as long as they
commence construction within 12 months from the date of this proposal.
1.5 Regulated Pollutant
This rule proposes to limit C02 emissions from affected sources. EPA is proposing these
requirements because C02 is a GHG and power plants are the country's largest stationary
source emitters of GHGs. In 2009, EPA found that by causing or contributing to climate change,
GHGs endanger both the public health and the public welfare of current and future
generations.
EPA is aware that other GHGs such as nitrous oxide (N20) (and to a lesser extent,
methane (CH4)) may be emitted from fossil-fuel-fired EGUs, especially from coal-fired
circulating fluidized bed combustors and from units with selective catalytic reduction and
selective non-catalytic reduction systems installed for nitrogen oxide (NOX) control. EPA is not
proposing separate N20 or CH4 emission limits or an equivalent C02 emission limit because of a
lack of available data for these affected sources. Additional information on the quantity and
significance of emissions and on the availability of cost effective controls would be needed
before proposing standards for these pollutants.
6 For purposes of this rule, covered EGUs do not include simple cycle combustion turbines. In addition, units
subject to emission requirements under CAA section 129 would not be subject to requirements under this
proposed rule.
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1.6 Baseline and Years of Analysis
The rule on which this analysis is based proposes the requirement for new EGUs to
achieve lower levels of GHG emissions. The baseline for this analysis, which uses the Integrated
Planning Model (IPM), includes state rules that have been finalized and/or approved by a
state's legislature or environmental agencies. Additional legally binding and enforceable
commitments for GHG reductions considered in the baseline are discussed in Chapter 5 of this
RIA.
All analysis is presented for compliance through the year 2020 and all estimates are
presented in 2007$. Because we expect similar economic conditions leading up to the year of
analysis, we also would not anticipate costs or benefits in any year prior to 2020. Any estimates
presented in this report represent annualized estimates of the benefits and costs of the
proposed ECU GHG NSPS rather than the net present value of a stream of benefits and costs in
these particular years of analysis.
1.7 Organization of the Regulatory Impact Analysis
This report presents EPA's analysis of the potential benefits, costs, and other economic
effects of the proposed ECU GHG NSPS to fulfill the requirements of a Regulatory Impact
Analysis. This RIA includes the following chapters:
• Chapter 2, Control Strategies, defines the source categories affected by the proposal
and describes the control strategies and regulatory alternatives for these source
categories.
• Chapter 3, Defining the Climate Change Problem and Rationale for the Rulemaking,
describes the effects of GHG emissions on climate and offers support for EPA
undertaking this rulemaking.
• Chapter 4, Electric Power Sector Profile, describes the industry affected by the rule.
• Chapter 5, Costs, Benefits, Economic, and Energy Impacts describes impacts of the
proposal.
• Chapter 6, Statutory and Executive Order Impact Analyses, describes the small
business, unfunded mandates, paperwork reduction act, environmental justice, and
other analyses conducted for the rule to meet statutory and Executive Order
requirements.
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CHAPTER 2
CONTROL STRATEGIES
2.1 Synopsis
This section defines the source categories affected by the proposal, outlines regulatory
actions included in the analytical baseline, and describes the control strategies and regulatory
alternatives for new, modified, reconstructed, and transitional sources. Existing ECU GHG
sources are not addressed in this action, but will be the subject of a subsequent action by the
EPA.
2.2 Definition of Affected Sources
2.2.1 Electric Utility Generating Unit
For the purposes of this rule, the EPA is proposing to define an ECU as any fossil fuel-
fired combustion unit that has the potential to produce more than 25 MW electrical output and
serves as a generator that produces electricity for sale, with the exception of simple cycle
turbines. For this rule, the term ECU includes steam generating units ("boilers"), NGCC
combustion turbines and their associated heat recovery steam generator (HRSG) and duct
burners, and Integrated Gasification Combined Cycle (IGCC, "coal gasification") units - including
their combustion turbines and associated HRSGs. A unit that cogenerates steam and electricity
or that cogenerates feedstocks (e.g., hydrogen or hydrocarbons from an IGCC) for chemical or
fuel production and supplies more than one-third of its potential electric output capacity and
more than 25 MW output to any utility power distribution system for sale is also considered to
be an ECU for the purposes of this rule. This rule does not cover simple cycle turbines.
2.2.2 New Sources
Sources affected by the new source provisions of the proposal are sources that are both
considered "EGUs" and are considered "new" as defined by this rule. The general NSPS
provisions (40 CFR Part 60) define a new source as one that begins construction (or
reconstruction) after the date the provisions are proposed.
CAA section lll(a)(2) defines a "new source" as "any stationary source, the
construction or modification of which is commenced after publication of regulations (or, if
early, proposed regulations) prescribing a standard of performance under [CAA section 111]
which will be applicable to such source." In contrast, CAA section lll(a)(6) defines an "existing
source" as "any stationary source other than a new source." The definition of a "new source"
applies for purposes of this rulemaking, except that special considerations come into play for
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sources undertaking physical or operational changes (modified sources), transitional sources,
and sources undertaking reconstruction.
2.2.3 Modified Sources
The EPA does not have a sufficient base of information to develop a proposal for the
relatively few affected sources that may take actions that would constitute "modifications," as
defined under the EPA's NSPS regulations, and therefore be subject to requirements for new
sources. A modification is any physical or operational change to a source that increases the
amount of any air pollutant emitted by the source or results in the emission of any air pollutant
not previously emitted. However, projects to install pollution controls required under other
CAA provisions are specifically exempted from the definition of "modifications" under 40 CFR
60.14(e)(5), even if they emit C02 as a byproduct. The significant majority of projects that the
EPA believes EGUs are most likely to undertake in the foreseeable future that could increase
the maximum achievable hourly rate of C02 emissions would be pollution control projects that
are exempt under this definition. More details on the approach for modified sources can be
found in the preamble.
EPA is not proposing a standard of performance for modifications at this time. As a
result, sources that undertake modifications will be treated as existing sources and thus not
subject to the requirements proposed in this notice, although they would be subject to
requirements that the EPA intends to propose separately for existing EGUs. The EPA is soliciting
comment on the treatment of modified sources and, depending on the information received,
may issue proposed standards of performance in the future.
2.2.4 Transitional Sources
This proposed rule sets no standard for transitional sources, although these sources may
be subject to an existing source standard in a subsequent rulemaking. In this proposal, EPA
identifies transitional sources as those sources that have received permits to construct, but
have not actually commenced construction. EPA believes that there are approximately 15 units
that would be classified as transitional sources (see Appendix 2A for a list of potential
transitional units). EPA is proposing that as long as these units commence construction within
one year of the effective date of this proposal, these sources will be classified as transitional
sources for the purposes of this rule and will not be subject to the NSPS.
Historically, obtaining a permit does not guarantee that a unit will be constructed. In
the last 10 years, 85 coal plants have been permitted. Of those, 40 (or less than half) have
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actually commenced construction. Thirty projects have been cancelled and approximately 15
sources (the transitional sources) have active permits. EPA notes that many variables in
addition to permitting appear to contribute to the likelihood of project completion. Based on
this history and current economic conditions in particular, not all units are likely to proceed.
EPA believes the transitional units that are most likely to commence construction are
those that have received government incentives to install CCS. These units would be able to
commence construction within the proposed rule time-frame.
2.2.5 Reconstructed Sources
The EPA's CAA section 111 regulations provide that reconstructed sources are to be
treated as new sources and, therefore, subject to new source standards of performance. The
regulations define reconstructed sources, in general, as existing sources: (i) that replace
components to such an extent that the capital costs of the new components exceed 50 percent
of the capital costs of an entirely new facility and (ii) for which compliance with standards of
performance for new sources is technologically and economically feasible (40 CFR 60.15).
Historically, very few power plants have undertaken reconstructions. We are not aware
that any power plants are presently planning any project that could meet the requirements for
a reconstruction. In light of this limited experience concerning reconstructions, the Agency lacks
adequate information that is needed to propose a standard of performance for reconstructions.
As a result, in today's action, the EPA is not including a proposal for reconstructions. Instead,
we solicit comment on how we should approach reconstructions and, depending on the
information we receive, we may propose and finalize a standard for reconstructions at a later
time. EPA is soliciting comment on the type of source that will undertake reconstruction; the
type of changes; the extent of emissions increases; and the type of control measures, including
their cost and emissions reductions.
2.2.6 Existing Sources
For the purposes of this rule an existing ECU is defined as any fossil fuel-fired
combustion unit that has the potential to produce more than 25 MW output and serves a
generator that produces electricity for sale and was in operation or commenced construction
on or before publication of this proposed rule. Existing sources are not covered in this
proposed action, but will be addressed in a subsequent rulemaking by the EPA.
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2.3 Control Strategies
This proposal requires that all new fossil-fuel fired units with greater than 25 MW
capacity be able to meet an emission rate standard of 1,000 Ib C02/MWh calculated over a
rolling 12-month period. It also proposes an alternative compliance option that would allow
units to meet the 1,000 Ib C02/MWh standard using a 30-year averaging period. These
standards could be met by NGCC generation with no additional GHG control or coal-fired
generation using carbon capture and sequestration technology.
2.4 Analytical Baseline
EPA used IPM v.4.10 to assess the baseline conditions described for the proposed new
source performance standards. IPM is a dynamic linear programming model that can be used
to examine the economic impacts of air pollution control policies for C02 and other air
pollutants throughout the contiguous U.S. for the entire power system. The modeling
conducted for this proposal is discussed more extensively in Chapter 5 of this RIA.
Documentation for IPM can be found in the docket for this rulemaking or at
http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html. For more information on the
analytical baseline see Chapter 5 of this report.
2.5 Emission Reductions
As will be discussed in more detail in Chapter 5 of this RIA, the EPA anticipates that the
proposed ECU GHG NSPS will result in negligible changes in GHG emissions over the analysis
period (through 2020). Even in the absence of this rule, the EPA expects that owners of new
units will choose generation technologies that meet these standards due to expected economic
conditions in the marketplace. Likewise, we anticipate that this rule will have negligible costs,
quantified benefits, and impacts on the price of electricity, labor markets, or the economy.
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APPENDIX 2A
POTENTIAL TRANSITIONAL UNITS
Plant Name
Trailblazer
Taylorville
Texas Clean Energy
Project
Cash Creek Generation
Power County Advanced
Energy Center
Good Spring
Limestone 3
Holcomb 2
White Stallion
James De Young
Wolverine
Coleto Creek
Size
600 MW
602 MW
400 MW
761 MW
520 MW
270 MW
750 MW
895 MW
1320 MW
78 MW
600 MW
650 MW
CO2 Mitigation Plan
CCS - EOR (supercritical PC)
CCS - EOR/Geologic (IGCC)
CCS - EOR (IGCC)
CCS - IGCC
CCS - EOR (IGCC)
CCS - IGCC
Agreement to capture or offset 50% of
CO2 (subcritical PC) - CCS ready
None (supercritical PC)
None (subcritical CFB)
None (subcritical CFB)
None (subcritical CFB) - CCS ready
None (supercritical PC) - CCS ready
Location
TX
IL
TX
KY
ID
PA
TX
KS
TX
Ml
Ml
TX
Washington County
850 MW
None (supercritical PC)
GA
Bonanza
Two Elk
110 MW None (subcritical CFB, waste coal)
None (subcritical PC, waste coal) - CCS
ready
UT
WY
Note: This table does not reflect an official list of transitional sources, but instead reflects sources that could potentially be
considered transitional under the proposed regulation.
PC = pulverized coal
CCS = carbon capture and storage
CFB = circulating fluidized bed
EOR = enhanced oil recovery
IGCC = integrated gasification combined cycle
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CHAPTER 3
DEFINING THE CLIMATE CHANGE PROBLEM AND RATIONALE FOR RULEMAKING
3.1 Overview of Climate Change Impacts from GHG Emissions
In 2009, the EPA Administrator found that elevated concentrations of greenhouse gases
in the atmosphere may reasonably be anticipated both to endanger public health and to
endanger public welfare. It is these adverse impacts that make it necessary for EPA to regulate
greenhouse gases from ECU sources. This proposed rule is designed to minimize emissions of
greenhouse gases, minimize the rate of increase of concentrations of these gases, and
therefore reduce the risk of adverse effects. As the analysis presented in Chapter 5 shows,
existing and anticipated economic conditions in the marketplace will lead electricity generators
to choose technologies that meet the proposed standards. However, rather than relying solely
on changeable energy market conditions to provide low emissions from new power plants in
the future, though this rule, EPA ensures that new electricity generation will be clean
generation.
This chapter summarizes the adverse effects on public health and public welfare
detailed in the 2009 Endangerment Finding.1 The major assessments by the U.S. Global Change
Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the
National Research Council (NRC) served as the primary scientific basis for these effects.
3.1.1 Public Health
Climate change threatens public health in a number of ways: direct temperature effects,
air quality effects, the potential for changes in vector-borne diseases, and the potential for
changes in the severity and frequency of extreme weather events. Additionally, susceptible
populations may be particularly at risk. Each of these effects will be addressed in turn in this
section, based on the 2009 Endangerment Finding.
Regarding direct temperature changes, it has already been estimated that unusually hot
days and heat waves are becoming more frequent, and that unusually cold days are becoming
less frequent. Heat is already the leading cause of weather-related deaths in the United States.
In the future, severe heat waves are projected to intensify in magnitude and duration over the
portions of the United States where these events already occur. Heat waves are associated with
marked short-term increases in mortality. Hot temperatures have also been associated with
1 Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act,
74 Fed. Reg. 66,496 (Dec. 15, 2009).
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increased morbidity. The projected warming is therefore projected to increase heat related
mortality and morbidity, especially among the elderly, young, and frail. The populations most
sensitive to hot temperatures are older adults, the chronically sick, the very young, city-
dwellers, those taking medications that disrupt thermoregulation, the mentally ill, those lacking
access to air conditioning, those working or playing outdoors, and socially isolated persons. As
warming increases over time, these adverse effects would be expected to increase as the
serious heat events become more serious.
Increases in temperature are also expected to lead to some reduction in the risk of
death related to extreme cold. It is not clear whether reduced mortality in the United States
from cold would be greater or less than increased heat-related mortality in the United States
due to climate change. However, there is a risk that projections of cold-related deaths, and the
potential for decreasing their numbers due to warmer winters, can be overestimated unless
they take into account the effects of season and influenza, which is not strongly associated with
monthly winter temperature. In addition, the latest USGCRP report (2009) refers to a study
(Medina-Ramon and Schwartz, 2007) that analyzed daily mortality and weather data in 50 U.S.
cities from 1989 to 2000 and found that, on average, cold snaps in the United States increased
death rates by 1.6 percent, while heat waves triggered a 5.7 percent increase in death rates.
The study concludes that increases in heat-related mortality due to global warming in the
United States are unlikely to be compensated for by decreases in cold-related mortality.
Regarding air quality effects, increases in regional ozone pollution relative to ozone
levels without climate change are expected due to higher temperatures and weaker circulation
in the United States relative to air quality levels without climate change. Climate change is
expected to increase regional ozone pollution, with associated risks in respiratory illnesses and
premature death. In addition to human health effects, tropospheric ozone has significant
adverse effects on crop yields, pasture and forest growth, and species composition.
Modeling studies discussed in EPA's Interim Assessment (2009) show that simulated
climate change causes increases in summertime ozone concentrations over substantial regions
of the country, though this was not uniform, and some areas showed little change or decreases,
though the decreases tend to be less pronounced than the increases. For those regions that
showed climate-induced increases, the increase in maximum daily 8-hour average ozone
concentration, a key metric for regulating U.S. air quality, was in the range of 2 to 8 ppb,
averaged over the summer season. The increases were substantially greater than this during
the peak pollution episodes that tend to occur over a number of days each summer. The overall
effect of climate change was projected to increase ozone levels, compared to what would occur
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without this climate change, over broad areas of the country, especially on the highest ozone
days and in the largest metropolitan areas with the worst ozone problems. Ozone decreases are
projected to be less pronounced, and generally to be limited to some regions of the country
with smaller population.
In addition to impacts on heat-related mortality and air quality, there is also the
potential for increased deaths, injuries, infectious diseases, and stress-related disorders and
other adverse effects associated with social disruption and migration from more frequent
extreme weather. Vulnerability to these disasters depends on the attributes of the people at
risk and on broader social and environmental factors.
Increases in the frequency of heavy precipitation events are associated with increased
risk of deaths and injuries as well as infectious, respiratory, and skin diseases. Floods are low-
probability, high-impact events that can overwhelm physical infrastructure, human resilience,
and social organization. Flood health impacts include deaths, injuries, infectious diseases,
intoxications, and mental health problems.
Increases in tropical cyclone intensity are linked to increases in the risk of deaths,
injuries, waterborne and food borne diseases, as well as post-traumatic stress disorders.
Drowning by storm surge, heightened by rising sea levels and more intense storms (as
projected by IPCC), is the major killer in coastal storms where there are large numbers of
deaths. Flooding can cause health impacts including direct injuries as well as increased
incidence of waterborne diseases.
According to the assessment literature, there will also likely be an increase in the spread
of several food and water-borne pathogens among susceptible populations depending on the
pathogens' survival, persistence, habitat range and transmission under changing climate and
environmental conditions. Food borne diseases show some relationship with temperature, and
the range of some zoonotic disease carriers such as the Lyme disease carrying tick may increase
with temperature.
Climate change, including changes in carbon dioxide concentrations, could impact the
production, distribution, dispersion, and allergenicity of aeroallergens and the growth and
distribution of weeds, grasses, and trees that produce them. These changes in aeroallergens
and subsequent human exposures could affect the prevalence and severity of allergy
symptoms. However, the scientific literature does not provide definitive data or conclusions on
how climate change might impact aeroallergens and subsequently the prevalence of allergenic
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illnesses in the United States. It has generally been observed that the presence of elevated
carbon dioxide concentrations and temperatures stimulate plants to increase photosynthesis,
biomass, water use efficiency, and reproductive effort. The IPCC concluded that pollens are
likely to increase with elevated temperature and carbon dioxide.
3.1.2 Public Welfare
As with public health, there are multiple pathways in which the greenhouse gas air
pollution and resultant climate change affect climate-sensitive sectors. These sectors include
food production and agriculture; forestry; water resources; sea level rise and coastal areas;
energy, infrastructure, and settlements; and ecosystems and wildlife. Impacts also arise from
climate change occurring outside of the United States, such as national security concerns for
the United States that may arise as a result of climate change impacts in other regions of the
world. Each of these effects will be addressed in turn in this section, based on the 2009 Finding.
Regarding food production and agriculture, elevated carbon dioxide concentrations can
have a stimulatory effect, as may modest temperature increases and a longer growing season
that results. However, elevated carbon dioxide concentrations may also enhance pest and
weed growth. In addition, higher temperature increases, changing precipitation patterns and
variability, and any increases in ground-level ozone induced by higher temperatures, can work
to counteract any direct stimulatory carbon dioxide effect, as well as lead to their own adverse
impacts. A USGCRP report (2009) concluded that while for some crops such as grain and oilseed
crops there may be a beneficial effect overall in the next couple decades, as temperature rises,
these crops will increasingly begin to experience failure, especially if climate variability
increases and precipitation lessens or becomes more variable. Changes in the intensity and
frequency of extreme weather events such as droughts and heavy storms have the potential to
have serious negative impact on U.S. food production and agriculture. Changing precipitation
patterns, in addition to increasing temperatures and longer growing seasons, can change the
demand for irrigation requirements, potentially increasing irrigation demand.
With respect to livestock, higher temperatures will very likely reduce livestock
production during the summer season in some areas, but these losses will very likely be
partially offset by warmer temperatures during the winter season. The impact on livestock
productivity due to increased variability in weather patterns will likely be far greater than
effects associated with the average change in climatic conditions.
For the forestry sector there are similar factors to consider. There is the potential for
beneficial effects due to elevated concentrations of carbon dioxide, increased temperatures,
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and nitrogen deposition, but there is also the potential for adverse effects from increasing
temperatures, changing precipitation patterns, increased insects and disease, and the potential
for more frequent and severe extreme weather events. According to the science assessment
reports on which the Administrator relied for the 2009 Finding, climate change has very likely
increased the size and number of wildfires, insect outbreaks, and tree mortality in the Interior
West, the Southwest, and Alaska, and will continue to do so.
If existing trends in precipitation continue, it is expected that forest productivity will
likely decrease in the Interior West, the Southwest, eastern portions of the Southeast, and
Alaska, and that forest productivity will likely increase in the northeastern United States, the
Lake States, and in western portions of the Southeast. An increase in drought events will very
likely reduce forest productivity wherever such events occur.
The sensitivity of water resources to climate change is very important given the
increasing demand for adequate water supplies and services for agricultural, municipal, and
energy and industrial uses, and the current strains on this resource in many parts of the
country. According to the assessment literature, climate change has already altered, and will
likely continue to alter, the water cycle, affecting where, when, and how much water is
available for all uses. With higher temperatures, the water-holding capacity of the atmosphere
and evaporation into the atmosphere increase, and this favors increased climate variability,
with more intense precipitation and more droughts.
Climate change is causing and will increasingly cause shrinking snowpack induced by
increasing temperature. In the western United States, there is already well-documented
evidence of shrinking snowpack due to warming. Earlier meltings, with increased runoff in the
winter and early spring, increase flood concerns and also result in substantially decreased
summer flows. This pattern of reduced snowpack and changes to the flow regime pose very
serious risks to major population regions, such as California, that rely on snowmelt-dominated
watersheds for their water supply. While increased precipitation is expected to increase water
flow levels in some eastern areas, this may be tempered by increased variability in the
precipitation and the accompanying increased risk of floods and other concerns such as water
pollution.
Climate change will likely further constrain already over-allocated water resources in
some regions of the United States, increasing competition among agricultural, municipal,
industrial, and ecological uses. Although water management practices in the United States are
generally advanced, particularly in the West, the reliance on past conditions as the basis for
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current and future planning may no longer be appropriate, as climate change increasingly
creates conditions well outside of historical observations. Increased incidence of extreme
weather and floods may also overwhelm or damage water treatment and management
systems, resulting in water quality impairments.
According to the assessment literature, sea level is rising along much of the U.S. coast
and the rate of change will very likely increase in the future, exacerbating the impacts of
progressive inundation, storm-surge flooding, and shoreline erosion. A large percentage of the
U.S. population lives in these coastal areas. The most vulnerable areas are the Atlantic and Gulf
Coasts, the Pacific Islands, and parts of Alaska. Cities such as New Orleans, Miami, and New
York are particularly at risk, and could have difficulty coping with the sea level rise projected by
the end of the century under a higher emissions scenario. Population growth and the rising
value of infrastructure increases the vulnerability to climate variability and future climate
change in coastal areas. Adverse impacts on islands present concerns for Hawaii and the U.S.
territories. Reductions in Arctic sea ice increases extreme coastal erosion in Alaska, due to the
increased exposure of the coastline to strong wave action. In the Great Lakes, where sea level
rise is not a concern, both extremely high and low water levels resulting from changes to the
hydrological cycle have been damaging and disruptive to shoreline communities.
Coastal wetland loss is being observed in the United States where these ecosystems are
squeezed between natural and artificial landward boundaries and rising sea levels. Up to 21
percent of the remaining coastal wetlands in the U.S. mid-Atlantic region are potentially at risk
of inundation between 2000 and 2100. Coastal habitats will likely be increasingly stressed by
climate change impacts interacting with development and pollution.
Although increases in mean sea level over the 21st century and beyond will inundate
unprotected, low-lying areas, the most devastating impacts are likely to be associated with
storm surge. Superimposed on expected rates of sea level rise, projected storm intensity, wave
height, and storm surge suggest more severe coastal flooding and erosion hazards. Higher sea
level provides an elevated base for storm surges to build upon and diminishes the rate at which
low-lying areas drain, thereby increasing the risk of flooding from rainstorms. In New York City
and Long Island, flooding from a combination of sea level rise and storm surge could be several
meters deep. Projections suggest that the return period of a 100-year flood event in this area
might be reduced to 4-60 years by the 2080s. Additionally, some major urban centers in the
United States, such as areas of New Orleans are situated in low-lying flood plains, presenting
increased risk from storm surges.
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With respect to infrastructure, climate change vulnerabilities of industry, settlement,
and society are mainly related to changes in intensity and frequency of extreme weather events
rather than to gradual climate change. Extreme weather events could threaten U.S. energy
infrastructure (transmission and distribution), transportation infrastructure (roads, bridges,
airports and seaports), water infrastructure, and other built aspects of human settlements.
Moreover, soil subsidence caused by the melting of permafrost in the Arctic region is a risk to
gas and oil pipelines, electrical transmission towers, roads, and water systems.
Within settlements experiencing climate change stressors, certain parts of the
population may be especially vulnerable based on their circumstances. These include the poor,
the elderly, the very young, those already in poor health, the disabled, those living alone,
and/or indigenous populations dependent on one or a few resources. In Alaska, indigenous
communities are likely to experience disruptive impacts, including shifts in the range or
abundance of wild species crucial to their livelihoods and well-being.
Climate change is exerting major influences on natural environments and biodiversity,
and these influences are generally expected to grow with increased warming. Observed
changes in the life cycles of plants and animals include shifts in habitat ranges, timing of
migration patterns, and changes in reproductive timing and behavior.
The underlying assessment literature finds with high confidence that substantial
changes in the structure and functioning of terrestrial ecosystems are very likely to occur with a
global warming greater than 2 to 3 °C above pre-industrial levels, with predominantly negative
consequences for biodiversity and the provisioning of ecosystem goods and services. With
global average temperature changes above 2 °C, many terrestrial, freshwater, and marine
species (particularly endemic species) are at a far greater risk of extinction than in the
geological past. Climate change and ocean acidification will likely impair a wide range of
planktonic and other marine calcifiers such as corals. Even without ocean acidification effects,
increases in sea surface temperature of about 1-3 °C are projected to result in more frequent
coral bleaching events and widespread mortality. In the Arctic, wildlife faces great challenges
from the effects of climatic warming, as projected reductions in sea ice will drastically shrink
marine habitat for polar bears, ice-inhabiting seals, and other animals.
Some common forest types are projected to expand, others are projected to contract,
and others, such as spruce-fir, are likely to disappear from the contiguous United States.
Changes in plant species composition in response to climate change can increase ecosystem
vulnerability to other disturbances, including wildfires and biological invasion. Disturbances
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such as wildfires and insect outbreaks are increasing in the United States and are likely to
intensify in a warmer future with warmer winters, drier soils and longer growing seasons. The
areal extent of drought-limited ecosystems is projected to increase 11 percent per °C warming
in the United States. In California, temperature increases greater than 2°C may lead to
conversion of shrubland into desert and grassland ecosystems and evergreen conifer forests
into mixed deciduous forests. Greater intensity of extreme events may alter disturbance
regimes in coastal ecosystems leading to changes in diversity and ecosystem functioning.
Species inhabiting salt marshes, mangroves, and coral reefs are likely to be particularly
vulnerable to these effects.
According to the USGCRP report of June 2009 and other sources, climate change
impacts in certain regions of the world may exacerbate problems that raise humanitarian,
trade, and national security issues for the United States.2 The IPCC identifies the most
vulnerable world regions as the Arctic, because of the effects of high rates of projected
warming on natural systems; Africa, especially the sub-Saharan region, because of current low
adaptive capacity as well as climate change; small islands, due to high exposure of population
and infrastructure to risk of sea-level rise and increased storm surge; and Asian mega-deltas
due to large populations and high exposure to sea level rise, storm surge, and river flooding.
Climate change has been described as a potential threat multiplier with regard to national
security issues. While some of these international risks do not readily lend themselves to
precise analyses or future projections, given the unavoidable global nature of the climate
change problem it is appropriate and prudent to consider how impacts in other world regions
may present risks to the U.S. population.
3.1.3 Recent Assessments
Since the Endangerment Finding was released, more recent assessments have produced
similar conclusions to those of the assessments upon which the Finding was based. In May
2010, the NRC published its comprehensive assessment, "Advancing the Science of Climate
Change" (2010). It concluded that "climate change is occurring, is caused largely by human
activities, and poses significant risks for — and in many cases is already affecting — a broad
range of human and natural systems." Furthermore, the NRC stated that this conclusion is
based on findings that are "consistent with the conclusions of recent assessments by the U.S.
2 "In an increasingly interdependent world, U.S. vulnerability to climate change is linked to the fates of other
nations. For example, conflicts or mass migrations of people resulting from food scarcity and other resource limits,
health impacts or environmental stresses in other parts of the world could threaten U.S. national security." (Karl et
ai, 2009).
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Global Change Research Program, the Intergovernmental Panel on Climate Change's Fourth
Assessment Report, and other assessments of the state of scientific knowledge on climate
change." These are the same assessments that served as the primary scientific references
underlying the Administrator's Endangerment Finding. Another NRC assessment, "Climate
Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia," was
published in 2011. This report found that climate change due to carbon dioxide emissions will
persist for many centuries. The report also estimate a number of specific climate change
impacts, finding that every degree Celsius of warming could lead to increases in the heaviest 15
percent of daily rainfalls of 3 to 10 percent, decreases of 5 to 15 percent in yields for a number
of crops (absent adaptation measures that do not presently exist), decreases of Arctic sea ice
extent of 25 percent in September and 15 percent annually averaged, along with changes in
precipitation and stream flow of 5 to 10 percent in many regions and river basins. The
assessment also found that for an increase of 4 degrees C nearly all land areas would
experience average summers warmer than all but 5 percent of summers in the 20th century,
that for an increase of 1 to 2 degrees C the area burnt by wildfires in western North America
will likely more than double, that coral bleaching and erosion will increase due both to warming
and ocean acidification, and that sea level will rise 1.6 to 3.3 feet by 2100 in a 3 degree C
scenario. The assessment notes that many important aspects of climate change are difficult to
quantify but that the risk of adverse impacts is likely to increase with increasing temperature,
and that the risk of surprises can be expected to increase with the duration and magnitude of
warming.
In the 2010 report cited above, the NRC stated that some of the largest potential risks
associated with future climate change may come not from relatively smooth changes that are
reasonably well understood, but from extreme events, abrupt changes, and surprises that
might occur when climate or environmental system thresholds are crossed. Examples cited as
warranting more research include the release of large quantities of GHGs stored in permafrost
(frozen soils) across the Arctic, rapid disintegration of the major ice sheets, irreversible drying
and desertification in the subtropics, changes in ocean circulation, and the rapid release of
destabilized methane hydrates in the oceans.
On ocean acidification, the same report noted the potential for broad, "catastrophic"
impacts on marine ecosystems. Ocean acidity has increased 25 percent since pre-industrial
times, and is projected to continue increasing. By the time atmospheric C02 content doubles
over its preindustrial value, there would be virtually no place left in the ocean that can sustain
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coral reef growth. Ocean acidification could have dramatic consequences for polar food webs
including salmon, the report said.
Importantly, these recent NRC assessments represent another independent and critical
inquiry of the state of climate change science, separate and apart from the previous IPCC, NRC,
and USGCRP assessments.
3.2 References
40 CFR Chapter I [EPA-HQ-OAR-2009-0171; FRL-9091-8] RIN 2060-ZA14, "Endangerment and
Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean
Air Act," Federal Register / Vol. 74, No. 239 / Tuesday, December 15, 2009 / Rules and
Regulations.
Karl, T., J. Melillo, and T. Peterson (Eds.) (2009). Global Climate Change Impacts in the United
States. Cambridge University Press, Cambridge, United Kingdom.
Medina-Ramon, M. and J. Schwartz, 2007: Temperature, temperature extremes, and mortality:
a study of acclimatization and effect modification in 50 U.S. cities. Occupational and
Environmental Medicine, 64(12), 827-833.
National Research Council (2010). Advancing the Science of Climate Change. National Academy
Press. Washington, DC.
National Research Council (2011). Climate Stabilization Targets: Emissions, Concentrations, and
Impacts over Decades to Millennia. National Academy Press, Washington, DC.
U.S. Environmental Protection Agency (2009). Assessment of the Impacts of Global Change on
Regional U.S. Air Quality: A Synthesis of Climate Change Impacts on Ground-Level Ozone.
An Interim Report of the U.S. EPA Global Change Research Program. U.S. Environmental
Protection Agency, Washington, DC, EPA/600/R-07/094.
U.S. Global Change Research Program (USGCRP). Global Climate Change Impacts in the United
States. Thomas R. Karl, Jerry M. Melillo, and Thomas C. Peterson, (eds.). Cambridge
University Press, 2009.
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CHAPTER 4
ELECTRIC POWER SECTOR PROFILE
4.1 Introduction
This chapter discusses important aspects of the power sector that relate to the
proposed ECU GHG NSPS, including the types of power-sector sources affected by the proposal,
and provides background on the power sector and EGUs. In addition, this chapter provides
some historical background on EPA regulation of, and future projections for, the power sector.
4.2 Power Sector Overview
The production and delivery of electricity to customers consists of three distinct
segments: generation, transmission, and distribution.
4.2.1 Generation
Electricity generation is the first process in the delivery of electricity to consumers. Most
of the existing capacity for generating electricity involves creating heat to rotate turbines
which, in turn, create electricity. The power sector consists of over 17,000 generating units,
comprising fossil-fuel-fired units, nuclear units, and hydroelectric and other renewable sources
dispersed throughout the country (see Table 4-1).
These electric generating sources provide electricity for commercial, industrial, and
residential uses, each of which consumes roughly a quarter to a third of the total electricity
produced (see Table 4-2). Some of these uses are highly variable, such as heating and air
conditioning in residential and commercial buildings, while others are relatively constant, such
as industrial processes that operate 24 hours a day.
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Table 4-1. Existing Electricity Generating Capacity by Energy Source, 2009
Energy Source
Coal
Petroleum
Natural Gas
Other Gases
Nuclear
Hydroelectric Conventional
Wind
Solar Thermal and Photovoltaic
Wood and Wood Derived Fuels
Geothermal
Other Biomass
Pumped Storage
Other
Total
Number of
Generators
1,436
3,757
5,470
98
104
4,005
620
110
353
222
1,502
151
48
17,876
Generator Generator Net Average
Nameplate Summer Capacity
Capacity (MW) Capacity (MW) Factor
338,723
63,254
459,803
2,218
106,618
77,910
34,683
640
7,829
3,421
5,007
20,538
1,042
1,121,686
314,294
56,781
401,272
1,932
101,004
78,518
34,296
619
6,939
2,382
4,317
22,160
888
1,025,400
63.8%
7.8%
42.2%
10.1%
90.3%
39.8%
N/A
N/A
N/A
N/A
N/A
N/A
N/A
44.9%
Source: EIA2009
Note: Average capacity factors not available for ElA's 2010 Electric Power Annual.
calculate average capacity factors for all energy sources presented in the table.
capacity. Actual net generation is presented in Table 4-3.
Additionally, EIA does not
This table presents generation
Table 4-2. Total U.S. Electric Power Industry Retail Sales in 2010 (Billion kWh)
Residential
Commercial
Retail Sales
Industrial
Transportation
Direct Use
Total End Use
Sales/Direct Use
(Billion kWh)
1,445
1,330
971
8
135
3,889
Share of Total End Use
37.2%
34.2%
25.0%
0.2%
3.5%
100%
Source: EIA 2010a
In 2010, electric generating sources produced 4,125 billion kWh to meet electricity
demand. Roughly 70 percent of this electricity was produced through the combustion of fossil
fuels, primarily coal and natural gas, with coal accounting for the largest single share (see
Table 4-3).
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Table 4-3. Electricity Net Generation in 2010 (Billion kWh)
Coal
Petroleum
Natural Gas
Other Gases
Nuclear
Hydroelectric
Other
Total
Net Generation (Billion kWh)
1,847
37
988
11
807
260
175
4,125
Fuel Source Share
44.8%
0.90%
23.9%
0.3%
19.6%
6.3%
4.2%
100%
Source: EIA2010a
Note: Retail sales are not equal to net generation because net generation includes net exported electricity and
loss of electricity that occurs through transmission and distribution.
Coal-fired generating units have historically supplied "base-load" electricity, the portion
of electricity loads which are continually present, and typically operate throughout the day.
Along with nuclear generation, these coal units meet the part of demand that is relatively
constant. Although much of the coal fleet operates as base load, there can be notable
differences across various facilities (see Table 4-4). For example, coal-fired units less than 100
MW in size compose 37 percent of the total number of coal-fired units, but only 6 percent of
total coal-fired capacity. Gas-fired generation is better able to vary output and is the primary
option used to meet the variable portion of the electricity load and typically supplies "peak"
power, when there is increased demand for electricity (for example, when businesses operate
throughout the day or when people return home from work and run appliances and
heating/air-conditioning), versus late at night or very early in the morning, when demand for
electricity is reduced.
The evolving economics of the power sector, in particular the increased natural gas
supply and relatively low natural gas prices, have resulted in more gas being utilized as base
load energy. Projections of new capacity and the impact of this rule on these new sources are
discussed in more detail in Chapter 5 of this RIA.
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Table 4-4. Coal Steam Electricity Generating Units, by Size, Age, Capacity, and Thermal
Efficiency (Heat Rate)
Unit Size Grouping
(MW)
0 to 25
>25 to 49
50 to 99
100 to 149
150 to 249
250 and up
Totals
No. Units
193
108
162
269
81
453
1,266
% of All
Units
15%
9%
13%
21%
6%
36%
Avg. Age
45
42
47
49
43
34
Avg. Net
Summer
Capacity
(MW)
15
38
75
141
224
532
Total Net
Summer
Capacity
(MW)
2,849
4,081
12,132
38,051
18,184
241,184
316,480
% Total
Capacity
1%
1%
4%
12%
6%
76%
Avg. Heat
Rate
(Btu/kWh)
11,154
11,722
11,328
10,641
10,303
10,193
Source: National Electric Energy Data System (NEEDS) v.4.10
Note: The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed
to a generation-weighted or capacity-weighted average heat rate.) A lower heat rate indicates a higher
level of fuel efficiency. Table is limited to coal-steam units online in 2010 or earlier, and excludes those
units with planned retirements.
4.2.2 Transmission
Transmission is the term used to describe the movement of electricity over a network of
high voltage lines, from electric generators to substations where power is stepped down for
local distribution. In the US and Canada, there are three separate interconnected networks of
high voltage transmission lines,1 each operating at a common frequency. Within each of these
transmission networks, there are multiple areas where the operation of power plants is
monitored and controlled to ensure that electricity generation and load are kept in balance. In
some areas, the operation of the transmission system is under the control of a single regional
operator; in others, individual utilities coordinate the operations of their generation,
transmission, and distribution systems to balance their common generation and load needs.
1These 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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Facility Capacity (MW)
• 2510100
• 100to500
• 500101,000
• 1.000 to 2,000
• 2,000 to 3,700
Figure 4-1. Fossil Fuel-Fired Electricity Generating Facilities, by Size
Source: National Electric Energy Data System (NEEDS) 4.10
Note: This map displays facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capacity on-line by the
end of 2011. This includes planned new builds and planned retirements. In areas with a dense
concentration of facilities, some facilities may be obscured.
4.2.3 Distribution
Distribution of electricity involves networks of lower voltage lines and substations that
take the higher voltage power from the transmission system and step it down to lower voltage
levels to match the needs of customers. The transmission and distribution system is the classic
example of a natural monopoly, in part because it is not practical to have more than one set of
lines running from the electricity generating sources to substations or from substations to
residences and business.
Transmission has generally been developed by the larger vertically integrated utilities
that typically operate generation and distribution networks. Distribution is handled by a large
number of utilities that often purchase and sell electricity, but do not generate it. Over the last
couple of decades, several jurisdictions in the United States began restructuring the power
industry to separate transmission and distribution from generation, ownership, and operation.
As discussed below, electricity restructuring has focused primarily on efforts to reorganize the
industry to encourage competition in the generation segment of the industry, including
ensuring open access of generation to the transmission and distribution services needed to
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deliver power to consumers. In many states, such efforts have also included separating
generation assets from transmission and distribution assets to form distinct economic entities.
Transmission and distribution remain price-regulated throughout the country based on the cost
of service.
4.3 Deregulation and Restructuring
The process of restructuring and deregulation of wholesale and retail electric markets
has changed the structure of the electric power industry. In addition to reorganizing asset
management between companies, restructuring sought a functional unbundling of the
generation, transmission, distribution, and ancillary services the power sector has historically
provided, with the aim of enhancing competition in the generation segment of the industry.
Beginning in the 1970s, government policy shifted against traditional regulatory
approaches and in favor of deregulation for many important industries, including
transportation (notably commercial airlines), communications, and energy, which were all
thought to be natural monopolies (prior to 1970) that warranted governmental control of
pricing. However, deregulation efforts in the power sector were most active during the 1990s.
Some of the primary drivers for deregulation of electric power included the desire for more
efficient investment choices, the economic incentive to provide least-cost electric rates through
market competition, reduced costs of combustion turbine technology that opened the door for
more companies to sell power with smaller investments, and complexity of monitoring utilities'
cost of service and establishing cost-based rates for various customer classes.
The pace of restructuring in the electric power industry slowed significantly in response
to market volatility in California and financial turmoil associated with bankruptcy filings of key
energy companies. By the end of 2001, restructuring had either been delayed or suspended in
eight states that previously enacted legislation or issued regulatory orders for its
implementation (shown as "Suspended" in Figure 4-2 below). Another 18 other states that had
seriously explored the possibility of deregulation in 2000 reported no legislative or regulatory
activity in 2001 (EIA, 2003) ("Not Active" in Figure 4-2 below). Currently, there are 15 states
where price deregulation of generation (restructuring) has occurred ("Active" in Figure 4-2
below). Power sector restructuring is more or less at a standstill; there have been no recent
proposals to the Federal Energy Regulatory Commission (FERC) for actions aimed at wider
restructuring, and no additional states have recently begun retail deregulation activity.
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Electricity Restructuring by State
Figure 4-2. Status of State Electricity Industry Restructuring Activities
Source: EIA2010b.
4.4 Emissions of Greenhouse Gases from Electric Utilities
The burning of fossil fuels, which generates about 70 percent of our electricity
nationwide, results in emissions of greenhouse gases. The power sector is a major contributor
of C02 in particular, but also contributes to emissions of sulfur hexafluoride (SF6), CH4, and N20.
In 2009, the power sector accounted for 33 percent of total nationwide greenhouse gas
emissions, measured in C02 equivalent, a slight increase from its 30 percent share in 1990.
Table 4-5 and Figure 4-3 show the contributions of the power sector relative to other major
economic sectors. Table 4-6 and Figure 4-4 show the contributions of C02 and other GHGs from
the power sector.
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Table 4-5. Domestic Emissions of Greenhouse Gases, by Economic Sector (million metric
tons of CO2 equivalent)
Implied Sectors
Electric Power Industry
Transportation
Industry
Agriculture
Commercial
Residential
U.S. Territories
Total Emissions
1990 1995
1,869 1,995
1,545 1,695
1,564 1,591
429 465
396 397
345 367
34 41
6,182 6,551
2000 2005
2,338 2,445
1,932 2,017
1,544 1,442
485 493
381 387
386 371
46 58
7,113 7,214
2009
2,193
1,812
1,323
490
410
360
46
6,633
Source: EPA 2011
M -"*-
c
1
Electric^
Utilities ^
2,193
33%
i
1
Figure 4-3. Domestic Emissions of Greenhouse Gases, 2009 (million metric tons of CO2
equivalent)
Source: EPA 2011
4-8
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Table 4-6. Electricity Generation-Related Greenhouse Gas Emissions, 2009 (million metric
tons of CO2 equivalent)
Source
Total Emissions
C02
CO2from Fossil Fuel Combustion
Coal
Natural Gas
Petroleum
Geothermal
Incineration of Waste
Limestone and Dolomite Use
CH4
Stationary Combustion*
Incineration of Waste
N2O
Stationary Combustion*
Incineration of Waste
SF6"
Electrical Transmission and Distribution
2,170.1
2,154.0
1,747.6
373.1
32.9
0.4
12.3
3.8
0.7
0.7
+
9.4
9.0
0.4
12.8
12.8
Total
2,193.0
Source: EPA 2011
* Includes only stationary combustion emissions related to the generation of electricity.
** SF6 is not covered by this rule, which specifically regulates GHG emissions from combustion.
+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.
The amount of C02 emitted during the combustion of fossil fuels varies according to the
carbon content and heating value of the fuel used (EIA, 2000) (see Table 4-7). Coal has higher
carbon content than oil or natural gas and, thus, releases more C02 during combustion. Coal
emits around 1.7 times as much carbon per unit of energy when burned as does natural gas and
1.25 times as much as oil (EPA 2011).
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100%
75%
50%
25%
0%
I Total Emissions
I Power Sector
.01%
CO 2
SFG
N20
CH4
Figure 4-4. GHG Emissions from the Power Sector Relative to Total Domestic GHG Emissions
(2009)
Source: EPA 2011
Table 4-7. Fossil Fuel Emission Factors in EPA Modeling Applications
Fuel Type
Carbon Dioxide (Ibs/MMBtu)
Coal
Bituminous
Subbituminous
Lignite
205.2-206.6
212.7-213.1
213.5-217.0
Natural Gas
117.1
Fuel Oil
Distillate
Residual
161.4
161.4-173.9
Biomass*
195
Waste Fuels
Waste Coal
Petroleum Coke
Fossil Waste
Non-Fossil Waste
Tires
Municipal Solid Waste
205.7
225.1
321.1
0
189.5
91.9
Source: Documentation for IPM Base Case v.4.10. See also Table 9.9 of IPM Documentation.
Note: CO2 emissions presented here for biomass account for combustion only and do not reflect lifecycle
emissions from initial photosynthesis (carbon sink) or harvesting activities and transportation (carbon
source).
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4.5 Pollution Control Technologies
There are several methods to reduce C02 emissions from the power sector, including
carbon capture and storage and improved fuel efficiency, which are discussed in more detail in
the following sections. Additional methods for C02 reduction include switching to lower-
emitting fuels, increased generation share from lower-emitting sources, decreased loss of
power via transmission and distribution systems, and improved end-use efficiency lowering
electricity demand for the same level of service provided. The first three strategies are within
the sphere of a generator's decision-making, whereas the latter two strategies are only
indirectly related to generators. The fourth strategy is an inherent property of the power
system responding to the implicit value of emissions as grid operators make dispatch decisions
to meet electricity demand at least cost (including the cost of harmful emissions). Increased
construction of natural gas-fired ECU capacity will increase the number of lower-emitting
sources from which grid operators may select to meet electricity demand.
4.5.1 Carbon Capture and Storage (CCS)
Carbon capture technology has been successfully applied since 1930 on several smaller
scale industrial facilities and is currently in the demonstration phase for power sector
applications. There are currently larger-scale projects under construction or in the advanced
planning stages. CCS can be achieved through either pre-combustion or post-combustion
capture of C02 from a gas stream associated with the fuel combusted. For post-combustion
capture, flue gas C02 stripping with a liquid absorbent which selectively reacts with the gaseous
carbon dioxide to remove it from the combustion gas stream. The absorbent, upon saturation,
transfers to a downstream operation which regenerates the absorbent by desorbing the C02
back to gaseous form. The absorbent recycles back into the process to repeat the capture cycle
while the removed carbon dioxide is compressed, sent to storage and sequestered. This process
is illustrated for a pulverized coal power plant in Figure 4-5.
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Flue Gas
Flue Gas
Volume %
CO; 12-14%
N2 -65%
H2O -18%
O2 -2%
15Psi/150T
Air
Coal
Storage
Figure 4-5. Post-Combustion CO2 Capture for a Pulverized Coal Power Plant
Source: Interagency Task Force on Carbon Capture and Storage 2010
Pre-combustion capture is mainly applicable to IGCC facilities, where the fuel is
converted into gaseous components ("syngas") under heat and pressure and the carbon
contained in the syngas is captured before combustion. These processes are energy intensive.
For post-combustion, a station's net generating output will be notably lower due to the energy
needs of the capture process. For pre-combustion technology, a significant amount of energy is
needed to gasify the fuel(s). This process is illustrated in Figure 4-6. For more detail on the
current state of CCS technology, see the "Report of the Interagency Task Force on Carbon
Capture and Storage" (2010).
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Shifted Syngas
H2 -50%
Sulfur
Figure 4-6. Pre-Combustion CO2 Capture for an IGCC Power Plant
Source: Interagency Task Force on Carbon Capture and Storage 2010
4.5.2 Thermal Efficiency Improvements
As the thermal (i.e. fuel) efficiency of a coal-fired ECU is increased, less coal is burned
per kilowatt-hour (kWh) generated, and there is a corresponding decrease in C02 and other
emissions per unit of energy generated. Numerous alternatives are available for improving
generating unit efficiency (Sargent & Lundy, 2009). Regular maintenance can achieve and
sustain optimal operational conditions, such as minimizing leakage of heat, assuring all
components are operating optimally, maintaining furnace operation near peak efficiency,
ensuring furnace soot removal system are functioning properly, and repairing tube leaks.
Efficiency gains can also be achieved through replacement of inefficient or obsolete equipment,
which can reduce parasitic power loads.2 There are many small actions that can be undertaken
which, cumulatively, can result in notable efficiency improvements. Such improvements include
optimizing air pre-heaters, installing heat recovery systems, reducing steam leaks, and
refurbishing the steam turbine. In a 2010 white paper, EPA summarized the efficiency
Reducing parasitic power loads increases the amount of generation for sale and therefore, where economical,
plant managers have an incentive to avoid these losses. However, reducing these loads does not necessarily
lower the gross CO2 emission rate of a plant, and therefore the structure of the proposed rule may not
significantly increase the incentive to reduce these losses.
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improvement techniques identified by the National Energy Technology Laboratory (NETL)
through a review of published articles and technical papers (EPA, 2010). The summary of these
findings is shown in Table 4-8.
Table 4-8. Existing Coal-Fired ECU Efficiency Improvements Reported for Actual Efficiency
Improvement Projects
Efficiency
Improvement
Technology
Description
Reported
Efficiency
Increase3
Combustion Combustion controls adjust coal and air flow to optimize steam production
Control for the steam turbine/generator set. The technologies include instruments
Optimization that measure carbon levels in ash, coal flow rates, air flow rates, CO levels,
oxygen levels, slag deposits, and burner metrics as well as advanced coal
nozzles and plasma assisted coal combustion. Combustion control for a coal-
fired EGU is complex and impacts a number of important operating
parameters including combustion efficiency, steam temperature, furnace
slagging and fouling, and NOX formation.
Cooling System Controls are applied to recover a portion of the heat loss from the warm
Heat Loss cooling water exiting the steam condenser prior to its circulation thorough a
Recovery cooling tower or discharge to a water body. The identified technologies
include replacing the cooling tower fill (heat transfer surface) and tuning the
cooling tower and condenser.
Flue Gas Heat Flue gas exit temperature from the air pre-heater can range from 250- 350°F
Recovery depending on the acid dew point temperature of the flue gas, which is
dependent on the concentration of vapor phase sulfuric acid and moisture.
For power plants equipped with wet FGD systems, the flue gas is further
cooled to approximately 125°F as it is sprayed with the FGD reagent slurry.
However, it may be possible to recover some of this lost energy in the flue
gas to preheat boiler feedwater via use of a condensing heat exchanger.
0.15 to 0.84%
0.2 to 1%
0.3 to 1.5%
(continued)
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Table 4-8. Existing Coal-Fired ECU Efficiency Improvements Reported for Actual Efficiency
Improvement Projects (continued)
Efficiency
Improvement
Technology
Description
Reported
Efficiency
Increase3
Low-rank Coal Subbituminous and lignite coals contain relatively large amounts of moisture 0.1 to 1.7%
Drying (15 to 40%) compared to bituminous coal (less than 10%). A significant
amount of the heat released during combustion of low-rank coals is used to
evaporate this moisture, rather than generate steam for the turbine. As a
result, boiler efficiency is typically lower for plants burning low-rank coal.
The technologies include using waste heat from the flue gas and/or cooling
water systems to dry low-rank coal prior to combustion.
Soot Blower Soot blowers intermittently inject high velocity jets of steam or air to clean 0.1 to 0.65%
Optimization coal ash deposits from boiler tube surfaces in order to maintain adequate
heat transfer. Proper control of the timing and intensity of individual soot
blowers is important to maintain steam temperature and boiler efficiency.
The identified technologies include intelligent or neural-network soot
blowing (i.e., soot blowing in response to real-time conditions in the boiler)
and detonation soot blowing.
Steam Turbine Recoverable energy losses can result from the mechanical design or physical 0.84 to 2.6%
Design condition of the steam turbine. For example, steam turbine manufacturers
have improved the design of turbine blades and steam seals which can
increase both efficiency and output (i.e., steam turbine dense pack
technology).
Source: EPA 2010, NETL 2008
a Reported efficiency improvement metrics adjusted to common basis by conversion methodology assuming
individual component efficiencies for a reference plant as follows: 87 percent boiler efficiency, 40 percent
turbine efficiency, 98 percent generator efficiency, and 6 percent auxiliary load. Based on these assumptions,
the reference power plant has an overall efficiency of 32 percent and a net heat rate of 10,600 Btu/kWh. As a
result, if a particular efficiency improvement method was reported to achieve a 1 percentage point increase in
boiler efficiency, it would be converted to a 0.37 percentage point increase in overall efficiency. Likewise, a
reported 100 Btu/kWh decrease in net heat rate would be converted to a 0.30 percentage point increase in
overall efficiency.
In addition to the techniques described above, new coal-fired ECU projects may use
other methods to maximize thermal efficiency. Under constant energy input, a higher pressure
and temperature for the water-steam cycle will increase the overall efficiency. Most existing
boilers, however, are already operating at the maximum pressure and temperature that the
boiler is designed to withstand. Most existing coal-fired EGUs have subcritical boilers that
typically operate at a pressure of 2,400 pounds per square inch (psi) and temperatures between
1,000 to 1,050°F. "Supercritical" boilers are those that use steam pressures above 3200 psi and
temperatures up to 1,100°F. Boilers that can operate above these conditions are considered
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"ultra-supercritical." Examples of ultra-supercritical coal-fired EGUs in Canada, Europe, and
Japan are cited as representing the highest efficiency coal-fired EGUs in the world (EPA, 2010).
4.5.3 Other Approaches to Reduce GHG Emissions
While CCS and fuel efficiency improvements are more closely related to potential NSPS
regulatory frameworks, they are not the only options available for EGUs to reduce emissions of
C02. As discussed previously, the amount of C02 emitted during the combustion of fossil fuels
varies according to the carbon content and heating value of the fuel used (see Table 4-7).
Switching from a higher-emitting to a lower-emitting fuel will reduce C02 emissions from an
ECU, all other things equal. Similarly, increasing the share of generation from lower-emitting
sources will also lead to a reduction in C02 emissions. As with increased generation efficiency,
improvements to efficiency in transmission and electricity use will also result in reductions in
C02 emissions. Note that these types of strategies would further reduce need for construction
of new units.
4.6 GHG Regulation in the Power Sector
In April 2007, the Supreme Court concluded that GHGs met the CAA definition of an air
pollutant, giving EPA the authority to regulate GHGs under the CAA based on the agency
determination that GHG emissions from new motor vehicles cause or contribute to air pollution
that may reasonably be anticipated to endanger public health or welfare. This decision to
regulate GHG emissions for motor vehicles set the stage for the determination of whether
other sources of GHG emissions, including stationary sources, would need to be regulated as
well.
In response to the FY2008 Consolidated Appropriations Act (H.R. 2764; Public Law 110-
161), EPA issued the Mandatory Reporting of Greenhouse Gases Rule (74 FR 5620) which
required reporting GHG data and other relevant information from fossil fuel suppliers and
industrial gas suppliers, direct greenhouse gas emitters, and manufacturers of heavy-duty and
off-road vehicles and engines. The purpose of the rule was to collect accurate and timely GHG
data to inform future policy decisions. As such, it did not require that sources control
greenhouse gases, only that sources above certain threshold levels monitor and report
emissions.
In August 2007, EPA issued a PSD permit to Deseret Power Electric Cooperative,
authorizing it to construct a new waste-coal-fired ECU near its existing Bonanza Power Plant, in
Bonanza, Utah. The permit did not include emissions control requirements for C02. EPA
acknowledged the Supreme Court decision, but found that decision alone did not require PSD
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permits to include limits on C02 emissions. Sierra Club challenged the Deseret permit. In
November 2008, the Environmental Appeals Board (EAB) remanded the permit to EPA to
reconsider "whether or not to impose a C02 BACT limit in light of the 'subject to regulation'
definition under the CAA." The remand was based in part on EAB's finding that there was not
an established EPA interpretation of the regulatory phrase "subject to regulation."
In December 2008, the Administrator issued a memo indicating that the PSD Permitting
Program would apply to pollutants that are subject to either a provision in the CAA or a
regulation adopted by EPA under the CAA that requires actual control of emissions of that
pollutant. The memo further explained that pollutants for which EPA regulations only require
monitoring or reporting, such as the provisions for C02 in the Acid Rain Program, are not
subject to PSD permitting. Fifteen organizations petitioned EPA for reconsideration, prompting
the agency to issue a revised finding in March 2009. After reviewing comments, EPA affirmed
the position that PSD permitting is not triggered for a pollutant such as GHGs until a final
nationwide rule requires actual control of emissions of the pollutant. For GHGs, this meant
January 2011 when the first national rule limiting GHG emissions for cars and light trucks was
scheduled to take effect. Therefore, a permit issued after January 2, 2011, it would have to
address GHG emissions.
The Administrator signed two distinct findings in December 2009 regarding greenhouse
gases under section 202(a) of the Clean Air Act. The endangerment finding indicated that
current and projected concentrations of the six key well-mixed greenhouse gases — C02, CH4,
N20, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and SF6 — in the atmosphere
threaten the public health and welfare of current and future generations. These greenhouse
gases have long lifetimes and, as a result, become homogeneously distributed through the
lower level of the Earth's atmosphere (IPCC, 2001). This differentiates them from other
greenhouse gases that are not homogeneously distributed in the atmosphere. The cause and
contribute finding indicated that the combined emissions of these well-mixed greenhouse gases
from new motor vehicles and new motor vehicle engines contribute to the greenhouse gas
pollution which threatens public health and welfare. Both findings were published in the
Federal Register on December 15, 2009 (Docket ID EPA-HQ-OAR-2009-0171). These findings did
not themselves impose any requirements on industry or other entities, but allowed EPA to
regulate greenhouse gases under the Clean Air Act. This action was a prerequisite to
implementing the EPA's proposed greenhouse gas emission standards for light-duty vehicles,
which was finalized in January 2010. Once a pollutant is regulated under the Clean Air Act, it is
subject to permitting requirements under the PSD and Title V programs.
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In May 2010, EPA issued the final Tailoring Rule which set thresholds for GHG emissions
that define when permits under the New Source Review PSD and Title V Operating Permit
programs are required for new and existing industrial facilities. Facilities responsible for nearly
70 percent of the national GHG emissions from stationary sources, including EGUs, were
subject to permitting requirements under the rule.
EPA entered into two proposed settlement agreements in December 2010 to issue rules
that will address greenhouse gas emissions from fossil fuel-fired power plants and refineries.
These two industrial sectors make up nearly 40 percent of the nation's greenhouse gas
emissions. For natural gas, oil, and coal-fired EGUs this rule establishes NSPS for new and
reconstructed sources, with the exception of combustion turbines. Existing source standards
will be addressed in a later action. Details of the settlement agreements can be found on the
EPA website.3
4.7 Revenues, Expenses, and Prices
Due to lower retail electricity sales, total utility operating revenues declined in 2009 to
$276 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008
levels in 2010, operating expenses were appreciably lower and as a result, net income also rose
in comparison to both 2008 and 2009 (see Table 4-9). Recent economic events have put
downward pressure on electricity demand, thus dampening electricity prices and consumption
(utility revenues), but have also reduced the price and cost of fossil fuels and other expenses.
Electricity sales and revenues associated with the generation, transmission, and distribution of
electricity are expected to rebound and increase modestly by 2015, when revenues are
projected to be roughly $360 billion (see Table 4-10).
Table 4-9 shows that investor-owned utilities (lOUs) earned income of about 11.5
percent compared to total revenues in 2009. Based on ElA's Annual Energy Outlook 2011, Table
4-10 shows that the power sector is projected to derive revenues of $360 billion in 2015.
Assuming the same income ratio from lOUs (with no income kept by public power), and using
the same proportion of power sales from public power as observed in 2009, EPA projects that
the power sector will expend over $320 billion in 2015 to generate, transmit, and distribute
electricity to end-use consumers.
Over the past 50 years, real retail electricity prices have ranged from around 7 cents per
kWh in the early 1970s, to around 11 cents, reached in the early 1980s. Generally, retail
3 http://www.epa.gov/airquality/ghgsettlement.html
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electricity prices do not change rapidly and do not display the variability of other energy or
commodity prices, although the frequency at which these prices change varies across different
types of customers. Retail rate regulation has largely insulated consumers from the rising and
falling wholesale electricity price signals whose variation in the marketplace on an hourly, daily,
and seasonal basis is critical for driving lowest-cost matching of supply and demand. In fact, the
real price of electricity today is lower than it was in the early 1960s and 1980s (see Figure 4-7).
Table 4-9. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities
for 2010 ($millions)
Utility Operating Revenues
Electric Utility
Other Utility
Utility Operating Expenses
Electric Utility
Operation
Production
Cost of Fuel
Purchased Power
Other
Transmission
Distribution
Customer Accounts
Customer Service
Sales
Admin, and
General
Maintenance
Depreciation
Taxes and Other
Other Utility
Net Utility Operating Income
2008
298,962
266,124
32,838
267,263
236,572
175,887
140,974
47,337
84,724
8,937
6,950
3,997
5,286
3,567
225
14,718
14,192
19,049
26,202
30,692
31,699
2009
276,124
249,303
26,822
244,243
219,544
154,925
118,816
40,242
67,630
10,970
6,742
3,947
5,203
3,857
178
15,991
14,092
20,095
29,081
24,698
31,881
2010
284,373
260,113
24,260
250,122
226,845
159,585
128,808
44,115
67,284
13,013
6,948
4,007
5,091
4,741
185
17,115
14,962
20,930
27,646
23,277
34,251
Source: EIA2010a
Note: This data does not include information for public utilities.
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Table 4-10. Projected Revenues by Service Category in 2015 for Public Power and Investor-
Owned Utilities (billions)
Generation
Transmission
Distribution
$195
36
129
Total
$360
Source: EIA2011
Note: Data are derived by taking either total electricity use (for generation) or sales (transmission and
distribution) and multiplying by forecasted prices by service category from Table 8 of EIA 2011 (Electricity
Supply, Disposition, Prices, and Emissions).
14
12
10
I.
V
u
1960
1970
1980
1990
2000
2010
Figure 4-7. National Average Retail Electricity Price (1960 - 2009)
Source: EIA2010a
On a state-by-state basis, retail electricity prices vary considerably. The Northeast and
California have average retail prices that can be as much as double those of other states (see
Figure 4-8).
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Average Retail Price of Electricity by State, 2009
Average Price (cents per kilowatthour)
[6 OS to 7,
^H 7 37 lo 8
8 42 lo 9 36
9.4010 1308
^H 13091021 21
Note: Data die displayed as 5 grcups ol 10 States and ihe District of Columbia.
U.S. total average price per kilovwui rnour is 9.93 cents.
Source: U 3 Eneigy Information
Power tf»dsutiy Report "
Figure 4-8. Average Retail Electricity Price by State (cents/kWh), 2009
Source: EIA2009
4.7.1 Natural Gas Market
The natural gas market in the United States has historically experienced significant price
volatility from year to year, between seasons within a year, and can undergo major price swings
during short-lived weather events (such as cold snaps leading to short-run spikes in heating
demand). Over the last decade, gas prices (both Henry Hub prices and delivered prices to the
power sector) have ranged from $3 per mmBtu to as high as $9 on an annual average basis (see
Figure 4-9). During that time, the daily price of natural gas reached as high as $15/mmBtu.
Recent forecasts of natural gas have also experienced considerable revision as new sources of
gas have been discovered and have come to market, although there continues to be some
uncertainty surrounding the precise quantity of the resource base.
EIA projections of future natural gas prices assume trends that are consistent with
historical and current market behavior, technological and demographic changes, and current
laws and regulations.4 Depending on actual conditions, there may be significant variation from
the price projected in the reference case and the price observed. To address this uncertainty,
EIA issues a range of alternative cases, including cases with higher and lower economic growth,
AEO 2010c.
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which address many of the uncertainties inherent in the long-term projections. EPA uses the
reference case and a number of alternative cases in its analyses.
CQ
c
o
01
Q.
i/l
O
•a
o
o
-EIA Historical Natural Gas Spot Price (Henry Hub)
EIA Projected (2011) Natural Gas Spot Price (Henry Hub)
EIA Projected (2012) Natural Gas Spot Price (Henry Hub)
EIA Projected (2010) Natural Gas Spot Price (Henry Hub)
1990
1995
2000
2005
2010
2015
2020
2025
2030
2035
Figure 4-9. Natural Gas Spot Price, Annual Average (Henry Hub)
Source: EIA 2010d, EIA 2011, EIA 2012
4.8 Electricity Demand and Demand Response
Electricity performs a vital and high-value function in the economy. Historically, growth
in electricity consumption has been closely aligned with economic growth. Overall, the U.S.
economy has become more efficient over time, producing more output (GDP) per unit of
energy input, with per capita energy use fairly constant over the past 30 years (EIA, 2010e). The
growth rate of electricity demanded has also been in overall decline for the past sixty years (see
Figure 4-8), with several key drivers that are worth noting. First, there has been a significant
structural shift in the U.S. economy towards less energy-intensive sectors, like services. Second,
companies have strong financial incentives to reduce expenditures, including those for energy.
Third, companies are responding to the marketplace and continually develop and bring to
market new technologies that reduce energy consumption. Fourth, other policies, such as
energy efficiency standards at the state and Federal level, have helped address certain market
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failures. These broader changes have altered the outlook for future electricity growth (see
Figure 4-10).
VVVVVVVVV 'V "V "V V "V 'V "
Figure 4-10. Electricity Growth Rate (3 Year Rolling Average) and Projections from the Annual
Energy Outlook 2011
Source: EIA 2009, EIA 2011
Note: Electricity demand projections in the AEO 2012 early release are very similar to those in AEO 2011 and would
not be expected to change this figure noticeably.
Energy efficiency initiatives have become more common, and investments in energy
efficiency are projected to continue to increase for the next 5 to 10 years, driven in part by the
growing number of states that have adopted energy efficiency resource standards.5 These
investments, and other energy efficiency policies at both the state and federal level, create
incentives to reduce energy consumption and peak load. According to EIA, demand-side
management provided actual peak load reductions of 31.7 GW in 2009. For context, the current
coal fleet is roughly 320 GW of capacity.
Demand for electricity, especially in the short run, is not very sensitive to changes in
prices and is considered relatively price inelastic, although some demand reduction does occur
in response to price. With that in mind, EPA modeling does not typically incorporate a "demand
response" in its electric generation modeling (Chapter 5) to the increases in electricity prices
' To the extent that EIA includes these measures in its baseline forecast from the Annual Energy Outlook, EPA has
also incorporated them into the baseline for purposes of assessing the economic impacts of this proposed rule.
See AEO 2011 and Chapter 7 of the IPM documentation for more detail.
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typically projected for EPA rulemakings. Electricity demand is considered to be constant in EPA
modeling applications and the reduction in production costs that would result from lower
demand is not considered in the primary analytical scenario that is modeled. This leads to some
overstatement in the private compliance costs that EPA estimates for rules where compliance
costs are anticipated for a rulemaking. Note that this NSPS is not anticipated to create
compliance costs for new ECU sources.
4.9 References
Interagency Task Force on Carbon Capture and Storage. Report of the Interagency Task Force on
Carbon Capture and Storage. August 2010. Available online at:
http://www.epa.gov/climatechange/downloads/CCS-Task-Force-Report-2010.pdf.
Intergovernmental Panel on Climate Change. Climate Change 2001: The Scientific Basis. 2001.
Available online at:
http://www.grida.no/publications/other/ipcc tar/?src=/climate/ipcc tar/wgl/218.htm.
National Energy Technology Laboratory (NETL). Reducing C02 Emissions by Improving the
Efficiency of Existing Coal-fired Power Plant Fleet. July 2008. Available online at:
http://www.netl.doe.gov/energv-analyses/pubs/CFPP%20Efficiencv-FINAL.pdf.
Pacific Northwest National Laboratory (PNNL). An Assessment of the Commercial Availability of
Carbon Dioxide Capture and Storage Technologies as of June 2009. June 2009. Available
online at: http://www.pnl.gov/science/pdf/PNNL-18520 Status of CCS 062009.pdf.
Sargent & Lundy, LLC. Coal-fired Power Plant Heat Rate Reductions. January 2009. Available
online at: http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf.
U.S. Energy Information Administration (U.S. EIA). Carbon Dioxide Emissions from the
Generation of Electric Power in the United States. July 2000. Available online at:
ftp://ftp.eia.doe.gov/environment/co2emissOO.pdf.
U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2003. 2003. Available
online at: http://www.eia.gov/electricity/annual/archive/03482003.pdf.
U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2009. 2009. Available
online at: http://www.eia.gov/electricity/annual/archive/03482009.pdf.
U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2010. 2010a. Available
online at: http://www.eia.gov/electricity/annual/.
U.S. Energy Information Administration (U.S. EIA). "Status of Electricity Restructuring by State."
2010b. Available online at:
http://www.eia.gov/cneaf/electricity/page/restructuring/restructure elect.html.
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U.S. Energy Information Administration (U.S. EIA). AEO 2010 Retrospective Review. 2010c.
Available online at: http://www.eia.gov/forecasts/aeo/retrospective/.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010d.
Available online at: http://www.eia.gov/oiaf/archive/aeolO/index.html.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Review 2010. 2010e. Available
online at: http://www.eia.gov/totalenergy/data/annual/pdf/aer.pdf.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2011. 2011. Available
online at: http://www.eia.gov/forecasts/archive/aeoll/.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2012 (Early Release).
2012. Available online at: http://www.eia.gov/forecasts/aeo/.
U.S. Environmental Protection Agency (U.S. EPA). Available and Emerging Technologies for
Reducing Greenhouse Gas Emissions from Coal-Fired Electric Generating Units. October
2010. Available online at: http://www.epa.gov/nsr/ghgdocs/electricgeneration.pdf.
U.S. Environmental Protection Agency (U.S. EPA). Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2009. April 2011. Available online at:
http://epa.gov/climatechange/emissions/downloadsll/US-GHG-lnventorv-2011-
Complete Report.pdf.
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CHAPTER 5
COSTS, BENEFITS, ECONOMIC, AND ENERGY IMPACTS
5.1 Synopsis
This chapter reports the compliance cost, economic, and energy impact analysis
performed for the ECU GHG NSPS. EPA used IPM, developed by ICF Consulting, in this analysis.
IPM is a dynamic linear programming model that can be used to examine air pollution control
policies throughout the United States for the entire power system. EPA used the IPM model to
forecast likely future electricity market conditions with and without the proposed rule.
Even in a baseline scenario without the proposed rule, the only capacity additions
subject to this rule projected during the analysis period (through 20201) are compliant with the
requirements of this rule (e.g., combined cycle natural gas and small amounts of coal with CCS
supported by DOE funding). This conclusion also holds for several sensitivity analyses EPA
performed. As a result, under a wide range of future electricity market conditions, this
proposed ECU GHG NSPS is not expected to change GHG emissions for newly constructed
EGUs, and is anticipated to impose negligible costs, economic impacts, or energy impacts on the
ECU sector or society. An additional illustrative analysis, presented at the end of this chapter,
indicates that even in the unlikely event that electricity market conditions change enough to
support additional new coal, the proposed ECU GHG NSPS would provide net benefits. This
analysis concluded based on sensitivity analyses that the price of natural gas would have to
increase to approximately $10/mmBtu for coal boilers without CCS to become competitive with
combined cycle natural gas units, which is projected to be very unlikely.2
5.2 Background
Over the last decade, EPA has conducted extensive analyses of regulatory actions
impacting the power sector. These efforts support the Agency's understanding of key policy
variables and provide the framework for how the Agency estimates the costs and benefits
associated with its actions. Current forecasts for the mix of new, and utilization of existing,
generating capacity are a key input into informing the design of EPA's proposal. Given excess
capacity within the existing fleet and relatively low forecasts of electricity demand growth,
there is limited new capacity, of any type, expected to be constructed over the next decade. A
small number of new coal-fired power plants have been built in recent years; however, EPA
Note that while the analysis presented in this RIA is for the year 2020, IPM projections were also made for 2030
and are available in the docket.
This chapter presents all costs in 2007$.
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does not forecast the construction of any new unplanned coal-fired additions over the time
horizon of this analysis (through the year 2020). For more detailed discussion of this forecast,
see section 5.5.
Under current and foreseeable future market conditions affecting new capacity
additions, gas-fired generating technologies can produce electricity at a lower levelized cost
than coal-fired generating technologies, and therefore utilities are expected to rely heavily on
combustion turbines and combined cycle plants using natural gas when they do need to expand
capacity during the time horizon considered for this analysis. Current and projected natural gas
prices are considerably lower than the prices observed over the past decade, largely due to
advances in hydraulic fracturing and horizontal drilling techniques that have opened up new
shale gas resources and substantially increased the supply of economically recoverable natural
gas. According to EIA,
Shale gas refers to natural gas that is trapped within shale formations. Shales are
fine-grained sedimentary rocks that can be rich sources of petroleum and natural
gas. Over the past decade, the combination of horizontal drilling and hydraulic
fracturing has allowed access to large volumes of shale gas that were previously
uneconomical to produce. The production of natural gas from shale formations
has rejuvenated the natural gas industry in the United States.
The U.S. Energy Information Administration's Annual Energy Outlook 2012 (Early
Release) estimates that the United States possessed 2,214 trillion cubic feet (Tcf) of
technically recoverable natural gas resources as of January 1, 2010. Natural gas from
proven and unproven shale resources accounts for 542 Tcf of this resource estimate.
Many shale formations, especially the Marcellus, are so large that only small portions of
the entire formations have been intensively production-tested. Consequently, the
estimate of technically recoverable resources is highly uncertain, and is regularly
updated as more information is gained through drilling and production. At the 2010 rate
of U.S. consumption (about 24.1 Tcf per year), 2,214 Tcf of natural gas is enough to
supply over 90 years of use. Although the estimate of the shale gas resource base is
lower than in the prior edition of the Outlook, shale gas production estimates increased
between the 2011 and 2012 Outlooks, driven by lower drilling costs and continued
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drilling in shale plays with high concentrations of natural gas liquids and crude oil, which
have a higher value in energy equivalent terms than dry natural gas.3
Based on these market conditions, and detailed analysis and modeling conducted by
EPA, the levelized cost of generation from a new natural gas power plant is expected to be
lower on average than the levelized cost of generation from a new coal-fired power plant.4'5
This trend has already been observed recently, as natural gas-fired capacity has been the
technology of choice for power generation over the last few years (see Figure 5-1).
3 For more information, see: http://www.eia.gov/forecasts/archive/aeoll/IF all.cfmtfprospectshale;
4 See Table 5-4, which reports the levelized cost of new generation in the Annual Energy Outlook (AEO) 2011.
5 Note that EPA's analysis, which is consistent with this expectation, is based on sophisticated IPM modeling, and is
http://www.eia.gov/energy in brief/about shale gas.cfm
ee Table 5-4, which reports the levelized cos
lote that EPA's analysis, which is consistent v
not based on simplified LCOE assumptions.
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70,000
60,000
Gas(CCandCT)
Renewable/Hydro
^^ullllll
Figure 5-1. Historical U.S. Power Plant Capacity Additions, by Technology
Source: National Electric Energy Data System (NEEDS) v4.10_PTox
Note: Renewables include geothermal, biomass, solar, and wind energy technologies. A considerable amount of
renewables were built in 2009 and 2010, and these are reflected in EPA modeling applications but not necessarily
in NEEDS.
Numerous energy sector modeling efforts, including recent projections from EIA, have
provided results that are consistent with these findings. The Annual Energy Outlook (AEO) for
2011 shows a modest amount of CCS-equipped new coal-fired power coming online past 2012
that would be in compliance with this proposal.6 EIA includes some additional new coal with
CCS in its baseline (2 GW), an assumption which EPA has adopted in IPM. The new CCS is in
response to existing Federal incentives for the technology (the Emergency Economic
Stabilization Act of 2008 and the American Reinvestment and Recovery Act of 2009). According
to the AEO 2011, the majority of new generating capacity is forecast to be either natural gas-
fired or renewable, with some lesser amounts of nuclear power. The AEO 2011 is based on
' AEO 2011 has a small amount of planned coal capacity that is under construction and expected to come online in
the next year. This capacity represents certain units that likely fit the definition of transitional sources under
this proposal. It also has 2 GW of unplanned coal capacity, which reflects new coal with CCS in response to
Federal incentives.
5-4
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existing policy and regulations, such as state Renewable Portfolio Standard programs and
Federal tax credits for renewables.7 Based on EIA analysis, DOE concluded, that "the low capital
expense, technical maturity, and dispatchability of natural gas generation are likely to dominate
investment decisions under current policies and projected prices."8 The economics favoring
new NGCC additions instead of conventional coal are robust under a range of sensitivity cases
examined in the AEO. Unplanned additions of coal by 2020 are also not forecast in sensitivity
cases that separately examine higher economic growth, lower coal prices, lower capital costs
for fossil capacity, no risk premium for greenhouse gas emissions liability from conventional
coal, slower oil and gas technology deployment, lower shale gas recovery per play, and lower
shale gas recovery per well. In addition, the ElA's AEO 2012 Early Release (AEO 2012 ER) does
not forecast new unplanned coal capacity without CCS through 2020. Furthermore, it projects
an increase over AEO 2011 in the price of coal relative to natural gas, strengthening the
conclusion that natural gas-fired generating technologies are likely to be the fossil fuel of choice
during the analysis period. The AEO 2012 ER also has lower electricity demand projections than
those used in IPM, reflecting an extended economic recovery and increasing energy efficiency
in end-use appliances,9 which would result in the need for less new capacity in general.
EPA uses IPM to support its understanding of the economic and emissions impacts of air
regulations on the power sector. IPM forecasts show patterns of future power plant
deployment that are similar to those presented in AEO 2011, and also forecasts no construction
of new conventional coal-fired power plants under the base case.10
A number of major utilities have made public announcements consistent with these
modeling results.11
IPM has been used for evaluating the economic and emission impacts of environmental
policies for over two decades. The economic modeling presented in this chapter has been
developed specifically for analysis of the power sector. Thus, the model has been designed to
7 http://www.eia.gov/forecasts/aeo/chapter legs regs.cfm
8 Department of Energy (2011). Report on the First Quadrennial Technology Review. Available at
http://enerav.aov/sites/prod/files/QTR report.pdf.
9 AEO 2012 Early Release Overview
10 http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.htmltfdocumentation
11 For example: "We have no other coal-fueled generation planned at this time... When we do need new capacity,
it is highly likely that we will look to natural gas plants instead of coal, especially if natural gas prices remain as
low as projected." AEP January 1, 2011, Washington Post; "If you actually look at the economics today, you
would be burning gas, not coal," Jack Fusco, Calpine, 12/1/2010, Marketplace; "Coal's most ardent defenders
are in no hurry to build new ones in this environment." John Rowe, Exelon, 9/2011, EnergyBiz; "With low gas
prices, gas-fired generation kind of snowplows everything else" Lew Hay, NextEra, 11/1/2010, Dow Jones.
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reflect the industry as accurately as possible. EPA uses the best available information from
utilities, industry experts, gas and coal market experts, financial institutions, and government
statistics as the basis for the detailed power sector modeling in IPM. More detail on IPM can be
found in the model documentation, which provides additional information on the assumptions
discussed here as well as all other assumptions and inputs to the model.
5.3 External Review of EPA Applications of IPM
EPA has used IPM extensively over the past two decades to analyze options for reducing
power-sector emissions. The model has been used by the Agency to support regulatory
initiatives as well as legislative proposals designed to address air emissions for the power
sector. All of the IPM scenarios conducted for this rulemaking are available at EPA's website
and in the public docket.12
The model undergoes periodic formal peer review, which includes separate expert
panels for both the model itself and EPA's key modeling input assumptions. For example, over
the past ten years several separate panels of independent experts have been convened to
review IPM's coal supply and transportation assumptions, natural gas assumptions, and model
formulation.
The rulemaking process also provides opportunity for expert review and comment by a
variety of stakeholders, including owners and operators of the electricity sector that is
represented by the model, public interest groups, and other developers of U.S. electricity sector
models. The feedback that the Agency receives provides a highly detailed check for key input
assumptions, model representation, and modeling results.
The Agency has used IPM in several recent regulatory contexts. The model has been
used to support the Agency's analytics for the Clean Air Interstate Rule, CSAPR, MATS, and over
a dozen legislative analytical efforts to forecast the costs, emission changes, and power sector
impacts of various policies to reduce power sector emissions. As part of the rulemaking
process, EPA is required to respond to every significant comment submitted.
The model has also been used by states (e.g., for Regional Greenhouse Gas Initiative,
the Western Regional Air Partnership, Ozone Transport Assessment Group), other Federal and
State agencies, environmental groups, and industry, all of whom subject the model to their own
review procedures.
12 http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html
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More specifically, the model has received extensive review by energy and
environmental modeling experts over the past two decades. States have used the model
extensively to inform issues related to ozone in the northeastern portion of the U.S. This
groundbreaking work set the stage for the NOX SIP call, which has helped reduce summer NOX
emissions and the formation of ozone in densely populated areas in the northeast. In the late
1990's, the Science Advisory Board reviewed IPM as part of the CAA Amendments Section 812
prospective studies that are periodically conducted. The model has also undergone
considerable interagency scrutiny as part of a series of legislative analyses over the past
decade. These analyses explored a variety of approaches to controlling emissions from the
power sector, and the results were presented to Congress in a comparative manner in order to
evaluate the merits of policy proposals. The model was also used to support the Agency's
power sector analyses of legislative climate proposals in 2005, continuing through 2010. In
addition, Regional Planning Organizations throughout the U.S. have extensively examined IPM
as a key element in the state implementation plan (SIP) process for the National Ambient Air
Quality Standards. The Agency has also used the model in a number of comparative modeling
exercises sponsored by Stanford University's Energy Modeling Forum over the past 15 years.
5.4 IPM is a Detailed Bottom-Up Model
EPA applies IPM to consider nationwide impacts of environmental policies, which can
also be considered at a regional level of detail appropriate to the functional organization of the
power section. Although the Agency typically focuses on broad system effects when assessing
the economic impacts of a particular policy, EPA's application of IPM includes a detailed and
sophisticated regional representation of key power sector variables. For example, the model
includes 32 power regions with detailed representation of the inter-regional transmission
system and reflects the regional aspects of natural gas and coal markets. When considering
which new units are most cost effective to build and operate, the model considers the relative
economics of various technologies based on their unique capital costs, operation and
maintenance (O&M) costs, fuel costs and emission profiles. The capital costs for new units are
regionalized through the application of regional adjustment factors that capture regional
differences in labor, material, and construction costs. These regional cost differentiation factors
are based on assumptions used in the ElA's AEO.
As part of the model's assessment of the relative economic value of building a new
power plant, the model incorporates a detailed representation of the fossil-fuel supply system
that supports fuel price projections, a key component of new power plant economics. The
model includes an endogenous representation of the North American natural gas supply system
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through a natural gas module that reflects a full supply/demand equilibrium of the North
American gas market. This module consists of 114 supply, demand, and storage nodes and 14
liquefied natural gas regasification facility locations that are tied together by a series of linkages
(i.e., pipelines) that represent the North American natural gas transmission and distribution
network.
IPM also endogenously models the coal supply and demand system throughout the
continental U.S., and reflects non-power sector demand and imports/exports. IPM reflects 84
coal supply curves, 12 coal sulfur grades, and the coal transport network, which consists of
1,230 linkages representing rail, barge, and truck and conveyer linkages. The coal supply curves
in IPM, which are publicly available, were developed during a thorough bottom-up, mine-by-
mine based approach that depict the coal choices and associated supply costs that power
plants will face over the modeling time horizon. The IPM documentation outlines the methods
and data used to quantify the economically recoverable coal reserves, characterize their cost,
and build the 84 coal supply curves that are implemented in EPA modeling applications. The
coal curves used by EPA were developed in consultation with Wood Mackenzie, one of the
leading energy consulting firms and specialists in coal supply. These curves have been
independently reviewed by industry experts and have been made available for public review on
several occasions over the past two years during the rulemaking process for CSAPR and MATS.
5.5 Base Case and Sensitivity Analysis of Future Generating Capacity
5.5.1 Base Case A nalysis
EPA began its analysis of the economic impacts of the proposed NSPS by conducting a
base case analysis of future generating capacity. This base case incorporates the final MATS and
the final Transport Rule (finalized as CSAPR).13 In addition to MATS and CSAPR, the baseline
takes into account emissions reductions associated with the implementation of all finalized
federal rules, state rules and statutes, and other binding, enforceable commitments that are
applicable to the power industry and which govern the installation and operation of pollution
controls during the timeframe covered in the analysis. EPA's IPM modeling for this rule relies on
ElA's Annual Energy Outlook for 2010's electric demand forecast for the US and employs a set
of EPA assumptions regarding fuel supplies, the performance and cost of electric generation
technologies, pollution controls, and numerous other parameters.
13 http://www.epa.gov/airquality/powerplanttoxics and http://www.epa.gov/airtransport.
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The IPM base case projection is based on an electricity demand growth assumption of
0.8 percent annually on average, similar to ElA's Annual Energy Outlook for 2010, and slightly
higher than the 0.7 percent annual average growth in the AEO 2012 ER. Total electricity
demand is projected to be 4,086 billion kWh by 2015. Table 5-2 shows current electricity
generation alongside EPA's projection for 2020 using IPM. This new demand will be fulfilled by
existing generating capacity that is currently not being fully utilized, and new renewable and
gas-fired generating capacity (see Table 5-1). The change in coal represents only retirements of
existing plants and no new unplanned coal builds. These projections are the result of least-cost
dispatching using IPM, and reflect the most cost-effective dispatch and investment option,
given a variety of variables and constraints. Although most new generating capacity will be
renewable and natural gas-fired, U.S. electricity demand will continue to be met by a diverse
mix of electricity generation sources (see Table 5-2). In addition, coal is projected to continue
to provide the largest share of America's electricity.14 By 2020, EPA forecasts roughly 27 GW of
new renewable capacity, 2 GW of coal with CCS, and 10 GW of new natural gas-fired capacity.
Although 2 GW of coal with CCS is included in the base case in response to incentives under
existing law, overall coal capacity is forecast to decline in response to current economics, along
with some retirements due to other air regulations (CSAPR and MATS).
14 Coal-fired generation is projected to increase above 2009 actual levels. 2020 natural gas-fired generation is
projected to be lower than 2010, due in large part to the smaller relative difference in delivered natural gas and
coal prices in different areas of the country projected to occur in 2020 than occurred in 2010. While the
projected narrowing of this gas price and coal price differential may increase dispatch (generation) from
existing coal units, it is insufficient to shift the economic decision to favor new conventional coal-fired capacity,
which requires consideration of capital costs in addition to generation costs. The same trend is seen in AEO
2011 projections.
5-9
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Table 5-1. Total Generation Capacity in 2010 and Projected by 2020 (GW)
Pulverized Coal
Natural Gas Combined Cycle
Combustion Turbine
Oil/Gas Steam
Non-Hydro Renewables
Hydro
Nuclear
Other
Total
2010
316
199
135
111
31
99
102
5
998
2020
304
212
143
90
73
99
106
4
1,030
Source: 2010 data from EPA's NEEDS v.4.10 PTR. 2020 projections from Integrated Planning Model run by EPA.
Notes: The sum of the table values in each column may not match the total figure due to rounding.
"Non-Hydro Renewables" include biomass, geothermal, solar, and wind electric generation capacity. The capacity of a
generating unit that is co-firing gas in a coal boiler is split in this table between "pulverized coal" and "Oil/Gas Steam"
proportionally by fuel use.
Table 5-2. 2010 U.S. Electricity Net Generation and EPA Base Case Projections for 2020
(Billion kWh)
Coal
Oil
Natural Gas
Nuclear
Hydroelectric
Non-hydro Renewables
Other
Total
Historical
2010
1,828
35
901
807
258
139
4
3,972
Projected
2020
1,976
0.126
869
840
286
289
45
4,305
Notes: The sum of the table values in each column may not match the total figure due to rounding.
Source: 2010 data from EIA Electric Power Annual 2010, Table 2.1; 2020 projection from IPM run by EPA, 2011.
5.5.2 Sensitivity Analyses
Forecasts suggesting that new coal is unlikely to be built by 2020 have been shown to be
robust under a range of alternative assumptions that influence the industry's decisions to build
new power plants. For example, EIA typically supplements the AEO with a series of distinct
scenarios that explore specific issues and examine a future state of the world that deviates
from the core parameter estimates that underlie the AEO reference case. Even under
5-10
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alternative scenarios where assumptions might improve the relative economic value of building
new coal-fired power plants, the AEO 2011 does not project new coal capacity being built
through 2025, beyond the coal capacity already planned outside of the modeling. Relevant
scenarios include higher economic growth forecast, lower cost of coal supply, lower capital
costs of fossil fuel-fired energy technologies, and less optimistic natural gas supply.15 Although
new coal capacity is built in some of these scenarios after 2025, CAA Section lll(b) requires
that this standard be reviewed every eight years, thus this regulatory requirement will likely be
reviewed and potentially revised after the 2020 timeframe, which serves as the primary focus
of this analysis. In addition to studying the alternative scenarios analyzed by EIA, EPA also
conducted three additional sensitivity analyses using IPM: a low shale gas recovery scenario, a
high electricity demand scenario, and a combination of the two.16 The lower shale recovery
scenario assumed, that 50 percent less natural gas is recovered from each shale play relative to
the base case (effectively lowering shale reserves by 50 percent, similar to the AEO 2011 low
shale gas recovery scenario). The high electricity demand scenario assumed that electricity
demand grows at an annual average rate of 1.1 percent, similar to ElA's high economic growth
scenario for AEO 2010 (compared to about 0.8 percent in the EPA baseline, which is similar to
the reference case in AEO 2010). Figure 5-2 and 5-3 illustrate electricity demand and natural
gas price in these sensitivity analyses. Note that the EPA structured the sensitivity analyses
such that natural gas prices and electricity demand growth are both considerably higher than
the comparable AEO 2011 scenarios.17
15 Conversely, modeling in support of the AEO 2011 show that new natural gas combined cycle capacity is expected
to be higher in 2020 in the low fossil cost and high economic growth scenarios relative to the reference case.
Although EPA and EIA do not typically combine scenarios (as EPA did with the natural gas and demand
sensitivity in this analysis), this scenario was performed to demonstrate that even when considering the
occurrence of two independent and highly unlikely assumptions that influence new power plant additions, new
unplanned coal is not expected to be built through 2020.
17 EPA's baseline electricity demand forecast used in IPM v4.10 is based on the demand forecast in AEO 2010. AEO
2010 electricity demand forecast for the year 2020 is roughly 2.5% higher than the 2020 forecast in AEO 2011.
EPA's sensitivity with higher electricity demand growth (using the AEO 2010) uses an electricity demand for
2020 that is about 6% higher than the reference case AEO 2011 demand for 2020, and about 3% higher than
the demand in the AEO 2011 high economic growth scenario. The EPA sensitivity with higher electric demand
represents a very conservative view of electricity demand in 2020 (meaning that its electricity demand
projection is considerably higher than the most recent reference case forecast, therefore representing a future
in which new coal-fired capacity would be of correspondingly higher economic value to build relative to the
reference case forecast conditions).
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4,600
4,400
4,200
4,000
3,800
3,600
3,400
3,200
3,000
EPA-Base Case EPA-High Demand AEO2010
AEO2011
AEO 2011-High
Econ. Growth
Figure 5-2. Projected Levels of Electricity Demand in 2020, EPA and EIA
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9.00
8.00
1.00
0.00
EPA-Base Case EPA-High EPA-Low Shale EPA-High EIA-Low Shale EIA Reference Average Price
Demand Recovery Demand + Low Recovery (AEO Case-AEO 2011 (2011, EIA)
Shale Recovery 2010)
Figure 5-3. Projected Natural Gas Prices in 2020, EPA and EIA (Delivered, Power Sector)
None of these analyzed scenarios resulted in new conventional coal-fired capacity being
built in 2020 (see Figure 5-4) beyond 2 GW of coal with CCS, which is built in response to the
financial incentives for CCS included in the Emergency Economic Stabilization Act of 2008 and
American Recovery and Reinvestment Act of 2009, which authorized and/or appropriated
funding to DOE for CCS deployment.18 In the short-term, most new capacity is projected as a
mix of wind and natural gas in response to the competitive marketplace for fuels and other
energy policies (such as tax credits and state renewable portfolio standards). These scenarios
show similar results as EIA, and serve to further confirm the high likelihood that no new coal
capacity is likely to be built by 2020 in baseline forecasts. See Table 5-3 for new capacity
projections in 2020.
A number of the sources that EPA has identified as transitional sources have received some form of DOE
financial assistance to demonstrate CCS. Several additional projects have received funding but have not yet
received air permits. Beyond these projects, prospects for additional federal funding are dependent on the
overall budget process.
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Table 5-3. Projected New Capacity in 2020
Coal +CCS
Natural Gas Combined Cycle
Combustion Turbine
Non-Hydro Renewables
Total
5.6 Analysis of Applica
EPA-
Base
Case
2.0
7.0
3.0
26.9
38.9
ibility of 1
EPA-
High
Demand
2.0
22.7
3.2
27.6
55.5
Proposed
EPA-Low
Shale
Recovery
2.0
7.3
2.4
27.3
39.0
1 ECU GHG
EPA-High
Demand +
Low Shale
Recovery
2.0
24.8
2.4
31.5
60.7
NSPS to Pr<
Capacity
As the second step in the analysis, EPA analyzed the applicability of the NSPS to new
generating capacity anticipated to be built through 2020, and whether the requirements would
require the regulated community to take actions different from those projected in the base
case.
The proposed ECU GHG NSPS discusses potential requirements for new units Analysis
performed by EPA, along with information from other sources, suggests that the standards as
specified in this proposed rule are likely to result in negligible emission changes, other
quantified benefits, energy impacts, costs, or economic impacts by 2020. This is because
analyses performed both by EPA and EIA, as well as statements and actions of a number of
major utilities, demonstrate that generation technologies other than coal (mostly natural gas
and renewable sources) are likely to be the technologies of choice for new sources due to
current and projected market conditions.19
5.6.1 New Units
This proposal requires that all new fossil-fuel fired units greater than 25 megawatt
capacity be able to meet an emission rate standard of 1,000 Ibs C02/MWh on a gross basis. It
also proposes an alternative compliance option that would allow new units to meet the 1,000
Ibs C02/MWh standard using a 30 year averaging period. These standards could be met either
by natural gas combined cycle generation or coal-fired generation using CCS.
1 EPA does not anticipate any oil or gas steam boilers to be constructed, either. Although these types of units
would be subject to this rule, they have not been a technology of choice for the sector in recent years and are
generally smaller (less than the 25 MW applicability threshold included as part of this rule). In addition, the
operating economics also do not favor this technology, similar to the dynamic with conventional new coal-fired
capacity.
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Of the new generating capacity projected to be constructed by 2020, only the fossil-fuel-
fired boilers would be affected by the proposed ECU GHG NSPS. The NGCC units, which are the
basis of the proposed standard, are projected to meet the proposed standard through their
inherent design.20 As discussed in section 5.5, no new conventional coal-fired boilers are
projected to be built (excluding new coal built with CCS). This implies that the NSPS will require
no changes in design or construction of new EGUs forecasted in the base case. Thus, under the
baseline projections as well as the sensitivity analyses presented above, the proposed ECU GHG
NSPS will not result in any reduction in emissions, or any costs.
Engineering cost analysis, even outside of a least-cost system dispatch modeling
environment, reaches similar conclusions. A comparison of levelized wholesale electricity costs
for differing generation technologies and natural gas prices are shown in Figure 5-4 and Table
5-4. It is important to note that both EIA and EPA include a capital charge rate adder (3
percent) for new conventional coal-fired generating capacity without CCS, which reflects the
additional cost of raising capital that is currently reflected in the marketplace, related at least in
part to uncertainty surrounding future greenhouse gas emission reduction requirements.21
Note that this figure only shows the costs to the generator and does not reflect the additional
social costs that are associated with damages from greenhouse gas emissions or conventional
air pollutants. As the figure shows, with a delivered natural gas price of $5 per million British
Thermal Units (mmBtu) and a delivered coal price of $2 per mmBtu, which reflect forecasted
prices from IPM in 2020,22 electricity generated by natural gas combined cycle units is less
expensive on average than coal generation.
20 Natural gas combustion turbines are not covered by this proposal.
21 EIA includes "a 3-percentage-point increase is added to the cost of capital for investments in GHG-intensive
technologies, such as coal-fired power plants without CCS and CTL plants." Source: EIA AEO 2009, Issues in
Focus. Reflecting Concerns Over Greenhouse Gas Emissions in AEO2009, available at:
http://www.eia.gov/forecasts/archive/aeo09/issues.html
See also http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html
22 EIA projects a U.S. average power sector delivered coal price of $2.08/MMBtu in 2020 ($2007). EPA and EIA
both project delivered (power sector) natural gas price of roughly $5/mmBtu in 2020.
5-15
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($2007)
140
120
100
^ 80
^ 60
40
20
0
Conventional
Coal (no
investor
climate
concern)
Conventional
Coal(w/CO2
Uncertainty
Adder)
NaturalGas NaturalGas
Combined Combined
Cycle ($5 gas) Cycle ($8 gas)
NaturalGas
Combined
Cycle ($9.60
gas)
Coal + CCS
Figure 5-4. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation
Technologies, EPA23
Notes: Assumptions derived from EPA's application of IPM. Technologies include Coal without CCS, Natural Gas Combined
Cycle with natural gas costing $5 per mmBtu, Natural Gas Combined Cycle with $8 per mmBtu costs of natural gas, and
Integrated Gasification Combined Cycle with CCS (with 90 percent capture). In this graph coal is a high sulfur bituminous at $2
mmBtu. Conventional Coal is at a heat rate of 8,875 Btu/kWh net, capacity factor of 85 percent assumed across all
technologies.
Although EPA believes that this cost data is broadly representative of the economics between new coal and new
natural gas facilities, this analysis assumes representative new units and does not reflect the full array of new
generating sources that could potentially be built. To the extent that other types of new units that would be
affected by this rule could be built, they could exhibit different costs than presented here. For example,
smaller new conventional coal facilities which would be more expensive on a $/kw basis and have a relatively
higher LCOE, and some technologies could potentially have a lower LCOE if fuel could be obtained cheaply and
capital costs remained similar, or lower than, an new base load convention coal plant (petroleum coke or waste
coal). These differences do not fundamentally change the analysis presented in this chapter.
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It is only when gas prices reach approximately $9.60/mmBtu (in 2007 dollars), that new
coal-fired generation without CCS becomes competitive, in terms of dollars per megawatt hour
wholesale cost of electricity generation (none of the EPA or EIA sensitivities with alternate
assumptions for natural gas approach this price level).
It is important to note that this analysis is based on assumptions regarding the average
national cost of generation at new facilities. As reported by the EIA, there is expected to be
significant spatial variation in the costs of new generation due to design differences, labor wage
and productivity differences, location adjustments, among other potential differences.24 EPA
acknowledges that there is some uncertainty around these estimates, and is unable to provide
estimates for all variants. However, the results are expected to hold for the majority of
situations. The analysis also does not explicitly consider new units designed to combust waste
coal or petroleum coke (pet coke), which may be affected by this rule, but also may exhibit
different local economics.25
This rule also proposes an alternative compliance option that would allow new units to
meet the 1,000 Ibs C02/MWh standard using a 30 year averaging period.26 To the extent
market participants have alternative views of both the cost and development of CCS, new
conventional coal-fired capacity (or IGCC) could be built and operated for some time, with the
intention to apply CCS with high removal efficiency at some later date, in order to achieve the
required average rate over the 30 year period. Also the above analysis reflects national
averages, and given their specific situation, a market participant could determine that the
economics of building a coal-powered facility that immediately achieves a C02 capture and/or
removal rate consistent with the emission standard are favorable.
24 http://www.eia.gov/oiaf/beck plantcosts/pdf/updatedplantcosts.pdf
25 This analysis also does not explicitly consider new units designed to combust waste coal or petroleum coke (pet
coke), which may be affected by this rule, but can exhibit different economics. Most other energy models,
including ElA's application of NEMS, do not consider these technologies for new electricity sources because
they are marginal technologies that are rarely built, and highly dependent upon specific local factors that are
difficult to model and highly speculative (like the ability to obtain a very inexpensive local supply of suitable
fuel). The models do include these technologies as part of the existing universe of sources, however. For
context, there are currently 59 units nationwide that are designed to combust either waste coal or petroleum
coke, with a total capacity of roughly 5 GW (or 0.5% of the entire fleet). To the extent that these technologies
would be built absent this rule due to unique local economics and fuel supply, there would be certain costs and
benefits associated with this proposed rule, although they would be expected to be small because these
sources are not often built. EPA is taking comment and solicits additional information on its consideration of
these technologies in the analysis.
26IPM does not consider the impact of elevation on performance, and utilizes a uniform elevation performance-
based assumption.
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Table 5-4. Estimated Levelized Cost of New Generation Resources from EIA, U.S. Average
(2016)
Plant Type
Capacity
Factor (%)
Conventional Coal
Advanced Coal
Advanced Coal with CCS
Natural Gas-fired
Conventional Combined
Cycle
Advanced Combined Cycle
Advanced CC with CCS
Conventional Comb. Turbine
Advanced Combustion
Turbine
Advanced Nuclear
Wind
Wind - Offshore
Solar PV
Solar Thermal
Geothermal
Biomass
Hydro
85
85
85
87
87
87
30
30
90
34
34
25
18
92
83
52
Levelized
Capital
Cost
65.3
74.6
92.7
17.5
17.9
34.6
45.8
31.6
90.1
83.9
209.3
194.6
259.4
79.3
55.3
74.5
U.S. Average Levelized Costs (2009 $/ MWh)
for Plants Entering Service in 2016
Variable Total
Fixed O&M Transmission System
O&M (Including Investment Levelized
fuel) Cost
3.9
7.9
9.2
1.9
1.9
3.9
3.7
5.5
11.1
9.6
28.1
12.1
46.6
11.9
13.7
3.8
24.5
25.7
33.1
45.6
42.1
49.6
71.5
62.9
11.7
0
0
0
0
9.5
42.3
6.3
1.2
1.2
1.2
1.2
1.2
1.2
3.5
3.5
1.0
3.5
5.9
4.0
5.8
1.0
1.3
1.9
94.8
109.4
136.5
66.1
63.1
89.1
124.5
103.5
113.9
97.0
243.2
210.7
311.8
101.7
112.5
86.4
Source: EIA, AEO 2011
Others have researched the cost and efficiency of varying levels of capture relative to
building other energy technologies.27 This ongoing research indicates that lower levels of
carbon capture at new coal facilities could be cost competitive, and the costs of meeting the
proposed emission rate immediately could be achievable. For example, The Clean Air Task
Force has compiled data that indicates the levelized cost of electricity for a new supercritical
pulverized coal unit with 50 percent CCS (or 1,080 Ib/MWh C02, which is just above the
proposed standard) could be $116/MWh compared to $147/MWh for 90 percent removal.
However, investment decisions will be made on a case by case basis dependent upon a number
of factors, all of which are difficult to estimate in advance.
Technical Options for Lowering Carbon Emissions from Power Plants. Clean Air Task Force (June, 2011). Available
at:
http://www.coaltransition.org/filebin/pdf/Technical Options for Lowering Carbon Emissions from Power.p
df
5-18
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5.6.2 Reconstructed Units
The EPA's CAA Section 111 regulations define reconstructed sources as, in general,
existing sources (i) that replace components to such an extent that the capital costs of the new
components exceed 50 percent of the capital costs of an entirely new facility, and (ii) for which
compliance with standards of performance for new sources is technologically and economically
feasible (40 CFR 60.15). The Agency is aware that, in theory, operators of existing power plants
may choose to reconstruct them, but we are not aware of any announced plans to do so. This
provision is rarely triggered. In light of this limited experience concerning reconstructions, the
Agency lacks adequate information that is needed to propose a standard of performance for
reconstructions. As a result, in today's action, the EPA is not including a proposal for
reconstructions. Instead, we solicit comment on how we should approach reconstructions and,
depending on the information we receive, we may propose and finalize a standard for
reconstructions at a later time.
5.6.3 Modified and Transitional Units
Modified and transitional units are described in the preamble and in Chapter 2 of this
RIA. EPA does not anticipate any costs being associated with these units.
5.7 Costs, Economic, and Energy Impacts of the Proposed Rule for New Electric Generating
Units
Under a wide range of electricity market conditions - including EPA's baseline scenario
as well as multiple sensitivity analyses - EPA projects that the industry will choose to construct
new units that already meet these standards, regardless of this proposal. As a result, EPA
anticipates that the proposed ECU GHG NSPS will result in negligible C02 emission changes,
energy impacts, or costs for new units constructed by 2020. Likewise, the Agency does not
anticipate any notable impacts on the price of electricity or energy supplies. Additionally, for
the reasons described above, the proposed rule is not expected to raise any reliability concerns,
since reserve margins will not be impacted and the rule does not impose any requirements on
existing facilities.
5.8 Comparison of Emissions from Generation Technologies
As discussed earlier in this chapter, natural gas combined cycle units are on average
expected to be more economical to build and operate than new coal units. These natural gas
units also have lower emission profiles for C02 and criteria air pollutants than new coal units.
While the proposed ECU GHG NSPS is anticipated to have negligible costs or quantified benefits
5-19
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under a range of likely market conditions, it is instructive to consider the differences in
emissions of C02 and conventional air pollutants between the two types of units.
As Table 5-5 below shows, emissions from a typical new natural gas combined cycle
facility are significantly lower than those from a traditional coal unit.28 For example, a typical
new supercritical pulverized coal facility that burns bituminous coal in compliance with new
utility regulations (e.g., CSAPR and MATS) would have considerably greater C02, sulfur dioxide
(S02), NOX, toxic metals, acid gases, and particulate emissions than a comparable natural gas
combined cycle facility. A typical natural gas combined cycle unit emits two million metric tons
less C02 per year than a typical new conventional coal unit, as well as 930 fewer short tons S02
and 1,200 fewer short tons of NOX each year. Importantly, these differences in emissions
assume a new coal unit that complies with all applicable regulations, including MATS.
Reductions in S02 emissions are a particularly significant driver for monetized health benefits,
as S02 is a precursor to the formation of particulates in the atmosphere, and particulates are
associated with premature death and other serious health effects. Further information on
these pollutants' health effects is included in the next subsection.
28 Estimated emissions of CO2, SO2, and NOX for the illustrative new coal and natural gas combined cycle units
could vary depending on a variety of assumptions including heat rate, fuel type, and emission controls, to name
a few.
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Table 5-5. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired Generating Units2
Conventional Coal
S02
NOX
C02
Emissions
(tons/year)
940
1,400
3.6 million
Emission Rate
(Ibs/MWh
net)
0.42
0.62
1,800
Natural Gas CC
Emissions
(tons/year)
10
200
1.7 million
Emission Rate
(Ibs/MWh
net)
0.0041
0.09
820
Coal with CCS
Emissions
(tons/year)
50
1,100
0.4 million
Emission Rate
(Ibs/MWh
net)
0.022
0.47
200
Notes: S02 and NOX in short tons, C02 in metric tons. As discussed in Section 5.4, the illustrative units represent relative
emissions for new well controlled 600 MW (net) baseload units running at 85 percent capacity factor (85% capacity factor
reflects operation of new baseload units and does not necessarily reflect the historic capacity factors of existing units with
specifications similar to these illustrative units). Assumed coal is high sulfur bituminous with scrubber and SCR, data are based
on EPA assumptions used in IPM.
5.9 Benefits of Reducing GHGs and Conventional Pollutants
Because emissions of C02 and criteria air pollutants adversely affect human health and
welfare, the differences in emissions presented above translate into differences in the external
social costs associated with different generation technologies. Here we provide a general
discussion about the differences in emissions of C02 and criteria air pollutants in the previous
illustrative example.
5.9.1 Social Cost of Carbon
The social cost of carbon (SCC) is a metric to estimate the monetary value of benefits
associated with marginal changes in C02 emissions, and may therefore be utilized to
understand the value of the difference in C02 emissions between the two representative units
discussed in Section 5.8. The SCC is an estimate of the monetized damages associated with an
incremental increase in carbon emissions in a given year. It is intended to include (but is not
limited to) changes in net agricultural productivity, human health, property damages from
increased flood risk, and the value of ecosystem services due to climate change. Federal
agencies typically use SCC estimates to assess the benefits of rulemakings that achieve marginal
reductions in C02 emissions. These estimates were developed through an interagency process
that included EPA and other executive branch entities, and concluded in February 2010. The
29 The emissions presented here are estimated on an output basis to enable easier comparisons and to illustrate
the potential impacts of moving from new coal to new natural gas. This analysis assumes representative new
units and does not reflect the full array of new generating sources that could potentially be built (e.g., a small
new conventional coal plant or a waste coal or petroleum coke facility). However, the emissions associated
with other facilities that could be built, and which would be subject to this proposal, would not change
noticeably (i.e., these new facilities would be subject to emissions standards for other pollutants and would
emit similar levels of SO2, NOX, and CO2, on an output basis).
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SCC Technical Support Document (SCC TSD) provides a complete discussion of the methods
used to develop these SCC estimates.30
The interagency group selected four SCC values for use in regulatory analyses: $7, $26,
$42, and $81 per metric ton of C02 emissions in 2020, in 2007 dollars.31'32 The first three values
are based on the average SCC from three integrated assessment models, at discount rates of 5,
3, and 2.5 percent, respectively. SCCs at several discount rates are included because the
literature shows that the SCC is quite sensitive to assumptions about the discount rate, and
because no consensus exists on the appropriate rate to use in an intergenerational context. The
fourth value is the 95th percentile of the SCC from all three models at a 3 percent discount rate.
It is included to represent higher-than-expected impacts from temperature change further out
in the tails of the SCC distribution.
The SCC increases over time because future emissions are expected to produce larger
incremental damages as physical and economic systems become more stressed in response to
greater climatic change. Note that the interagency group estimated the growth rate of the SCC
directly using the three integrated assessment models rather than assuming a constant annual
growth rate. This helps to ensure that the estimates are internally consistent with other
modeling assumptions. Table 5-6 presents the SCC estimates for the years 2015 to 2050. In
order to calculate the dollar value for emission reductions, the SCC estimate for each emissions
year would be applied to changes in C02 emissions for that year, and then discounted back to
the analysis year using the same discount rate used to estimate the SCC.
When attempting to assess the incremental economic impacts of carbon dioxide
emissions, the analyst faces a number of serious challenges. A recent report from the National
Academies of Science (NRC 2009) points out that any assessment will suffer from uncertainty,
30 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support Document: Social Cost of Carbon for Regulatory
Impact Analysis Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon, with
participation by Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture,
Department of Commerce, Department of Energy, Department of Transportation, Environmental Protection
Agency, National Economic Council, Office of Energy and Climate Change, Office of Management and Budget,
Office of Science and Technology Policy, and Department of Treasury (February 2010). Also available at
http://epa.gov/otaq/climate/regulations.htm
31 Note that upstream emissions changes were not considered for this rule. There may be changes in greenhouse
gas emissions (in particular, methane) due to changes in fossil fuel extraction and transport in response to this
proposal, but those were not quantified.
32 The interagency group concluded that a global measure of the benefits from reducing U.S. GHG emissions should
be the standard practice when conducting regulatory impact analysis in support of federal rule makings. See
Interagency Working Group on Social Cost of Carbon. 2010. Technical Support Document: Social Cost of
Carbon for Regulatory Impact Analysis Under Executive Order 12866.
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speculation, and lack of information about (1) future emissions of greenhouse gases, (2) the
effects of past and future emissions on the climate system, (3) the impact of changes in climate
on the physical and biological environment, and (4) the translation of these environmental
impacts into economic damages.33 As a result, any effort to quantify and monetize the harms
associated with climate change will raise serious questions of science, economics, and ethics
and should be viewed as provisional.
The interagency group noted a number of limitations to the SCC analysis, including the
incomplete way in which the integrated assessment models capture catastrophic and non-
catastrophic impacts, their incomplete treatment of adaptation and technological change,
uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding
risk aversion. Current integrated assessment models do not assign value to all of the important
physical, ecological, and economic impacts of climate change recognized in the climate change
literature because of lack of precise information on the nature of damages and because the
science incorporated into these models understandably lags behind the most recent research.
The limited amount of research linking climate impacts to economic damages makes the
interagency modeling exercise even more difficult. The interagency group hopes that over time
researchers and modelers will work to fill these gaps and that the SCC estimates used for
regulatory analysis by the Federal government will continue to evolve with improvements in
modeling. It is important to emphasize that the interagency process is committed to updating
these estimates as the science and economic understanding of climate change and its impacts
on society improves over time. Specifically, they have set a preliminary goal of revisiting the
SCC values within two years, or at such time as substantially updated models become available,
and to continue to support research in this area. Additional details on these limitations are
discussed in the SCCTSD.
33 National Research Council (2009). Hidden Costs of Energy: Unpriced Consequences of Energy Production and Use.
National Academies Press. See docket ID EPA-HQ-OAR-2009-0472-11486.
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Table 5-6. Social Cost of CO2, 2015-20503 (in 2007 dollars)
Year
2015
2020
2025
2030
2035
2040
2045
2050
5% Average
$6
$7
$8
$10
$11
$13
$14
$16
Discount
3% Average
$24
$26
$30
$33
$36
$39
$42
$45
Rate and Statistic
2.5% Average
$38
$42
$46
$50
$54
$58
$62
$65
3%
95th percentile
$73
$81
$90
$100
$110
$119
$128
$136
a The SCC values vary depending on the year of CO2 emissions and are defined in real terms.
5.9.2 Health Impacts of SO2 and NOX
S02 is a precursor for fine particulate matter (PM2.5) formation. NOX is a precursor for
PM2.5 and ozone formation. As such, reductions of S02 and NOX would in turn lower overall
ambient concentrations of these pollutants as well as PM2.5 and ozone. Reducing exposure to
PM2.5and ozone is associated with significant human health benefits, including avoided
mortality and morbidity. Researchers have associated PM2.5 and ozone exposure with adverse
health effects in numerous toxicological, clinical, and epidemiological studies (U.S. EPA, 2009;
U.S. EPA, 2006). Health effects associated with exposure to PM2.5 include premature mortality
for adults and infants, cardiovascular morbidity such as heart attacks and hospital admissions,
and respiratory morbidity such as asthma attacks, bronchitis, hospital and emergency room
visits, work loss days, restricted activity days, and respiratory symptoms. Health effects
associated with exposure to ozone include premature mortality and respiratory morbidity such
as asthma attacks, hospital and emergency room visits, and school loss days. For a full
discussion of the human health benefits of reducing S02 and NOX emissions from power sector
sources, including reducing methyl mercury, S02, and N02 exposure, please refer to the RIA for
CSAPR(U.S. EPA, 2011).
In addition to human health benefits, reducing S02 and NOX emissions would also result
in human welfare improvements by improving ecosystem services—the benefits that the public
obtains from ecosystems that directly or indirectly contribute to social welfare. S02 and NOX
emissions can adversely impact vegetation, certain manmade materials, acidic deposition,
nutrient enrichment, visibility, and climate (U.S. EPA, 2009; U.S. EPA, 2008). Reducing these
harmful emissions improves human welfare. For more information about the welfare benefits
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of S02 and NOX emission reductions from power sector sources, please refer to the Regulatory
Impact Analysis for the CSAPR (U.S. EPA, 2011).
Because the health and welfare benefits of S02 and NOX emissions in terms of
incidences of health effects avoided or monetized value of health or welfare improvements
depend on power plant location, the potential benefits cannot be quantified precisely for the
purposes of this illustrative example. However, reducing one thousand tons of annual S02 from
U.S. EGUs in 2020 has been estimated34 to yield between 3 and 9 incidences of premature
mortality avoided annually and annual monetized PM2.5-related health benefits (including these
incidences of premature mortality avoided) between $30 million and $75 million (2007$) using
a 3% discount rate or between $28 million and $67 million (2007$) using a 7% discount rate
(where the range is due to EPA's use of two alternative primary estimates of PM2.5 mortality
impacts, a lower primary estimate based on Pope et al. (2002) and a higher primary estimate
based on Laden et al. (2006)). Additionally, reducing one thousand tons of annual NOX from U.S.
EGUs in 2020 has been estimated35 to yield up to 1 incidence of premature mortality avoided
annually and annual monetized PM2.5-related health benefits (including these incidences of
34 The SO2 and NOX benefit per-ton (BPT) values presented here consist of only PM2.5-related health benefits from
reductions in SO2 and NOX (precursors to PM2.5 formation). EPA relied on air quality modeling used to develop
a previous rulemaking affecting power sector emissions of SO2 and NOX to develop these BPT values (Air Quality
Modeling Technical Support Document for the final Transport Rule;
http://epa.gov/airtransport/pdfs/AQModeling.pdf). EPA utilized Transport Rule (Cross-State Air Pollution Rule)
modeling rather than air quality modeling of EPA's Mercury and Air Toxics Standards (MATS) because EPA did
not estimate NOX BPT values for MATS and because the utilized Transport Rule modeling reduced emissions of
SO2 and NOX independently, allowing for better estimation of PM25-related SO2 and NOX BPT values. The air
quality modeling utilized reflects emission reductions in the eastern U.S. In order to better understand the
relative difference between BPT values for emission reductions in the east and west, see Table 5C-3 of the
MATS Regulatory Impact Analysis (RIA) . Using this
existing air quality modeling, EPA used BenMAP (www.epa.gov/air/benmap) to estimate the benefits of air
quality improvements using projected 2020 population, baseline incidence rates, and economic factors. These
BPT values are methodologically consistent with those reported in Fann et al. (2009). As EPA models avoided
premature deaths among populations exposed to levels of PM2.5, we have lower confidence in levels below
the lowest measured level (LML) for each study. However, studies using data from more recent years, during
which time PM25 concentrations have fallen, continue to report strong associations with mortality. For more
information refer to the MATS RIA. The average BPT values reflect a specific geographic distribution of SO2 and
NOX reductions resulting in a specific reduction in PM25 exposure and may not fully reflect local or regional
variability in population density, meteorology, exposure, baseline health incidence rates, or other factors that
might lead to an over-estimate or under-estimate of the actual benefits associated with PM25 precursors.
These BPT values are purely illustrative as EPA does not assert a specific location for the illustrative coal and
natural gas combined cycle units and is therefore unable to specifically determine the population that would be
affected by their emissions. Therefore, the benefits for any specific unit can be very different than the
estimates shown here. EPA notes that the BPT estimates do not reflect emission reductions after
implementation of EPA's Mercury and Air Toxics Standards.
35 Ibid.
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premature mortality avoided) of between $2.5 million and $6.2 million (2007$) using a 3%
discount rate or between $2.3 million and $5.6 million (2007$) using a 7% discount rate.
5.10 Illustrative Analysis of the Social Costs of New Generating Sources
As the analysis in sections 5.5 and 5.6 demonstrated, under a wide range of likely
electricity market conditions - including EPA's baseline scenario as well as multiple sensitivity
analyses - EPA projects that the industry will choose to construct new units that already meet
these standards, regardless of this proposal.
In this section, we consider the unlikely scenario where future market conditions
support the construction of new conventional (advanced, but without CCS) coal capacity during
the analysis period in the absence of the rule. The analysis in this section indicates that in this
scenario, the proposed ECU GHG NSPS is highly likely to provide net benefits to society as a
whole.
The starting point for this analysis is the illustrative comparison (presented in Figure 5-4
above) of the relative private costs of constructing and operating a representative new
conventional coal ECU and a representative NGCC unit.36 This comparison shows that, at
forecast relative fuel prices, there is a significant difference in the levelized cost of these two
generating technologies. However, in the context of a social welfare analysis, the appropriate
comparison between multiple options is on the basis of benefits and costs to society as a
whole, and not solely the private cost to an investor.
From the perspective of society, the appropriate cost comparison for new generation
capacity should account for the pollution damages associated with the competing generation
technologies in addition to private generating costs. This section further explores how the
potential social benefits and costs of this NSPS standard may change across a wide range of
natural gas prices, a key factor in the potential cost of the policy. It begins by estimating
illustrative environmental damages per MWh for coal relative to gas generation and then uses
36 By fixing generation in this comparison, we are assuming that both technologies generate the same benefits in
the form of electricity generating services. We assume in the discussion that the benefit of electricity
production to consumers outweighs the private and social investment cost. However, at particularly high fuel
prices this might not be the case. For a discussion of when comparing the levelized costs of different generating
technologies provides informative results and when it does not see, for example, Joskow 2010 and 2011.
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these estimates to conduct an illustrative sensitivity analysis for the potential social costs of the
policy in this illustrative example.37
It should be emphasized that the analysis presented here is illustrative, although EPA
believes that it leads to a robust conclusion. From an analytical perspective, the challenge is to
estimate expected benefits and costs given uncertainty about future market conditions. An
ideal benefit-cost analysis would first model projected generation capacity and capacity
additions for every plausible set of market conditions (e.g., different combinations of natural
gas and coal supplies and electricity demand). The effects of the proposed ECU GHG NSPS
could then be estimated in each of those scenarios including the resulting estimated benefits
and costs (which would depend on the amount of new generation capacity built, the
technologies used, the location of new generating plants, and so on). The analysis would then
estimate the conditional probability distribution of those outcomes (for example, the
probability distribution of future natural gas prices or future electricity demand conditional on
the current information on supply). Finally, the analysis would integrate the estimated benefits
and costs over the conditional probability distribution of outcomes, to arrive at the expected
net benefits of the rule.
The analysis just described is beyond the scope of the current RIA, and EPA believes that
the sensitivity cases presented in section 5.6.1, combined with the illustrative analysis here,
provide a robust picture of the likely costs and benefits of the standard. Nonetheless, EPA is
inviting comment on whether a more detailed analysis would be practical, feasible, and an
effective use of limited analytical resources, and if so, how it might be carried out and what
information it would be expected to provide. If commenters believe that such an analysis
would be practical and appropriate, EPA invites comment on what variables should be treated
as uncertain (e.g., natural gas and coal prices, electricity demand) and on the specific
conditional and potentially joint probability distributions that should be used for the future
state of those variables.
In the spirit of the "ideal" analysis just described, in the remainder of this section EPA
provides an illustrative analysis focusing on uncertainty in the price of natural gas, which is a
key determinant of the economics of electricity generation and therefore the potential impacts
of this proposed rule.
37 From an economic perspective, the analysis in sections 5.5 and 5.6 considered the net benefits of the rule under
expected market conditions, and found those to be zero (because the rule would not affect what new capacity
is built under those market conditions). The analysis in this section, while still purely illustrative, is an initial
step toward estimating the expected net benefits of the rule as a function of market conditions.
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5.10.1 Illustrative Environmental Damages per MWh
As previously discussed in this chapter, the damages associated with emissions from
new sources of electricity generation are greater for coal-fired units than for natural gas
combined cycle units (even when accounting for compliance with EPA's recent Mercury and Air
Toxics Standard). To gauge the general effect of accounting for both the private and external
costs of electricity generation for new generation options we continue with the illustrative
example from Section 5.8. The external costs are defined as the damages associated with
pollution that are not accounted for in the private investor's decision making.38
To illustrate the external costs associated with new generation options we combine the
illustrative emission profiles for the new units, as provided in Table 5-5, and the illustrative
emissions and damage estimates discussed in the previous two sections.39 Specifically, for each
generating technology we multiply the C02 emissions by the estimates of the SCC and add that
to the S02 emissions40 multiplied by the PM2.5-related S02 benefit per-ton estimates,41
subsequently dividing by MWh to estimate the external costs per unit of generation.
Table 5-7 reports the additional pollution damages from the illustrative new coal plant
relative to the illustrative new natural gas plant given different mortality risk studies and
assumptions about the discount rate. These pollution damages should be relatively invariant
across natural gas prices and other economic factors. Depending on the discount rate and
mortality risk study used, damages associated with generation from a representative new coal
unit are $11 to $81 per MWh, while damages associated with the illustrative new natural gas
combined cycle unit are $3 to $31 per MWh (2007$).42
It is important to note that although the ranges appear to overlap, for any set of
assumptions (i.e., any specific mortality risk study and choice of SCC value) estimate the
38 See Baumol and Dates, 1988.
39 Only the direct emissions of two pollutants (CO2 andSO2) are considered in this illustrative exercise. Other
pollutants and lifecycle emissions are not considered.
40 See footnote 32 in section 5.8.
41 See footnote 34 in section 5.9.2 for a description of the benefit-per-ton values. In this exercise they are
interpreted as damage-per-ton values.
42 Different discount rates are applied to SCC than to the other damage estimates because CO2 emissions are long-
lived and subsequent damages occur over many years. Moreover, several rates are applied to SCC because the
literature shows that it is sensitive to assumptions about discount rate and because no consensus exists on the
appropriate rate to use in an intergenerational context. The SCC interagency group centered its attention on
the 3 percent discount rate but emphasized the importance of considering all four SCC estimates. See the "SCC
TSD," Interagency Working Group on Social Cost of Carbon (IWGSC). 2010. Technical Support Document: Social
Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. Docket ID EPA-HQ-OAR-2009-
0472-114577. http://www.epa.gov/otaq/climate/regulations/scc-tsd.pdffor details.
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pollution damages associated with new coal generation are significantly higher than those
associated with new natural gas combined cycle generation in this illustrative, but
representative example. For example, considering the S02 per ton damages based on Pope et
al. 2002 using a 7% discount rate and the SCC estimate based on the 3% discount rate, new
generation based on conventional coal in this example would result in an additional $17 per
MWh in pollution damages compared to a new NGCC plant. Alternately, damages that reflect
the S02 per ton damage estimate based on Laden et al. 2006 using a 3% discount rate and the
SCC estimate based on a 2.5% discount rate suggest an additional $33 of pollution damages per
MWh from a new conventional coal unit compared to a new NGCC plant.
As with the relative investment costs of a new coal unit and a new natural gas combined
cycle system, the actual environmental damages associated with these two technologies
depends on the location under consideration and the specific fuels that would be used. An
ideal benefit-cost analysis would account for these local circumstances (and consider
alternative sources of generation).43 However, these factors will not change the qualitative
conclusion. The damages associated with C02 emissions, which are the focus of this rule, do not
depend on the location of generation. Furthermore, the damages associated with sulfur dioxide
emissions from a new very well-controlled coal-fired unit firing low-sulfur coal would still be
greater than the damages from a new natural gas combined cycle unit independent of the
location.
43 EPA does not assert a specific location for the illustrative coal and natural gas combined cycle units and is
therefore unable to specifically determine the population that would be affected by their SO2 emissions.
Therefore, the benefits for any specific unit can be very different than the estimates shown here.
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Table 5-7. Pollution Damages ($/MWh) from Illustrative New Coal Unit Relative to New
Natural Gas Combined Cycle Unit44
SCC Discount Rate
Damages from CO2
5%
3%
2.5%
3% (95th percentile)
$3
$11
$18
$34
Damages from SO2 Only
Discount Rate Applied to Health Co-Benefits
Mortality-Risk
Study
Pope (2002)
Laden (2006)
3% Discount Rate
$6
$16
7% Discount Rate
$6
$14
SCC Discount Rate
Combined Damages from CO2 and SO2
Discount Rate Applied to Health Co-Benefits
3% Discount Rate 7% Discount Rate
5%
3%
2.5%
3% (95th percentile)
$9-$19
$17 - $27
$24 - $33
$41 - $50
$9 - $17
$17-$25
$24-$32
$40 - $48
Notes: Values in first two tables may not sum due to rounding.
The range of costs within each SCC value and discount rate for S02 pollution damages pairing reflects the use of two core
estimates of PM2.5-related premature mortality, Pope et al. (2002) representing the lower of our core estimates and Laden et
al. (2006) represent the higher of our core estimates. Assumed coal is high sulfur bituminous with scrubber and SCR. The
combinations of health studies and discount rates represent lower and higher valuations of impacts of S02 emissions in the
Eastern U.S. EPA has evaluated the range of potential impacts per MWh by combining all SCC values with health damages
values at the 3 percent and 7 percent discount rates. To be consistent with concepts of intergenerational discounting, values for
health damages, which occur within a generation, would only be combined with SCC values using a lower discount rate, e.g. the
7 percent health damages estimates would be combined with 5 percent or lower SCC values, but the 3 percent health damages
would not be combined with the 5 percent SCC value. While the 5 percent SCC and 3 percent health damages estimate falls
within the range of values we analyze, this individual estimate should not be used independently in an analysis, as it is
represents a combination of discount rates that is unlikely to occur. Combining the 3 percent SCC values with the 3 percent
health damage values assumes that there is no difference in discount rates between intragenerational and intergenerational
impacts.
The damages presented here are estimated on an output basis to enable easier comparisons and to illustrate the
potential impacts of moving from new coal to new natural gas. This analysis assumes representative new units
and does not reflect the full array of new generating sources that could potentially be built (e.g., a comparison
of a small new conventional coal plant with a small natural gas plant, or a comparison of a waste coal or
petroleum coke facility to a natural gas plant of a comparable size and capacity factor). However, the damages
associated with other facilities that could be built, and which would be subject to this proposal, would not
change noticeably (i.e., these new facilities would be subject to emissions standards for other pollutants and
would emit similar levels of SO2 and CO2, on an output basis) except for differences in local conditions, as
discussed below.
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The conclusion from this analysis is that there are significant environmental damages
associated with electricity generation from a representative new conventional coal unit relative
to a representative new natural gas combined cycle unit.45 Other studies of the social costs of
coal and natural gas fired generation provide similar findings (Muller et. a I, 2011; NRC, 2009).46
An important implication is that if market conditions changed sufficiently so that new coal units
became marginally more profitable to operate, these new units are still likely to impose a net
cost to society relative to a new natural gas plant. This idea is discussed in more detail in the
next section.47
5.10.2 Social Benefits and Costs across a Range of Gas Prices - Sensitivity Analysis
We now discuss how a consideration of the environmental damages associated with
new coal and natural gas EGUs informs the comparison of the two technologies from the
standpoint of net benefits - building on the illustrative comparison of a representative new coal
unit and a representative natural gas unit developed in Sections 5.8 and 5.9
At current natural gas prices relative to other fuels, the difference in the estimated
levelized cost of electricity for a representative NGCC unit is roughly $27 per MWh less than for
a representative new conventional coal unit (see Figure 5-4). This is consistent with EPA's
projection, discussed at length above, that the proposed ECU GHG NSPS will not impose any
social costs (or generate quantified net benefits) under current and likely future market
conditions.
Because the impacts of this proposed rule depend on future natural gas prices, which
are uncertain, EPA conducted an illustrative analysis of the impacts of the rule over a wide
range of natural gas prices. This analysis considers two distinct thresholds in the price of natural
45 As previously noted in this section and the previous sections on the costs and damages associated with these
technologies, EPA does not assert a specific location for the illustrative coal and natural gas combined cycle
units and is therefore unable to specifically determine the population that would be affected by their SO2
emissions. Therefore, the benefits for any specific unit can be very different than the estimates shown here,
though the proportion associated with CO2, which is a well dispersed global pollutant, will not be affected by
location.
46 Muller et al. 2011 conclude that, "coal-fired power plants have air pollution damages larger than their value
added", while the same is not true for natural gas plants (see Table 5). However, these comparisons are based
on typical existing coal and natural gas units, including natural gas boilers, and are not sensitive to location. The
NRC 2009 study shows that only the most polluting natural gas units may cause greater damages than even the
least polluting existing coal plants (compare Tables 2-9 and 2-15). However, the NAS comparison does not
compare new units located in the same place, and so some of the natural gas units with the greatest damages
may be attributable to their location, and includes natural gas steam boilers, which have a higher emission
rates per unit of generation than natural gas combined cycle units.
47 The presence of net benefits for a given regulatory option is a necessary but not a sufficient condition for
optimal regulatory design. It does however; signify that the regulatory option is welfare improving for society.
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gas at present: one price at which the private cost of a representative new coal unit falls below
that of a representative NGCC unit, but the generation cost advantage remains outweighed by
the environmental damages from the perspective of society as a whole; and an even higher
price at which the environmental damages no longer outweigh the private cost advantage. This
analysis presents three relevant ranges within the conditional distribution of future natural gas
prices that can be classified as a range of likely gas prices, unexpectedly high natural gas prices,
and unprecedented natural gas prices. It is important to note that this illustrative analysis
considers variation in the natural gas price holding all else constant; as discussed above, an
ideal analysis would vary other conditions simultaneously.48 In general, this analysis shows that
the policy would likely have a net benefit even under scenarios with much higher gas prices.
Under some conditions, higher natural gas prices result in a net cost, holding all other
parameters constant and disregarding benefits that we are unable to monetize.49 However, it is
important to note that this analysis is limited in the types of social benefits and costs
considered, given that it does address the life-cycle pollution associated with fossil fuels along
with the limitations of current SCC estimates, as previously discussed.
Likely Natural Gas Prices. As described earlier in this chapter, the base case modeling
that EPA performed for this rule (as well as base case modeling that EPA has performed for
other recent air rules) indicates that new fossil fuel-fired generating capacity projected to be
built through 2020 will be either natural gas-fired combined cycle generation or coal-fired
generation with CCS (the latter is assumed to be built with support from federal grants). This
conclusion also holds for the high-demand and low-shale-gas sensitivity analyses considered
above. As shown earlier in the illustrative analysis, it is only when gas prices reach
approximately $9.60/mmBtu, that new conventional coal-fired generation becomes
competitive with NGCC in terms of the levelized cost of electricity (in dollars per megawatt
hour).
Projections of future market conditions suggest that it is likely that natural gas prices
will remain below this level. As noted earlier in this chapter, ElA's projected natural gas price
for 2020 in its reference scenario for AEO 2011 is $5.30 (in 2007 dollars). Even ElA's most
pessimistic gas sensitivity case ("low shale gas recovery per well") only projects an electricity
sector gas price of $7.01/mmBtu (in 2007 dollars) in 2020 (the "low shale gas recovery per play"
scenario projects a price of $6.13/mmBtu (in 2007 dollars) in 2020). In other words, even under
48 For example, high economic growth would raise both natural gas and coal prices at the same time - extending
the range of natural gas prices for which NGCC retained a cost advantage.
In reality this is unlikely to be the case. For example, high economic growth
coal prices at the same time - making it harder to alter the underlying cost advantage of NGCC generation.
49 In reality this is unlikely to be the case. For example, high economic growth would increase both natural gas and
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pessimistic natural gas sensitivity cases, NGCC is likely to remain the economic choice for
generation over the next two decades even in the absence of this standard. In this scenario, it
appears very likely that the costs - and benefits - of the proposed standard will be zero.
Unexpectedly High Natural Gas Prices. In this illustrative analysis, at natural gas prices
above approximately $9.60/mmBtu, the private levelized cost of electricity for a representative
new conventional coal unit falls below that of a new NGCC unit. Therefore, above that price
level some new conventional coal units might be constructed in the absence of the standard,
provided there is sufficient demand and new coal without CCS is competitive with other
generating technologies.50 However, these coal units would also impose additional
environmental and health damages in the form of global warming pollution and particulate
matter (as a result of S02 and NOX emissions) - an element of social costs that are avoided by
building an NGCC unit instead.
For a range of natural gas prices above $9.60/mmBtu, the resulting external costs will
outweigh the difference in the private costs in this illustrative example - indicating that the
proposed standard would yield net benefits. For example, at gas prices of $10/MMBtu, the
illustrative conventional coal unit would generate power for $3/MWh less than an NGCC unit,51
but result in greater pollution damages of $9 to$50/MWh (see table 5-7).52 Under the
proposed standard, if in this example the NGCC unit were built instead, the resulting net social
benefit would be $6 to $47/MWh.
For context, we note that these circumstances are far less likely than the zero cost
scenario outlined above. To put this gas price point into historical context, $9.60/MMBtu is
higher than any average annual gas price (in 2007 dollars) observed over the last 10 years, and
it has only been reached temporarily in 8 of the last 120 months.53'54 Looking forward, the
50 See section 5.4 for a discussion of how local conditions and other factors influencing the levelized cost
comparison may influence the natural gas price where the levelized cost of the conventional coal unit and the
NGCC unit are the same.
51 Assuming an increase of $6.80/MWh in the cost of gas generation for every $l/MMBtu increase in natural gas
prices.
52 Again, assuming that coal prices do not increase along with natural gas prices as they historically have. See
previous footnote.
53 See: http://www.eia.gov/dnav/ng/hist/n3045us3A.htm. EIA reports average annual delivered natural gas prices
to the electricity sector for the past 15 years (since 1996) and reports average monthly delivered natural gas
prices to the electricity sector over the past 10 years (since 2001).
54 It is important to note that relatively high gases prices in a single month or year will not drive the investment
decision in the technology employed for new generating units. Instead that decision will be motivated by
expectations of relative fuel prices over the lifetime of the unit. Therefore given the historical path of natural
gas prices and the forecasts for the future, it is highly unlikely that expectations of sustained high natural gas
prices, to the degree necessary to drive technology choices, will be realized.
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continued development of unconventional natural gas resources in the U.S. suggests that gas
prices would actually tend to be towards the lower end of the historical range. As discussed
above, none of the EIA sensitivity cases (which represent future price trajectories for both gas
and coal) show scenarios where non-compliant coal becomes more economic than NGCC
before 2020.
Unprecedented Natural Gas Prices. At extremely high natural gas prices, the private
generating costs of non-compliant coal would be sufficiently lower than the cost of new natural
gas that the net social benefit of the standard could be negative (i.e., a net cost) under some
assumptions for environmental damages. For example, at gas prices of $15/MMBtu, the
illustrative conventional coal unit would generate power for roughly $37/MWh less than an
NGCC unit but result in social costs of $9 to $50/MWh (see table 5-7). Under the proposed
standard, if an NGCC unit were built instead, the resulting net social impact would range from a
net cost of $28 to a net benefit of $13/MWh. The point at which this standard would result in
net social costs depends heavily upon the value for damages from GHGs and S02. For example,
assuming an SCC using a 3% discount rate, along with a 7% discount rate for estimating benefits
from reduced S02 and the mortality-risk estimate from Pope (2002), natural gas prices above
$12/mmBtu in this illustrative example would result in net social costs from the proposed
standard. Alternatively, using an SCC value of 3% and using the mortality-risk estimate from
Laden (2006) along with a 3% discount rate for PM benefits, the corresponding threshold for
natural gas prices would be $14/mmBtu. Natural gas prices above these levels would be
unprecedented. Average annual natural gas prices delivered to the electricity sector have not
exceeded $9.47 /mmBtu (in 2007 dollars) over the last 15 years, and projected prices do not
begin to approach this level in any of ElA's scenarios.55'56 As a result, based on historical gas
prices as well as projections, EPA believes that there is an extremely small probability that
natural gas prices will reach (let alone remain at) levels at which this standard would generate
net social costs.
We emphasize that differences in generating costs, plant design, local factors, and the
relative differences between fuels costs can all have major impacts on the precise
circumstances under which this standard would be projected to have no costs, net benefits or
55 http://www.eia.gov/dnav/ng/ng pri sum dcu nus a.htm. EIA reports average annual delivered natural gas
prices to the electricity sector for the past 15 years (since 1996) and reports average monthly delivered natural
gas prices to the electricity sector over the past 10 years (since 2001).
56 Note that while EIA forecasts natural gas prices to rise, it also forecasts coal price to rise as well. An ideal
comparison of levelized costs in future time periods should account for the expected change in both natural gas
and coal prices.
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net costs. However, based on average annual gas prices over the last 15 years, we project that
this standard is most likely to have negligible costs, and, if it does impose costs, it likely also
produces positive, although modest, net benefits. There is an exceedingly low probability that it
results in net costs.
5.10.3 Illustrative Costs and Benefits of CCS Compared with Conventional Coal
The analysis above focuses on two well developed control technologies, conventional
supercritical coal and natural gas combined cycle. Because these technologies are well
developed, there is significantly more certainty about operating costs than for new, emerging
technologies like coal with CCS. As a result, any analysis that examines the relative social costs
of coal vs. coal with CCS is considerably more uncertain and should primarily be used as a guide
to the key sensitivities in the relative social costs. EPA compared the costs and damages for a
model pulverized coal (PC) ECU using supercritical steam conditions (like the one used in the
comparisons above) to and IGCC plant with a CCS system (e.g. Selexol). See technical memo
"Control Cost and Environmental Impacts of the Proposed GHG NSPS on new Coal-Fired Electric
Utility Generating Units" for more details.
EPA analyzed the cost and emission impacts for two scenarios. In the first scenario,
partial capture achieves the proposed emissions rate of 1,000 Ib C02/MWh gross output. This
requires that approximately 39% of the C02 is captured and stored. EPA has not previously
developed costs for such a unit, therefore, this analysis may not fully realize all of the cost
savings possible from building a unit with significantly less than 90% capture (for instance, an
IGCC could be built with a conventional gas turbine, rather than one designed for higher
temperature characteristics of a higher hydrogen content fuel). A 90% capture system was also
examined to analyze the cost of several proposed new coal-fired EGUs using CCS. In the near
term, any new coal-fired ECU with CCS would most likely be located in areas amenable to using
the captured C02 in enhanced oil recovery (EOR) operations. This is because EOR provides a
revenue stream that is not available for other forms of geologic storage. For example, the Texas
Clean Energy project57 is planning to capture 90% of the C02 and sell it for enhanced oil
recovery.
To evaluate the potential revenues from EOR we examined two options. We considered
a case where C02 could be sold for $45/ton based on recent DOE studies for the 90% capture
case.58 We also considered a lower revenue sensitivity where C02 could be sold for $15/ton
57 http://www.texascleanenergyproiect.com/
58 US DOE / NETL studies have assumed a delivered CO2 price ranging from $40 - $45/tonne. "Improving Domestic
Energy Security and Lowering CO2 Emissions with "Next Generation" CO2-Enhanced Oil Recovery (CO2-EOR)",
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(equivalent to the cost assumed for the transport and storage of C02 in the analysis) for the
partial capture case. Costs for the IGCC unit with 90% capture and the supercritical pulverized
coal-fired (SPC) unit without CCS were derived from IPM version 4.10.59 These cost estimates
are generally consistent with the range of studies estimating the cost of CCS that are available,
however there is uncertainty around any such projections of technology costs, particularly for
early movers of this technology. Capital costs for the IGCC unit with 39% capture were assumed
to be 90% of the capital costs for an IGCC unit with 90% CCS. EPA estimated the benefits
associated with avoided C02 and S02 emissions in a similar fashion to the one described above.
See technical memo "Control Cost and Environmental Impacts of the Proposed GHG NSPS on
new Coal-Fired Electric Utility Generating Units" for more details.
Table 5-8. Illustrative Costs and Benefits for two CCS Scenarios Compared to Conventional
Coal Plant (per MWh 2007$)
Additional Gross Annual Private Costs
Revenue from EOR
Net Additional Annual Private Costs
Value of Monetized Benefits
SCC 3% with Pope 7%
SCC 3% with Laden 3%
Net Monetized Benefits
SCC 3% with Pope 7%
SCC 3% with Laden 3%
SPC to IGCC with 39%
Capture
$17
$5 (@$15/ton)
$12
$13
$23
$1
$11
SPC to IGCC with 90%
Capture
$34
$37(@$45/ton)
($3)
$24
$34
$27
$37
This analysis suggests that the relative social cost of CCS compared to conventional coal
is sensitive to the achieved generating costs for CCS units, the revenue stream from EOR, and
the monetary value of avoided climate and other air pollution damages. However, it also
suggests that, at relatively low prices for EOR revenue ($15/MWh), CCS generation can
generate net social benefits compared to conventional coal generation. As before, it is
important to note that these comparisons omit additional benefits that may be associated with
the abatement of greenhouse gas emissions.
DOE/NETL-2011/1504 (June 2011); and "Storing CO2 with Enhanced Oil Recovery, DOE/NETL-402/1312
(February 2008).
59http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410. html
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5.11 Macroeconomic and Employment Impacts
This proposed ECU GHG NSPS is not anticipated to change GHG emissions for newly
constructed electric generating units, and is anticipated to impose negligible costs or quantified
benefits. EPA typically presents the economic impacts to secondary markets (e.g., changes in
industrial markets resulting from changes in electricity prices) and impacts to employment or
labor markets associated with proposed rules based on the estimated compliance costs and
other energy impacts, which serve as an input to such analyses. However, since the EPA does
not forecast a change in behavior relative to the baseline in response to this proposed rule,
there are no notable macroeconomic or employment impacts expected as a result of this
proposed rule.
5.12 References
Baumol, W.J. and W. E. Gates, The Theory of Environmental Policy. 2nd Edition. Cambridge
University Press: New York (1988).
Blyth, W. and Yang, M. and Bradley, R. Climate policy uncertainty and investment risk. 2007.
OECD/IEA.
Dalia Patino-Echeverri, Paul Fischbeck, and Elmar Kriegler. Economic and Environmental Costs
of Regulatory Uncertainty for Coal-Fired Power Plants. Environmental Science &
Technology 2009 43 (3), 578-584.
Hoffmann, Volker H. and Trautmann, Thomas and Hamprecht, Jens. Regulatory Uncertainty: A
Reason to Postpone Investments? Not Necessarily. Journal of Management Studies
2009 46 (7), 1467-6486.
Joskow, P.L. 2010. Comparing the Cost of Intermittent and Dispatchable Electricity Generating
Technologies. MIT Center for Energy and Environmental Policy Research Working Paper
10-013.
Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 2006. Reduction in Fine Particulate Air
Pollution and Mortality. American Journal of Respiratory and Critical Care Medicine
173:667-672.
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.
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Muller, N.Z., R. Mendelsohn, and W. Nordhaus. Environmental Accounting for Pollution in the
United States Economy. American Economic Review. 101:1649-1675.
Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Calle, D. Krewski, K. Ito, and G.D. Thurston. 2002.
Lung Cancer, Cardiopulmonary Mortality, and Long-term Exposure to Fine Particulate Air
Pollution. Journal of the American Medical Association 287:1132-1141.
Reinelt, Peter S.; Keith, David W. Carbon Capture Retrofits and the Cost of Regulatory
Uncertainty. Energy Journal, 2007, Vol. 28 Issue 4, plOl-127.
Rosenberg, M. 2011, September/October. "The Reign of Cheap Gas." EnergyBiz Magazine.
Retrieved from http://www.energybiz.com/magazine/article/234577/reign-cheap-gas.
Teisberg, E.G. An Option Valuation Analysis of Investment Choices by a Regulated Firm.
Management Science, 1994, 40 (4) 535-548.
long, S. 2010, November 1. Placing Bets on Clean Energy. [Radio transcript]. American Public
Media: Marketplace [Online]. Available: Marketplace Programs on Demand.
National Research of Council (NRC). 2009. Hidden Costs of Energy: Unpriced Consequences of
Energy Production and Use. National Academies Press: Washington, D.C.
U.S. Environmental Protection Agency (U.S. EPA). 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
.
U.S. Environmental Protection Agency (U.S. EPA). 2006. Air Quality Criteria for Ozone and
Related Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. Washington, DC: U.S.
EPA. February. Available on the Internet at
.
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
.
U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis (RIA) for the
final Transport Rule. Office of Air and Radiation, Washington, DC. June. Available on the
Internet at
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CHAPTER 6
STATUTORY AND EXECUTIVE ORDER ANALYSES
6.1 Synopsis
This chapter presents discussion and analyses relating to Executive Orders and statutory
requirements relevant to the proposed ECU GHG NSPS.1 We discuss analyses conducted to
meet the requirements of Executive Orders 12866 and 13563, as well as, potential impacts to
affected small entities required by the Regulatory Flexibility Act (RFA), as amended by the Small
Business Regulatory Enforcement Fairness Act (SBREFA). We also discuss the requirements of
the Unfunded Mandates Reform Act of 1995 (UMRA) and assess the impact of the proposed
rule on state, local and tribal governments and the private sector, along with the analysis
conducted to comply with the Paperwork Reduction Act (PRA). In addition, we address the
requirements of Executive Order (EO) 13045: Protection of Children from Environmental
Health and Safety Risks; EO 13132: Federalism; EO 13175: Consultation and Coordination with
Indian Tribal Governments; EO 12898: Federal Actions to Address Environmental Justice in
Minority Populations and Low-Income Populations; EO 13211: Actions that Significantly Affect
Energy Supply, Distribution, or Use; and the National Technology Transfer and Advancement
Act (NTTAA).
6.2 Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563,
Improving Regulation and Regulatory Review
Under EO 12866 (58 FR 51,735, October 4, 1993), this action is a "significant regulatory
action" because it "raises novel legal or policy issues arising out of legal mandates."
Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for
review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any
changes made in response to OMB recommendations have been documented in the docket for
this action.
In addition, EPA prepared an analysis of the potential costs and benefits associated with
this action. This analysis is contained in this RIA. Based on the analysis presented in Chapter 5,
EPA believes this rule will have negligible compliance costs associated with it, over a range of
likely sensitivity conditions, because even in the absence of the proposal, electric power
companies will choose to build new EGUs that comply with the regulatory requirements of this
proposal because of existing and expected market conditions. Because our modeling shows
1 Electricity Generating Unit Greenhouse Gas New Source Performance Standard - The NSPS would be established
under section lll(b) of the Clean Air Act (CAA).
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that new fossil-fuel fired capacity constructed through 2020 will most likely be natural gas
combined cycle capacity along with a small amount of coal with CCS supported by federal
funding, the proposed standard of performance — which is based on the emission rate of a
new NGCC unit — would not add costs. The EPA does not project any new coal-fired EGUs
without CCS to be built.
6.3 Paperwork Reduction Act
The information collection requirements have been submitted for approval to the Office
of Management and Budget under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
Information Collection Request (ICR) document prepared by the EPA has been assigned EPA ICR
number 2465.01.
This proposed action would impose minimal new information collection burden on
affected sources beyond what those sources would already be subject to under the authorities
of CAA parts 75 and 98. OMB has previously approved the information collection requirements
contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under
the provisions of the PRA, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060-
0626 and 2060-0629, respectively. Apart from certain reporting costs based on requirements in
the NSPS General Provisions (40 CFR part 60, subpart A), which are mandatory for all
owners/operators subject to CAA section 111 national emission standards, there are no new
information collection costs, as the information required by this proposed rule is already
collected and reported by other regulatory programs. The recordkeeping and reporting
requirements are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information
submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR
part 2, subpart B.
The EPA believes that electric power companies will choose to build new EGUs that
comply with the regulatory requirements of this proposal because of existing and expected
market conditions. The EPA does not project any new coal-fired EGUs without CCS that
commence construction after this proposal to commence operation over the 3-year period
covered by this ICR. We estimate that 17 new affected NGCC units would commence operation
during that time period. As a result of this proposal, those units would be required to prepare a
summary report, which includes reporting of excess emissions and downtime every 6 months.
When a malfunction occurs, sources must report them according to the applicable
reporting requirements of 40 CFR part 60, subpart TTTT. An affirmative defense to civil
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penalties for exceedances of emission limits that are caused by malfunctions is available to a
source if it can demonstrate that certain criteria and requirements are satisfied. The criteria
ensure that the affirmative defense is available only where the event that causes an
exceedance of the emission limit meets the narrow definition of malfunction (sudden,
infrequent, not reasonable preventable, and not caused by poor maintenance and or careless
operation) and where the source took necessary actions to minimize emissions. In addition, the
source must meet certain notification and reporting requirements. For example, the source
must prepare a written root cause analysis and submit a written report to the Administrator
documenting that it has met the conditions and requirements for assertion of the affirmative
defense.
To provide the public with an estimate of the relative magnitude of the burden
associated with an assertion of the affirmative defense position adopted by a source, the EPA
has estimated what the notification, record keeping, and reporting requirements associated
with the assertion of the affirmative defense might entail. The EPA's estimate for the required
notification, reports, and records, including the root cause analysis, associated with a single
incident totals approximately totals $3,141, and is based on the time and effort required of a
source to review relevant data, interview plant employees, and document the events
surrounding a malfunction that has caused an exceedance of an emission limit. The estimate
also includes time to produce and retain the record and reports for submission to the EPA. The
EPA provides this illustrative estimate of this burden, because these costs are only incurred if
there has been a violation, and a source chooses to take advantage of the affirmative defense.
The EPA provides this illustrative estimate of this burden because these costs are only
incurred if there has been a violation and a source chooses to take advantage of the affirmative
defense. Given the variety of circumstances under which malfunctions could occur, as well as
differences among sources' operation and maintenance practices, we cannot reliably predict
the severity and frequency of malfunction-related excess emissions events for a particular
source. It is important to note that the EPA has no basis currently for estimating the number of
malfunctions that would qualify for an affirmative defense. Current historical records would be
an inappropriate basis, as source owners or operators previously operated their facilities in
recognition that they were exempt from the requirement to comply with emissions standards
during malfunctions. Of the number of excess emissions events reported by source operators,
only a small number would be expected to result from a malfunction (based on the definition
above), and only a subset of excess emissions caused by malfunctions would result in the
source choosing to assert the affirmative defense. Thus, we believe the number of instances in
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which source operators might be expected to avail themselves of the affirmative defense will
be extremely small. In fact, we estimate that there will be no such occurrences for any new
sources subject to 40 CFR part 60, subpart I I IT over the 3-year period covered by this ICR. We
expect to gather information on such events in the future, and will revise this estimate as better
information becomes available.
The annual information collection burden for this collection consists only of reporting
burden as explained above. The reporting burden for this collection (averaged over the first 3
years after the effective date of the standards) is estimated to be $15,570 and 396 labor hours.
This estimate includes semi-annual summary reports which include reporting of excess
emissions and downtime. All burden estimates are in 2010 dollars. Average burden hours per
response are estimated to be 16.5 hours. The total number of respondents over the 3-year ICR
period is estimated to be 36. Burden is defined at 5 CFR 1320.3(b).
An agency may not conduct or sponsor, and a person is not required to respond to, a
collection of information unless it displays a currently valid OMB control number. The OMB
control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9.
To comment on the Agency's need for this information, the accuracy of the provided
burden estimates, and any suggested methods for minimizing respondent burden the EPA has
established a public docket for this proposed rule, which includes this ICR, under Docket ID
number EPA-HQ-OAR-2011-0660. The final rule will respond to any OMB or public comments
on the information collection requirements contained in this proposal.
6.4. Regulatory Flexibility Act as Amended by the Small Business Regulatory Enforcement
Fairness Act of 1996, 5 U.S.C. et seq.
The RFA generally requires an agency to prepare a regulatory flexibility analysis of any
rule subject to notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities. Small entities include
small businesses, small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this rule on small entities, small entity is
defined as:
(1) A small business that is defined by the Small Business Administration's regulations at
13 CFR 121.201 (for the electric power generation industry, the small business size standard is
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an ultimate parent entity defined as having a total electric output of 4 million MWh or less in
the previous fiscal year. The NAICS codes for the affected industry are in Table 6-1 below);
(2) A small governmental jurisdiction that is a government of a city, county, town, school
district, or special district with a population of less than 50,000; and
(3) A small organization that is any not-for-profit enterprise which is independently
owned and operated and is not dominant in its field.
Table 6-1. Potentially Regulated Categories and Entities3
Category
NAICS Code
Examples of Potentially Regulated Entities
Industry
Federal Government
State/Local
Government
Tribal Government
221112
221112
221112
921150
Fossil fuel electric power generating units.
Fossil fuel electric power generating units owned by the federal
government.
Fossil fuel electric power generating units owned by municipalities.
Fossil fuel electric power generating units in Indian Country.
Include NAICS categories for source categories that own and operate electric power generating units (includes boilers and
stationary combined cycle combustion turbines).
b Federal, state, or local government-owned and operated establishments are classified according to the activity in which they
are engaged.
After considering the economic impacts of this proposed rule on small entities, the
Administrator of EPA certifies that this action will not have a significant economic impact on a
substantial number of small entities.
We do not include an analysis of the illustrative impacts on small entities that may result
from implementation of this proposed rule by states because we anticipate negligible
compliance costs over a range of likely sensitivities as a result of this proposal. Thus the cost-
to-sales ratios for any affected small entity would be zero costs as compared to annual sales
revenue for the entity. The EPA believes that electric power companies will choose to build
new EGUs that comply with the regulatory requirements of this proposal because of existing
and expected market conditions. (See the RIA for further discussion of sensitivities.) Because
our modeling shows that new fossil-fuel fired capacity constructed through 2020 will most likely
be natural gas combined cycle capacity along with a small amount of coal with CCS supported
by federal funding, the proposed standard of performance — which is based on the emission
rate of a new NGCC unit — would not add costs. The EPA does not project any new coal-fired
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EGUs without CCS to be built. Accordingly, there are no anticipated economic impacts as a
result of this proposal.
Nevertheless, the EPA is aware that there is substantial interest in this rule among small
entities (municipal and rural electric cooperatives). In light of this interest, the EPA determined
to seek early input from representatives of small entities while formulating the provisions of
this proposed regulation. Such outreach is also consistent with the President's January 18, 2011
Memorandum on Regulatory Flexibility, Small Business, and Job Creation, which emphasizes
the important role small businesses play in the American economy. This process has enabled
the EPA to hear directly from these representatives, at a very preliminary stage, about how it
should approach the complex question of how to apply Section 111 of the CAA to the regulation
of GHGs from these source categories. The EPA's outreach regarded planned actions for new
and existing sources, but only new sources would be affected by this proposed action.
The EPA conducted an initial outreach meeting with small entity representatives on
April 6, 2011. The purpose of the meeting was to provide an overview of recent EPA proposals
impacting the power sector. Specifically, overviews of the Cross-State Air Pollution Rule, the
Mercury and Air Toxics Standards, and the Clean Water Act 316(b) Rule proposals were
presented.
The EPA conducted outreach with representatives from 20 various small entities that
potentially would be affected by this rule. The representatives included small entity
municipalities, cooperatives, and private investors. The EPA distributed outreach materials to
the small entity representatives; these materials included background, an overview of affected
sources and GHG emissions from the power sector, an overview of CAA section 111, an
assessment of C02 emissions control technologies, potential impacts on small entities, and a
summary of the five listening sessions that EPA held in February and March 2011 with various
stakeholder groups to get feedback from key stakeholders and the public before the agency
initiated the rulemaking process for new greenhouse gas emissions standards.2 EPA met with
eight of the small entity representatives, as well as three participants from organizations
representing power producers, on June 17, 2011, to discuss the outreach materials, potential
requirements of the rule, and regulatory areas where the EPA has discretion and could
potentially provide flexibility.
2 http://www.epa.gov/airquality/listen.html
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A second outreach meeting was conducted on July 13, 2011. We met with nine of the
small entity representatives, as well as three participants from organizations representing
power producers. During the second outreach meeting, various small entity representatives
and participants from organizations representing power producers presented information
regarding issues of concern with respect to development of standards for GHG emissions for
both new and existing sources. Specifically, topics discussed included: boilers with limited
opportunities for efficiency improvements due to NSR complications for conventional
pollutants; variances per kilowatt-hour and in heat rates over monthly and annual operations;
significance of plant age; legal issues; importance of future determination of carbon neutrality
of biomass; and differences between municipal government electric utilities and other utilities.
Small entities expressed concern regarding units making modifications being regulated
as new sources. As explained above, we are not proposing a standard of performance for
modifications. As a result, sources that undertake modifications would be treated as existing
sources and thus would not be subject to the requirements proposed in this notice. As also
explained above, the EPA is not proposing standards of performance for existing proposed
EGUs, which are referred to as transitional sources, that have acquired a complete
preconstruction permit by the time of this proposal and that commence construction within 12
months of this proposal. As a result, any transitional sources owned by small entities would not
be subject to the standards of performance proposed in today's rule.
We invite comments on all aspects of the proposal and its impacts, including potential
adverse impacts, on small entities.
6.5 Unfunded Mandates Reform Act of 1995
This proposed rule does not contain a Federal mandate that may result in expenditures
of $100 million of more for State, local, or tribal governments, in the aggregate, or the private
sector in any one year. The EPA believes this proposed rule will have negligible compliance
costs associated with it over a range of likely sensitivity conditions because electric power
companies will choose to build new EGUs that comply with the regulatory requirements of this
proposal because of existing and expected market conditions. (See the RIA for further
discussion of sensitivities.) As previously explained, because our modeling shows that new
fossil-fuel fired capacity constructed through 2020 will most likely be natural gas combined
cycle capacity along with a small amount of coal with CCS supported by federal funding, the
proposed standard of performance — which is based on the emission rate of a new NGCC unit
— would not add costs. The EPA does not project any new coal-fired EGUs without CCS to be
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built. Thus, this proposed rule is not subject to the requirements of sections 202 or 205 of
UMRA. This proposed rule is also not subject to the requirements of section 203 of UMRA
because it contains no regulatory requirements that might significantly or uniquely affect small
governments.
In light of interest in this rule among governmental entities, the EPA initiated
consultations with governmental entities. The EPA invited the following 10 national
organizations representing state and local elected officials to a meeting held on April 12, 2011,
in Washington DC: 1) National Governors Association; 2) National Conference of State
Legislatures, 3) Council of State Governments, 4) National League of Cities, 5) U.S. Conference
of Mayors, 6) National Association of Counties, 7) International City/County Management
Association, 8) National Association of Towns and Townships, 9) County Executives of America,
and 10) Environmental Council of States. These 10 organizations representing elected state and
local officials have been identified by the EPA as the "Big 10" organizations appropriate to
contact for purpose of consultation with elected officials. The purposes of the consultations
were to provide general background on the proposal, answer questions, and solicit input from
state/local governments. The EPA's consultation regarded planned actions for new and existing
sources, but only new sources would be affected by this proposed action.
During the meeting, officials asked clarifying questions regarding CAA section 111
requirements and efficiency improvements that would reduce C02 emissions. In addition, they
expressed concern with regard to the potential burden associated with impacts on state and
local entities that own/operate affected utility boilers, as well as on state and local entities with
regard to implementing the rule. Subsequent to the April 12, 2011 meeting, the EPA received a
letter from the National Conference of State Legislatures. In that letter, the National
Conference of State Legislatures urged the EPA to ensure that the choice of regulatory options
maximizes benefit and minimizes implementation and compliance costs on state and local
governments; to pay particular attention to options that would provide states with as much
flexibility as possible; and to take into consideration the constraints of the state legislative
calendars and ensure that sufficient time is allowed for state actions necessary to come into
compliance.
6.6 Executive Order 13132, Federalism
This proposed action does not have federalism implications. It would not have
substantial direct effects on the States, on the relationship between the national government
and the States, or on the distribution of power and responsibilities among the various levels of
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government, as specified in EO 13132. This proposed action would not impose substantial
direct compliance costs on state or local governments nor would it preempt state law. Thus,
Executive Order 13132 does not apply to this action. The EPA consulted with state and local
officials in the process of developing the proposed rule to permit them to have meaningful and
timely input into its development. The EPA's consultation regarded planned actions for new
and existing sources, but only new sources would be affected by this proposed action. The EPA
met with 10 national organizations representing state and local elected officials to provide
general background on the proposal, answer questions, and solicit input from state/local
governments. The UMRA discussion in this chapter includes a description of the consultation. In
the spirit of EO 13132 and consistent with EPA policy to promote communications between the
EPA and state and local governments, the EPA specifically solicits comment on this proposed
action from state and local officials.
6.7 Executive Order 13175, Consultation and Coordination with Indian Tribal
Governments
Subject to the EO 13175 (65 FR 67249, November 9, 2000) EPA may not issue a
regulation that has tribal implications, that imposes substantial direct compliance costs, and
that is not required by statute, unless the Federal government provides the funds necessary to
pay the direct compliance costs incurred by tribal governments, or EPA consults with tribal
officials early in the process of developing the proposed regulation and develops a tribal
summary impact statement.
EPA has concluded that this proposed action would not have tribal implications. It
would neither impose substantial direct compliance costs on tribal governments, nor preempt
tribal law. This proposed rule would impose requirements on owners and operators of EGUs.
The EPA is aware of three coal-fired EGUs located in Indian country but is not aware of any
EGUs owned or operated by tribal entities. The EPA notes that this proposal does not affect
existing sources such as the three coal-fired EGUs located in Indian country, but addresses C02
emissions for new ECU sources only.
Because the EPA is aware of tribal interest in this proposed rule, the EPA offered
consultation with tribal officials early in the process of developing this proposed regulation to
permit them to have meaningful and timely input into its development. The EPA's consultation
regarded planned actions for new and existing sources, but only new sources would be affected
by this proposed action.
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Consultation letters were sent to 584 tribal leaders. The letters provided information
regarding EPA's development of NSPS and emission guidelines for EGUs and offered
consultation. A consultation/outreach meeting was held on May 23, 2011, with the Forest
County Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa Reservation,
and the Leech Lake Band of Ojibwe. Other tribes participated in the call for information
gathering purposes. In this meeting, the EPA provided background information on the GHG
emission standards to be developed and a summary of issues being explored by the Agency.
Tribes suggested that the EPA consider expanding coverage of the GHG standards to include
combustion turbines, lowering the 250 MMBtu per hour heat input threshold so as to capture
more EGUs, and including credit for use of renewables. The tribes were also interested in the
scope of the emissions averaging being considered by the Agency (e.g., over what time period,
across what units) for a possible existing source standard. In addition, the EPA held a series of
listening sessions on this proposed action. Tribes participated in a session on February 17, 2011
with the state agencies, as well as in a separate session with tribes on April 20, 2011.
The EPA will also hold additional meetings with tribal environmental staff to inform
them of the content of this proposal as well as provide additional consultation with tribal
elected officials where it is appropriate. We specifically solicit additional comment on this
proposed rule from tribal officials.
6.8 Executive Order 13045, Protection of Children from Environmental Health Risks and
Safety Risks
The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those
regulatory actions that concern health or safety risks, such that the analysis required under
section 5-501 of the Order has potential to influence the regulation. This proposed action is not
subject to EO 13045 because it is based solely on technology performance. The proposal is not
expected to produce changes in emissions of greenhouse gases or other pollutants but does
encourage the current trend towards cleaner generation, helping to protect air quality and
children's health. The Agency recognizes that children are among the groups most vulnerable
to climate change impacts and the public is invited to submit comments or identify peer
reviewed studies relevant to this proposal.
6.9 Executive Order 13211, Actions Concerning Regulations That Significantly Affect
Energy Supply, Distribution, or Use
This proposed action is not a "significant energy action" as defined in Executive Order
13211 (66 FR 28355, May 22, 2001), because it is not likely to have a significant adverse effect
on the supply, distribution, or use of energy. This proposed action is anticipated to have
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negligible impacts on emissions, costs or energy supply decisions for the affected electric utility
industry.
6.10 National Technology Transfer and Advancement Act
Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 15 U.S.C. 272 note) directs
the EPA to use Voluntary Census Standards (VCS) in their regulatory and procurement activities
unless to do so would be inconsistent with applicable law or otherwise impractical. VCS are
technical standards (e.g., materials specifications, test methods, sampling procedures, business
practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA
directs the EPA to provide Congress, through annual reports to the OMB, with explanations
when an agency does not use available and applicable VCS.
This proposed rulemaking involves technical standards. The EPA cites the following
standards in this proposed rule: D5287-08 (Standard Practice for Automatic Sampling of
Gaseous Fuels), D4057-06 (Standard Practice for Manual Sampling of Petroleum and Petroleum
Products), and 04177-95(2010) (Standard Practice for Automatic Sampling of Petroleum and
Petroleum Products). The EPA is proposing use of Appendices B, D, F, and G to 40 CFR part 75;
these Appendices contain standards that have already been reviewed under the NTTAA.
The EPA welcomes comments on this aspect of the proposed rulemaking and,
specifically, invites the public to identify potentially-applicable VCS and to explain why such
standards should be used in this action.
6.11 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority
Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive
policy on environmental justice. Its main provision directs Federal agencies, to the greatest
extent practicable and permitted by law, to make environmental justice part of their mission by
identifying and addressing, as appropriate, disproportionately high and adverse human health
or environmental effects of their programs, policies, and activities on minority populations and
low-income populations in the U.S. EPA has determined that this proposed rule would not
result in disproportionately high and adverse human health or environmental effects on any
minority, low-income, or indigenous populations.
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United States Office of Air Quality Planning and Standards Publication No. EPA-452/R-12-001
Environmental Protection Health and Environmental Impacts Division March 2012
Agency Research Triangle Park, NC
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