W"*"*°" I1"
Regulatory Impact Analysis for the Final Standards of
Performance for Greenhouse Gas Emissions from New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units
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EPA-452/R-15-005
August 2015
Regulatory Impact Analysis for the Final Standards of Performance for Greenhouse Gas
Emissions from New, Modified, and Reconstructed 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, 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.
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ACRONYMS
AEO Annual Energy Outlook
ANSI American National Standards Institute
ASTM American Society for Testing and Materials
BPT Benefit-per-Ton
BSER Best System of Emissions Reduction
Btu British Thermal Units
CAA Clean Air Act
CAIR Clean Air Interstate Rule
CCR Coal Combustion Residuals
CCS Carbon Capture and Sequestration or Carbon Capture and Storage
CESA Clean Energy States Alliance
CFR Code of Federal Regulations
CH4 Methane
Carbon Dioxide
Carbon Dioxide Equivalent
CRA Congressional Review Act
CRF Capital Recovery Factor
CSAPR Cross-State Air Pollution Rule
CT Combustion Turbines
CUA Climate Uncertainty Adder
DOE U.S. Department of Energy
ECU Electric Generating Unit
EIA U.S. Energy Information Administration
ELG Effluent Limitation Guidelines
EMM Electricity Market Module
EO Executive Order
EOR Enhanced Oil Recovery
EPA U.S. Environmental Protection Agency
FERC Federal Energy Regulatory Commission
FOM Fixed Operating and Maintenance
FR Federal Register
FRCC Florida Reliability Coordinating Council
GDP Gross Domestic Product
GHG Greenhouse Gas
iv
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GS
GW
GWh
1AM
ICR
IGCC
IOU
IPCC
IPM
IPP
IRP
IWG
kWh
Ib
LCOE
MATS
MMBtu
MW
MWh
N20
NATCARB
NCA3
NEEDS
NEMS
NERC
NETL
NGCC
NOAK
NODA
NOX
NRC
NSPS
NTTAA
OMB
PM2.5
Geologic Sequestration
Gigawatt
Giga watt-hours
Integrated Assessment Model
Information Collection Request
Integrated Gasification Combined Cycle
Investor Owned Utility
Intergovernmental Panel on Climate Change
Integrated Planning Model
Independent Power Producers
Integrated Resource Plan
Interagency Working Group
Kilowatt-hour
Pound or Pounds
Levelized Cost of Electricity
Mercury and Air Toxics Standards
Million British Thermal Units
Megawatt
Megawatt-hour
Nitrous Oxide
National Carbon Sequestration Database and Geographic Information
System
Third National Climate Assessment
National Electric Energy Data System
National Energy Modeling System
North American Electric Reliability Corporation
National Energy Technology Laboratory
Natural Gas Combined Cycle
Nth of a Kind
Notice of Data Availability
Nitrogen Oxide
National Research Council
New Source Performance Standard
National Technology Transfer and Advancement Act
Office of Management and Budget
Fine Particulate Matter
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PM NAAQS
PRA
RES
RFA
RGGI
RIA
RPS
SC-C02
SCPC
SF6
SIP
S02
Tcf
TkWh
TSD
TS&M
UMRA
U.S.C.
USGCRP
USGS
VOM
National Ambient Air Quality Standards for Particulate Matter
Paperwork Reduction Act
Renewable Electricity Standards
Regulatory Flexibility Act
Regional Greenhouse Gas Initiative
Regulatory Impact Analysis
Renewable Portfolio Standards
Social Cost of Carbon
Supercritical Pulverized Coal
Sulfur Hexafluoride
State Implementation Plan
Sulfur Dioxide
Trillion Cubic Feet
Trillion Kilowatt-Hours
Technical Support Document
Transportation Storage and Monitoring
Unfunded Mandates Reform Act
U.S. Code
U.S. Global Change Research Program
U.S. Geological Survey
Variable Operating and Maintenance
VI
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Contents
Acronyms iv
Executive Summary ES-1
ES.l Background and Context of Final Rule ES-1
ES.2 Summary of the Final Rule ES-2
ES.3 Key Findings of Economic Analysis ES-3
Chapter 1 Introduction and Background 1-1
1.1 Introduction 1-1
1.1.1 Legal Basis for this Rulemaking 1-1
1.1.2 Regulatory Analysis 1-3
1.2 Background for the Final ECU New, Modified, and Reconstructed Source
GHG Standards 1-5
1.2.1 Baseline and Years of Analysis 1-5
1.2.2 Definition of Affected EGUs 1-6
1.2.3 Regulated Pollutant 1-7
1.2.4 Emission Limits 1-7
1.2.5 Emission Reductions 1-8
1.3 Organization of the Regulatory Impact Analysis 1-9
Chapter 2 Electric Power Sector Profile 2-1
2.1 Introduction 2-1
2.2 Power Sector Overview 2-1
2.2.1 Generation 2-1
2.2.2 Transmission 2-8
2.2.3 Distribution 2-9
2.3 Sales, Expenses, and Prices 2-9
2.3.1 Electricity Prices 2-10
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2.3.2 Prices of Fossil Fuels Used for Generating Electricity 2-15
2.3.3 Changes in Electricity Intensity of the U.S. Economy Between 2002
to 2012 2-16
2.4 Deregulation and Restructuring 2-18
2.5 Emissions of Greenhouse Gases from Electric Utilities 2-22
2.6 Carbon Dioxide Control Technologies 2-25
2.6.1 Carbon Capture and Storage 2-27
2.7 Geologic and Geographic Considerations for Geologic Sequestration 2-31
2.7.1 Availability of Geologic Sequestration in Deep Saline Formations 2-35
2.7.2 Availability of CCh Storage via Enhanced Oil Recovery 2-35
2.8 State Policies on GHG and Clean Energy Regulation in the Power Sector 2-37
2.9 Revenues and Expenses 2-39
2.10 Natural Gas Market 2-40
2.11 References 2-44
Chapter 3 Benefits of Reducing Greenhouse Gas Emissions and Other Pollutants 3-1
3.1 Overview of Climate Change Impacts from GHG Emissions 3-1
3.2 Social Cost of Carbon 3-2
3.3 Health Co-Benefits of S02 and NOx Reductions 3-8
3.4 References 3-11
Chapter 4 Costs, Economic, and Energy Impacts of the New Source Standards 4-1
4.1 Synopsis 4-1
4.2 Requirements of the Final GHG ECU NSPS 4-2
4.3 Power Sector Modeling Framework 4-3
4.3.1 Modeling Overview 4-3
4.3.2 The Integrated Planning Model 4-4
4.4 Analyses of Future Generating Capacity 4-7
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4.4.1 Base Case Power Sector Modeling Projections 4-7
4.4.2 Alternative Scenarios from AEO 2014 4-13
4.5 Levelized Cost of Electricity Analysis 4-20
4.5.1 Overview of the Concept of Levelized Cost of Electricity 4-20
4.5.2 Cost and Performance of Technologies 4-21
4.5.3 Levelized Cost of Electricity of New Generation Technologies 4-24
4.5.4 Levelized Cost of Electricity of NGCC and Non-compliant Coal 4-26
4.5.5 Levelized Cost of Simple Cycle Combustion Turbine and Natural
Gas Combined Cycle 4-34
4.6 Macroeconomic and Employment Impacts 4-35
4.7 References 4-36
Chapter 5 Analysis of Illustrative Benefit-Cost Scenarios For New Sources 5-1
5.1 Synopsis 5-1
5.2 Comparison of Emissions from Generation Technologies 5-1
5.3 Comparison of Health and Climate Impacts from Generation Technologies 5-5
5.4 Illustrative Analysis - Benefits and Costs of New Source Standards across
a Range of Gas Prices 5-11
5.4.1 Likely Natural Gas Prices 5-14
5.4.2 Unexpectedly High Natural Gas Prices 5-14
5.4.3 Unprecedented Natural Gas Prices 5-15
5.5 Illustrative Analysis - Benefits and Costs of Non-Compliant Coal and
Compliant Coal 5-16
5.6 Impact of the New Source Standards Considering the Cost of Lost Option
Value 5-23
5.7 References 5-25
Chapter 6 Modified and Reconstructed Source Impacts 6-1
6.1 Introduction 6-1
6.2 Reconstructed Sources 6-1
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6.3 Modified Sources 6-1
Chapter 7 Statutory and Executive Order Reviews 7-1
7.1 Executive Order 12866, Regulatory Planning and Review, and Executive
Order 13563, Improving Regulation and Regulatory Review 7-1
7.2 Paperwork Reduction Act (PRA) 7-1
7.2.1 Newly constructed EGUs 7-2
7.2.2 Modified and Reconstructed EGUs 7-3
7.2.3 Information Collection Burden 7-4
7.3 Regulatory Flexibility Act (RFA) 7-4
7.3.1 Newly constructed EGUs 7-4
7.3.2 Modified and Reconstructed EGUs 7-5
7.4 Unfunded Mandates Reform Act (UMRA) 7-5
7.5 Executive Order 13132, Federalism 7-6
7.6 Executive Order 13175, Consultation and Coordination with Indian Tribal
Governments 7-6
7.7 Executive Order 13045, Protection of Children from Environmental Health
Risks and Safety Risks 7-8
7.8 Executive Order 13211, Actions Concerning Regulations That Significantly
Affect Energy Supply, Distribution, or Use 7-9
7.9 National Technology Transfer and Advancement Act 7-9
7.10 Executive Order 12898: Federal Actions to Address Environmental Justice
in Minority Populations and Low-Income Populations 7-9
7.11 Congressional Review Act (CRA) 7-12
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EXECUTIVE SUMMARY
This Regulatory Impact Analysis (RIA) discusses potential benefits, costs, and economic
impacts of the Final Standards of Performance for Greenhouse Gas Emissions from New,
Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units (herein
referred to as the ECU New, Modified, and Reconstructed Source GHG Standards).
ES.l Background and Context of Final Rule
The final ECU New, Modified and Reconstructed Source GHG Standards will set emission
limits for greenhouse gas emissions (GHG) from newly constructed, modified, and
reconstructed fossil fuel-fired electricity generating units (EGUs). These limits will apply to
carbon dioxide (CCh) emissions from any affected fossil fuel-fired ECU. The United States
Environmental Protection Agency (EPA) is finalizing requirements for these sources because
C02 is an air pollutant under the Clean Air Act, section 111 (a) and (b) of the Act authorize the
EPA to establish standards of performance for air pollutants emitted from source categories like
the one here listed by the EPA because the source category causes, or contributes significantly
to air pollution which may reasonably be anticipated to endanger public health or welfare.
Fossil fuel-fired power plants are the country's largest stationary source emitters of GHGs. As
stated in the EPA's Endangerment and Cause or Contribute Findings for Greenhouse Gases
Under Section 202(a) of the Clean Air Act (CAA) (74 FR 66518), and summarized in Chapter 3 of
this RIA, the anthropogenic buildup of GHGs in the atmosphere is the cause of most of the
observed global warming over the last 50 years.
On June 25, 2013, in conjunction with the announcement of his Climate Action Plan,
President Obama issued a Presidential Memorandum directing the EPA to issue a proposal to
address carbon pollution from new power plants by September 30, 2013, and to issue
"standards, regulations, or guidelines, as appropriate, which address carbon pollution from
modified, reconstructed, and existing power plants." On September 20, 2013, pursuant to
authority in CAA section lll(b), EPA Administrator Gina McCarthy signed proposed carbon
pollution standards for newly constructed fossil fuel-fired power plants (79 FR 1430, January 8,
2014).
The EPA subsequently issued a Notice of Data Availability (NODA), soliciting comment
on its initial interpretation of provisions in the Energy Policy Act of 2005 and the Internal
Revenue Code, and also soliciting comment on a Technical Support Document, which addressed
these provisions' relationship to the factual record supporting the proposed rule (79 FR 10750,
February 26, 2014).
ES-1
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On June 2, 2014, Administrator McCarthy signed proposed standards of performance,
also pursuant to CAA section lll(b), to limit emissions of CCh from modified and reconstructed
fossil fuel-fired electric utility steam generating units and stationary combustion turbines (79 FR
34959, June 18, 2014).
In this action, the EPA is finalizing standards of performance to limit emissions of
from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam
generating units and stationary combustion turbines. Consistent with the requirements of CAA
section lll(a) and (b), these standards reflect the degree of emission limitation achievable
through the application of the best system of emission reduction (BSER) that the EPA has
determined has been adequately demonstrated for each type of unit.
ES.2 Summary of the Final Rule
The EPA has determined that the BSER for newly constructed steam generating units is a
supercritical pulverized coal (SCPC) unit using post-combustion partial carbon capture and
storage (CCS) technology to meet an emission limitation of 1,400 Ib CCh/MWh-gross. The
standard for steam generating units that conduct modifications resulting in a potential hourly
increase in CCh emissions (mass per hour) of more than 10 percent1 is a unit-specific emission
limitation consistent with each modified unit's best one-year historical performance during the
years from 2002 to the time of the modification. For reconstructed steam generating units, the
BSER is the most efficient demonstrated generating technology for these types of units (i.e.,
meeting a standard of performance consistent with a reconstructed boiler using most efficient
steam conditions available, even if the boiler was not originally designed to do so).
The BSER for primarily natural gas-fired stationary combustion turbines expected to
serve intermediate and base load power demand is the use of well-designed, well-maintained,
and well-operated natural gas combined cycle (NGCC) technology. These units will be required
to meet an emission standard of 1,000 Ib C02/MWh-gross output (or 1,030 Ib C02/MWh of net
energy output). For non-base load and multi-fuel-fired units, BSER is the use of clean fuels.
The BSER determination and final standards for each affected ECU are shown in Table
ES-1. The applicability of these standards based on the capacity and operation of a source are
described in the preamble for this final rule. The final standards for all source categories will be
met on a 12-operating month rolling average basis.
1 More than 10 percent as compared to its highest potential during the previous five years. The EPA is not finalizing
standards for units that conduct modifications with a potential hourly increase in CCh of 10 percent of less.
ES-2
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ES.3 Key Findings of Economic Analysis
CAA Section lll(b) requires that the new source performance standards (NSPS) be
reviewed every eight years. As a result, this rulemaking's analysis is primarily focused on
projected impacts within the current eight-year NSPS timeframe.2 As explained in detail in this
document, energy market data and projections support the conclusion that, even in the
absence of this rule, expected economic conditions will lead electricity generators to choose
new generation technologies that meet the standards without the need for additional controls.
The base case modeling the EPA performed for this rule and for other recent air rules
projects that, even in the absence of this action, new fossil-fuel fired capacity constructed
through 2022 and the years following will most likely be NGCC capacity that complies with the
final standards. Analyses performed both by the EPA and the Energy Information
Administration (EIA) project that new compliant natural gas-fired units and renewable sources
are likely to be the technologies of choice for new generating capacity due to current and
projected economic market conditions.3
2 In some cases, conditions in the analysis year of 2022 (eight years from proposal) are represented by results of
power sector modeling for the year 2020. An analysis year of 2023 (eight years from finalization) would not
substantively alter the overall conclusions of this RIA.
3 See the ElA's 2009 to 2015 Annual Energy Outlooks (AEO).
ES-3
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Table ES-1. Summary of BSER and Final Standards for Affected EGUs
Affected EGU
BSER
Standard
Newly Constructed Fossil Fuel-Fired
Steam Generating Units
Efficient newSCPC utility boiler
implementing partial CCS
1,400 Ib CCh/MWh-gross
Modified Fossil Fuel-Fired Steam
Generating Units
Most efficient generation at the
affected EGU achievable through a
combination of best operating
practices and equipment upgrades
Sources making modifications
resulting in an increase in CO2
hourly emissions of more than 10
percent are required to meet a
unit-specific emission limit
determined by the unit's best
historical annual CO2 emission rate
(from 2002 to the date of the
modification); the emission limit
will be no more stringent than:
1. 1,800 Ib CCh/MWh-gross for
sources with heat input > 2,000
MMBtu/h.
OR
2. 2,000 Ib CCh/MWh-gross for
sources with heat input < 2,000
MMBtu/h.
Reconstructed Fossil Fuel-Fired Steam
Generating Units
Most efficient generating
technology at the affected EGU.
1. 1,800 Ib CCh/MWh-gross for
sources with heat input > 2,000
MMBtu/h.
OR
2. 2,000 Ib CO2/MWh-gross for
sources with heat input < 2,000
MMBtu/h.
Newly Constructed and Reconstructed
Natural Gas-Fired Stationary
Combustion Turbines
Efficient NGCC technology for
natural gas-fired base load units
and clean fuels for non-base load
and multi-fuel-fired units.
1. 1,000 Ib CO2/MWh-gross or
1,030 Ib CO2/MWh-net for
base load natural gas-fired
units.
2. 120 lbCO2/MMBtu for non-
base load natural gas-fired
units.
3. 120 to 160 Ib CO2/MMBtu for
multi-fuel-fired units.
Historically, the EPA has been notified of very few modifications (for criteria pollutants)
or reconstructions under the NSPS provisions. As such, the EPA anticipates few covered units
will trigger the reconstruction or modification provisions in the period of analysis.
Therefore, based on the analysis presented in Chapter 4 of this RIA, the EPA anticipates
that the EGU New, Modified, and Reconstructed Source GHG Standards will result in negligible
emission changes, energy impacts, quantified benefits, costs, and economic impacts by
ES-4
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2022. Accordingly, the EPA also does not anticipate this rule will have any significant impacts on
the price of electricity, employment or labor markets, or the U.S. economy.
Although the primary conclusion of the analysis presented in this RIA is that the
standards for newly constructed EGUs will result in negligible costs and benefits, the EPA has
also performed several illustrative analyses, in Chapter 5, that show the potential impacts of
the rule if certain key assumptions were to change. This analysis finds that under conditions
that deviate from current projections about natural gas prices, the monetized benefits of the
standards to society likely outweigh the costs of the standards. The analysis also presents the
costs and benefits that would occur in the unlikely case where assumptions about economic
conditions do not change but an operator chooses to construct new coal-fired capacity. In that
analysis, monetized benefits outweigh costs under a range of assumptions.
The final standards provide the benefit of regulatory certainty that any new coal-fired
power plant must limit CCh emissions to the level of the standard of performance: 1,400 Ib
CCh/MWh. The final standards also reduce regulatory uncertainty by defining the requirements
to limit emissions of CCh from new, modified, and reconstructed fossil fuel-fired steam
generating sources.
In addition, the EPA intends this rule to send a clear signal about the current and future
status of CCS technology. Additional CCS applications are expected to lead to improvements in
this technology's performance and consequent reductions in its cost. Identifying post-
combustion partial CCS technology as the BSER for coal-fired power plants promotes further
development and encourages continued research of CCS,4'5 which is important for long-term
emission reductions.
The final standards also provide regulatory certainty for stationary combustion turbines
that, along with new renewable sources, are expected to be the primary technology options to
provide new generating capacity in the analysis period. Any new stationary combustion
turbines must be well-designed, well-maintained, and well-operated.
4 Statement by Department of Energy Secretary Steven Chu. Statement by Secretary Chu.
http://energy.gov/articles/building-clean-energv-partnerships-china-and-iapan.
5 Friedman, Dr. Julio S. "A U.S. - China CCS Roadmap." Lawrence Livermore National Laboratory Carbon
Management Program. http://www.nrcce.wvu.edu/cleanenergy/docs/Friedmann.pdf.
ES-5
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CHAPTER 1
INTRODUCTION AND BACKGROUND
1.1 Introduction
In this action, the U.S. Environmental Protection Agency (EPA) is adopting emission
limits for greenhouse gases (GHGs), specifically carbon dioxide (CCh), emitted from fossil fuel-
fired EGUs. This document presents the expected economic impacts of the Electricity
Generating Unit (ECU) New, Modified, and Reconstructed Source GHG Standards rule through
2022, including some projections for years up to 2030. Based on the analysis presented in
Chapter 4, the current forecast of economic conditions (e.g., price of natural gas) will lead
electricity generators to choose fuels and technologies that will meet the final standards for
new sources without the need for additional control, even in the absence of the rule. As a
result, the final new source standards are expected to have no, or negligible, costs or quantified
benefits associated with them. However, should forecast economic conditions change or
operators choose to construct new coal-fired capacity, we project that emission reductions
associated with the standard may result in monetized benefits exceeding the cost of control,
and would also provide unquantified benefits. (See Chapters.) The EPA has reached a similar
conclusion for the final reconstruction and modification provisions. Based on historical
information that has been reported to the EPA, we anticipate few covered units will trigger the
reconstruction or modification provisions in the period of analysis. As a result, we anticipate
negligible costs or benefits associated with those standards. This chapter contains background
information on the rule and an outline of the chapters of the report.
1.1.1 Legal Basis for this Rulemaking
Section 111 of the Clean Air Act (CAA) requires performance standards for air pollutant
emissions from categories of stationary sources which are listed by the EPA because they may
reasonably contribute to the endangerment of public health or welfare. In April 2007, the
Supreme Court ruled in State of Massachusetts v. EPA that GHGs meet the definition of an "air
pollutant" under the CAA. This ruling clarified that the authorities and requirements of the CAA
apply to GHGs. As a result, the EPA is authorized to make decisions about whether to regulate
GHGs under certain provisions of the CAA, based on relevant statutory criteria. Because CCh is
an air pollutant emitted from a source category the EPA has listed for purposes of section 111,
the EPA may establish standards under section 111 (a) and (b) for CCh for this source category.
In 2009, the EPA issued a final determination that emissions of certain specified GHGs endanger
both the public health and the public welfare of current and future generations in the
Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of
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the CAA (74 FR 66,496; Dec. 15, 2009), and has explained in detail how emissions of C02 from
this source category cause or contribute significantly to air pollution that endangers health and
welfare. As described in Chapter 2, this source category contributes more CCh than any other
domestic stationary source.
On June 25, 2013, in conjunction with the announcement of his Climate Action Plan,
President Obama issued a Presidential Memorandum directing the EPA to issue a proposal to
address carbon pollution from new power plants by September 30, 2013, and to issue
"standards, regulations, or guidelines, as appropriate, which address carbon pollution from
modified, reconstructed, and existing power plants." On September 20, 2013, pursuant to
authority in CAA section lll(b), EPA Administrator Gina McCarthy signed proposed carbon
pollution standards for newly constructed fossil fuel-fired power plants (79 FR 1430, January 8,
2014).
The EPA subsequently issued a Notice of Data Availability (NODA), soliciting comment
on its initial interpretation of provisions in the Energy Policy Act of 2005 and the Internal
Revenue Code, and also soliciting comment on a Technical Support Document, which addressed
these provisions' relationship to the factual record supporting the proposed rule (79 FR 10750,
February 26, 2014).
On June 2, 2014, Administrator McCarthy signed proposed standards of performance,
also pursuant to CAA section lll(b), to limit emissions of C02 from modified and reconstructed
fossil fuel-fired electric utility steam generating units and stationary combustion turbines (79 FR
34959, June 18, 2014).
In this action, the EPA is finalizing standards of performance to limit emissions of C02
from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam
generating units and stationary combustion turbines. Consistent with the requirements of CAA
section lll(b), these standards reflect the degree of emission limitation achievable through the
application of the best system of emission reduction (BSER) that the EPA has determined has
been adequately demonstrated for each type of unit.
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1.1.2 Regulatory Analysis1
In accordance with Executive Order (EO) 12866, EO 13563, and the EPA's Guidelines for
Preparing Economic Analyses, the EPA prepared this Regulatory Impact Analysis (RIA) for this
"significant regulatory action." This rule is not anticipated to have an annual effect on the
economy of $100 million or more or adversely affect in a material way the economy, a sector of
the economy, productivity, competition, jobs, the environment, public health or safety, or
state, local, or tribal governments or communities and is therefore not an "economically
significant rule." However, under EO 12866 (58 FR 51,735, October 4, 1993), this action is a
"significant regulatory action" because it "raises novel legal or policy issues arising out of legal
mandates." As a matter of policy, the EPA has attempted to provide a thorough analysis of the
potential impacts of this rule, consistent with requirements of the Executive Orders.
This RIA addresses the potential costs and benefits of the new, modified, and
reconstructed source emission limits that are the focus of this action. As described in Chapter 4,
the EPA does not anticipate any costs or quantified benefits will result from the new source
standards if utilities and project developers make the type of choices related to new generation
sources that are forecast by the EPA's and ElA's models and that many publicly available utility
integrated resource plans (IRPs) indicate are likely. However, if future economic conditions
(e.g., natural gas prices) differ from these forecasts and utilities would have constructed new
coal-fired units in the baseline, there could be some compliance costs. In these cases, the EPA's
analysis shows that the rule will result in net benefits under a range of assumptions.
For new sources the EPA and EIA, through their models2, project that new fossil-fired
electric utility steam generating units and natural gas-fired stationary combustion turbines that
meet the applicability criteria would meet the respective standards under this rule in the
baseline where no such standards are implemented. Some limited new coal-fired units with
federally-supported carbon capture and storage (CCS) are included in the modeling, though
these units are expected to be compliant with the applicable standards under this rule. Because
this rule does not change these forecasts, it is expected to have no, or negligible, costs,3 or
quantified benefits.
1 The analysis in this RIA and the draft RIA that accompanied the proposal together constitute the economic
assessment required by CAA section 317. In the EPA's judgment, the assessment is as extensive as practicable
taking into account the EPA's time, resources, and other duties and authorities."
2 See the ElA's 2009 to 2015 Annual Energy Outlooks (AEO).
3 Any additional monitoring or reporting costs from this rule should be negligible because new generators would
already be required to monitor and report their CCh emissions under the information collection requirements
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New non-compliant coal-fired units are not expected to be constructed in the baseline,
due in part to the low cost of constructing and operating new NGCC units relative to the cost of
new coal-fired units, relatively low forecast growth in electricity demand, and an expectation
that the growth in end-use energy efficiency and renewable energy resources will continue. The
expectation that no new non-compliant coal-fired units will be constructed in the baseline, and
therefore that the promulgated standard of performance would not be a factor in decisions to
construct, holds under a range of alternative baseline scenarios.
Natural gas-fired combustion turbine units intended to serve as intermediate and base
load generators constructed in the baseline are expected to be compliant with the standard,
due in part to the cost-effectiveness of constructing and operating new combined cycle units
relative to the cost of new simple cycle units. Absent significantly lower natural gas prices, the
cost of electricity generated by combined cycle units operating at intermediate and base load
capacity are lower than simple cycle units operating at the same capacity factor.
Chapter 5 complements and extends the sector level analysis by examining conditions
(e.g., significantly higher natural gas prices) in which conclusions regarding the future economic
competitiveness of new non-compliant coal-fired units relative to other new generation
technologies may differ from those in the sector-wide analysis. The analysis evaluates the cost
and benefits of adopting different competing generating technologies to serve base load
demand at an individual facility level. When considering a wide range of natural gas price
assumptions, along with information on historical and projected gas prices, this illustrative
facility-level analysis supports the conclusion that these final standards are highly likely to incur
no costs or quantified benefits. Furthermore, the analysis examines the costs and benefits that
would occur in the unlikely case where an investor might choose to construct new coal-fired
capacity, and shows that the result is a net monetized benefit under a range of assumptions.
As described in Chapter 6, the EPA has reached a similar conclusion for the
reconstruction and modification provisions for both steam generating units and stationary
combustion turbines. The EPA has historically been notified of few modifications or
reconstructions under the NSPS provisions and, as such, anticipates few covered units will
contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98). Costs are only incurred
if there has been a violation of an emission standard caused by a malfunction and a source chooses to assert an
affirmative defense. The owner/operator must meet the burden of proving all of the requirements in an
affirmative defense. See Chapter 7 for more details on monitoring and reporting costs.
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trigger the NSPS reconstruction or modification provisions in the period of analysis. As a result,
we do not anticipate any significant costs or benefits associated with this rule.
1.2 Background for the Final ECU New, Modified, and Reconstructed Source GHG
Standards
1.2.1 Baseline and Years of Analysis
The standards on which this analysis is based set GHG emission limits for new, modified,
and reconstructed fossil fuel-fired EGUs. The baseline for this analysis, which uses the
Integrated Planning Model (IPM), includes state rules that have been finalized and/or approved
by a state's legislature or environmental agency as well as final federal rules. Additional legally
binding and enforceable commitments for GHG reductions considered in the baseline are
discussed in Chapter 4 of this RIA.
All analyses are presented for compliance through the year 20224 and all estimates are
presented in 2011 dollars. CAA Section lll(b) requires that the NSPS be reviewed every eight
years. As a result, this analysis is primarily focused on projected impacts within the current
eight-year NSPS timeframe. The EPA's finding of no new non-compliant units (and therefore,
no projected costs or quantified benefits) is robust beyond the analysis period (past 2030) in
both the IPM base case and the ElA's Annual Energy Outlook 2014 Reference Case modeling
projections. Furthermore, this finding is robust in the analysis period across a wide range of
alternative potential market, technical, and regulatory scenarios that influence power sector
investment decisions evaluated by EIA.5 Chapter 5 complements and extends the sector level
analysis by examining conditions (e.g., significantly high natural gas prices) in which these
conclusions regarding the future economic competitiveness of new non-compliant coal-fired
units relative to other new generation technologies may differ. The analysis evaluates the cost
and benefits of adopting different competing generating technologies to serve base load
demand at an individual facility level.
Benefits and costs presented in the illustrative analyses in Chapter 5 of this RIA
represent estimates from emission reductions under the finalized standards in a particular year.
The latent and/or ongoing damages associated with pollution from these sources in a particular
4 In IPM, conditions in the analysis year of 2022 are represented by a model year of 2020.
5 For example, in the 2014 AEO low gas resource sensitivity case, one of the scenarios most favorable to the
construction of new coal capacity, the operation of new non-compliant coal capacity in the baseline is not
forecast by the model until 2027.
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analysis year are discounted to the analysis year.6 The benefits and costs presented do not
represent the net present value of a stream of benefits and costs due to emission reductions
overtime.
1.2.2 Definition of Affected EGUs
1.2.2.1 New Sources
The statutory authority for this action is CAA section lll(b), which addresses standards
of performance for new, modified, and reconstructed sources. The final standards for newly
constructed fossil fuel-fired EGUs apply to those sources that commenced construction on or
after January 8, 2014.
1.2.2.2 Modified Sources
A modification is any physical or operational change to a source that increases the
amount of any air pollutant emitted by the source or results in the emission of any air pollutant
not previously emitted. The final standards for modified fossil fuel-fired steam generating units
apply to those sources that make modifications resulting in an increase of hourly CCh emissions
of more than 10 percent on or after June 18, 2014. However, projects to install pollution
controls required under other CAA provisions are specifically exempted from the definition of
"modifications" under 40 CFR 60.14(e)(5), even if they emit CCh as a byproduct.
1.2.2.3 Reconstructed Sources
The EPA's CAA section 111 regulations provide that reconstructed sources are to be
treated as new sources and, therefore, subject to new source standards of performance. The
regulations define reconstructed sources, in general, as existing sources: (i) that replace
components to such an extent that the capital costs of the new components exceed 50 percent
of the capital costs of an entirely new facility and (ii) for which compliance with standards of
performance for new sources is technologically and economically feasible (40 CFR 60.15). The
final standards for reconstructed fossil fuel-fired EGUs apply to those sources that reconstruct
on or after June 18, 2014.
6 The CCh-related benefits, which are estimated using the social cost of carbon, vary depending on the year in
which the change in CCh emissions occurs. The social cost of carbon increases over time because future
emissions are expected to produce larger incremental damages as physical and economic systems become
more stressed in response to greater climatic change. The EPA relied on a national-average benefit per-ton
method to estimate Plvh.s-related health impacts of SCh and NOx emissions. Despite our attempts to quantify
and monetize as many of the co-benefits of reducing emissions from electricity generating sources as possible,
not all known health and non-health co-benefits are accounted for in this assessment. See Chapter 3 for details.
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1.2.3 Regulated Pollutant
These final standards set limits for emissions of CCh from affected EGUs. The EPA is
aware that other GHGs such as nitrous oxide (INhO) and to a lesser extent, methane (CI-U), may
be emitted from fossil-fuel-fired EGUs, especially from coal-fired circulating fluidized bed
combustors and from units with selective catalytic reduction and selective non-catalytic
reduction systems installed for nitrogen oxide (NOx) control. The EPA is not setting separate
INhO or CI-U emission limits or an equivalent CCh emission limit because of a lack of available
data for these affected EGUs. Additional information on the quantity and significance of
emissions and on the availability of cost effective controls would be needed before setting
standards for these pollutants.
1.2.4 Emission Limits
The EPA has determined that the BSER for newly constructed steam generating units is a
supercritical pulverized coal (SCPC) unit with post-combustion partial CCS technology. The
standard of performance achievable using that BSER is 1,400 Ib CCh/MWh-gross. The standard
for modified steam generating units that conduct modifications resulting in a potential hourly
increase in CCh emissions (mass per hour) of more than 10 percent7 is a unit-specific emission
limitation consistent with each modified unit's best one-year historical performance during the
years from 2002 to the time of the modification. For reconstructed steam generating units, the
BSER is the most efficient demonstrated generating technology for these types of units (i.e.,
meeting a standard of performance consistent with a reconstructed boiler using most efficient
steam conditions available, even if the boiler was not originally designed to do so).
The BSER for new and reconstructed primarily natural gas-fired combustion turbines
expected to serve intermediate and base load is the use of well-designed, well-maintained, and
well-operated natural gas combined cycle (NGCC) technology. The standard of performance
achievable using that BSER is 1,000 lb/C02/MWh-gross.
The applicability of these standards is based on the capacity and operation of a source
and is described in the preamble for this final rule. The final standards will be met on a 12-
operating month rolling average basis. The BSER determination and final standards for each
affected ECU are shown in Table 1-1.
7 More than 10 percent as compared to its highest potential to emit in the past 5 years. The EPA is deferring issuing
standards for units that conduct modifications with a potential hourly increase in CCh of 10 percent or less.
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Table 1-1. Summary of BSER and Final Standards for Affected EGUs
Affected EGU
BSER
Standard
Newly Constructed Fossil Fuel-Fired
Steam Generating Units
Efficient new SCPC utility boiler
implementing partial CCS
1,400 Ib CCh/MWh-gross
Modified Fossil Fuel-Fired Steam
Generating Units
Most efficient generation at the
affected EGU achievable through a
combination of best operating
practices and equipment upgrades
Sources making modifications
resulting in an increase in CO2
hourly emissions of more than 10
percent are required to meet a
unit-specific emission limit
determined by the unit's best
historical annual CO2 emission rate
(from 2002 to the date of the
modification); the emission limit
will be no more stringent than:
1. 1,800 Ib CCh/MWh-gross for
sources with heat input > 2,000
MMBtu/h.
OR
2. 2,000 Ib CCh/MWh-gross for
sources with heat input < 2,000
MMBtu/h.
Reconstructed Fossil Fuel-Fired Steam
Generating Units
Most efficient generating
technology at the affected EGU.
1. 1,800 Ib CCh/MWh-gross for
sources with heat input > 2,000
MMBtu/h.
OR
2. 2,000 Ib CO2/MWh-gross for
sources with heat input < 2,000
MMBtu/h.
Newly Constructed and Reconstructed
Natural Gas-Fired Stationary
Combustion Turbines
Efficient NGCC technology for 4. 1,000 Ib CO2/MWh-gross or
natural gas-fired base load units
and clean fuels for non-base load
and multi-fuel-fired units.
1,030 Ib CO2/MWh-net for
base load natural gas-fired
units.
5. 120 lbCO2/MMBtu for non-
base load natural gas-fired
units.
6. 120 to 160 Ib CO2/MMBtu for
multi-fuel-fired units.
1.2.5 Emission Reductions
As will be discussed in more detail in Chapter 4 of this RIA, the EPA anticipates that the
EGU New, Modified, and Reconstructed Source GHG Standards will result in negligible changes
in GHG emissions over the analysis period. The EPA expects that owners of new units will
choose generation technologies that meet these standards in the baseline due to expected
economic conditions in the marketplace. Based on historical precedent, the EPA anticipates few
1-8
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covered units will trigger the NSPS reconstruction or modification provisions in the period of
analysis. As a result, we do not anticipate any significant costs or monetized benefits associated
with this rule.
1.3 Organization of the Regulatory Impact Analysis
This report presents the EPA's analysis of the potential benefits, costs, and other
economic effects of the ECU New, Modified, and Reconstructed Source GHG Standards to fulfill
the requirements of an RIA. This RIA includes the following chapters:
• Chapter 2, Electric Power Sector Profile, describes the industry affected by the rule.
• Chapter 3, Benefits of Reducing GHGs and Other Pollutants, describes the effects of
emissions on climate and health and provides background information to support
the benefits analysis.
• Chapter 4, Costs, Economic, and Energy Impacts of the New Source Standards,
describes impacts of the rule for new sources.
• Chapter 5, Analysis of Illustrative Benefit-Cost Scenarios for New Sources, describes
additional analyses examining potential impacts under a range of scenarios.
• Chapter 6, Modified and Reconstructed Sources, describes the potential impacts of
the standards for modified and reconstructed sources.
• Chapter 7, Statutory and Executive Order Impact Analyses, describes the small
business, unfunded mandates, paperwork reduction act, environmental justice, and
other analyses conducted for the rule to meet statutory and Executive Order
requirements.
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CHAPTER 2
ELECTRIC POWER SECTOR PROFILE
2.1 Introduction
This chapter discusses important aspects of the power sector that relate to the ECU
New, Modified and Reconstructed Source GHG Standards, including the types of electricity
generating units (EGUs) affected by the regulation, and provides background on the power
sector and EGUs. In addition, this chapter provides some historical background on trends in the
past decade in the power sector, as well as about existing U.S. Environmental Protection
Agency (EPA) regulation of the power sector.
In the past decade there have been significant structural changes in the both the mix of
generating capacity and in the share of electricity generation supplied by different types of
generation. These changes are the result of multiple factors in the power sector, including
normal replacements of older generating units with new units, changes in the electricity
intensity of the U.S. economy, growth and regional changes in the U.S. population,
technological improvements in electricity generation from both existing and new units, changes
in the prices and availability of different fuels, and substantial growth in electricity generation
by renewable and unconventional methods. Many of these trends will continue to contribute to
the evolution of the power sector. The evolving economics of the power sector, in particular
the increased natural gas supply and subsequent relatively low natural gas prices, have resulted
in more gas being utilized as base load energy in addition to supplying electricity during peak
load. This chapter presents data on the evolution of the power sector from 2002 through 2012.
Projections of new capacity and the impact of this rule on these new sources are discussed in
more detail in Chapter 4 of this Regulatory Impact Assessment (RIA).
2.2 Power Sector Overview
The production and delivery of electricity to customers consists of three distinct
segments: generation, transmission, and distribution.
2.2.1 Generation
Electricity generation is the first process in the delivery of electricity to consumers.
There are two important aspects of electricity generation: capacity and net generation.
Generating capacity refers to the maximum amount of production from an ECU in a typical
hour, typically measured in megawatts (MW) or gigawatts (1 GW = 1,000 MW). Electricity
generation refers to the amount of electricity actually produced by EGUs, measured in kilowatt-
2-1
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hours (kWh) or gigawatt-hours (GWh = 1 million kWh). In addition to producing electricity for
sale to the grid, generators perform other services important to reliable electricity supply, such
as providing backup generating capacity in the event of unexpected changes in demand or
unexpected changes in the availability of other generators. Other important services provided
by generators include facilitating the regulation of the voltage of supplied generation.
Individual EGUs are not used to generate electricity 100 percent of the time. Individual
EGUs are periodically not needed to meet the regular daily and seasonal fluctuations of
electricity demand. Furthermore, EGUs relying on renewable resources such as wind, sunlight,
and surface water to generate electricity are routinely constrained by the availability of
adequate wind, sunlight, or water at different times of the day and season. Units are also
unavailable during routine and unanticipated outages for maintenance. These factors result in
the mix of generating capacity types available (i.e., the share of capacity of each type of ECU)
being substantially different than the mix of the share of total electricity produced by each type
of ECU in a given season or year.
Most of the existing capacity generates electricity by creating heat to generate high
pressure steam that is released to rotate turbines which, in turn, create electricity. Natural gas
combined cycle (NGCC) units have two generating components operating from a single source
of heat. The first cycle is a gas-fired turbine, which generates electricity directly from the heat
of burning natural gas. The second cycle reuses the waste heat from the first cycle to generate
steam, which is then used to generate electricity from a steam turbine. Other EGUs generate
electricity by using water or wind to rotate turbine, and a variety of other methods also make
up a small, but growing, share of the overall electricity supply. The generating capacity includes
fossil-fuel-fired units, nuclear units, and hydroelectric and other renewable sources (see Table
2-1). Table 2-1 also shows the comparison between the generating capacity in 2002 and 2012.
In 2012, the power sector consisted of over 19,000 generating units with a total
capacity1 of 1,168 GW, an increase of 188 GW (or 19 percent) from the capacity in 2002 (980
1 As with all data presented in this section, this includes generating capacity not only at EGUs primarily operated to
supply electricity to the grid, but also generating capacity at commercial and industrial facilities that produce
both electricity used onsite as well as dispatched to the grid. Unless otherwise indicated, capacity data
presented in this RIA is installed nameplate capacity (also known as nominal capacity), defined by EIA as "The
maximum rated output of a generator, prime mover, or other electric power production equipment under
specific conditions designated by the manufacturer." Nameplate capacity is consistently reported to regulatory
authorities with a common definition, where alternate measures of capacity (e.g., net summer capacity and net
winter capacity) can use a variety of definitions and specified conditions.
2-2
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GW). The 188 GW increase consisted primarily of natural gas fired EGUs (134 GW) and wind
generators (55 GW), with substantially smaller net increases and decreases in other types of
generating units.
Table 2-1. Existing Electricity Generating Capacity by Energy Source, 2002 and 2012
Energy Source
Coal
Natural Gas1
Nuclear
Hydro
Petroleum
Wind
Other Renewable
Misc
Total
2002
Generator
Nameplate
Capacity
(MW)
338,199
352,128
104,933
96,344
66,219
4,531
14,208
3,023
979,585
% Total
Capacity
35%
36%
11%
10%
7%
0.5%
1.5%
0.3%
100%
2012
Generator
Nameplate
Capacity
(MW)
336,341
485,957
107,938
99,099
53,789
59,629
20,986
4,257
1,167,995
% Total
Capacity
29%
42%
9%
8%
5%
5.1%
1.8%
0.4%
100%
Change
%
Increase
-1%
38%
3%
3%
-19%
1216%
47.7%
40.8%
19%
Between '02 and '12
Nameplate
Capacity
Change
(MW)
-1,858
133,829
3,005
2,755
-12,430
55,098
6,778
1,234
188,410
% of Total
Capacity
Increase
-1%
71%
2%
1%
-7%
29%
3.6%
0.7%
100%
Note: This table presents generation capacity. Actual net generation is presented in Table 2-2.
Source: U.S. EIA Electric Power Annual, 2014. Downloaded from EIA Electricity Data Browser, Electric Power Plants
Generating Capacity By Source, 2000 - 2013. Available at http://www.eia.gov/electricity/data.cfmtfgencapacity.
1 Natural Gas information in this chapter (unless otherwise stated) reflects data for all generating units using
natural gas as the primary fossil heat source. This includes Combined Cycle Combustion Turbine (31 percent of
2012 NG-fired capacity), Gas Turbine (30 percent), Combined Cycle Steam (19 percent), Steam Turbine (17
percent), and miscellaneous (< 1 percent).
The 19 percent increase in generating capacity is the net impact of newly built
generating units, retirements of generating units, and a variety of increases and decreases to
the nameplate capacity of individual existing units due to changes in operating equipment,
changes in emission controls, etc. During the period 2002 to 2012, a total of 315,752 MW of
new generating capacity was built and brought online, and 64,763 MW existing units were
retired. The net effect of the re-rating of existing units reduced the total capacity by 62,579
MW. The overall net change in capacity was 188,410 MW, as shown in Table 2-1.
The newly built generating capacity was primarily natural gas (226,605 MW), which was
partially offset by gas retirements (29,859 MW). Wind capacity was the second largest type of
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new builds (55,583 MW), augmented by 2,807 MW of solar.2 The overall mix of newly built and
retired capacity, along with the net effect, is shown on Figure 2-1.
350,000
300,000
250,000
200,000
New Build
Retirement
Net Change
-50,000
ICoal Nat Gas BWind& Solar mO\\& Other
Figure 2-1. New Build and Retired Capacity (MW) by Fuel Type, 2002-2012
Source: EIA Form 860
Not displayed: wind and solar retirements = 87 MW, net change in coal capacity = -56 MW
In 2012, electric generating sources produced a net 4,048 trillion kWh to meet electricity
demand, a 5 percent increase from 2002 (3,858 trillion kWh). As presented in Table 2-2, almost
70 percent of electricity in 2012 was produced through the combustion of fossil fuels, primarily
coal and natural gas, with coal accounting for the largest single share. Although the share of the
total generation from fossil fuels in 2012 (67 percent) was only modestly smaller than the total
fossil share in 2002 (71 percent), the mix of fossil fuel generation changed substantially during
that period. Coal generation declined by 22 percent and petroleum generation by 75 percent,
while natural gas generation increased by 77 percent. This reflects both the increase in natural
gas capacity during that period as well as an increase in the utilization of new and existing gas
EGUs during that period. Wind generation also grew from a very small portion of the overall
total in 2002 to 3.5 percent of the 2012 total.
'• Partially offset by 87 MW retired wind or solar capacity.
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Table 2-2. Net Generation in 2002 and 2012 (Trillion kWh = TWh)
2002
2012
Change Between '02 and '12
Coal
Natural Gas
Nuclear
Hydro
Petroleum
Wind
Other Renewable
Misc
Total
Net
Generation
(TWh)
1,933.1
702.5
780.1
255.6
94.6
10.4
68.8
13.5
3,858
Fuel
Source
Share
50%
18%
20%
7%
2.5%
0.3%
1.8%
0.4%
100%
Net
Generation
(TWh)
1,514.0
1,237.8
769.3
271.3
23.2
140.8
77.5
12.4
4,046
Fuel Source
Share
37%
31%
19%
7%
0.6%
3.5%
1.9%
0.3%
100%
Net
Generation
Change
(TWh)
-419.1
535.3
-10.7
15.7
-71.4
130.5
8.8
-1.2
188
% Change in
Net
Generation
-21.7%
76.2%
-1.4%
6.1%
-75.5%
1260.0%
12.7%
-8.7%
5%
Source: U.S. EIA Monthly Energy Review, July 2014. Table 7.2a Electricity Net Generation: Total (All Sectors).
Available at http://www.eia.gov/totalenergy/data/monthlv/. Accessed 7/29/2015
Coal-fired and nuclear generating units have historically supplied "base load" electricity,
the portion of electricity loads which are continually present, and typically operate throughout
all hours of the year. The coal units meet the part of demand that is relatively constant.
Although much of the coal fleet operates as base load, there can be notable differences across
various facilities (see Table 2-3). For example, coal-fired units less than 100 megawatts (MW) in
size compose 37 percent of the total number of coal-fired units, but only 6 percent of total coal-
fired capacity. Gas-fired generation is better able to vary output and is the primary option used
to meet the variable portion of the electricity load and has historically supplied "peak" and
"intermediate" power, when there is increased demand for electricity (for example, when
businesses operate throughout the day or when people return home from work and run
appliances and heating/air-conditioning), versus late at night or very early in the morning, when
demand for electricity is reduced.
Table 2-3 also shows comparable data for the capacity and age distribution of natural
gas units. Compared with the fleet of coal EGUs, the natural gas fleet is generally smaller and
newer. While 55 percent of the coal ECU fleet is over 500 MW per unit, 77 percent of the gas
fleet is between 50 and 500 MW per unit. Many of the largest gas units are gas-fired steam-
generating EGUs.
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Table 2-3. Coal and Natural Gas Generating Units, by Size, Age, Capacity,
and Thermal Efficiency (Heat Rate)
Unit Size
Grouping
(MW)
No.
Units
% of All
Units
Avg.
Age
Avg. Net
Summer
Capacity
(MW)
Total Net
Summer Avg. Heat
Capacity % Total Rate
(MW) Capacity (Btu/kWh)
COAL
0-24
25-49
50-99
100 - 149
150 - 249
250-499
500 - 749
750-999
1000 - 1500
Total Coal
223
108
157
128
181
205
187
57
11
1257
18%
9%
12%
10%
14%
16%
15%
5%
1%
100%
40.7
44.2
49.0
50.6
48.7
38.4
35.4
31.4
35.7
42.6
11.4
36.7
74.1
122.7
190.4
356.2
604.6
823.9
1259.1
250.7
2,538
3,963
11,627
15,710
34,454
73,030
113,056
46,963
13,850
315,191
1%
1%
4%
5%
11%
23%
36%
15%
4%
100%
11,733
11,990
11,883
10,971
10,620
10,502
10,231
9,942
9,732
11,013
NATURAL GAS
0-24
25-49
50-99
100 - 149
150 - 249
250-499
500 - 749
750 - 1000
Total Gas
1992
410
962
802
167
982
37
14
5366
37%
8%
18%
15%
3%
18%
1%
0.3%
100%
37.6
21.8
15.6
23.4
28.7
24.6
40.0
35.9
27.7
7.0
125.0
174.2
39.9
342.4
71.1
588.8
820.9
79.2
13,863
51,247
167,536
31,982
57,179
69,788
21,785
11,492
424,872
3%
12%
39%
8%
13%
16%
5%
3%
100%
13,531
9,690
8,489
11,765
9,311
12,083
11,569
10,478
11,652
Source: National Electric Energy Data System (NEEDS) v.5.14
Note: The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed to
a generation-weighted or capacity-weighted average heat rate.) A lower heat rate indicates a higher level of fuel
efficiency. Table is limited to coal-steam units in operation in 2013 or earlier, and excludes those units in NEEDS
with planned retirements in 2014 or 2015.
In terms of the age of the generating units, 50 percent of the total coal generating
capacity has been in service for more than 38 years, while 50 percent of the natural gas
capacity has been in service less than 15 years. Figure 2-2 presents the cumulative age
distributions of the coal and gas fleets, highlighting the pronounced differences in the ages of
the fleets of these two types of fossil-fuel generating capacity. Figure 2-2 also includes the
distribution of generation.
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9O%
SOS
"~
_^x^^
30 40
Age of EGU (years)
- Gas Cap ...... Gas Gen
Figure 2-2. Cumulative Distribution in 2010 of Coal and Natural Gas Electricity Capacity and
Generation, by Age
Source: National Electric Energy Data System (NEEDS) v.5.13
Not displayed: coal units (376 MW total, 1 percent of total) and gas units (62 MW, < .01 percent of total)) over 70
years old for clarity. Figure is limited to coal-steam units in NEEDS v.5.13 in operation in 2013 or earlier (excludes
~2,100 MW of coal-fired IGCC and fossil waste capacity), and excludes those units in NEEDS with planned
retirements in 2014 or 2015.
The locations of existing fossil units in the EPA's National Electric Energy Data System
(NEEDS) v.5.13 are shown in Figure 2-3.
2-7
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^Facility Capacity (MW)
010100
• 10010500
• 500101.000
• 1.000102,000
• 2.000 to 3.700
Figure 2-3. Fossil Fuel-Fired Electricity Generating Facilities, by Size
Source: National Electric Energy Data System (NEEDS) v.5.13
Note: This map displays fossil capacity at facilities in the NEEDS v.5.13 IPM frame. NEEDS v.5.13 reflects
generating capacity expected to be online at the end of 2015. This includes planned new builds already under
construction and planned retirements. In areas with a dense concentration of facilities, some facilities may be
obscured.
2.2.2 Transmission
Transmission is the term used to describe the bulk transfer of electricity over a network
of high voltage lines, from electric generators to substations where power is stepped down for
local distribution. In the U.S. and Canada, there are three separate interconnected networks of
high voltage transmission lines,3 each operating synchronously. Within each of these
transmission networks, there are multiple areas where the operation of power plants is
monitored and controlled to ensure that electricity generation and load are kept in balance. In
some areas, the operation of the transmission system is under the control of a single regional
3 These three network interconnections are the Western Interconnection, comprising the western parts of both the
U.S. and Canada (approximately the area to the west of the Rocky Mountains), the Eastern Interconnection,
comprising the eastern parts of both the U.S. and Canada (except those part of eastern Canada that are in the
Quebec Interconnection), and the Electric Reliability Council of Texas (ERCOT) Interconnection, comprising
most of Texas. See map of all NERC interconnections at
http://www.nerc.eom/AboutNERC/keyplayers/Documents/N ERC_lnterconnections_Color_072512.jpg
2-8
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operator. In others, individual utilities coordinate the operation of their generation,
transmission, and distribution systems to balance their common generation and load needs.
2.2.3 Distribution
Distribution of electricity involves networks of lower voltage lines and substations that
take the higher voltage power from the transmission system and step it down to lower voltage
levels to match the needs of customers. The transmission and distribution system is the classic
example of a natural monopoly, in part because it is not practical to have more than one set of
lines running from the electricity generating sources to substations or from substations to
residences and businesses.
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. Historically, the transmission system had been developed by
vertically integrated utilities, establishing much of the existing transmission infrastructure.
However, as parts of the country have restructured the industry, transmission infrastructure
has also been developed by transmission utilities, electric cooperatives, and merchant
transmission companies, among others. Distribution, also historically developed by vertically
integrated utilities, is now often managed by a number of utilities that purchase and sell
electricity, but do not generate it. As discussed below, electricity restructuring has focused
primarily on efforts to reorganize the industry to encourage competition in the generation
segment of the industry, including ensuring open access of generation to the transmission and
distribution services needed to deliver power to consumers. In many states, such efforts have
also included separating generation assets from transmission and distribution assets to form
distinct economic entities. Transmission and distribution remain price-regulated throughout the
country based on the cost of service.
2.3 Sales, Expenses, and Prices
These electric generating sources provide electricity for ultimate commercial, industrial,
and residential customers. Each of the three major categories of ultimate customers consume
roughly a quarter to a third of the total electricity produced4 (see Table 2-4). Some of these uses
are highly variable, such as heating and air conditioning in residential and commercial buildings,
4 Transportation (primarily urban and regional electrical trains) is a fourth ultimate customer category which
accounts less than one percent of electricity consumption.
2-9
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while others are relatively constant, such as industrial processes that operate 24 hours a day.
The distribution between the end use categories changed very little between 2002 and 2012.
Table 2-4. Total U.S. Electric Power Industry Retail Sales in 2012 (billion kWh)
Sales
Residential
Commercial
Industrial
Transportation
Other
Total
Direct Use
Total End Use
2002
Sales/Direct
Use (Billion Share of Total
kWh)
1,265
1,104
990
NA
106
3,465
166
3,632
End Use
35%
30%
27%
-
3%
95%
5%
100%
2012
Sales/Direct
Use (Billion
kWh)
1,375
1,327
986
7
NA
3,695
138
3,832
Share of Total End
Use
35.9%
34.6%
25.7%
0.2%
-
96%
4%
100%
Source: Table 2.2, EIA Electric Power Annual, 2013
Notes:
Retail sales are not equal to net generation (Table 2-2) because net generation includes net exported electricity
and loss of electricity that occurs through transmission and distribution.
Direct Use represents commercial and industrial facility use of onsite net electricity generation; and electricity
sales or transfers to adjacent or co-located facilities for which revenue information is not available.
2.3.1 Electricity Prices
Electricity prices vary substantially across the United States, differing both between the
ultimate customer categories and also by state and region of the country. Electricity prices are
typically highest for residential and commercial customers because of the relatively high costs
of distributing electricity to individual homes and commercial establishments. The high prices
for residential and commercial customers are the result both of the necessary extensive
distribution network reaching to virtually every part of the country and every building, and also
the fact that generating stations are increasingly located relatively far from population centers,
which increases transmission costs. Industrial customers generally pay the lowest average
prices, reflecting both their proximity to generating stations and the fact that industrial
customers receive electricity at higher voltages, which makes transmission more efficient and
less expensive). Industrial customers frequently pay variable prices for electricity by the season
and time of day, while residential and commercial prices historically have been less variable.
Overall industrial customer prices are usually considerably closer to the wholesale marginal cost
of generating electricity than residential and commercial prices.
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On a state-by-state basis, all retail electricity prices vary considerably. In 2011 the
national average retail electricity price (all sectors) was 9.90 cents/KWh, with a range from 6.44
cents (Idaho) to 31.59 cents (Hawaii). The Northeast, California, and Alaska have average retail
prices that can be as much as double those of other states (see Figure 2-4), and Hawaii has the
most expensive retail price of electricity in the country.
Average Price (cents per kilowatthour)
| | 6.44 - 7.80
j^|7.88-878
| | 8.80-9 39
| | 9.61 - 12.81
~| 13.04-31.59
Note: Data are displayed as 5 groups of 10 States and the District of Columbia.
U.S. total average price per kilowatthour is 9.90cents.
Source: U.S. Energy Information Administration, Annual Energy Review -
Electricity Section, Table 4, September 27,2012.
Figure 2-4. Average Retail Electricity Price by State (cents/kWh), 2011
Average national retail electricity prices increased between 2002 and 2012 by 36.7
percent in nominal (current year $) terms. The amount of increase differed for the three major
end use categories (residential, commercial and industrial). National average residential prices
increased the most (40.8 percent), and commercial prices increased the least (27.9 percent).
The nominal year prices for 2002 through 2012 are shown in Figure 2-5.
2-11
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14.0
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
^^^— Residential ^^^— Commercial ^^^— Industrial — — Total
Figure 2-5. Nominal National Average Electricity Prices for Three Major End-Use Categories
Source: EIA AEO 2012, Table 2.4
Electricity prices for all three end-use categories increased more than overall inflation
through this period, measured by either the Gross Domestic Product (GDP) implicit price
deflator (23.5 percent) or the consumer price index (CPI-U, which increased by 27.7 percent)5.
Most of these electricity price increases occurred between 2002 and 2008. Since 2008 nominal
electricity prices have been relatively stable while overall inflation continued to increase. The
increase in nominal electricity prices for the major end use categories, as well as increases in
the GDP price and CPI-U indices for comparison, are shown in Figure 2-6.
5 Source: Federal Reserve Economic Data, FRB St. Louis. Available at http://research.stlouisfed.org/fred2/.
2-12
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45%
2OO2
• Residential
2004 2006
— Commercial ^^^
2008
• Industrial •••
201O
CPI-U
2012
• GDP Price
Figure 2-6. Relative Increases in Nominal National Average Electricity Prices for Major End-
Use Categories, with Inflation Indices
The real (inflation-adjusted) change in average national electricity prices can be
calculated using the GDP implicit price deflator. Figure 2-7 shows real6 (2011$) electricity prices
for the three major customer categories from 1960 to 2012, and Figure 2-8 shows the relative
change in real electricity prices relative to the prices in 1960. As can be seen in the figures, the
price for industrial customers has always been lower than for either residential or commercial
customers, but the industrial price has been more volatile. While the industrial real price of
electricity in 2012 was relatively unchanged from 1960, residential and commercial real prices
are 23 percent and 28 percent lower respectively than in 1960.
6 All prices in this section are estimated as real 2011 prices adjusted using the GDP implicit price deflator unless
otherwise indicated.
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Real Electricity Prices, 1960-2014 (including taxes)
I960 1970
— Residential
1980 1990 2000
• Commercial ^^^— Industrial
2010
Figure 2-7. Real National Average Electricity Prices (2011$) for Three Major End-Use
Categories
Source: EIA Monthly Energy Review, April 2015, Table 9.8
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Relative Change in Electricity Prices,
1960-2014 (including taxes)
60%
-50%
1960
1970
• Residential
1980
• Commercial
1990
2000
• Industrial
2010
• Total
Figure 2-8. Relative Change in Real National Average Electricity Prices (2011$) for Three
Major End-Use Categories
Source: EIA Monthly Energy Review, April 2015, Table 9.8
2.3.2 Prices of Fossil Fuels Used for Generating Electricity
Another important factor in the changes in electricity prices are the changes in fuel
prices for the three major fossil fuels used in electricity generation: coal, natural gas and oil.
Relative to real prices in 2002, the national average real price (in 2011$) of coal delivered to
EGUs in 2012 had increased by 54 percent, while the real price of natural gas decreased by 22
percent. The real price of oil increased by 203 percent, but with oil declining as an ECU fuel (in
2012 oil generated only 1 percent of electricity) the doubling of oil prices had little overall
impact in the electricity market. The combined real delivered price of all fossil fuels in 2012
increased by 23 percent over 2002 prices. Figure 2-9 shows the relative changes in real price of
all three fossil fuels between 2002 and 2012.
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-50%
2002
2004
^—Coal
2006
— Oil
2008
•Gas
2010
• Average
2012
Figure 2-9. Relative Real Prices of Fossil Fuels for Electricity Generation and Change in
National Average Real Price per MBtu Delivered to ECU
Source: EIA AEO 2012, Table 9.9
2.3.3 Changes in Electricity Intensity of the U.S. Economy Between 2002 to 2012
An important aspect of the changes in electricity generation (i.e., electricity demand)
between 2002 and 2012 is that while total net generation increased by 4.9 percent over that
period, the demand growth for generation has been low, and in fact was lower than both the
population growth (9.2 percent) and real GDP growth (19.8 percent). Figure 2-10 shows the
growth of electricity generation, population and real GDP during this period.
2-16
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25%
20%
15%
10%
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Real GDP Population Generation
Figure 2-10. Relative Growth of Electricity Generation, Population, and Real GDP Since 2002
Sources: U.S. EIA Monthly Energy Review, December 2014. Table 7.2a Electricity Net Generation: Total (All
Sectors). U.S. Census.
Because demand for electricity generation grew more slowly than both the population
and GDP, the relative electric intensity of the U.S. economy improved (i.e., less electricity used
per person and per real dollar of output) during 2002 to 2012. On a per capita basis, real GDP
per capita grew by 10.9 percent, increasing from $44,900 (in 2011$) per person in 2002 to
$49,800 per person in 2012. At the same time electricity generation per capita decreased by 3.9
percent, declining from 13.4 MWh per person in 2002 to 12.8 MWh per person in 2012. The
combined effect of these two changes improved the overall electricity efficiency of the U.S.
economy. Electricity generation per dollar of real GDP decreased 12.5 percent, declining from
299 MWh per $1 million of GDP to 261 MWh per $1 million GDP. These relative changes are
shown in Figure 2-11. Figures 2-10 and 2-11 clearly show the effects of the 2007 - 2009
recession on both GDP and electricity generation, as well as the effects of the subsequent
economic recovery.
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-15%
2002 2003 2004 2005
Real GDP/Capita
2006 2007 2008 2009 2010 2011
—Generation/Capita Generation/ Real GDP
2012
Figure 2-11. Relative Change of Real GDP, Population, and Electricity Generation Intensity
Since 2002
Sources: U.S. EIA Monthly Energy Review, December 2014. Table 7.2a Electricity Net Generation: Total (All
Sectors). U.S. Census
2.4 Deregulation and Restructuring
The process of restructuring and deregulation of wholesale and retail electric markets
has changed the structure of the electric power industry. In addition to reorganizing asset
management between companies, restructuring sought a functional unbundling of the
generation, transmission, distribution, and ancillary services the power sector has historically
provided, with the aim of enhancing competition in the generation segment of the industry.
Beginning in the 1970s, government policy shifted against traditional regulatory
approaches and in favor of deregulation for many important industries, including
transportation (notably commercial airlines), communications, and energy, which were all
thought to be natural monopolies (prior to 1970) that warranted governmental control of
pricing. However, deregulation efforts in the power sector were most active during the 1990s.
Some of the primary drivers for deregulation of electric power included the desire for more
efficient investment choices, the economic incentive to provide least-cost electric rates through
market competition, reduced costs of combustion turbine technology that opened the door for
more companies to sell power with smaller investments, and complexity of monitoring utilities'
cost of service and establishing cost-based rates for various customer classes. Deregulation and
market restructuring in the power sector involved the divestiture of generation from utilities,
the formation of organized wholesale spot energy markets with economic mechanisms for the
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rationing of scarce transmission resources during periods of peak demand, the introduction of
retail choice programs, and the establishment of new forms of market oversight and
coordination.
The pace of restructuring in the electric power industry slowed significantly in response
to market volatility in California and financial turmoil associated with bankruptcy filings of key
energy companies. By the end of 2001, restructuring had either been delayed or suspended in
eight states that previously enacted legislation or issued regulatory orders for its
implementation (shown as "Suspended" in Figure 2-12). Eighteen other states that had
seriously explored the possibility of deregulation in 2000 reported no legislative or regulatory
activity in 2001 (EIA, 2003) ("Not Active" in Figure 2-12). Currently, there are 15 states plus the
District of Columbia where price deregulation of generation (restructuring) has occurred
("Active" in Figure 2-12). Power sector restructuring is more or less at a standstill; by 2010 there
were no active proposals under review by the Federal Energy Regulatory Commission (FERC) for
actions aimed at wider restructuring, and no additional states have begun retail deregulation
activity since that time.
Electricity Restructuring by State
Figure 2-12. Status of State Electricity Industry Restructuring Activities
Source: EIA 2010. "Status of Electricity Restructuring by State." Available online at:
http://www.eia.gov/cneaf/electricity/page/restructuring/restructure elect.html.
One major effect of the restructuring and deregulation of the power sector was a
significant change in type of ownership of electricity generating units in the states that
deregulated prices. Throughout most of the 20th century, electricity was supplied by vertically
2-19
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integrated regulated utilities. The traditional integrated utilities controlled generation,
transmission, and distribution in their designated areas, and prices were set by cost of service
regulations set by state government agencies (e.g., Public Utility Commissions). Deregulation
and restructuring resulted in unbundling of the vertical integration structure. Transmission and
distribution continued to operate as monopolies with cost of service regulation, while
generation shifted to a mix of ownership affiliates of traditional utility ownership and some
generation owned and operated by competitive companies known as Independent Power
Producers (IPP). The resulting generating sector differed by state or region, as the power sector
adapted to the restructuring and deregulation requirements in each state.
By 2002, the major impacts of adapting to changes brought about by deregulation and
restructuring during the 1990s were largely in place. The resulting ownership mix of generating
capacity (MW) in 2002 was 62 percent of the generating capacity owned by traditional utilities,
35 percent owned by IPPs,7 and 3 percent owned by commercial and industrial producers. The
mix of electricity generated (MWh) was more heavily weighted towards the utilities, with a
distribution in 2002 of 66 percent, 30 percent, and 4 percent for utilities, IPPs and
commercial/industrial, respectively.
Since 2002 IPPs have expanded faster than traditional utilities, substantially increasing
their share by 2012 of both capacity (58 percent utility, 39 percent IPPs, and 3 percent
commercial/industrial) and generation (58 percent, 38 percent, and 4 percent).
The mix of capacity and generation in 2002 and 2012 for each of the ownership types is
shown in Figures 2-13 (capacity) and 2-14 (generation). The capacity and generation data for
commercial and industrial owners are not shown on these figures due to the small magnitude
of those ownership types. A portion of the shift of capacity and generation is due to sales and
transfers of generation assets from traditional utilities to IPPs, rather than strictly the result of
newly built units.
7 IPP data presented in this section include both combined and non-combined heat and power plants.
2-20
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Capacity Mix, 2002 & 2012
700,000
600,000
^500,000
1400,000
i
I 300,000
L
;
200,000
100,000
Generation Mix, 2002 & 2012
3,000,000
2,500,000
II „
& V V V
I Nuclear BCoal Gas • Hydro BWind IAN Other
Nuclear BCoal Gas • Hydro BWind • All Other
Figures 2-13 & 2-14. Capacity and Generation Mix by Ownership Type, 2002 & 2012
Capacity Built 2002-2012
by Ownership Type
I Coal
Utility IPP
IGas Wind & Solar BOther
Capacity Retirements 2002-2012
by Ownership Type
35,000
30,000
25,000
Utility IPP
ICoal BGas Wind & Solar HOther
Figures 2-15 and 2-16. Generation Capacity Built and Retired between 2002 and 2012 by
Ownership Type
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The mix of capacity by fuel types that have been built and retired between 2002 and
2012 also varies significantly by type of ownership. Figure 2-15 presents the new capacity built
during that period, showing that IPPs built the majority of both new wind and solar generating
capacity, as well as somewhat more natural gas capacity than the traditional utilities built.
Figure 2-16 presents comparable data for the retired capacity, showing that utilities retired
more coal and "other" capacity (mostly oil-fired) than IPPs retired, while the IPPs retired more
natural gas capacity than the utilities retired. The retired gas capacity was primarily (60
percent) steam and combustion turbines.
2.5 Emissions of Greenhouse Gases from Electric Utilities
The burning of fossil fuels, which generates about 69 percent of our electricity
nationwide, results in emissions of greenhouse gases. The power sector is a major contributor
of C02 in particular, but also contributes to emissions of sulfur hexafluoride (SFe), methane
(ChU), and nitrous oxide (INhO). In 2013, the electricity generation accounted for 38 percent of
national CCh emissions. Including both generation and transmission (a source of SFe), the power
sector accounted for 31 percent of total nationwide greenhouse gas emissions, measured in
CCh equivalent. Table 2-5 and Figure 2-17 show the GHG emissions8 from the power sector
relative to other major economic sectors. Table 2-6 shows the contributions of CCh and other
GHGs from the power sector and other major emitting economic sectors.
5 COz equivalent data in this section are calculated with the IPCCSAR (Second Assessment Report) GWP potential
factors.
2-22
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Table 2-5. Domestic Emissions of Greenhouse Gases, by Economic Sector (million tons of
equivalent)
2002
2013
Change Between '02 and '13
Sector/Source
Electric Power Industry
Transportation
Industry
Agriculture
Commercial
Residential
U.S. Territories
Total GHG Emissions
Sinks and Reductions
Net GHG Emissions
GHG
Emissions
2,550
2,158
1,564
618
402
412
58
7,762
% Total
GHG
Emissions
33%
28%
20%
8%
5%
5%
<1%
100%
-976
6,786
GHG
Emissions
2,289
1,991
1,535
647
442
413
38
7,356
% Total
GHG
Emissions
31%
27%
21%
9%
6%
6%
<1%
100%
-972
6,384
Change in
Emissions
-260
-167
-29
29
40
1
-19
-406
4
-402
% Change
in
Emissions
-10%
-8%
-2%
5%
10%
0%
-33%
-5%
0%
-6%
% of Total
Change in
Emissions
64%
41%
7%
-7%
-10%
0%
5%
100%
Source: EPA, 2015 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013", Table 2-12. Includes CO2,
CH4, INhO and SFs emissions.
2002 2013
I Electric Power Industry • Transportation • Industry
(Agriculture • Commercial • Residential
Figure 2-17. Domestic Emissions of Greenhouse Gases from Major Sectors, 2002 and 2013
(million tons of COz equivalent)
Source: EPA, 2015 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013", Table 2-12
Not Shown: CChe emissions from U.S. Territories.
2-23
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The amount of CO2 emitted during the combustion of fossil fuels varies according to the
carbon content and heating value of the fuel used. The CCh emission factors used in IPM v5.14
(same as used in v5.13) are shown in Table 2-7. Coal has higher carbon content than oil or
natural gas, and thus releases more CCh during combustion. Coal emits about 1.7 times as
much carbon per unit of energy when burned as natural gas does (EPA 2013).
Table 2-6. Greenhouse Gas Emissions from the Electricity Sector (Generation, Transmission
and Distribution), 2002 and 2013 (million tons of COz equivalent)
Gas/Fuel Type or Source
C02
CH4
N2O
SF6
Fossil Fuel Combustion
Coal
Natural Gas
Petroleum
Geothermal
Incineration of Waste
Other Process Uses of
Carbonates
Stationary
Combustion*
Incineration of Waste
Stationary
Combustion*
Incineration of Waste
Electrical Transmission
and Distribution
Total GHG Emissions
2002
GHG
Emissions
2,521
2,505
2,083
337
84.7
0.4
13.0
2.9
0.4
0.4
+
13.7
13.2
0.4
14.7
14.7
% of Total
GHG
Emissions
from Power
Sector
98.9%
98.2%
81.7%
13.22%
3.32%
0.02%
0.51%
0.11%
0.02%
0.02%
0.54%
0.52%
0.02%
0.57%
0.57%
2,550
2013
GHG
Emissions
2,262
2,248
1,736
487
24.7
0.4
11.1
2.4
0.4
0.4
+
21.4
21.1
0.3
5.6
5.6
% of Total
GHG
Emissions
from Power
Sector
98.8%
98.2%
75.8%
21.28%
1.08%
0.02%
0.49%
0.11%
0.02%
0.02%
0.93%
0.92%
0.01%
0.25%
0.25%
2,289
Change Between '02 and
'13
Change in
GHG
Emissions
-259
-257
-347
150
-60.0
0.0
-1.9
-0.4
0.0
0.0
7.7
7.8
-0.1
-9.0
-9.0
% Change
in
Emissions
-10%
-10%
-17%
45%
-71%
0%
-14%
-15%
0%
0%
56%
59%
-25%
-62%
-62%
-260
Source: EPA, 2015 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013", Table 2-11
* Includes only stationary combustion emissions related to the generation of electricity.
** SFs is not covered by this rule, which specifically regulates CCb emissions from combustion.
+ Does not exceed 0.05 Tg CCh Eq. or 0.05 percent.
2-24
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Table 2-7. Fossil Fuel Emission Factors in the EPA Base Case 5.14 IPM Power Sector
Modeling Application
Fuel Type Carbon Dioxide (Ib/MMBtu)
Coal
Bituminous 202.8-209.6
Subbituminous 209.2-215.8
Lignite 212.6-219.
Natural Gas 117.1
Fuel Oil
Distillate 161.4
Residual 161.4-173.9
Biomass 195
Waste Fuels
Waste Coal 204.7
Petroleum Coke 225.1
Fossil Waste 321.1
Non-Fossil Waste 0
Tires 189.5
Municipal Solid Waste 91.9
Source: Documentation for IPM Base Case v.5.13, Table 11-5. The emission factors used in Base Case 5.14 are
identical to the emission factors in IPM Base Case 5.13.
Note: CCh emissions presented here for biomass account for combustion only and do not reflect emissions from
initial photosynthesis (carbon sink) or harvesting activities and transportation (carbon source).
2.6 Carbon Dioxide Control Technologies
In the power sector, current approaches available for significantly reducing the CCh
emissions of new fossil fuel combustion sources to meet a 1,400 Ib CCh/MWh emission rate
include the use of: (1) highly efficient coal-fired generation (e.g., modern supercritical or ultra-
supercritical steam units) with partial carbon capture and storage (CCS), (2) highly efficient coal-
fired designs (e.g., modern supercritical or ultra-supercritical steam units) with up to 40 percent
natural gas co-firing, (3), integrated coal gasification combined cycle (IGCC) co-firing with up to
10 percent natural gas, and/or (4) natural gas combined cycle (NGCC) combustion
turbine/steam-turbine units.
Investment decisions for the optimal choice of the type of new generating capacity
capable of meeting the 1,400 Ib CCh/MWh standard of performance depend in part on the
intended primary use of new generating capacity. Daily peak electricity demands, involving
operation for relatively few hours per year, are often most economically met by simple-cycle
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combustion turbines (CT). Stationary CTs used for power generation can be installed quickly, at
relatively low capital cost. They can be remotely started and loaded quickly, and can follow
rapid demand changes. Full-load efficiencies of large current technology CTs are typically 30-33
percent but can be has high as 40 percent or more (high heating value basis), as compared to
efficiencies of 50 percent or more for new combined-cycle units that recover and use the
exhaust heat otherwise wasted from a CT. A simple-cycle CT's lower efficiency causes it to burn
much more fuel to produce a MWh of electricity than a combined-cycle unit. Thus, when
burning natural gas its CCh emission rate per MWh could be 40-60 percent higher than a more
efficient NGCC unit.
Base load electricity demand can be met with NGCC generation, coal and other fossil-
fired steam generation, and IGCC technology, as well as generation from sources that do not
emit CCh, such as nuclear and hydro. IGCC employs the use of a gasifier to transform fossil fuels
into synthesis gas ("syngas") and heat. The syngas is used to fuel a combined cycle generator,
and the heat from the syngas conversion can produce steam for the steam turbine portion of
the combined cycle generator. Electricity can be generated through this IGCC process
somewhat more efficiently than through conventional boiler-steam generators. Additionally,
with gasification, some of the syngas can be converted into other marketable products such as
fertilizers and chemical feedstocks for processes to manufacture liquid hydrocarbons (e.g., fuels
and lubricants), and CCh can be captured for use in EOR. Figure 2-18 shows the array of
products (including electricity) and by-products that can be produced in a syngas process.
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Gasification
Facility
Slag for
Construction
Materials
Combined
Cyde
Chemical
Production
Fischer
Tropsch
Synthesis
Argon. Nitrogen. &
Oxygen
Carbon Dioxide
Sulfur / Sulfuric Acid
Sleam
Hot Water
Electricity
Hydrogen
Carbon Monoxide
Ammonia-based Fertilizer
Synthetic Natural Gas
Industrial Chemicals
Methanol / Ethanol
Naphtha
High Cetane Diesel
Jet Fuel
Wax
Figure 2-18. Marketable products from Syngas Generation
Source: National Energy Technology Lab. Gasifipedia. Available at http://www.netl.doe.gov/research/coal/energy-
systems/gasification/gasifipedia/co-generation
2.6.1 Carbon Capture and Storage
CCS can be achieved through either pre-combustion or post-combustion capture of CCh
from a gas stream associated with the fuel combusted. Furthermore, CCS can be designed and
operated for full capture of the C02 in the gas stream (i.e., above 90 percent) or for partial
capture (below 90 percent). Post-combustion capture processes remove C02 from the exhaust
gas of a combustion system - such as a utility boiler. It is referred to as "post-combustion
capture" because the C02 is the product of the combustion of the primary fuel and the capture
takes place after the combustion of that fuel. This process is illustrated for a pulverized coal
power plant in Figure 2-19 and described in more detail in the preamble. (See preamble section
V.D.) For post-combustion, a station's net generating output will be lower due to the energy
needs of the capture process.
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Flue Gas
Flue Gas
Volume %
CO; 12-14%
N2 -65%
H;>O ~18%
O2 -2%
15Psi/150cF
Ail-
Coal
C02 To Storage
Figure 2-19. Post-Combustion COz 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 syngas under heat and pressure and some percentage of the carbon contained
in the syngas is captured before combustion.9 For pre-combustion technology, a significant
amount of energy is needed to gasify the fuel(s). This process is illustrated in Figure 2-20.
Application of post-combustion CCS with IGCC can be designed to use no water-gas shift, or
single- or two-stage shift processes, to obtain varying percentages of CCh removal - from a
"partial capture" percentage to 90 percent "full capture." Pre-combustion CCS typically has a
lesser impact on net energy output than does post-combustion CCS. For more detail on CCS
technology, see the "Report of the Interagency Task Force on Carbon Capture and Storage"
(2010).10
9 Note that pre-combustion CCS is not considered the best system of emission reduction for this standard. This
information is provided for background purposes.
10 For more information on the cost and performance of CCS, see http://www.netl.doe.gov/energy-
analyses/baseline studies.html.
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Sulfur
Oxygen
Coa,
Power
Figure 2-20. Pre-Combustion CO2 Capture for an IGCC Power Plant
Source: Interagency Task Force on Carbon Capture and Storage 2010
Carbon capture technology has been successfully applied since 1930 on several smaller
scale industrial facilities and more recently in a number of demonstration phase projects
worldwide for power sector applications. In October 2014, the first commercial-scale coal-fired
capture and storage project for electricity generation began operation at the Boundary Dam
Power Station in Saskatchewan, Canada. The Boundary Dam Station is owned by the Province
of Saskatchewan, and operated by SaskPower, a provincially owned corporation that is the
primary electric utility in the Province. The commercial-scale demonstration project retrofit
Unit 3 (a 130 MW, coal fired built in 1970, and rebuilt in 2013) at a total cost of approximately
$1.5 billion (Canadian, or about $1.2 billion U.S.), including a partial subsidy of $240 million
(Canadian) by the Canadian federal government. The carbon capture system is a post-
combustion process designed to capture 90 percent of the CCh emitted by Unit #3. Retrofitting
the carbon capture system reduced the capacity of the unit to 110 M W. The majority of the
captured CCh is used for an enhanced oil recovery (EOR) project in southern Saskatchewan. The
portion of the CCh is being stored in a nearby research and monitoring geological storage
facility, where the captured CCh will be injected 3.4 kilometers underground into a sandstone
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formation located below the major coal field supplying lignite to Unit # 3. The remaining
captured CCh will be injected into deep saline formations.
In the United States there are two commercial-scale CCS facilities nearing completion:
1) the Kemper County Carbon Dioxide Capture and Storage Project in Mississippi, and
2) The W.A. Parish Petra Nova CCA Project near Houston, Texas.
Construction began on the Kemper project in 2010, and the startup is currently
scheduled for May 2016. The Kemper project is constructing a new 524 MW lignite unit as well
as a 58 MW natural gas unit. Mississippi Power (a division of Southern Power) is building and
will operate the Kemper project. The control system is designed to capture 65 percent of the
CCh generated by the plant, and is projected to capture 3.5 million tons of CCh per year. The
resulting CCh emission rate is expected to be approximately 800 pounds per MWh produced.
The current total cost estimate is $5.6 billion, a substantial increase from the original $2.4
billion estimate.11 The construction has received a $270 million grant from the U.S. Department
of Energy, and $133 million in investment tax credits from the Internal Revenue Service. The
captured CCh will be transported via a 60 mile pipeline and used for EOR projects in mature
Mississippi oil fields.12
The only other commercial-scale electricity power sector CCS project currently under
construction in the United States is the W.A. Parish Petra Nova CCS Project near Houston,
Texas. The Parish Petra project is a 50/50 partnership between NRG Energy (an integrated
electricity company generating and supplying electricity to 1.6 million customers in Texas) and
the Nippon Oil and Gas Exploration Company. The Parish project will retrofit a post-combustion
CCS system on a portion of the flue gas from the existing 610 MW coal fired Unit # 8. The CCS
system will treat a 240 MW slipstream of the flue gas, and is designed to capture 90 percent of
the CCh in the treated flue gas. The capacity rating of Unit # 8 will not be reduced due to the
CCS project because an 85 MW custom-built natural gas fired combustion turbine co-
generation unit is being built on-site to provide both electricity and steam to the CCS unit. The
11 The Mississippi Public Utilities Staff authorized an independent monitor to conduct a review of the project. The
findings of the review are provided in a summary report available at:
http://www.psc.state.ms.us/lnsiteConnect/lnSiteView.aspx7modehlNSITE CONNECT&queue=CTS ARCHIVEQ
&docid=328417
12 Carbon Capture and Sequestration Technologies Program at MIT. Accessed 1/23/2015.
https://sequestration. mit.edu/tools/projects/kemper. html
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total cost of the CCS project is estimated to be $1 billion (including a $167 million grant from
the U.S. Department of Energy), and the project is expected to extract 1.4 - 1.6 million tons of
CCh per year. The construction contract was awarded in July, 2014, and operation is expected
to begin in early 2016. The CCh will be piped 85 miles to a reservoir for EOR in the West Ranch
Oil Field.13
2.7 Geologic and Geographic Considerations for Geologic Sequestration
Geologic sequestration (GS) (i.e., long-term containment of a CCh stream in subsurface
geologic formations) is technically feasible and available throughout most of the United States.
(See generally preamble to final rule at sections V.M and N.) GS is feasible in different types of
geologic formations including deep saline formations (formations with high salinity formation
fluids) or in oil and gas formations, such as where injected CCh increases oil production
efficiency through EOR. C02 may also be used for other types of enhanced recovery, such as for
natural gas production. Reservoirs, such as unmineable coal seams, also offer the potential for
GS. The geographic availability of deep saline formations, EOR, and unmineable coal seams is
shown in Figure 2-21. Estimates of C02 storage resources by state compiled by the Department
of Energy's (DOE) National Carbon Sequestration Database and Geographic Information System
(NATCARB) and published in DOE's 2012 United States Carbon Utilization and Storage Atlas
(discussed below) are provided in Table 2-8.
13 U.S. DOE (2010) "Recovery Act: W.A. Parish Post-Combustion CO2 Capture and Sequestration Project".
http://www.netl. doe.gov/research/proj?k=FE0003311 Accessed 1/23/2015
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• Existing CO2 pipeline (Department of Transportation)
Probable, planned, or under study C02 pipeline
Counties with active C02-EOR operations (EPAGHG Reporting Program
Oil & Natural Gas Reservoirs (Department of Energy, NATCARB)
Deep Saline Formations (Department of Energy, NATCARB)
Unmineable Coal Seams (Department of Energy, NATCARB)
100 km from Geologic Sequestration
Figure 2-21 Geologic Sequestration in the Continental United States
Sources: EPA Greenhouse Gas Reporting Program; Department of Energy, NATCARB; Department of
Transportation, National Pipeline Management System.
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Table 2-8. Total COz Storage Resource (U.S. Department of Energy (DOE) National Energy
Technology Laboratory (NETL))14
Million Tons
State
Low Estimate
High Estimate
ALABAMA
ALASKA
ARIZONA
ARKANSAS
CALIFORNIA
COLORADO
CONNECTICUT
DELAWARE
DISTRICT OF COLUMBIA
FLORIDA
GEORGIA
HAWAII
IDAHO
ILLINOIS
INDIANA
IOWA
KANSAS
KENTUCKY
LOUISIANA
MAINE
MARYLAND
MASSACHUSETTS
135,022
9,524
143
6,812
37,357
41,458
not assessed by DOE-NETL
44
not assessed by DOE-NETL
113,251
160,210
not assessed by DOE-NETL
44
11,045
35,296
11
11,993
3,219
186,842
not assessed by DOE-NETL
2,050
not assessed by DOE-NETL
765,422
21,771
1,290
70,184
463,665
393,734
not assessed by DOE-NETL
44
not assessed by DOE-NETL
611,793
175,322
not assessed by DOE-NETL
430
128,772
75,189
55
95,173
8,433
2,319,238
not assessed by DOE-NETL
2,127
not assessed by DOE-NETL
(Continued on next page)
14 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of
Fossil Energy, National Energy Technology Laboratory (NETL).
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Table 2-8. Total CO2 Storage Resource (DOE-NETL), cont.
State
MICHIGAN
MINNESOTA
MISSISSIPPI
MISSOURI
MONTANA
NEBRASKA
NEVADA
NEW HAMPSHIRE
NEW JERSEY
NEW MEXICO
NEW YORK
NORTH CAROLINA
NORTH DAKOTA
Offshore Federal Only
OHIO
OKLAHOMA
OREGON
PENNSYLVANIA
RHODE ISLAND
SOUTH CAROLINA
SOUTH DAKOTA
TENNESSEE
TEXAS
UTAH
VERMONT
VIRGINIA
WASHINGTON
WEST VIRGINIA
WISCONSIN
WYOMING
U.S. Total
Million
Low Estimate
20,999
not assessed by DOE-NETL
159,846
11
93,233
26,202
not assessed by DOE-NETL
not assessed by DOE-NETL
0
47,135
5,115
1,477
73,954
539,956
14,837
62,777
7,507
24,361
not assessed by DOE-NETL
33,180
9,656
474
489,205
28,076
not assessed by DOE-NETL
485
40,367
18,353
not assessed by DOE-NETL
80,127
2,531,653
Tons*
High Estimate
52,040
not assessed by DOE-NETL
1,306,270
187
1,006,100
124,826
not assessed by DOE-NETL
not assessed by DOE-NETL
0
395,828
5,115
20,271
162,569
7,098,976
14,837
269,570
103,286
24,361
not assessed by DOE-NETL
37,677
26,489
4,255
4,772,925
265,558
not assessed by DOE-NETL
3,208
547,550
18,353
not assessed by DOE-NETL
754,917
22,147,811
* States with a "zero" value represent estimates of minimal COz storage resource. States that have not yet been
assessed by DOE-NETL have been identified.
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2.7.1 A vail ability of Geologic Sequestration in Deep Saline Formations
DOE and the United States Geological Survey (USGS) have independently conducted
preliminary analyses of the availability and potential CCh sequestration capacity of deep saline
formations in the United States. DOE estimates are compiled by the DOE's NATCARB system
using volumetric models and published in a Carbon Utilization and Storage Atlas.15 DOE
estimates that areas of the United States with appropriate geology have a sequestration
potential of at least 2,200 billion tons of C02 in deep saline formations. According to DOE, at
least 39 states have geologic characteristics that are amenable to deep saline GS in either
onshore or offshore locations. In 2013, the USGS completed its evaluation of the technically
accessible GS resources for C02 in U.S. onshore areas and state waters using probabilistic
assessment.16 The USGS estimates a mean of 3,300 billion tons of subsurface C02 sequestration
potential, including saline and oil and gas reservoirs, across the basins studied in the United
States. As shown in Figure 2-21, there are 39 states for which onshore and offshore deep saline
formation storage capacity has been identified.17
2.7.2 Availability of CO2 Storage via Enhanced Oil Recovery
Although the regulatory impact analysis for this rule relies on GS in deep saline
formations, the EPA also recognizes the potential for securely sequestering C02 via EOR. EOR
has been successfully used at numerous production fields throughout the United States to
increase oil recovery. The oil industry in the United States has over 40 years of experience with
EOR. An oil industry study in 2014 identified more than 125 EOR projects in 98 fields in the
United States.18 More than half of the projects evaluated in the study have been in operation
for more than 10 years, and many have been in operation for more than 30 years. This
experience provides a strong foundation for demonstrating successful C02 injection and
monitoring technologies, which are needed for safe and secure GS that can be used for
deployment of CCS across geographically diverse areas.
15 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S. Department of Energy, Office
of Fossil Energy, National Energy Technology Laboratory (NETL).
16 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment
of geologic carbon dioxide storage resources—Results: U.S. Geological Survey Circular 1386, p. 41,
http://pubs.usgs.gov/circ/1386/.
17 Alaska is not shown in the figure; it has deep saline formation storage capacity, geology amenable to EOR
operations, and potential GS capacity in unmineable coal.
18 Koottungal, Leena, 2014, 2014 Worldwide EOR Survey, Oil & Gas Journal, Volume 112, Issue 4, April 7, 2014
(corrected tables appear in Volume 112, Issue 5, May 5, 2014).
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Currently, 12 states have active EOR operations and most have developed an extensive
infrastructure, including pipelines, to support the continued operation and growth of EOR.
An additional 18 states are within 100 kilometers (62 miles) of current EOR operations (see
Figure 2-21).19 The vast majority of EOR is conducted in oil reservoirs in the Permian Basin,
which extends through southwest Texas and southeast New Mexico. States where EOR is
currently used include Alabama, Colorado, Louisiana, Michigan, Mississippi, New Mexico,
Oklahoma, Texas, Utah, and Wyoming.
At the project level, the volume of C02 already injected for EOR and the duration of
operations are of similar magnitude to the duration and volume of C02 expected to be captured
from fossil fuel-fired EGUs. The volume of C02 used in EOR operations can be large (e.g., 55
million tons of C02 were stored in the SACROC unit in the Permian Basin over 35 years), and
operations at a single oil field may last for decades, injecting into multiple parts of the field.20
According to data reported to the EPA's Greenhouse Gas Reporting Program (GHGRP),
approximately 66 million tons of C02 were supplied to EOR in the United States in 2013.21
Approximately 70 percent of this total C02 supplied was produced from natural (geologic) C02
sources, and approximately 30 percent was captured from anthropogenic sources.22
A DOE-sponsored study has analyzed the geographic availability of applying EOR in 11
major oil producing regions of the United States and found that there is an opportunity to
significantly increase the application of EOR to areas outside of current operations.23 DOE-
sponsored geologic and engineering analyses show that expanding EOR operations into areas
additional to the capacity already identified and applying new methods and techniques over the
next 20 years could utilize 20 billion tons of anthropogenic C02 and increase total oil production
by 67 billion barrels. The availability of anthropogenic C02 in areas outside of current sources
could drive new EOR projects by making more C02 locally available.
19 The distance of 100 kilometers reflects the assumptions in the DOE-NETL cost estimates.
20 Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F P. "Evaluation of CCh trapping mechanisms at the
SACROC northern platform, Permian basin, Texas, site of 35 years of CCh injection." American Journal of
Science 310. (2010): 282-324.
21 Greenhouse Gas Reporting Program, data reported as of August 18, 2014.
22lbid.
23 "Improving Domestic Energy Security and Lowering CCh Emissions with 'Next Generation' CCh-Enhanced Oil
Recovery", Advanced Resources International, Inc. (ARI), 2011. Available at:
http://www.netl.doe.gov/research/energy-analysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-
04a505al9185.
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2.8 State Policies on GHG and Clean Energy Regulation in the Power Sector
Several states have also established emission performance standards or other measures
to limit emissions of GHGs from new EGUs that are comparable to or more stringent than this
rulemaking.
In 2003, then-Governor George Pataki sent a letter to his counterparts in the Northeast
and Mid-Atlantic inviting them to participate in the development of a regional cap-and-trade
program addressing power plant CCh emissions. This program, known as the Regional
Greenhouse Gas Initiative (RGGI), began in 2009 and sets a regional CCh cap for participating
states. The currently participating states include: Connecticut, Delaware, Maine, Maryland,
Massachusetts, New Hampshire, New York, Rhode Island, and Vermont. The cap covers CCh
emissions from all fossil-fired EGUs greater than 25 MW in participating states, and limits total
emissions to 91 million tons in 2014. The 2014 emissions cap is a 51 percent reduction below
the initial cap in 2009 to 2011 of 188 million tons. This emissions budget is reduced 2.5 percent
annually from 2015 to 2020. RGGI CCh allowances are sold in a quarterly auction. RGGI
conducted their 27th quarterly allowance auction in March, 2015 the market clearing price was
$5.41 per ton of CCh for current allowances, which was a record high price (the February '15
price of $5.21 was the previous record). A total of allowances for 15.3 million tons were sold in
the March 2015 auction, well below the record of 38.7 million tons sold in June 2013 for $3.21
per ton.
In September 2006, California Governor Schwarzenegger signed into law Senate Bill
1368. The law limits long-term investments in base load generation by the state's utilities to
power plants that meet an emissions performance standard jointly established by the California
Energy Commission and the California Public Utilities Commission. The Energy Commission has
designed regulations that establish a standard for new and existing base load generation owned
by, or under long-term contract to publicly owned utilities, of 1,100 Ib CCh/MWh -net.
In 2006, Governor Schwarzenegger also signed into law Assembly Bill 32, the Global
Warming Solutions Act of 2006. This act includes a multi-sector GHG cap-and-trade program
which covers approximately 85 percent of the state GHG emissions. EGUs are included in phase
I of the program, which began in 2013. Phase II begins in 2020 and includes upstream sources.
The cap is based on a 2 percent reduction from total 2012 expected emissions, and declines 2
percent annually through 2014, then 3 percent each year until 2020. The AB32 cap and trade
program began functioning in 2011, and functioning market is now operating on the NYMEX
futures commodity market. The final 2014 market price for carbon allowances was $11.23/ton
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of carbon. On April 17, 2015 the 2015 allowance futures price was $11.48/ton, and the spot
price was $11.30/ton.
In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, "Base
load Electric Generation Performance" which established statewide GHG emissions reduction
goals, and imposed an emission standard that applies to any base load electric generation that
commenced operation after June 1, 2008 and is located in Washington, whether or not that
generation serves load located within the state. Base load generation facilities must initially
comply with an emission limit of 1,100 Ib C02/MWh-net. In 2013 the State of Washington
revised24 the emission limit to 970 Ib C02/MWh-net based on a survey of available NGCC
generation units commercially available in the United States.
In 1997, Oregon required a new base load gas fired power plants to meet a C02
emission standard that was 17 percent below the most efficient NGCC unit operating in the
United States. In 2000 Oregon established that the effective 17 percent below most efficient
was 675 Ib C02/MWh-net In July 2009, Oregon Governor Kulongoski signed Senate Bill 101,
which mandated that facilities generating base load electricity, whether gas- or coal-fired, must
have emissions equal to or less than 1,100 Ib C02/MWh-net regardless of fuel type, and
prohibited utilities from entering into long-term purchase agreements for base load electricity
with out-of-state facilities that do not meet that standard. Natural gas- and petroleum
distillate-fired facilities that are primarily used to serve peak demand or to integrate energy
from renewable resources are specifically exempted from the performance standard.
In August 2011, New York Governor Cuomo signed the Power NY Act of 2011.
Implementing regulations established C02 emission standards for new and modified electric
generators greater than 25 M W. The standards vary based on the type of facility: base load
facilities must meet a C02 standard of 925 Ib/MWh-net or 120 Ib/MMBtu, and peaking facilities
must meet a C02 standard of 1,450 Ib/MWh-net or 160 Ib/MMBtu.
Several other states have enacted C02 regulations affecting EGUs that do not set
emission limits, but set other regulatory requirements limiting C02 emissions from EGUs. For
example, Montana enacted a law in 2007 requiring the Public Service Commission to limit
approvals of new equity interests in or leases of a facility used to generate coal-based electricity
24 Washington Department of Commerce, 2013. "Greenhouse Gas Emission Performance Standard for Baseload
Electric Generation." Available at http://www.commerce.wa.gov/Documents/Concise-Expl-Stmt-WSR-13-06-
074.pdf.
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to facilities that capture and sequester at least half of their CCh emissions. Minnesota enacted
the Next Generation Energy Act in 2007 requiring increases in power sector greenhouse gas
emissions from any new large coal energy facilities built in Minnesota or the import of
electricity from such a facility located out of state to be offset by equivalent emission
reductions. New Mexico enacted legislation in 2007 authorizing tax credits and cost recovery
incentives for qualifying coal-fired facilities. To qualify, plants must capture and store emissions
so that they emit less than 1,100 Ib CCh/MWh, among other requirements.
Additionally, most states have implemented Renewable Portfolio Standards (RPS), or
Renewable Electricity Standards (RES). These programs are designed to increase the renewable
share of a state's total electricity generation. Currently 29 states, the District of Columbia and
Guam have enforceable RPS or other mandatory renewable capacity policies, and 8 states,
Puerto Rico and Guam have voluntary goals.25 These programs vary widely in structure,
enforcement, and scope.
2.9 Revenues and Expenses
Due to lower retail electricity sales, total utility operating revenues declined in 2012 to
$271 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008
levels in 2012, operating expenses were appreciably lower and as a result, net income also rose
in comparison to 2008 (see Table 2-9). Recent economic events have put downward pressure
on electricity demand, thus dampening electricity prices and consumption (utility revenues),
but have also reduced the price and cost of fossil fuels and other expenses. In 2012 electricity
generation was 1.28 percent below the generation in 2011, and has declined in four of the past
five years.
Table 2-9 shows that investor-owned utilities (lOUs) earned income of about 13.0
percent compared to total revenues in 2012. The 2012 return on revenue was the third highest
year for the period 2002 to 2012 (average: 11.9 percent, range: 10.6 percent to 13.32 percent).
25 Clean Energy States Alliance 2013
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Table 2-9. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities
for 2002, 2008 and 2012 (nominal $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
2002
219,609
200,360
19,250
189,062
171,604
116,660
90,715
24,149
58,810
7,776
3,560
3,117
4,168
1,820
264
13,018
10,861
16,199
26,716
17,457
30,548
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
2012
270,912
249,166
21,745
235,694
220,722
152,379
111,714
38,998
54,570
18,146
7,183
4,181
5,086
5,640
221
18,353
15,489
23,677
29,177
14,972
35,218
Source: Table 8.3, EIA Electric Power Annual, 2012
Note: These data do not include information for public utilities, nor for IPPs.
2.10 Natural Gas Market
The natural gas market in the United States has historically experienced significant price
volatility from year to year and between seasons, can undergo major price swings during short-
lived weather events (such as cold snaps leading to short-run spikes in heating demand), and
has seen a dramatic shift since 2008 due to increased production from shale formations. Over
the last decade, the annual average nominal price of gas delivered to the power sector peaked
in 2008 at $9.02/MMBtu and has since fallen dramatically to a low of $3.42/MMBtu in 2012.
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During that time, the daily price26of natural gas reached as high as $18.48/MMBtu and as low
as $2.03/MMBtu. Adjusting for inflation using the GDP implicit price deflator, in 2011 dollars
the annual average price of natural gas delivered to the power sector peaked at $9.38/MMBtu
in 2008 and has fallen to a low of $3.36/MMBtu in 2012. The annual natural gas prices in both
nominal and real (2011$) terms are shown in Figure 2-22. A comparison of the trends in the real
price of natural gas with the real prices of delivered coal and oil is shown in Figure 2-23. Figure
2-23 shows that while the real price of coal and oil increased from 2002 to 2012 (+54 percent
and +203 percent respectively), the real price of natural gas declined by 22 percent in the same
period. Most of the decline in real natural gas prices occurred between 2008 (the peak price
year) and 2012, during which real gas prices declined by 64 percent while coal and oil prices
both increased by 9 percent in the same period. The sharp decline in natural gas prices from
2008 to 2012 was primarily caused by the rapid increase in natural gas production from shale
formations.
$0.00
2002
2004
2006
Nominal Price
2008
• Real Price
2010
2012
Figure 2-22. Nominal and Real (2011$) Prices of Natural Gas Delivered to the Power Sector
($/MMBtu)
Source: http://www.eia.gov/totalenergy/data/monthlv/tfprices. Downloaded 2/15/2015.
26 Henry Hub daily prices. Henry Hub is a major gas distribution hub in Louisiana; Henry Hub prices are generally
seen as the primary metric for national gas prices for all end uses. The price of natural gas delivered to
electricity generation differs substantially in different regions of the country, and can be higher or lower than
the Henry Hub national benchmark price.
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-50%
2002
2012
Figure 2-23. Relative Change in Real (2011$) Prices of Fossil Fuels Delivered to the Power
Sector ($/MMBtu)
Source: http://www.eia.gov/totalenergy/data/monthlv/tfprices. Downloaded 2/15/2015.
Current and projected natural gas prices are considerably lower than the prices
observed over the past decade, largely due to advances in hydraulic fracturing and horizontal
drilling techniques that have opened up new shale gas resources and substantially increased
the supply of economically recoverable natural gas. According to the U.S. Energy Information
Administration's Annual Energy Outlook 2012 (AEO 2012) (EIA 2012):
Shale gas refers to natural gas that is trapped within shale formations. Shales are fine-
grained sedimentary rocks that can be rich sources of petroleum and natural gas. Over
the past decade, the combination of horizontal drilling and hydraulic fracturing has
allowed access to large volumes of shale gas that were previously uneconomical to
produce. The production of natural gas from shale formations has rejuvenated the
natural gas industry in the United States.
The ElA's AEO 2014 estimates that the United States possessed 2,266 trillion cubic feet
(Tcf) of technically recoverable dry natural gas resources as of January 1, 2012. Proven reserves
make up 15 percent of the technically recoverable total estimate, with the remaining 85
percent from unproven reserves. Natural gas from proven and unproven shale resources
accounts for 611 Tcf of this resource estimate.
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Many shale formations, especially the Ma reel I us27, are so large that only small portions
of the entire formations have been intensively production-tested. Furthermore, estimates from
the Marcellus and other emerging fields with few wells already drilled are likely to shift
significantly over time as new geological and production information becomes available.
Consequently, there is some uncertainty in estimate of technically recoverable resources, and it
is regularly updated as more information is gained through drilling and production.
At the 2012 rate of U.S. consumption (about 25.6 Tcf per year), 2,266 Tcf of natural gas
is enough to supply nearly 90 years of use. The AEO 2014 estimate of the shale gas resource
base is modestly higher than the AEO 2012 estimate (2,214 Tcf) of shale gas production, driven
by lower drilling costs and continued drilling in shale plays with high concentrations of natural
gas liquids and crude oil, which have a higher value in energy equivalent terms than dry natural
gas.28
ElA's projections of natural gas conditions did not change substantially in AEO 2014
from either the AEO 2012 or 2013, and EIA is continues to forecast abundant reserves
consistent with the above findings. Recent historical data reported to EIA is also consistent
with these trends, with 2014 being the highest year on record29 for domestic natural gas
production.30
27 The Marcellus formation, underlying most of Pennsylvania and West Virginia, along with portions of New York
and Ohio, in 2014 produced 36 percent of the U.S. total natural gas extracted from shale formations.
28 For more information, see: http://www.eia.gov/forecasts/archive/aeoll/IF all.cfmtfprospectshale;
http://www.eia.gov/energy in brief/about shale gas.cfm
29 The total dry gas production in 2012 from the lower 48 states, including both onshore and offshore production,
was 23.97 Tcf, a 1.5 percent increase from 2013 and a 7.9 percent total increase from 2011
30http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2014&subiect=8-AEO2014&table=72-
AEO2014®ion=0-0&cases=ref2014-dl02413a
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2.11 References
Advanced Resources International. Improving Domestic Energy Security and Lowering C02
Emissions with "Next Generation" C02-Enhanced Oil Recovery (C02-EOR). 2011. Available
online at: http://www.netl.doe.gov/research/energy-
analysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-04a505al9185.
Clean Energy States Alliance (CESA). The State of State Renewable Portfolio Standards. June
2013. Available online at http://www.cesa.org/assets/2013-Files/RPS/State-of-State-
RPSs-Report-Final-June-2013.pdf
Han, Weon S., McPherson, B J., Lichtner, P C, and Wang, F P. Evaluation of CO2 trapping
mechanisms at the SACROC northern platform, Permian basin, Texas, site of 35 years of
C02 injection. American Journal of Science 310. (2010): 282-324.
Independent Monitor's Prudency Evaluation Report for the Kemper County IGCC Project. April
15, 2014. Available online at:
http://www.psc.state.ms.us/lnsiteConnect/lnSiteView.aspx7modehlNSITE CONNECT&q
ueue=CTS ARCHIVEQ&docid=328417.
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/wg 1/218.htm.
International Energy Agency (IEA). Tracking Clean Energy Progress 2013. Input to the Clean
Energy Ministerial. 2013. Available online at: http://www.iea.org/etp/tracking/.
Koottungal, Leena. 2014 Worldwide EOR Survey, Oil & Gas Journal, Volume 112, Issue 4, April 7,
2014 (corrected tables appear in Volume 112, Issue 5, May 5, 2014).
National Energy Technology Laboratory (NETL). Reducing 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.
National Energy Technology Laboratory (NETL). The United States 2012 Carbon Utilization and
Storage Atlas, Fourth Edition. 2012. Available online at:
http://www.netl.doe.gov/technologies/carbon seq/refshelf/atlaslV/.
National Energy Technology Laboratory (NETL). Energy Analyses: Cost and Performance
Baselines for Fossil Energy Plants. 2013. Available online at:
http://www.netl.doe.gov/energv-analyses/baseline studies.html.
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Pacific Northwest National Laboratory (PNNL). An Assessment of the Commercial Availability of
Carbon Dioxide Capture and Storage Technologies as of June 2009. June 2009. Available
online at: http://www.pnl.gov/science/pdf/PNNL-18520 Status of CCS 062009.pdf.
U.S. Energy Information Administration (U.S. EIA). Carbon Dioxide Emissions from the
Generation of Electric Power in the United States. July 2000. Available online at:
ftp://ftp.eia.doe.gov/environment/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 2011. 2013. Available
online at: http://www.eia.gov/electricity/annual/.
U.S. Energy Information Administration (U.S. EIA). "Status of Electricity Restructuring by State."
2010a. Available online at:
http://www.eia.gov/cneaf/electricity/page/restructuring/restructure elect.html.
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Available online at: http://www.eia.gov/forecasts/aeo/retrospective/.
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Available online at: http://www.eia.gov/oiaf/archive/aeolO/index.html.
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online at: http://www.eia.gov/totalenergy/data/annual/pdf/aer.pdf.
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online at: http://www.eia.gov/forecasts/archive/aeoll/.
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online at: http://www.eia.gov/forecasts/aeo/.
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U.S. Environmental Protection Agency (U.S. EPA). Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2011. April 2013. Available online at:
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assessment of geologic carbon dioxide storage resources - Results: U.S. Geological
Survey Circular 1386. Available online at: http://pubs.usgs.gov/circ/1386/.
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CHAPTER 3
BENEFITS OF REDUCING GREENHOUSE GAS EMISSIONS AND OTHER POLLUTANTS
This rule is designed to set emission limits for carbon dioxide (CCh), thereby limiting
potential increases in future emissions and atmospheric CCh concentrations. This will reduce
the risk of adverse effects of climate change. As discussed in Chapter 4, the U.S. Environmental
Protection Agency (EPA) anticipates negligible CCh emission changes resulting from the rule
relative to baseline conditions, due to market baseline market conditions. The final standards
provide the benefit of regulatory certainty that any new coal-fired power plant must limit its
CCh emissions to a level reflecting the performance of a highly efficient super critical pulverized
coal (SCPC) unit utilizing post-combustion partial carbon capture and storage (CCS). As
explained in preamble section V.P.l.b, there are documented instances of project developers
abandoning projects using CCS due to this lack of regulatory certainty. In addition, the history
of regulatory actions has shown that emission standards that are based on the performance of
advanced control equipment lead to increased use of that control equipment, and that the
absence of a requirement stifles technology development. (See preamble section V.P.l.b.)
This chapter summarizes the adverse effects on public health and public welfare from
the emissions of CCh, which is a well-mixed greenhouse gas. This form of air pollution was
determined by the EPA in the 2009 Endangerment Finding to endanger public health and
welfare.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 bases for the Endangerment Finding. A discussion of climate
science findings from newer assessments can be found in the Preamble. This chapter also
provides a general discussion about how the climate-related and human health benefits of
emissions reductions are estimated. These valuation approaches are used in Chapter 5 to
quantify and monetize the relative differences in emissions between electric generating
technologies that may be constructed in the future.
3.1 Overview of Climate Change Impacts from GHG Emissions
Through the implementation of CAA regulations, the EPA addresses the negative
externalities caused by air pollution. The preamble to the final rule summarizes the public
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). See also Coalition for Responsible Regulation v. EPA, 684 F. 3d at 119-126,
upholding the Endangerment Finding in all respects, and noting that "[t]he body of scientific evidence
marshaled by EPA in support of the Endangerment Finding is substantial" (id. at 120).
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health and public welfare impacts that were detailed in the 2009 Endangerment Finding. For
health, these include the increased likelihood of heat waves, negative impacts on air quality,
more intense hurricanes, more frequent and intense storms and heavy precipitation, and
impacts on infectious and waterborne diseases. For welfare, these include reduced water
supplies in some regions, increased water pollution, increased occurrences of floods and
droughts, rising sea levels and damage to coastal infrastructure, increased peak electricity
demand, changes in ecosystems, and impacts on indigenous communities.
The preamble also summarizes new scientific assessments and recent climatic
observations. Major scientific assessments released since the 2009 Endangerment Finding have
further improved scientific understanding of climate change, and provide even more evidence
that GHG emissions endanger public health and welfare for current and future generations. The
Third National Climate Assessment (NCA3), in particular, assessed the impacts of climate
change on human health in the United States, finding that, Americans will be impacted by
"increased extreme weather events, wildfire, decreased air quality, threats to mental health,
and illnesses transmitted by food, water, and disease-carriers such as mosquitoes and ticks."
The IPCC reported similar conclusions in its Fifth Assessment Report, finding that it is likely that
adverse health impacts related to heat exposure are already being exacerbated by climate
change and that, if unabated, climate change will lead to a greater risk of morbidity and
mortality due to more intense heat waves, undernutrition, and increased prevalence of food-
and water-borne illnesses. These assessments also detail the risks to vulnerable groups such as
children, the elderly and low income households. Furthermore, the assessments present an
improved understanding of the impacts of climate change on public welfare, improved
projections of future warming over the next century, higher projections of future sea level rise
than had been previously estimated due in part to improved understanding of the Antarctic and
Greenland ice sheets, more detailed description of U.S. impacts based on the National Climate
Assessment, improved understanding of changes in rainfall and droughts, and new assessments
of the impacts of climate change on permafrost and ocean acidification. The impacts of GHG
emissions will be realized worldwide, independent upon their location of origin, and impacts
outside of the United States will produce consequences relevant to the United States.
3.2 Social Cost of Carbon
The social cost of carbon (SC-CCh) is a metric that estimates the monetary value of
impacts associated with marginal changes in CCh emissions in a given year. It includes a wide
range of anticipated climate impacts, such as net changes in agricultural productivity and
human health, property damage from increased flood risk, and changes in energy system costs,
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such as reduced costs for heating and increased costs for air conditioning. It is typically used to
assess the avoided damages as a result of regulatory actions (i.e., benefits of rulemakings that
lead to an incremental reduction in cumulative global CCh emissions). This section discusses the
development of the SC-CCh estimates and the analyses in Chapter 5 apply the SC-CCh estimates
to illustrate the value to society of the difference in CCh emissions among different generation
technologies.
The SC-C02 estimates used in these analyses were developed over many years, using the
best science available, and with multiple opportunities for input from the public, which is
discussed further below.2 Specifically, an interagency working group (IWG) that included the
EPA and other executive branch agencies and offices used three integrated assessment models
(lAMs) to develop the SC-CCh estimates and recommended four global values for use in
regulatory analyses. As noted in the Government Accountability Office's 2014 review, this
interagency working group (1) used consensus-based decision-making, (2) relied on existing
academic literature and modeling, and (3) took steps to disclose limitations and incorporate
new information by considering public comments and revising the estimates as updated
research became available.
The SC-C02 estimates were first released in February 2010 and updated in 2013 using
new versions of each 1AM. As discussed further below, the IWG published two minor
corrections to the SC-CCh estimates in July 2015. These estimates are published in the Technical
Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact
Analysis Under Executive Order 12866 ("current SC-CChTSD") and henceforth we refer to them
as the "SC-C02 estimates."
The SC-C02 estimates were developed using an ensemble of the three most widely cited
integrated assessment models in the economics literature with the ability to estimate the SC-
CCh. A key objective of the IWG was to draw from the insights of the three models while
respecting the different approaches to linking GHG emissions and monetized damages taken by
modelers in the published literature. After conducting an extensive literature review, the
interagency group selected three sets of input parameters (climate sensitivity, socioeconomic
and emissions trajectories, and discount rates) to use consistently in each model. All other
model features were left unchanged, relying on the model developers' best estimates and
2 Ample opportunity for public comment on all aspects of the SC-CCh estimates has been provided, including the
estimates selected by the IWG in 2009 and in the numerous proposed rules issued by the EPA and other federal
agencies between February 2010 and May 2013 that made use of the estimates.
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judgments, as informed by the literature. Specifically, a common probability distribution for the
equilibrium climate sensitivity parameter, which informs the strength of climate's response to
atmospheric GHG concentrations, was used across all three models. In addition, a common
range of scenarios for the socioeconomic parameters and emissions forecasts were used in all
three models. Finally, the marginal damage estimates from the three models were estimated
using a consistent range of discount rates, 2.5, 3.0, and 5.0 percent. See the 2010 SC-CCh TSD
for a complete discussion of the methods used to develop the estimates and the key
uncertainties, and the current SC-CCh TSD for the latest estimates.
The SC-C02 estimates represent global measures because of the distinctive nature of the
climate change, which is highly unusual in at least three respects. First, emissions of most GHGs
contribute to damages around the world independent of the country in which they are emitted.
The SC-C02 must therefore incorporate the full (global) damages caused by GHG emissions to
address the global nature of the problem. Second, the U.S. operates in a global and highly
interconnected economy, such that impacts on the other side of the world can affect our
economy. This means that the true costs of climate change to the U.S. are larger than the
direct impacts that simply occur within the U.S. Third, climate change represents a classic public
goods problem because each country's reductions benefit everyone else and no country can be
excluded from enjoying the benefits of other countries' reductions, even if it provides no
reductions itself. In this situation, the only way to achieve an economically efficient level of
emissions reductions is for countries to cooperate in providing mutually beneficial reductions
beyond the level that would be justified only by their own domestic benefits. In reference to
the public good nature of mitigation and its role in foreign relations, thirteen prominent
academics noted that these "are compelling reasons to focus on a global [SC-CCh]" in a recent
article on the SC-CCh (Pizer et al., 2014). In addition, as noted in OMB's Response to Comments
on the SC-C02, there is no bright line between domestic and global damages. Adverse impacts
on other countries can have spillover effects on the United States, particularly in the areas of
national security, international trade, public health and humanitarian concerns.3
The 2010 SC-C02 TSD noted a number of limitations to the SC-CCh 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
3 See: (1) Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean
Air Act, 74 Fed. Reg. 66,496, 66,535 (Dec. 15, 2009) and (2) National Research Council: Climate and Social
Stress: Implications for Security Analysis. Washington, DC: The National Academies Press, 2013.
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risk aversion. Current integrated assessment models do not assign value to all of the important
physical, ecological, and economic impacts of climate change recognized in the climate change
literature due to a lack of precise information on the nature of damages and because the
science incorporated into these models understandably lags behind the most recent research.4
The limited amount of research linking climate impacts to economic damages makes the
modeling exercise even more difficult. These individual limitations do not all work in the same
direction in terms of their influence on the SC-CCh estimates, though taken together they
suggest that the SC-CCh estimates are likely conservative. In particular, the IPCC Fourth
Assessment Report (2007), which was the most current IPCC assessment available at the time
of the IWG's 2009-2010 review, concluded that "It is very likely that [SC-C02 estimates]
underestimate the damage costs because they cannot include many non-quantifiable impacts."
Since then, the peer-reviewed literature has continued to support this conclusion. For example,
the IPCC Fifth Assessment report observed that SC-CCh estimates continue to omit various
impacts that would likely increase damages. The 95th percentile estimate was included in the
recommended range for regulatory impact analysis to address these concerns.
The EPA and other agencies have continued to consider feedback on the SC-CCh
estimates from stakeholders through a range of channels, including public comments on this
rulemaking and others that use the SC-CCh in supporting analyses and through regular
interactions with stakeholders and research analysts implementing the SC-CCh methodology
used by the interagency working group. The SC-CCh comments received on this rulemaking
covered a wide range of topics including the technical details of the modeling conducted to
develop the SC-CCh estimates, the aggregation and presentation of the SC-CCh estimates, and
the process by which the SC-CCh estimates were derived. The EPA Response to Comments
document provides a summary and response to the SC-CCh comments submitted to this
rulemaking.
Many of the comments the EPA received in this proceeding mirrored those that OMB
received in response to a separate request for public comment on the approach used to
develop the estimates and the EPA has carefully considered those comments and responses
here. After careful evaluation of the full range of comments submitted to OMB, the IWG
4 Climate change impacts and SCC modeling is an area of active research. For example, see: (1) Howard, Peter,
"Omitted Damages: What's Missing from the Social Cost of Carbon." March 13, 2014,
http://costofcarbon.org/files/Omitted_Damages_Whats_Missing_From_the_Social_Cost_of_Carbon.pdf; and
(2) Electric Power Research Institute, "Understanding the Social Cost of carbon: A Technical Assessment,"
October 2014, www.epri.com.
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continued to recommend the use of these SC-CCh estimates in regulatory impact analysis. The
IWG remains committed to ensuring that the SC-CCh estimates continue to reflect the best
available scientific and economic information on climate change. In light of this commitment,
the IWG announced plans to obtain expert independent advice from the National Academies of
Sciences, Engineering, and Medicine.5 The Academies process will be informed by the public
comments received and focus on the technical merits and challenges of potential approaches to
improving the SC-CCh estimates in future updates.
OMB also has published a revised TSD that informed our analysis here. The revision to
the TSD is limited to two minor technical corrections to the current estimates. One technical
correction addressed an inadvertent omission of climate change damages in the last year of
analysis (2300) in one model and the second addressed a minor indexing error in another
model. On average the revised recommended SC-C02 estimates are one dollar less than the
mean SC-C02 estimates reported in the November 2013 revision to the May 2013 TSD. The
change in the estimates associated with the 95th percentile estimates when using a 3 percent
discount rate is slightly larger, as those estimates are heavily influenced by the results from the
model that was affected by the indexing error.6
The EPA has examined the minor technical corrections in the revised TSD and the public
comments—including those submitted to OMB's separate SC-C02 comment process—here as
part of its consideration of whether and how to use SC-C02 estimates in this proceeding. Based
on this examination, the EPA concurs with the consensus-based interagency working group, of
which it is an active member, and finds that it is reasonable, and scientifically appropriate, to
use the current SC-C02 estimates for purposes of analysis here.
The four SC-C02 estimates the EPA is selecting to use in its analysis here are as follows:
$13, $41, $62, and $120 per short ton of C02 emissions in the year 2022 (2011$).7 The first
three values are based on the average SC-C02 from the three lAMs, at discount rates of 5, 3,
and 2.5 percent, respectively. SC-C02 estimates for several discount rates are included because
5 See https://www.whitehouse.gov/blog/2015/07/02/estimating-benefits-carbon-dioxide-emissions-reductions
6 The TSDs report SC-CCh estimates in dollars per metric ton. The impact of the correction does not change with
the conversion to short tons.
7 The current version of the TSD is available at http://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-
tsd-final-iulv-2015.pdf. The 2010 and 2013 TSDs present SC-CO2 in 2007$ per metric ton. The unrounded estimates
from the current TSD were adjusted to (1) short tons for using conversion factor 0.90718474 and (2) 2011$ using
the GDP Implicit Price Deflator (1.0613744) from the National Income and Product Accounts Tables; the
unrounded 2011$ estimates are used in the Chapter 5 illustrative analysis. The RIA presents SC-CCh estimates
rounded to two significant digits.
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the literature shows that the SC-CCh is quite sensitive to assumptions about the discount rate,
and because no consensus exists on the appropriate rate to use in an intergenerational context
(where costs and benefits are incurred by different generations). The fourth value is the 95th
percentile of the SC-CCh from all three models at a 3 percent discount rate. It is included to
represent higher-than-expected impacts from temperature change further out in the tails of the
SC-C02 distribution (representing less likely, but potentially catastrophic, outcomes).
Table 3-1 presents the global SC-C02 estimates for the years 2015 to 2050. In order to
calculate the dollar value for emission reductions, the SC-CCh estimate for each emissions year
would be applied to changes in CCh emissions for that year, and then discounted back to the
analysis year using the same discount rate used to estimate the SC-CCh. The SC-CCh increases
over time because future emissions are expected to produce larger incremental damages as
physical and economic systems become more stressed in response to greater climate change.
Note that the interagency group estimated the growth rate of the SC-CCh 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 3-1. Social Cost of CO2, 2015-20503 (in 2011$)
Year
2015
2020
2022
2025
2030
2035
2040
2045
2050
5% Average
$11
$12
$13
$13
$15
$17
$20
$22
$25
Discount
3% Average
$35
$41
$41
$44
$48
$53
$58
$62
$66
Rate and Statistic
2.5% Average
$54
$60
$62
$65
$70
$75
$81
$86
$90
3%
95th percentile
$100
$120
$120
$130
$150
$160
$180
$190
$200
' These SC-CCh values are stated in $/short ton and rounded to two significant figures. Unrounded estimates from
the current TSD have been converted from $/metric ton to $/short ton using conversion factor 0.90718474 for
consistency with this rulemaking and adjusted to 2011$ using the GDP Implicit Price Deflator (1.0613744). This
calculation does not change the underlying methodology nor does it change the meaning of the SC-CCh
estimates. For both metric and imperial denominated SC-CCb estimates, the values vary depending on the year
of COz emissions and are defined in real terms. The unrounded 2011$ estimates are used in the Chapter 5
illustrative analysis. The SC-CCb estimates shown in this table have been rounded to two significant digits.
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3.3 Health Co-Benefits of SO2 and NOx Reductions
The EPA anticipates that this rule will result in negligible emission changes over the
baseline by 2022. However, if CCh emissions are reduced from new EGUs under this rule, then
emissions of other pollutants from the power sector would also likely be reduced. For example,
reducing CCh emissions through the adoption of CCS by coal-fired boilers may also yield sulfur
dioxide (802) and emission reductions, which in turn would yield health benefits. We refer to
these additional benefits as "co-benefits".
is a precursor for fine particulate matter formation, which is particulate matter 2.5
micrometers in diameter and smaller (PIVh.s), while NOx is a precursor for PIVh.s and ground-
level ozone formation. As such, reductions of SCh and NOx would in turn lower overall ambient
concentrations of PM2.5 and ozone. Reducing exposure to PM2.sand ozone is associated with
human health benefits including avoided mortality and morbidity. Researchers have associated
PIVh.s and ozone exposure with adverse health effects in numerous toxicological, clinical, and
epidemiological studies (U.S. EPA, 2009; U.S. EPA, 2013a). Health effects associated with
exposure to PIVh.s include premature mortality for adults and infants, cardiovascular morbidity
such as heart attacks and hospital admissions, and respiratory morbidity such as asthma
attacks, bronchitis, hospital and emergency room visits, work loss days, restricted activity days,
and respiratory symptoms. Health effects associated with exposure to ozone include premature
mortality and respiratory morbidity such as hospital admissions, emergency room visits, and
school loss days. In addition to human health co-benefits associated with PIVh.s and ozone
exposure, reducing S02 and NOx emissions under this rule would result in reduced health
impacts from direct exposure to these pollutants. For example, ambient concentrations of S02
are associated with respiratory symptoms in children, emergency department visits, and
hospitalizations for respiratory conditions.
Reducing S02 and NOx emissions would also result in other human welfare (non-health)
improvements including improvements in ecosystem services. S02 and NOx emissions can
adversely impact vegetation and ecosystems through acidic deposition and nutrient
enrichment, and can affect certain manmade materials, visibility, and climate (U.S. EPA, 2009;
U.S. EPA, 2008).
The avoided incidences of health effects and monetized value of health or non-health
improvements that result from S02 and NOX emissions reductions depend on the location of
those reductions. For a full discussion of the human health, ecosystem and other benefits of
reducing S02 and NOx emissions from power sector sources, please refer to the Regulatory
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Impact Analysis for the Final Carbon Pollution Guidelines for Existing Power Plants (U.S. EPA,
2015).
As described in Chapter 4, the EPA anticipates that this rule will result in no emission
changes by 2022. As a result we did not need to perform a full health co-benefit impact
assessment for a specific modeled compliance scenario. In Chapter 5, the EPA presents results
for several illustrative plant-level analyses that show the potential impacts of the rule if certain
key assumptions were to change substantially. When assessing the co-benefits of differences in
emissions from different generation technologies in Chapter 5, the EPA does not assume a
specific location for the illustrative new unit.8 Instead, the EPA relied on a national-average
benefit per-ton (BPT) method to estimate PM2.5-related health impacts of SCh and NOx
emissions. The BPT approach provides an estimate of the total monetized human health
benefits (the sum of premature mortality and morbidity) of reducing one ton of PIVh.5 precursor
(i.e., NOx and SCh) from the sector. To develop the BPT estimates used in this analysis the EPA
utilized detailed air quality modeling of the entire power sector SCh and NOx emissions along
with the BenMAP model9 to estimate the benefits of air quality improvements using projected
2020 population, baseline incidence rates, and economic factors.
The S02- and NOx-related BPT estimates utilized in this analysis are derived from the
TSD on estimating the BPT of reducing PM2.5 and its precursors (U.S. EPA, 2013b). These BPT
values are estimated in a methodologically consistent manner with those reported in Fann et al.
(2012). They differ from those reported in Fann et al. (2012) as they reflect the health impact
studies and population data updated in the benefits analysis of the final PM NAAQS RIA (U.S.
EPA, 2012). The recalculation of the Fann et al. (2012) BPT values based on the updated data
from the PM NAAQS RIA (U.S. EPA, 2012) is described in the TSD (U.S. EPA, 2013b). The BPT
values are for the entire electricity sector and are not differentiated by fuel or generator type.
The methods used for this analysis are consistent with those used to estimate the health
co-benefits from secondary PIVh.5 formation for the Regulatory Impact Analysis for the Final
Carbon Pollution Guidelines for Existing Power Plants (U.S. EPA, 2015). One notable difference
between the BPT values used in the two analyses is that this analysis utilizes national-average
BPT estimates because the EPA does not assert a specific location for the illustrative new unit,
8 If the EPA assumed a location for a particular new unit it may be possible to perform a full health impact
assessment of different technology options for generating electricity at that location. Doing so for a number of
locations is beyond the scope of this analysis and would be better captured in sector-wide modeling.
9 Available at http://www.epa.gov/air/benmap.
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whereas the BPT estimates used in the RIA for the final existing source guidelines differ by
region.10
Despite our attempts to quantify and monetize as many of the co-benefits of reducing
emissions from electricity generating sources as possible, not all known health and non-health
co-benefits from reducing SCh and NOX are accounted for in this assessment. For more
information about unquantified health and non-health co-benefits of SCh and NOX please refer
to tables 5-2 and 6-2 of the PM NAAQS RIA (U.S. EPA, 2012), respectively. Furthermore, the
analysis that follows does not account for known differences in other air and water pollutants
between the different generating technologies, including, for example, ozone or directly-
emitted PM. The implications for limiting our consideration of co-benefits to pollutants that
cause secondary PIVh.5 is discussed in Chapter 5.
As we do not assume a specific location for the new units being compared, this RIA is
unable to include the type of detailed uncertainty assessment found in the RIA for the National
Ambient Air Quality Standards for Particulate Matter (PM NAAQS RIA) (U.S. EPA, 2012).
However, the results of the uncertainty analyses presented in the PM NAAQS RIA can provide
some information regarding the uncertainty inherent in the benefits results presented in this
analysis. In addition to the uncertainties described in the PM NAAQS RIA, the use of BPT
estimates come with additional uncertainty. Specifically, these national-average BPT estimates
reflect a specific geographic distribution of S02 and NOx reductions resulting in a specific
reduction in PM2.5 exposure and may not fully reflect local or regional variability in population
density, meteorology, exposure, baseline health incidence rates, timing of emissions, or other
factors that might lead to an over-estimate or under-estimate of the actual benefits associated
with PM2.5 precursors in a specific location. These estimates are illustrative as the EPA does not
assume a specific location for the illustrative electricity generation technologies and is
therefore unable to specifically determine the population that would be affected by their
emissions. Therefore, the benefits for any specific unit can be different than the estimates
shown here.
Notwithstanding these limitations, reducing one thousand tons of annual S02 from U.S.
power sector sources has been estimated to yield between four and nine incidences of
premature mortality avoided and monetized PM2.s-related health benefits (including these
incidences of premature mortality avoided) between $38 million and $85 million in 2020
10 Separate BPT values are generated for California, the Eastern U.S., and the Western U.S. excluding California. For
further information, see EPA 2015.
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(2011$) using a 3 percent discount rate or between $34 million and $76 million (2011$) using a
7 percent discount rate. Additionally, reducing one thousand tons of annual NOx from U.S.
EGUs has been estimated to yield up to one incidence of premature mortality avoided and
monetized PM2.5-related health benefits (including these incidences of premature mortality
avoided) of between $5.5 million and $12 million in 2020 (2011$) using a 3 percent discount
rate or between $5.0 million and $11 million (2011$) using a 7 percent discount rate. For each
pollutant, the range of estimated benefits for each discount rate is due to the EPA's use of two
alternative primary estimates of PIVh.s-related mortality impacts: a lower primary estimate
based on Krewski et al. (2009) and a higher primary estimate based on Lepeule et al. (2012).
The benefit per ton values are reported in Table 3-2.
Table 3-2. Monetized Health Benefits Per Ton of PIN/h.s Precursor Reductions in 2020a (in
2011$)
3% Discount Rate
Krewski et al. (2009)
Lepeule etal. (2012)
7% Discount Rate
Krewski et al. (2009)
Lepeule etal. (2012)
S02
$38,000
$85,000
$34,000
$76,000
PMz.5 Precursor
NOx
$5,500
$12,000
$5,000
$11,000
a These estimates are from U.S. EPA, 2013a (electricity generating units) and are adjusted to 2011$ using the Gross
Domestic Product implicit price deflator reported by the Department of Commerce.
3.4 References
40 CFR Chapter I [EPA-HQ-OAR-2009-0171; FRL-9091-8] RIN 2060-ZA14, "Endangerment and
Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean
Air Act," Federal Register / Vol. 74, No. 239 / Tuesday, December 15, 2009 / Rules and
Regulations.
Fann, N., K.R. Baker, CM. Fulcher. 2012. Characterizing the PM2.5-related health benefits of
emission reductions for 17 industrial, area and mobile emission sectors across the U.S.
Environment International, Volume 49,15 November 2012, Pages 141-151, ISSN 0160-
4120, http://dx.doi.0rg/10.1016/i.envint.2012.08.017.
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Interagency Working Group (IWG) on Social Cost of Carbon (SC-C02). 2010. Technical Support
Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order
12866. Docket ID EPA-HQ-OAR-2009-0472-114577. Participation by Council of Economic
Advisers, Council on Environmental Quality, Department of Agriculture, Department of
Commerce, Department of Energy, Department of Transportation, Environmental
Protection Agency, National Economic Council, Office of Energy and Climate Change,
Office of Management and Budget, Office of Science and Technology Policy, and
Department of Treasury.
http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-
of-Carbon-for-RIA.pdf Accessed March 31, 2015.
Interagency Working Group (IWG) on Social Cost of Carbon (SC-C02). 2013, Revised July 2015.
Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis
Under Executive Order 12866. Docket ID EPA-HQ-OAR-2013-0495. Participation by
Council of Economic Advisers, Council on Environmental Quality, Department of
Agriculture, Department of Commerce, Department of Energy, Department of
Transportation, Domestic Policy Council, Environmental Protection Agency, National
Economic Council, Office of Management and Budget, Office of Science and Technology
Policy, and Department of Treasury.
Accessed July 2, 2015.
Intergovernmental Panel on Climate Change (IPCC). 2007. Climate Change 2007: Synthesis
Report. Contribution of Working Groups I, II and III to the Fourth Assessment Report of
the Intergovernmental Panel on Climate Change (AR4) [Core Writing Team, Pachauri,
R.K and Reisinger, A. (eds.)]. IPCC, Geneva, Switzerland, 104 pp.
. Accessed March 30, 2015.
Intergovernmental Panel on Climate Change (IPCC). 2014. Climate Change 2014: Impacts,
Adaptation, and Vulnerability. Contribution of Working Group II to the Fifth Assessment
Report of the Intergovernmental Panel on Climate Change. Cambridge University Press,
Cambridge, United Kingdom and New York, NY, USA.
Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz,
and W.H. White. 2009. "Reanalysis of the Harvard Six Cities Study and the American
Cancer Society Study of Particulate Air Pollution and Mortality." Special Report to the
Health Effects Institute. Cambridge, MA. July.
Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. "Chronic Exposure to Fine Particles and
Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009."
Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.
3-12
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Medina-Ramon, M. and J. Schwartz, 2007: Temperature, temperature extremes, and mortality:
a study of acclimatization and effect modification in 50 U.S. cities. Occupational and
Environmental Medicine, 64(12), 827-833.
National Research Council (NRC). 2009. Hidden Cost of Energy: Unpriced Consequences of
Energy Production and Use. National Academies Press. Washington, DC.
National Research Council (NRC). 2013. Climate and Social Stress: Implications for Security
Analysis. The National Academies Press. Washington, DC.
Pizer, W., M. Adler, J. Aldy, D. Anthoff, M. Cropper, K. Gillingham, M. Greenstone, B. Murray, R.
Newell, R. Richels, A. Rowell, S. Waldhoff, J. Wiener. 2014. "Using and improving the
social cost of carbon." Science, Vol. 346, No. 6214, 12/05/14, pp 1189-1190.
U.S. Environmental Protection Agency (U.S. EPA). 2008. Integrated Science Assessment for
Oxides of Nitrogen and Sulfur -Ecological Criteria National (Final Report). National
Center for Environmental Assessment, Research Triangle Park, NC. EPA/600/R-08/139.
December. Available on the Internet at
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485.
U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for
Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for
Environmental Assessment - RTP Division. December. Available on the Internet at
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.
U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis for the Final
Mercury and Air Toxics Standards. Office of Air Quality Planning and Standards,
Research Triangle Park, NC. December. Available on the Internet at
http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the
Final Revisions to the National Ambient Air Quality Standards for Particulate Matter.
Office of Air Quality Planning and Standards, Research Triangle Park, NC. December.
Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2013a. Integrated Science Assessment for
Ozone and Related Photochemical Oxidants. EPA/600/R-10/076F. Research Triangle
Park, NC: U.S. EPA. February. Available on the Internet at
http://oaspub.epa.gov/eims/eimscomm.getfile7p download id=511347.
U.S. Environmental Protection Agency (U.S. EPA). 2013b. Technical Support Document
Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of
Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on
the Internet at http://www2.epa.gov/sites/production/files/2014-
10/documents/sourceapportion mentbpttsd.pdf
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U.S. Environmental Protection Agency (U.S. EPA). 2015. Regulatory Impact Analysis for the Final
Carbon Pollution Guidelines for Existing Power Plants.
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
COSTS, ECONOMIC, AND ENERGY IMPACTS OF THE NEW SOURCE STANDARDS
4.1 Synopsis
This chapter reports the compliance cost, economic, and energy impact analyses
performed for the final ECU New Source GHG Standards.1 The U.S. Environmental Protection
Agency (EPA) analyzed and assessed a wide range of potential scenarios and outcomes, using a
detailed power sector model, other government projections for the power sector, and
additional economic assessments and analyses to determine the potential impacts of this
action.
The primary finding of this assessment is that in the baseline, all projected unplanned2
capacity additions affected by these standards during the analysis period would already be
compliant with the rule's requirements (e.g., natural gas combined cycle units, low capacity
factor natural gas combustion turbines, and small amounts of coal-fired units with carbon
capture and storage (CCS) supported by federal and state funding). The analysis period is
defined as through 20223 to reflect that CAA Section lll(b) requires that the NSPS be reviewed
every eight years. The EPA's conclusion was based on:
• EIA power sector modeling projections,
• EPA power sector modeling projections,
• Electric utility integrated resource planning (IRP) documents, and
• Projected new EGUs reported by industry to the U.S. Energy Information
Administration (EIA).
The EPA's forecast of no new non-compliant coal-fired capacity remains robust beyond
the analysis period (past 2030 in both EIA and EPA baseline modeling projections) and across a
wide range of alternative potential market, technical, and regulatory scenarios that influence
1 Chapter 6 reports the compliance cost, economic, and energy impact analyses performed for the final EGU
Modified and Reconstructed Source Standards.
2 Unplanned capacity represents projected capacity additions that are not under construction.
3 In some cases, conditions in the analysis year of 2022 are represented by results of power sector modeling for the
year 2020. An analysis year of 2023 (8 years from finalization) would not substantively alter the overall
conclusions of this RIA. Integrated Planning Model (IPM) output for subsequent years has been made available
in the docket and is discussed where appropriate throughout the document.
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power sector investment decisions. As a result, the ECU New Source GHG Standards are not
expected to change GHG emissions for newly constructed EGUs, and are anticipated to yield no
monetized benefits and impose negligible costs, economic impacts, or energy impacts on the
electricity sector or society. While the EPA does not project any new coal-fired EGUs without
CCS to be built in the absence of this rule, this chapter presents an analysis of the project-level
costs of building new coal-fired capacity with and without CCS to demonstrate that a
requirement of partial CCS would not preclude new coal construction due to economic
conditions. An additional illustrative analysis, presented in Chapter 5, shows that even in the
unlikely event that new, non-compliant ECU capacity would be built, the final ECU New Source
GHG Standards would provide net benefits under a range of assumptions.
4.2 Requirements of the Final GHG EGU NSPS
In this action, the EPA is finalizing standards of performance for two basic categories of
new units that have not commenced construction by January 8, 2014: (i) fossil fuel-fired electric
utility steam generating units (boilers and IGCC units) and (ii) natural gas-fired stationary
combustion turbines that generate electricity for sale and meet certain applicability criteria.
The EPA is finalizing standards of performance for affected EGUs within the following
two categories: (1) all fossil fuel-fired steam generating units (steam generating units, boilers
and integrated gasification combined cycle (IGCC) units), and (2) all natural gas-fired stationary
combustion turbines, regardless of the size of the stationary turbine unit. All affected new fossil
fuel-fired EGUs would be required to meet an output-based emission rate of a specific mass of
carbon dioxide (CCh) per megawatt-hour (MWh) of electricity generated energy output on a
gross basis.
New fossil fuel-fired steam generating units (boilers and IGCC units) would be required
to meet an emission standard of 1,400 Ib CCh/MWh of gross energy output.
Newly constructed natural gas-fired stationary combustion turbines will be required to
meet a standard of 1,000 Ib C02/MWh of gross energy output (or 1,030 Ib C02/MWh of net
energy output). This emission limit applies to all affected natural gas-fired stationary
combustion units regardless of size. The natural gas combustion turbine standard, however, will
only apply to units that will exceed a sales threshold on the amount of electricity generated
that is sold to the electric grid. The purpose of the sales threshold criterion is to permit gas-
fired combustion turbines that only sell a small portion of the gross electricity generated to the
grid ("non-base load units") to not have to meet the same emission standard as a combustion
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turbine unit designed primarily to generate base and intermediate electricity to be sold to the
grid.
Please refer to the preamble for additional detail concerning affected EGUs and
standards of performance.
4.3 Power Sector Modeling Framework
4.3.1 Modeling Overview
Over the last decade, the EPA has conducted extensive analyses of regulatory actions
impacting the power sector. These efforts support the Agency's understanding of key policy
variables and provide the framework for how the Agency estimates the costs and benefits
associated with its actions that impact the power sector. Current forecasts for the utilization of
new and existing generating capacity are a key input into evaluating the impact of this rule.
Given excess capacity within the existing fleet and relatively low forecasts of electricity demand
growth, there is limited new capacity of any type expected to be constructed over the next
decade. A small number of new coal-fired power plants have been completed and brought
online in recent years. However, the EPA does not expect the construction of any new non-
compliant coal-fired capacity through the analysis period. The EPA also does not expect any
new non-compliant natural gas-fired stationary combustion turbines meeting the applicability
criteria to be built. This conclusion is based in part on the Agency's own power sector modeling
utilizing the Integrated Planning Model (IPM) as well as ElA's Annual Energy Outlook 2014 (AEO
2014) projections.
IPM, developed by ICF International, Inc, is a state-of-the-art, peer reviewed, dynamic
linear programming model that can be used to project power sector behavior under future
business as usual conditions and examine prospective air pollution control policies throughout
the United States for the entire electric power system. The EPA used IPM to project likely future
electricity market conditions with and without this rule.
In addition to using IPM, the EPA has closely examined modeling results from a number
of alternative baseline scenarios in the AEO 2014 from the EIA. To produce the AEO, EIA
employs the National Energy Modeling System (NEMS), an energy-economy modeling system of
the United States. According to EIA:4
' http://www.eia.gov/oiaf/aeo/overview/
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NEMS projects the production, imports, conversion, consumption, and prices of energy,
subject to assumptions on macroeconomic and financial factors, world energy markets,
resource availability and costs, behavioral and technological choice criteria, cost and
performance characteristics of energy technologies, and demographics.
The Electricity Market Module of NEMS produces projections of power sector behavior
that minimize the cost of meeting electricity demand subject to the sector's inherent
constraints, including the availability of existing generation capacity, transmission capacity and
cost, cost of utility and nonutility technologies, expected load shapes, fuel markets, regulations,
and other factors. ElA's AEO projections independently corroborate the EPA's conclusions in
that the forecast no new generation capacity being constructed through the analysis period
that would not already meet the final new source standards. Both the IPM and AEO 2014
NEMS modeling results are presented in Section 4.4.
4.3.2 The Integrated Planning Model
IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S.
electric power sector. It provides forecasts of least cost capacity expansion, electricity dispatch,
and emission control strategies while meeting energy demand and environmental,
transmission, dispatch, and reliability constraints. The EPA has used IPM for over two decades
to better understand power sector behavior under future business as usual conditions and
evaluate the economic and emission impacts of prospective environmental policies. The model
is designed to reflect electricity markets as accurately as possible.5 The EPA uses the best
available information from utilities, industry experts, gas and coal market experts, financial
institutions, and government statistics as the basis for the detailed power sector modeling in
IPM. The model documentation provides additional information on the assumptions discussed
here as well as all other model assumptions and inputs.6'7
Although the Agency typically focuses on broad system effects when assessing the
economic impacts of a particular policy, the EPA's application of IPM includes a detailed and
sophisticated regional representation of key power sector variables and its organization. When
considering which new units are most cost effective to build and operate, the model considers
the relative economics of various technologies based on a wide spectrum of current and future
considerations, including capital costs, operation and maintenance costs, fuel costs, utility
5 http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html
6 http://www.epa.gov/airmarkets/programs/ipm/psmodel.html
7 http://www.epa.gov/airmarkets/documents/ipm/EPA Base Case v514 Incremental Documentation.pdf
4-4
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sector regulations, and emission profiles. The capital costs for new units account for regional
differences in labor, material, and construction costs. These regional cost differentiation factors
were developed based on data and assumptions used in the ElA's AEO 2013.
As part of IPM's assessment of the relative economic value of building a new power
plant, the model incorporates a detailed representation of the fossil-fuel supply system that is
used to forecast equilibrium fuel prices, a key component of new power plant economics. The
model includes an endogenous representation of the North American natural gas supply system
through a natural gas module that reflects full supply/demand equilibrium of the North
American gas market. This module consists of 118 supply, demand, and storage nodes, 15
liquefied natural gas regasification facility locations and three LNG export facility locations that
are tied together by a series of linkages (i.e., pipelines) that represent the North American
natural gas transmission and distribution network.
IPM also endogenously models the coal supply and demand system throughout the
continental U.S., and reflects non-power sector demand and imports/exports. IPM reflects 36
coal supply regions, 465 coal supply curves for each of nine years, 14 coal sulfur grades, and the
coal transport network, which consists of 4,947 linkages representing the costs of transporting
coal via rail, barge, and truck and conveyer linkages connecting 41 regions with 575 individual
coal-fired generating stations. The coal supply curves and the transport network costs used in
IPM are publicly available,8 and were developed during a thorough bottom-up, mine-by-mine
approach that depicts the coal choices and associated supply costs that power plants will face
over the modeling time horizon. The IPM documentation outlines the methods and data used
to quantify the economically recoverable coal reserves, characterize their cost, and build the 84
coal supply curves. These curves have been independently reviewed by industry experts and
have been made available for public review on several occasions over the past two years during
other rulemaking processes.
The EPA has used IPM extensively over the past two decades to analyze options for
reducing power sector emissions. The model has been used to forecast the costs, emission
changes, and power sector impacts for the Clean Air Interstate Rule (CAIR), Cross-State Air
Pollution Rule (CSAPR), the Mercury and Air Toxics Standards (MATS), and the proposed GHG
8 The IPM coal supply curves are presented in detail in Appendix 9-24 of the IPM Base Case documentation, which
is available at http://www.epa.gov/airmarkets/programs/ipm/psmodel.html. The coal transport network costs
are in Appendix 9-23, available at that same link.
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emission guidelines for existing source EGUs.9 Recently IPM has also been used to estimate the
air pollution reductions and power sector impacts of water and waste regulations affecting
EGUs, including Cooling Water Intakes (316(b)) Rule, Disposal of Coal Combustion Residuals
from Electric Utilities (CCR) and Steam Electric Effluent Limitation Guidelines (ELG).
The model undergoes periodic formal peer review, which includes separate expert
panels for both the model itself and the EPA's key modeling input assumptions.10 The
rulemaking process also provides opportunity for expert review and comment by stakeholders,
including owners and operators of the electricity sector that is represented by the model, public
interest groups, and other developers of U.S. electricity sector models. The EPA is required to
respond to significant comments submitted regarding the inputs used in IPM, its structure, and
application. The feedback that the Agency receives provides a detailed check for key input
assumptions, model representation, and modeling results. IPM has received extensive review
by energy and environmental modeling experts in a variety of contexts. For example, from the
mid-1990s through 2011 the Science Advisory Board reviewed IPM as part of the Clean Air Act
(CAA) Amendments Section 812 studies of the CAA costs and benefits that are periodically
conducted.11 The model has also undergone considerable interagency scrutiny when it has
been used to conduct over one dozen legislative analyses performed at Congress' request over
the past decade. In addition, Regional Planning Organizations throughout the U.S. have
extensively examined IPM as a key element in the state implementation plan (SIP) process for
achieving the National Ambient Air Quality Standards. The Agency has also used the model in a
number of comparative modeling exercises sponsored by Stanford University's Energy
Modeling Forum over the past 15 years.
IPM has also been employed by state partnerships (e.g., the Regional Greenhouse Gas
Initiative (RGGI), the Western Regional Air Partnership, Ozone Transport Assessment Group),
other federal and state agencies, environmental groups, and industry, all of whom subject the
model to their own review procedures. States have also used the model extensively to inform
issues related to ozone in the northeastern U.S. This groundbreaking work set the stage for the
NOX SIP call, which has helped reduce summer nitrogen oxide (NOX) emissions and the
formation of ozone in densely populated areas in the northeast.
9 The IPM projection conducted for this rulemaking is available at the EPA's website and in the public docket.
10 http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html
11 http://www.epa.gov/air/sect812/index.html
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4.4 Analyses of Future Generating Capacity
4.4.1 Base Case Power Sector Modeling Projections
The "base case" for this analysis is a business-as-usual scenario that would be expected
under market and regulatory conditions in the absence of this rule. As such, the IPM base case
represents the baseline for this regulatory impact analysis. The EPA frequently updates the IPM
base case to reflect the latest available electricity demand forecasts, as well as expected costs
and availability of new and existing generating resources, fuels, and emissions control
technologies.
The EPA conducted analysis and modeling in support of the April 2012 ECU GHG New
Source Standards proposal, and concluded that new unplanned non-compliant base load power
plants are not expected to be built through the analysis period (2020 for the original proposal)
and beyond (77 FR 22392, April 13, 2012). The EPA conducted an analysis of the economic
impacts by modeling a base case scenario of future electricity market conditions. The EPA's IPM
modeling for the 2012 proposal utilized the IPM v. 4.10 base case, and relied on the AEO 2010
for the electric demand forecast for the U.S. and employed a set of the EPA's assumptions
regarding fuel supplies, the performance and cost of electric generation technologies, pollution
controls, and numerous other parameters. For the 2012 proposal, the EPA also conducted three
additional base case sensitivity analyses using IPM.12
After considering public comments received on the 2012 proposal, the EPA issued a new
proposal for carbon emissions from new power plants (79 FR 1430, January 8, 2014). The EPA's
IPM modeling of the 2013 proposal relied on the AEO 2013 electric demand forecast, and was
analyzed using the IPM v. 5.13 base case. The EPA also conducted three additional base case
sensitivity analyses using IPM.13
For the analysis of the final rule, the EPA used the IPM v. 5.14 base case, which relied on
the electric demand forecast in AEO 2014. The v. 5.14 base case updated v. 5.13 unit level
specifications (including control configurations) based on comments received and ECU
compliance plans in response to environmental regulations. The base case accounts for the
effects of the finalized MATS and CSAPR rules, New Source Review settlements and state rules
through 2014 impacting sulfur dioxide (S02), NOX, directly emitted particulate matter and C02,
12 http://www2.epa.gov/sites/production/files/2013-09/documents/20120327proposalria.pdf
13 http://www2.epa.gov/sites/production/files/2013-09/documents/20130920proposalria.pdf and
http://www.epa.gov/airmarkets/programs/ipm/proposedEGU GHG NSPS.html
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and final actions the EPA has taken to implement the Regional Haze Rule. The EPA's IPM base
case also includes two federal non-air rules effecting EGUs: the Cooling Water Intakes (316(b))
Rule and the Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR).
Table 4-1 reports the unplanned capacity additions forecast by the IPM base case.
Unplanned capacity additions are those that the model forecasts to be built in response to
forecast economic conditions, such as fuel prices and demand growth. The EPA's IPM base case
forecast finds that EGUs are projected to adopt technology for new steam and combustion
turbine generation capacity that would be compliant with the standards, even in the absence of
this rule. Only some new coal-fired units with carbon capture and storage (CCS) technology,
which are receiving partial federal financial support, are included in the baseline modeling.
Furthermore, new simple-cycle combustion turbines (CTs) constructed in the EPA's IPM base
case are assumed to operate at an emissions rate above the standard. However, mirroring real
world behavior, relatively low levels of CT generation are projected in the base case. In the base
case new CTs are forecast to operate, on average in each domestic model region, at capacity
factors well below the applicability requirements of this rule. In the base case the maximum
average capacity factor for individual new CTs is 14 percent or less across all domestic regions
and all simulation years. The emissions rate of new natural gas combined cycle (NGCC) units in
the EPA's IPM base case is below the emissions rate standard of this final rule, although this is
by assumption. However, assuming an emissions rate for new NGCC units that is below the
emissions rate standard is consistent with the detailed emissions rate analysis described in the
preamble for this rule. That analysis carefully considered emissions rate data on newly
constructed NGCC units and GHG limitations in recently issued construction permits for NGCC
facilities and found that these facilities operated below the standard or were permitted to
operate below the standard.
The EIA projections that are reflected in AEO 2014 reference case are summarized in the
following tables alongside the EPA base case projections. According to the EIA, the AEO 2014
reference case "projection is a business-as-usual trend estimate, given known technology and
technological and demographic trends."14 It represents existing policies and regulations
influencing the power sector.15 As shown in Table 4-1, new coal-fired capacity through 2030 is
projected to be entirely CCS-equipped and would be in compliance with these standards (300
MW) in the AEO 2014 reference case. The projected CCS-equipped capacity is assumed to
14 http://www.eia.gov/forecasts/archive/aeol4/pdf/0383(2014).pdf
15 Reference case assumptions are described in Assumptions to the Annual Energy Outlook 2014 (U.S. EIA 2014b).
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occur in response to existing federal, state, and local incentives for the technology.16 The AEO
2014 reference case forecasts that the vast majority of new, unplanned generating capacity will
be either natural gas-fired or renewable.17 The reference case projects a capacity factor for
simple cycle combustion turbines of less than 20 percent in all regions and in all years, and
therefore these units are projected to operate below the applicability limit for this final rule. As
in the IPM-based analysis, the emission rate for new NGCC units in the AEO 2014 reference case
is assumed to be below the applicable standard in this final rule.
As described in detail in 4.4.2, the economics favoring new natural gas combined cycle
(NGCC) additions instead of coal-fired additions are robust under a range of sensitivity cases
examined in the AEO 2014. Sensitivity cases that EIA conducted in the AEO 2014, as well as the
AEO 2013, separately examine higher economic growth, lower coal prices, no risk premium for
greenhouse gas emissions liability from conventional coal, and lower oil and natural gas
resources. None of these sensitivity cases forecast unplanned additions of coal-fired capacity
without CCS in the analysis period. This has been a consistent finding in the AEO, which led the
Department of Energy (DOE) to conclude that "the low capital expense, technical maturity, and
dispatchability of natural gas generation are likely to dominate investment decisions under
current policies and projected prices."18
16 These programs include the Emergency Economic Stabilization Act of 2008, the American Reinvestment and
Recovery Act of 2009 (which assisted in funding for such programs as the Clean Coal Power Initiative through
DOE and tax credits for Clean Energy Manufactures through DOE and the Treasury Department), as well as
loans provided by USDA for COz capture projects. See also preamble section S.H.S.g discussing the EPAct 2005.
17 http://www.eia.gov/forecasts/aeo/chapter legs regs.cfm
18 Department of Energy (2011). Report on the First Quadrennial Technology Review. Available at
http://enerciv.ciov/sites/prod/files/Q.TR report.pdf.
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Table 4-1. Unplanned Cumulative Capacity Additions (GW)
Capacity Type
Conventional Coal
Coal with CCS
Natural Gas CC
Natural Gas CT
Nuclear
Renewables19
Distributed Generation20
Total
EPA Base Case
2020
0
0.3
6.9
2.6
0
15.9
-
25.8
AEO
2020
0
0.3
9.8
14.1
0
17.4
1.6
43.2
2014 Reference
2025
0
0.3
28.8
34.5
0
19.3
3.3
86.3
Case
2030
0
0.3
95.7
49.2
0
22.5
4.6
141.4
Notes: The sum of the table values in each column may not match the total figure due to rounding. EPA capacity data is net
nameplate capacity, AEO capacity data is net summer generating capacity.
Source: EPA 2020 projection from IPM v. 5.14 base case; EIA 2020-2030 projection from EIA Annual Energy Outlook 2014, Table
A9.
The capacity projections of EIA and the EPA represent a continuation of current trends,
where natural gas-fired capacity has been the technology of choice for base load and
intermediate load power generation over the last few years (see Figure 4-1), due in large part
to its significant levelized cost of electricity21 (LCOE) advantage over coal-fired generating
technologies. A greater discussion of the relative LCOE of different generating technologies is
provided beginning in Section 4.4.
19 Renewable projections in 2020 are larger in the AEO 2014 reference case than in the EPA's IPM v 5.14 base case
primarily due to differences in modeling assumptions regarding the amount of 'planned' renewable capacity
additions and 'unplanned' additions in the AEO forecast. The overall amount of total renewable capacity in use
by 2020 is largely similar in the two forecasts. The EPA planned cumulative renewable capacity additions
include utility-scale onshore wind, solar PV, geothermal and biomass built between 2015 and 2020. The AEO
2014 unplanned renewable capacity additions includes conventional hydroelectric, geothermal, wood, wood
waste, all municipal waste, landfill gas, biomass (not co-fired with coal), PV and thermal solar, and wind power
built between 2012 and 2020.
20 The term "Distributed Generation" refers to two different concepts. AEO defines the term distributed generation
as "primarily peak-load capacity fueled by natural gas." The EPA forecasts using the IPM model do not model
new construction of distributed generation or capacity, which in the IPM model refers to small scale generation
such as rooftop PV, household geothermal, etc. Such small scale generation does not generate net electricity
that can be sold to the grid, although it can reduce peak load demands on the grid system.
21The levelized cost of electricity is an economic assessment of the cost of electricity from a new generating unit or
plant, including all the costs over its lifetime: initial investment, operations and maintenance, cost of fuel, and
cost of capital.
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60,000
50,000
40,000
(D
30,000
u
ro
Q.
U 20,000
10,000
i Wind
Other Renewables
i Other
i Nudear
i Gas
i Coal
. -iillll
cncncncncncncncncncncncncncncncncncncncncn
1 1 "
i*~ o no UD 01 rx
oo en en en en c
en en en en en c
*H *H *H *H *H rx
1891-1913)
LO 00
o o
o o
(N (N
T-t
*H
O
(N
Figure 4-1. Historical U.S. Power Plant Capacity Additions, by Technology, 1891-2013
Source: Form EIA-860 (2013)
Notes: Figure reflects all capacity brought online from 1891 - 2013, including 77 GW subsequently retired. Total
capacity shown: 1,126 GW, including 12 GW built pre-1940. Other Renewables include: hydro, biomass, solar,
landfill gases, solid waste combustion and geothermal. Other includes: petroleum & distillates, petroleum coke,
propane, other gases and waste heat not otherwise included.
In addition to new builds, increased electricity demand is expected to be partially
fulfilled by increased utilization of existing generating capacity. Generation projections are the
result of least-cost economic modeling both in IPM and AEO 2014, and reflect the most cost-
effective dispatch and investment decisions modeled, given a variety of variables and
constraints. Even without the deployment of new conventional coal-fired capacity, U.S.
electricity demand will continue to be met by a diverse mix of electricity generation sources
with coal projected to continue to provide the largest share of electricity (36 percent of total
2020 generation in AEO 2014 and 37 percent in the EPA's projections), as displayed in Table 4-
2.
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Table 4-2. 2012 U.S. Electricity Net Generation and Projections for 2020, 2025, and 2030
(Billion kWh)
Coal
Oil
Natural Gas
Nuclear
Hydroelectric
Wind
Other Renewables
Other
Total
Historical
2012
1,512
23
1,228
769
274
142
48
71
4,067
EPA Base
Case
2020
1,534
47
1,156
815
282
251
121
-7
4,199
AEO 2014 Reference Case
2020
1,646
18
1,286
779
288
218
102
65
4,402
2025
1,689
19
1,410
711
291
218
133
151
4,622
2030
1,692
19
1,552
782
294
219
154
103
4,815
Source: Historical data from Form EIA-860, 2012. EPA 2020 projection from IPM 5.14 base case; EIA 2020-2030 projection from
EIA Annual Energy Outlook 2014, Tables AS and A16
Notes: The sum of the table values in each column may not match the total figure due to rounding. "Other Renewables"
include biomass, geothermal, waste and solar electric generation capacity. "Other" includes pumped storage (net loss, non-
biogenic waste, batteries, hydrogen, and other miscellaneous generation and storage technologies. Negative value reflects net
energy loss from pumped storage.
It has been previously noted that the current projections for key market variables, such
as natural gas prices, and state and regional regulations are now even less favorable to the
development of non-compliant coal-fired capacity than at the time of the 2012 proposal. State
and regional regulations have changed since the 2012 proposal, as noted in Section 2.8, most
notably regulations of GHG emissions from the power sector and state renewable portfolio
standards (RPS):
• State regulations addressing CCh emissions - Several states have adopted
measures to address emissions of CCh from the power sector. These approaches
include flexible market-based programs like California's Assembly Bill 32 and
RGGI in the Northeast, and specific GHG performance standards for new power
plants in California, Oregon, New York, and Washington.
• State Renewable Portfolio Standards (RPS) -There are now 29 states, the District
of Columbia and Puerto Rico that have an enforceable RPS, or similar laws.22
Eight other States, the Virgin Islands and Guam have voluntary goals. These
22http://www.cesa.org/assets/2013-Files/RPS/State-of-State-RPSs-Report-Final-June-2013.pdf
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measures, in conjunction with federal financial incentives, are key drivers of the
significant growth in new renewable energy seen over the past few years and
expected over the next decade. Only 12 states do not currently have an
enforceable RPS.23
• State and Utility IRPs- IRPs, which are usually adopted by utilities in response to
state requirements, allow regulators and utilities to consider a broader array of
measures to meet future electric demand most cost effectively. IRPs also help
electric planners to consider key strategic and policy goals like electric reliability,
environmental impacts, and the economic efficiency of power sector
investments.24 In general, these plans confirm the expectation that utilities
anticipate any new sources of generation will be from sources that meet the
standards set in this regulation. Furthermore, these plans reflect an expectation
of relatively low demand growth due, in part, to policies and regulations to
reduce the electricity consumption such as energy efficiency regulations and
policies, evolution of the Smart Grid, and demand response measures.
4.4.2 Alternative Scenarios from AEO 2014
As described in the previous section, in addition to the EPA's own analysis, the EPA
reviewed ElA's recent forecasts of new capacity in the electricity sector for the AEO 2014. The
AEO 2014 reference case forecasts no new non-compliant capacity would be built. Power sector
modeling by EIA also projects that their conclusion of there being no new coal-fired capacity
built in the analysis period is robust under a range of alternative assumptions that influence the
industry's decisions to build new power plants. For example, EIA typically supplements the AEO
with scenarios that explore key market, technical, and regulatory issues. Of the 31 scenarios
contained in the AEO 2014, none project new coal-fired capacity in the analysis period used by
the EPA for this RIA, including the four scenarios that may be considered most favorable to the
development of coal-fired capacity displayed in Table 4-3.
23 In January 2015 West Virginia repealed the West Virginia Alternative Renewable Energy Portfolio Act, which was
enacted in 2009. E.g, http://www.govemor.wv.gov/media/pressreleases/2015/Pages/GOVERNOR-TOMBLIN-
APPROVES-REPEAL-OF-ALTERNATIVE-RENEWABLE-ENERGY-PORTFOLIO-ACT.aspx
24 See Integrated Resource Plan Technical Support Document for more information.
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Table 4-3. AEO 2014 Reference Case and Alternative Scenario Forecasts of Unplanned
Cumulative Capacity Additions by 2020, GW
Capacity Type
Conventional Coal
Coal with CCS
Natural Gas
Nuclear
Non-Hydro Renewables
Other
Total
Reference
0
0.3
23.9
0
17.4
1.6
43.2
High
Growth
0
0.3
34.4
0
19.7
2.0
56.5
Low Coal
Cost
0
0.3
19.8
0.0
17.6
1.5
39.3
Low Gas
&OM
Resource
0
0.3
16.3
2.5
23.7
0.8
43.6
NoGHG
Concern
0
0.3
22.7
0.0
17.5
1.6
42.1
Note: The AEO 2014 scenario definitions are: High Economic Growth increases annual real GDP growth by 2.8
percent per year through 2040 (reference case GDP growth is 2.4 percent per year); Low Coal Cost assumes 2.4
percent greater regional coal mining productivity growth than in the reference case, and lower wages,
equipment, and declining transportation costs for the coal industry than in the reference case, falling to 25
percent below the reference case by 2040; Low Oil and Gas Resource reduces the ultimate estimated recovery
of shale gas, tight gas, and tight oil by 50 percent; No GHG Concern removes the perceived risk of incurring costs
under a future GHG policy from market investment decisions.
4.4.3 Power Sector Fuel Price Dynamics and Trends
Expectations about what new fossil-fired generation would serve future demand have
changed over the past decade from generating sources that use coal to those, primarily
combined cycle systems, which use natural gas. As mature technologies, the cost and
performance characteristics of conventional coal-fired capacity and NGCC are projected by the
EPA to be relatively stable over time.25 Therefore, expectations of future fuel prices play a key
role in determining the overall cost competitiveness of conventional coal-fired units versus
NGCC units.
Current and projected natural gas prices are considerably lower than observed
prices over the past decade. This is largely due to advances in hydraulic fracturing and
horizontal drilling techniques that have opened up new shale gas resources and
substantially increased the supply of economically recoverable natural gas. According to
EIA:
Shale gas refers to natural gas that is trapped within shale formations. Shales are
fine-grained sedimentary rocks that can be rich sources of petroleum and natural
gas. Over the past decade, the combination of horizontal drilling and hydraulic
25 http://www.epa.gov/airmarkets/documents/ipm/Chapter 4.pdf
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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.
Of the natural gas consumed in the United States in 2011, about 95 percent was
produced domestically; thus, the supply of natural gas is not as dependent on foreign
producers as is the supply of crude oil, and the delivery system is less subject to
interruption. The availability of large quantities of shale gas should enable the United
States to consume a predominantly domestic supply of gas for many years and produce
more natural gas than it consumes.26
The AEO 2014 projects U.S. natural gas production will increase by 13.3 trillion cubic
feet (Tcf), a 55 percent increase (from 24.3 Tcf in 2014 to 37.5 Tcf in 2040). Over 75 percent of
this forecast increase in domestic natural gas production is due the projected doubling of shale
gas production, which is forecast to increase by 10.2 TCF (from 9.6 TCF in 2014 to 19.8 TCF in
2040).27
Recent historical data reported to EIA is also consistent with these trends, with 2014
being the highest year on record for domestic natural gas production.28 Gas production in 2014
was 6.3 percent above production in 2013, which is the largest annual growth rate since 1984.
The average real (2011$) natural gas price delivered to the power sector was $4.39/MMBtu in
2014, an increase from $4.25/MMBtu in 2013.29'30
Increases in the natural gas resource base have led to fundamental changes in the
outlook for natural gas. While sources may disagree on the absolute level of increases from
shale resources, there is general agreement that recoverable natural gas resources will be
substantially higher for the foreseeable future than previously anticipated, exerting downward
pressure on natural gas prices.31'32 Modeling by the EPA and EIA incorporates the impact of
26 For more information, see: http://www.eia.gov/forecasts/archive/aeoll/IF_all.cfm#prospectshale;
http://www.eia.gov/energy in brief/about shale gas.cfm
27 AEO 2014, Appendix A, Table A14. Oil and Gas Supply
28 http://www.eia.gov/dnav/ng/hist/n9010us2a.htm
29 http://www.eia.gov/dnav/ng/hist/n3045us3A.htm; Assumes that 1TCF = 1.023 MMBtu natural gas
(http://www.eia. gov/tools/faqs/faq.cfm?id=45&t=8)
30 The relative prices of natural gas and coal rather than the price of any single fuel drive power sector investment
decisions. The projections for relative fuel prices are discussed in Section 4.4.4.
31 National Petroleum Council. 2011. Prudent Development: Realizing the Potential of North America's Abundant
Natural Gas and Oil Resources, http://www.npc.org/reports/rd.html (see Figure 1.2 on p. 47).
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these additional resources on the forecasts of the price of natural gas used by electric
generating units. The increases in the natural gas resource base are reflected not only in
current natural gas prices and projections (e.g., AEO 2014), but also in current capacity planning
by utilities and electricity producers across the country. The North American Electric Reliability
Corporation's (NERC) Long Term Reliability Assessment, which is based on utility plans for new
capacity over a 10-year period, reinforces this consensus by stating that "gas-fired generation
[is] the primary choice for new capacity."33
The EPA's and ElA's modeling frameworks are designed to reflect the longer term,
fundamentals-based perspective that electric utilities and developers employ in evaluating
capital investments, while analyzing alternative scenarios to account for broader fuel market
uncertainties. Short-term fuel price volatility is not the most relevant factor in this context
because new power plants have asset lives measured in decades, not in months or years, and
new capacity investment decisions are based on long-run expected prices, not month-to-
month, or even year-to year, variations in fuel prices. Shorter-term prices will affect how units
are dispatched, but these potential dispatch impacts are considered with other factors over a
longer time horizon and factored into the choice of which type of plant to build. In contrast,
the uncertainty surrounding long-term fuel prices will exert significantly greater influence on
the technology selected for new capacity additions. In a modeling context with perfect
foresight, this longer term uncertainty may be evaluated by the comparisons of alternative
scenarios presented throughout this chapter.
In addition to major changes in the gas supply outlook, there have been notable changes
in the coal supply outlook. Coal costs have generally increased over the past few years due
primarily to increased production costs. These costs have increased as the most accessible and
economically viable mines are depleted, requiring movement into coal reserves that are more
costly to mine. The basic trends in coal supply are not expected to change for the foreseeable
future.34
32 EIA. 2014. U.S. Crude Oil and Natural Gas Proved Reserves, 2013.
http://www.eia.gov/naturalgas/crudeoilreserves/pdf/usreserves.pdf
33 NERC, Long-Term Reliability Assessments for 2012. New capacity includes both planned and conceptual
resources as defined by NERC.
34 http://www.eia.gov/forecasts/aeo/assumptions/pdf/coal.pdf
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Taken together, current and expected natural gas and coal market trends are
contributing to a recent fundamental shift in the economic conditions for new power plant
development that utilities and developers have recognized and responded to in planning.35
4.4.4 Power Sector Fuel Projections
To examine the potential impacts of uncertainty inherent in natural gas and coal
markets, the EIA used scenario analysis to generate the 2020 fuel price projections in Table 4-4.
The relative prices of available fuels partially drive power sector investment decisions. Even
under scenarios where the spread between the unit price of gas and coal is highest, no
construction of new non-compliant generating capacity is projected in 2020, as shown in Table
4-3.
35 For example: "We don't have any plans to build new coal plants. So the rules won't have much of an impact.
Any additional generation plants we'd build for the next generation will be natural gas." American Electric
Power, 3/26/2012, National Journal; "As we look out over the next two decades, we do not plan to build
another coal plant.... As the evidence is coming in, [shale gas] is proving to be the real deal. If we have no
plans, as one of the largest utilities and largest users of coal in this country, no plans to build a new coal plant
for two decades, the regulations are not relevant." Jim Rogers (Duke), 3/27/2012, NPR All Things Considered.;
"If you actually look at the economics today, you would be burning gas, not coal," Jack Fusco, Calpine,
12/1/2010, Marketplace; "Coal's most ardent defenders are in no hurry to build new ones in this environment."
John Rowe, Exelon, 9/2011, EnergyBiz; "With low gas prices, gas-fired generation kind of snowplows everything
else" Lew Hay, NextEra, 11/1/2010, Dow Jones. "The Demise of Coal-Fired Power Plants" , Washington Post,
Nov 23, 2012 (new EGU construction is natural-gas fired, even in Kentucky coal country).
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Table 4-4. National Delivered 2020 Fuel Prices by AEO 2014 Scenario (2011$/MMBtu)
Scenario
Reference
High Growth
Low Growth
High Coal Cost
Low Coal Cost
High Gas/Oil Resource
Low Gas/Oil Resource
Natural Gas
4.99
5.28
4.97
5.13
4.88
4.30
5.63
Coal
2.57
2.59
2.55
2.90
2.27
2.45
2.63
Note: AEO 2014 scenario definitions: High Economic Growth assumes real GDP growth is 2.8 percent peryear
from 2012 to 2040 (base case assumes 2.4 percent); Low Economic Growth assumes real GDP growth is 1.9
percent per year High Coal Cost assumes lower regional productivity growth rates and higher wages, equipment,
and transportation costs for the coal industry; Low Coal Cost assumes greater regional productivity growth rates
and lower wages, equipment, and transportation costs for the coal industry; High Oil and Gas Resource expands
the ultimate estimated recovery of shale gas, tight gas, and tight oil by 100 percent; Low Oil and Gas Resource
reduces the ultimate estimated recovery of shale gas, tight gas, and tight oil by 50 percent.
However, given that power plants are long-lived assets, capacity planning decisions are
necessarily undertaken with a forward view of expected market and regulatory conditions. In
producing the AEO 2014, EIA capacity expansion projections are informed by a lifecycle cost
analysis over a 30-year period in which the expectations of future prices are consistent with the
projections realized in the model (i.e. the model executes decisions with perfect foresight of
future market, technical, and regulatory conditions). Therefore, the fuel prices that inform
capacity expansion decisions in 2020 are not only the prices that year, but the entire future fuel
price stream. For example, Figure 4-2 displays ElA's natural gas price projections for the
Reference Case and several key scenarios through 2050.
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• Reference
• High growth
Low growth
•High coal cost
Low coal cost
High resource
•Low resource
Figure 4-2. National Real Price of Natural Gas Delivered to EGUs for Select AEO 2014
Scenarios (2011$/MMBtu)
Note: The AEO gas price forecasts go through 2040. The AEO forecasted prices are interpolated to 2050 by
applying the average annual rate of price increase from 2035 to 2040 in each AEO scenario to all
subsequent years from 2041 through 2049.
Natural gas prices are expected to increase after 2020 in all scenarios.36 However, rising
natural gas prices through 2040 - including in ElA's low gas/oil resource scenario - are still not
sufficient to support new, non-compliant coal-fired generation through 2022 in these scenarios.
This demonstrates that natural gas prices do not have to continue at currently low levels for
NGCC to maintain its economic advantage over coal-fired technologies.
While the uniformity of EIA scenarios in projecting no new, non-compliant coal-fired
capacity through the analysis period is compelling, the scenario projections cannot fully
illustrate the extent of the economic advantage that NGCC maintains over conventional coal,
only that the advantage remains intact across a broad range of market and technical scenarios.
To identify potential market conditions that could fully erode the cost advantages of NGCC over
' Coal prices are also expected to rise in all scenarios.
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coal-fired technologies during the analysis period, the unit-level engineering cost analysis in
section 5.4 compares these technologies. That analysis builds on the unit-level cost
comparisons presented in the following sections of this chapter.
4.5 Levelized Cost of Electricity Analysis
New capacity projections from the EPA and EIA reviewed in the previous section
indicate that the NSPS is not projected to require changes in the design or construction of new
EGUs from what would be expected in the absence of the rule. Thus, under both the baseline
projections and alternative scenarios analyzed in AEO 2014, the final ECU New Source GHG
Standards are projected to result in negligible emission reductions, quantified benefits, or costs.
To further examine the robustness of these conclusions the EPA conducted additional
analysis using the levelized cost of electricity (LCOE) for different types of new generation
technologies. The LCOE is a widely used metric that represents the cost, in dollars per output,
of building and operating a generating facility over the entirety of its economic life. Evaluating
competitiveness on the basis of the LCOE is particularly useful in establishing cost comparisons
between generation types with similar operating characteristics but with different cost and
financial characteristics. The typical cost components associated with the LCOE include capital,
fixed operating and maintenance (FOM), variable operating and maintenance (VOM),
transportation, storage and monitoring (TS&M) and fuel. (See preamble section V. H. 5.)
4.5.1 Overview of the Concept of Levelized Cost of Electricity
The levelized capital and FOM costs may be calculated by taking the annualized capital
and FOM (expressed in $/kW-yr) costs and spreading the expense over the annual generation
of the facility using the expected average annual capacity factor (the percent of full load at
which a unit would produce its actual annual generation if it operated for 8,760 hours). The
annualized capital cost (expressed in $/kW-yr) is the product of the $/kW capital cost and the
capital recovery factor (CRF). A CRF may be calculated using the project's interest rate and
book life.37
The VOM cost, which is already expressed in terms of cost per unit output, may be
presented with or without the fuel expense. The fuel expense is typically the largest
component of VOM costs (non-fuel components to VOM include start-up fuel, consumables,
37 The interest rate assumed for NGCC and CT projects is 9.06 percent; the interest rate assumed for coal-fired
projects is 9.57 percent. All three types of projects are assumed to have a 30-year book life, resulting in a
capital recovery factor of 9.78 percent for NGCC and CT projects and 10.23 percent for coal-fired projects.
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inspections, etc.) and for certain capacity types - such as NGCC - fuel expense may represent
the majority of the LCOE.
Because levelized costs consider the entire lifecycle of the facility, fuel expenses are
represented by the levelized fuel price which captures the forecast of annual delivered fuel
prices over the economic life of the facility at a given discount rate.38 Levelizing fuel prices
recognizes the necessity to consider the trajectory of fuel costs over the facility's entire
economic life.
It should be noted that there are other important considerations beyond the LCOE that
impact power plant investment decisions. New power plant developers must consider the
particular demand characteristics in any particular region, the existing mix of generators,
operational flexibility of different types of generation, prevailing and expected electricity prices,
other potential revenue opportunities (e.g., the capacity value of a particular unit, where
certain power markets have mechanisms to compensate units for availability to maintain
reliability, sale of co-products, etc.), and the varying financial risks associated with different
generation technologies. Broader system-wide power sector modeling - such as the analyses
conducted by the EPA and EIA - is able to more effectively capture some of these
considerations.
4.5.2 Cost and Performance of Technologies
This section reports the LCOE of individual technologies that are affected EGUs of this
final rule. These are compared in the following sections. The NGCC and coal-fired generation
technology cost and performance assumptions that form the basis for the LCOE analysis in this
RIA are from the DOE's National Energy Technology Laboratory (NETL).39 NETL cost and
38 As an illustration of applying a discount rate to a stream of future fuel prices, the levelized fuel price will be less
than the mean fuel price if prices are increasing, equal to the mean if fuel prices are constant, and greater than
the mean if fuel prices are declining. The weighting of nearer-term prices through the application of a discount
rate is consistent with modeling economic behavior of investors. The EPA used a 5 percent discount rate to
calculate levelized fuel prices, a value consistent with the discount rate embedded in IPM. The model applies a
discount rate of 4.77 percent for optimizing the sector's decision-making over time. IPM's discount rate,
designed to represent a broad range of private-sector decisions for power generation, rates differs from
discount rates used in other analyses in this RIA, such as the benefits analysis which each assume alternative
social discount rates of 3 percent and 7 percent. These discount rates represent social rates of time preference,
whereas the discount rate in IPM represents an empirically-informed price of raising capital for the power
sector. Like all other assumed price inputs in IPM, the EPA uses the best available information from utilities,
financial institutions, debt rating agencies, and government statistics as the basis for the capital charge rates
and the discount rate used for power sector modeling in IPM.
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performance characteristics were selected for coal-fired technologies because the NETL
estimates were unique in the detail of their cost and performance estimates for a range of
capture levels for both new super critical pulverized coal (SCPC) and integrated gasification
combined cycle (IGCC) facilities.40'41 In particular, the NETL costs released in 2015 include vendor
quotes for new technology deployed. The use of NETL cost and performance characteristics also
allows for comparisons to be made across generating technologies using a single, internally
consistent framework. The CCh capture sensitivity analysis included an evaluation of the cost,
performance, and environmental profile of these facilities under different configurations that
were tailored to achieve a specific level of carbon capture. For simple cycle CTs, NETL cost and
performance estimates were not available or sufficiently recent so the EPA adopted ElA's AEO
2014 estimates of the LCOE.
To represent a new SCPC facility, NETL assumed a new boiler with a combination of low-
NOx burners with overfire air and a selective catalytic reduction system for NOx control. The
plant was assumed to have a fabric filter and a wet limestone flue gas desulfurization scrubber
for particulate matter and SCh control, respectively. For configurations including CCS, the plant
was assumed to have a sodium hydroxide polishing scrubber to ensure that the flue gas
entering the CCh capture system has a SCh concentration of 10 parts per million or less. The
SCPC unit treating a slip stream with partial post-combustion CCS were assumed to be
equipped with the CCh removal system designed by Shell Cansolv, the system currently in full-
40 All potential build types are compliant with all current environmental regulations, including the EPA's MATS.
41 The NETL cost data intend to represent the next commercial offering, and relies on vendor cost estimates for
component technologies. It also applies process contingencies at the appropriate subsystem levels in an
attempt to account for expected but undefined costs (a challenge for emerging technologies). The cost
estimates for plant designs that only contain fully mature technologies which have been widely deployed at
commercial scale (e.g., pulverized coal power plants without CCh capture) reflect nth-of-a-kind (NOAK) on the
technology commercialization maturity spectrum. The costs of such plants have dropped over time due to
"learning by doing" and risk reduction benefits that result from serial deployments as well as from continuing
research and development. The cost estimates for plant designs that include technologies that are not yet fully
mature (e.g., IGCC and any plant with CCh capture) use the same cost estimating methodology as for the
mature plant designs, which does not fully account for the unique cost premiums associated with the initial,
complex integrations of emerging technologies in a commercial application. Thus, it is anticipated that initial
deployments of the IGCC and capture plants may incur costs higher than those reflected within this report.
Actual reported project costs for all of the plant types are also expected to deviate from the cost estimates in
this report due to project- and site-specific considerations (e.g. contracting strategy, local labor costs, seismic
conditions, water quality, financing parameters, local environmental concerns, weather delays, etc.) that may
make construction more costly. Such variations are not captured by the reported cost uncertainty.
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scale commercial use at the Boundary Dam facility.42 Estimated costs for the system reflect the
latest vendor quotations.
Specific to the partial capture configurations for SCPC, the NETL study identified two
options. The first option identified was to process the entire flue gas stream through the
capture system, but at reduced solvent circulation rates. The second option was to maintain the
same high solvent circulation rate and stripping steam requirement as would be used for full
capture, but only treat a portion of the total flue gas stream. The NETL report determined that
this "slip stream" approach was the most economical because a reduction in flue gas flow rate
would: (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce the size of
the C02 absorption columns; and (3) trim the cooling water requirement of the direct contact
cooling system.43 The "slip stream" approach - which leads to lower capital and operating costs
- was therefore adopted by the EPA for cost and performance estimates under partial capture.
44The technology cost and performance characteristics utilized by the EPA in developing the
LCOE estimates discussed in this chapter and Chapter 5 are listed below in Table 4-5.
42 NETL 2015 at 59, 137.
43 NETL based this determination primarily upon a review of the literature. See page 2 of
http://www.netl.doe.gov/energy-analvses/pubs/Gerdes-08022011.pdf
44 For additional detail and discussion on the specific technology configurations selected for this analysis, please
refer to the preamble.
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Table 4-5. Technology Cost and Performance Specifications (2011$)
Capacity
Type
Capital Cost
($/MWh)
Fixed
Operations &
Maintenance
($/MWh)
Variable
Operations &
Maintenance
($/MWh)
TS&M
($/MWh)
Level ized
Fuel Cost
($/MWh)
Net Plant
HHV
Efficiency (%)
NGCC
13
1.8
42
50.2
SCPC
SCPC w/
Partial CCS
(1,400
Ib/MWh
gross)
SCPC Co-
Firing
Natural Gas
(1,400
Ib/MWh
gross)
IGCC
IGCC Co-
Firing
Natural Gas
(1,400
Ib/MWh)
39
51
10
11
10
25
26
39
54
54
10
14
14
34
26
28
40.7
39.2
40.3
39.0
39.0
Notes: Cost from NETL 2015. The coal assumed is a bituminous coal with a sulfur content of 2.8 percent (dry) at a real (2011$)
price of $2.94/MMBtu, consistent with NETL 2015. The analysis uses a natural gas price of $6.19. NETL uses a high-risk financial
structure resulting in a capital charge factor (CCF) of 0.124 to evaluate the costs of all cases with C02 capture (non-capture case
uses a conventional financial structure with a CCF of 0.116).
NETL (2015) explains that there are a range of future potential costs that are up to 15 percent below, or 30 percent above their
central estimate, consistent with a "feasibility study" level of design engineering applied to the various cases in this study. The
value of the studies lie not in the absolute accuracy of the individual case results but in the fact that all cases were evaluated
under the same set of technical and economic assumptions. This consistency of approach allows meaningful comparisons
among the cases evaluated.
4.5.3 Levelized Cost of Electricity of New Generation Technologies
To support and provide context for the sectoral modeling results presented above, this section
presents two LCOE comparisons:45
45 As the sectoral modeling may not capture all considerations, particularly local ones, under which a non-
compliant coal unit may be built, Section 5.5 provides a comparison of the cost of a non-compliant coal unit to
a compliant coal unit, either with partial CCS or natural gas co-firing. The analysis demonstrates that the
standard could be accommodated and would not, based on the cost increment of constructing and operating a
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1. NGCC to non-compliant Coal - to demonstrate the cost advantages of NGCC across a
range of natural gas prices and regional market conditions.
2. NGCC to CT - to demonstrate the low likelihood of a new combustion turbine being
built with the expectation of meeting the applicability criteria based on utilization
and thus being covered by these standards.
The illustrative unit cost and performance characteristics used in this section assume
representative costs associated with spatially dependent components, such as connecting to
existing fuel delivery infrastructure and the transmission grid. In practice units may experience
higher or lower costs for these components depending on where they are located. It should be
noted that the LCOE comparisons presented in this section only represent the cost to the
generator and do not reflect the additional social costs that are associated with emissions of
greenhouse gases or other air pollutants. A broader consideration of the health and welfare
(i.e., non-health benefits) impacts of emissions from these technologies is considered in
Chapter 5.
It is also important to note that both the EIA and the EPA apply a climate uncertainty
adder (CUA) - represented by a three percent increase to the weighted average cost of capital -
to new, conventional coal-fired capacity types.46 EIA developed the CUA to address
inconsistencies between power sector modeling absent GHG regulation and the widespread
use of a cost of CCh emissions in power sector resource planning. While baseline power sector
modeling scenarios may not specify potential future GHG regulatory requirements, investors in
the industry typically incorporate some expectation of a future cost to limit CCh emissions in
resource planning evaluations that influence investment decisions. Therefore, the CUA reflects
the additional planning cost typically assigned by project developers and utilities to GHG-
intensive projects in a context of climate uncertainty. The EPA believes the inclusion of the CUA
in LCOE estimates is consistent with the industry's current planning and evaluation framework
for future projects (demonstrable through IRPs and public utility commission orders) and is
CCS, preclude new coal construction. The section also demonstrates how the cost to a non-compliant coal unit
of complying with the final standard is mitigated by the emission reduction benefits of controlling its emissions.
46 While this statement is true in the AEO Reference Case, EIA evaluates No GHG Concern where the CUA is
removed. Results from this scenario on investment in new technology are reported in Table 4-3.
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therefore pertinent when evaluating the cost competitiveness of alternative generating
technologies.47
In defining the CUA, EIA states that "the adjustment should not be seen as an increase in
the actual cost of financing, but rather as representing the implicit hurdle being added to GHG-
intensive projects to account for the possibility they may eventually have to purchase
allowances or invest in other GHG emission-reducing projects that offset their emissions."48
Therefore, the EPA recognizes the application of the CUA is context dependent. As a part of the
planning process, it is appropriately applied to evaluating prospective projects, and then
removed once a project transitions from planning to execution. While omitting the CUA is
inconsistent with an analysis considering how project characteristics and market conditions
would lead a developer or utility to select a certain project, as is the purpose of this section, for
transparency the cost estimates based on the 2015 NETL analysis for non-compliant coal-fired
projects are presented in the following analysis both with and without the CUA. All LCOE
estimates of coal-fired facilities with CCS are presented without the CUA, to represent the
reduced CCh liability associated with such technologies.
4.5.4 Levelized Cost of Electricity of NGCC and Non-compliant Coal
The EPA's base LCOE estimates for NGCC, SCPC, and IGCC are shown in Figure 4-3 by
cost component (capital, FOM, VOM, TS&M, and fuel) and assume a construction date of 2020
and an 85 percent capacity factor. Although the EPA believes that this cost data is broadly
representative of the economics between new coal and new natural gas facilities, this analysis
assumes representative new units and does not reflect the full array of new generating sources
that could potentially be built. To the extent that other types of new EGUs that would be
affected by this rule are built, they may exhibit different costs than those presented here. For
example, new conventional coal facilities of a size smaller than what is assumed in the base
estimate would tend to exhibit a relatively higher LCOE, while some technologies could
potentially display a lower LCOE if, all else equal, fuel could be obtained at a lower price than
that assumed in this analysis (such as may be the case for petroleum coke or waste coal
47 For example, a 2011 Synapse Report lists 15 utilities that adopted a value for estimating CCh emissions liability in
their integrated resource planning. http://www.synapse-energy.com/Downloads/SynapsePaper.2011-
02.0.2011-Carbon-Paper.A0029.pdf. In addition to utilities, several state commissions have mandated the
inclusion of potential financial liabilities associated with CCh emissions in long-term planning (e.g., Minnesota
utilities must adopt a price beginning in 2017).
48 http://www.eia.gov/forecasts/aeo/electricity generation.cfm
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facilities). These potential differences do not fundamentally change the analysis presented in
thisRIA.
On a levelized cost basis, NGCC is significantly cheaper than all of the non-compliant
coal-fired options. For technologies that are included in the IPM Base Case and the AEO, their
LCOE values are comparable to the LCOE values calculated from the NETL study. The difference
in the LCOE of NGCC and non-compliant coal technologies explains the finding in the sectoral
modeling described above that natural gas generation is forecast to be the source of new fossil-
fired generation.
In addition to the disparity in total LCOE, there are fundamental differences in the cost
composition between natural gas- and coal-fired facilities. NGCC costs are dominated by fuel
expense while the levelized cost of coal-fired technologies driven by capital expense.
Consequently, this section will explore the impact of changes in natural gas price and the
capital costs of coal-fired facilities to better quantify the magnitude of the relative cost
advantage NGCC exhibits over coal-fired alternatives.
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Figure 4-3. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation
Technologies by Cost Component
$125
$100
$75
o
IN
$50
$25
$0
NGCC SCPC SCPC SCPC SCPC w. IGCC
w.CUA 16% CCS co-firing
• Capital • Fixed O&M IVar. O&M TSM • Fuel
IGCC
w.CUA
IGCC w.
co-firing
Notes:
(1) The coal assumed is a bituminous coal with a sulfur content of 2.8 percent (dry) and a real delivered price of
$2.94/MMBtu consistent with NETL 2015.
(2) The levelized delivered price of natural gas is $6.19/MMBtu (2011$).
(3) SCPC and IGCC without CCS are shown first without any CUA and then with a 3 percent CUA.
(4) The cost of C02 transport, storage and monitoring (TS&M) is included as part of LCOE for SCPC with 18 percent
CCS, which captures and sells C02.
(5) A capacity factor of 85 percent is assumed across all technologies.
(6) NETL uses a high-risk financial structure resulting in a capital charge factor (CCF) of 0.124 to evaluate the costs of
all cases with C02 capture (non-capture case uses a conventional financial structure with a CCF of 0.116).
(7) For comparison, EIA estimates of levelized costs in 2019 under AEO 2014 Reference Case assumptions for SCPC
and IGCC are $94.4/MWh and $114.7/MWh ( both in 2012$), respectively, including a 3 percent CUA and
excluding transmission investment costs.49 The levelized costs presented above are based on NETL assumptions
and will necessarily differ from AEO 2014 levelized costs for a variety of reasons, including cost and performance
characteristics, financial assumptions, and fuel input prices.
1 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
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Figure 4-4 presents the LCOE of an NGCC facility at four alternative levelized natural gas
price levels. For comparison, the LCOE estimates for SCPC and IGCC (with no CCh control)
including the CUA are provided as well.50
$140
$120
^$100
o
rM
O
u
$80
$60
$40
$20
$0
$113
$118
NGCC NGCC NGCC NGCC
($6.19/MMBtu) ($10/MMBtu) ($ll/MMBtu) ($14/MMBtu)
SCPC (w. CUA) IGCC (w. CUA)
Figure 4-4. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation
Technologies Across Alternative Natural Gas Prices
It is only when natural gas prices exceed $ll/MMBtu on a levelized basis (in 2011$) that new
coal-fired generation without CCS approaches parity with NGCC in terms of the LCOE. None of
the AEO 2014 scenarios described in this chapter project national average natural gas prices
near that level.51 To achieve an $ll/MMBtu levelized price in 2020 would require a
significantly more pessimistic natural gas outlook than what is contained in AEO's low natural
gas resource scenario. To illustrate, Table 4-6 report the levelized natural gas prices (initial year
of 2020) for both a 20-year period (to accommodate the end of ElA's modeling projections in
50 Some new units could be designed to combust waste coal or petroleum coke (pet coke), which may be affected
by this rule. These technologies could exhibit different local economics, particularly in the delivered price of
fuel. From a capital and operating perspective, the EPA believes the cost and performance of these units are
broadly similar and therefore well represented by new, conventional coal-fired facilities (e.g. SCPC).
51 As noted earlier in this chapter, investment decisions require consideration of fuel price projections over long
periods of time; similarly, the power sector modeling cited here make fuel price projections over long periods
of time. Neither these modeling projections nor these LCOE calculations are meant to suggest that the gas
price could not reach as high as $10/MMBtu at any given point in time, but these analyses do not expect such a
price level to be sustained over a period of time that would influence an economic assessment of which type of
new capacity offers a better investment.
4-29
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2040) and 30-year period (calculated by continuing the projected level of price increases
through 2050).
Table 4-6. Levelized Natural Gas Prices by Select AEO 2014 Scenario (2011$/MMBtu)
Scenario
Reference
High Growth
Low Growth
High Coal Cost
Low Coal Cost
High Gas/Oil Resource
Low Gas/Oil Resource
20- Year AEO
Projection
(2020-2039)
6.07
6.32
5.78
6.19
6.03
4.80
7.70
30-YearAEO-Based
Projection
(2020-2049)
6.53
6.96
6.20
6.69
6.47
4.85
8.45
Note: Discount rate of 5 percent, consistent with IPM assumptions. The 30-year natural
gas price is calculated by applying the average annual rate of price increase from 2035 to
2040 in all subsequent years from 2041 through 2049. The scenarios are described in
Table 4-4.
As an illustration, one potential price path that would achieve a $10/MMBtu on a 20-
year levelized basis in 2020 is a natural gas price path 30 percent higher than ElA's low resource
scenario in all years (see Figure 4-5). This illustrative price path to achieve a $10/MMBtu
levelized price would result in an $11.02/MMBtu annual real price in 2030 and a
$13.81/MMBtu real price in 2040. Even on this significantly higher price path, a representative
NGCC unit would have a lower LCOE than a non-compliant coal unit. What this information
indicates is that natural gas price forecasts need to be notably higher than the highest forecast
in the AEO 2014 scenarios before we would expect that general market dynamics would favor
new non-compliant coal generation over new compliant natural gas generation as the fossil-
fuel technology of choice to satisfy demand. Chapter 5 discusses this finding further by bringing
in the consideration of the emissions damages associated with these technologies.
4-30
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$14
$12
$10
o
01
-a
$10/MMBtu Levelized Price
It is important to note that the LCOE calculations are based on assumptions regarding
the representative national cost of generation at new facilities.52 It is known that there is
significant spatial variation in the costs of new generation due to design differences, labor
productivity and wage differences, and delivered fuel prices, among other potential factors.
For example, EIA utilizes capital cost scalars to capture regional differences in labor, material
52 Actual reported project costs for all of the plant types are also expected to deviate from the cost estimates in
this report due to project- and site-specific considerations (e.g. contracting strategy, local labor costs, seismic
conditions, water quality, financing parameters, local environmental concerns, weather delays, etc.) that may
make construction more costly. Such variations are not captured by the reported cost uncertainty
4-31
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and construction costs.53 The minimum and maximum capital cost scalars across all regions in
AEO 2014 for SCPC, IGCC, and NGCC build options are presented in Table 4-7.54
Table 4-7. AEO 2014 Regional Capital Cost Scalars by Capacity Type
Minimum Capital Maximum Capital Cost
Capacity Type _ . _ .
K y yK Cost Scalar Scalar
SCPC 0.885 1.152
IGCC 0.908 1.136
NGCC 0.893 1.205
Applying the regional capital cost scalars displayed above to the base LCOE estimates
from NETL developed earlier in this section produces only a small change in the relative
competitiveness of the technologies as seen in Table 4-8.
Table 4-8. LCOE Estimates with Minimum and Maximum AEO 2014 Regional Capital Cost
Scalars (2011$/MWh)
Capacity Type
SCPC (no CCS, without CUA)
SCPC (no CCS, with CUA)
IGCC (no CCS, without CUA)
IGCC (no CCS, with CUA)
NGCC
Reference
LCOE
($/MWh)
82
94
103
118
60
LCOE Using
Minimum Capital
Cost Scalar
($/MWh)
73
83
93
108
54
LCOE Using
Maximum Capital
Cost Scalar
($/MWh)
95
108
117
135
72
The LCOE of SCPC in the lowest capital cost region still results in an LCOE that is 1
percent higher than an NGCC located in the most expensive capital cost region, even without
the CUA. (The difference is 15 percent when the CUA is included.) The IGCC LCOE is 29 percent
above NGCC in the most expensive region, even without considering the CUA.
The other primary driver in determining the regional impact on competitiveness of new
build options is delivered fuel prices. As part of the AEO, EIA releases electric power
projections- including fuel prices -for each of the 22 Electricity Market Module (EMM)
regions. The two regions with the highest projected 2020 natural gas prices in the AEO 2014
are the Western Electricity Coordinating Council/Southwest (Southwest) and the Florida
53 http://www.eia.gov/oiaf/beck plantcosts/pdf/updatedplantcosts.pdf
54 Excluding the New York City and Long Island areas, as well as those areas of the country that prohibit the
development of new, non-compliant coal-fired facilities.
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Reliability Coordinating Council (FRCC). The 20-year levelized natural gas and coal price
forecasts (2020-2039) in the AEO 2014 reference case are displayed in Figure 4-6 for both
regions.
FRCC
WECC-Southwest
I Gas • Coal
Figure 4-6. Levelized Regional Fuel Price from AEO 2014 Reference Case, 2020-2039
(2011$/MMBtu)55
The FRCC region experiences the highest overall natural gas prices as well as a greater
unit price differential between coal and natural gas prices under the AEO projections. The
impact on the LCOE of the SCPC, IGCC, and NGCC technologies without CCS is reported in Table
4-9 for both sets of fuel prices, as well as the national average for comparison.
Table 4-9. LCOE Estimates For Minimum and Maximum AEO 2014 Regional Fuel Prices
(2011$/MWh)
Capacity Type
SCPC (no CCS, without CUA)
SCPC (no CCS, with 3% CUA)
IGCC (no CCS, without CUA)
IGCC (no CCS, with 3% CUA)
NGCC
LCOE Using
National
Average Fuel
Prices
($/MWh)
82
94
103
118
60
LCOE Using FRCC
Fuel Prices
($/MWh)
94
105
114
130
87
LCOE Using
Southwest Fuel
($/MWh)
82
93
102
118
70
' Assuming 5 percent discount rate.
4-33
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Due to the greater fuel price differential, the more favorable region for the
development of coal-fired facilities from an LCOE perspective is the FRCC, where the regional
fuel prices reduce the LCOE advantage of NGCC to $7/MWh over SCPC (compared with a
$22/MWh advantage with national fuel prices) and $27/MWh over IGCC (compared with a
$43/MWh advantage with national fuel prices.
In conclusion, even the most favorable combination of regional variability in capital
costs and delivered fuel prices represented by EIA are insufficient to support new, unplanned,
conventional coal-fired capacity in the analysis period.
4.5.5 Levelized Cost of Simple Cycle Combustion Turbine and Natural Gas Combined Cycle
Simple cycle combustion turbines (CTs) fulfill a fundamentally different function in
power sector operations than that of NGCC and fossil-fired steam facilities. CTs are designed to
start quickly in order to meet demand for electricity during peak operating periods and are
generally less expensive to build on a capital cost basis, but are also less fuel efficient than
combined cycle technology, which employs heat recovery systems. Due to lower fuel
efficiencies, CTs produce a significantly higher cost of electricity (cost per kWh) at higher
capacity factors and consequently are typically utilized at levels below the applicability
requirements for EGUs affected by the ECU New Source GHG Standards. New CTs are expected
to most often be built to ensure reserve margins are met during peak periods (typically in the
summer), and in some instances be able to generate additional revenues by selling capacity into
power markets. The EPA expects that any CT unit built in the period of analysis would be
classified as a non-base load unit and would not incur any costs to meet the relevant standard.
To illustrate the economic incentives of utilizing combustion turbines in an intermediate
and base load mode of operation, Figure 4-7 presents the LCOE estimates for a new
conventional CT, Advanced CT and NGCC at increasing capacity factors. The estimates utilize
the AEO 2014 Reference Case levelized natural gas price for 2020.
4-34
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$350
$300
$250
$200
§. $150
LU
o
U $100
$50
$0
0% 20% 40% 60% 80%
Capacity Factor
NGCC Conventional CT Advanced CT
100%
Figure 4-7. Levelized Cost of Electricity Across a Range of Capacity Factors, CT and NGCC
(2011$/MWh at $6.07/MMBtu Levelized Natural Gas Price)
In the LCOE figure above, utilizing a CT for generation is less expensive than an NGCC
unit only at capacity factors of less than 20 percent.56 If expected utilization is greater than 20
percent, it can reasonably be expected that a utility or developer would seek to deploy NGCC
over CT for a host of economic, environmental, and technical reasons. Furthermore, the design
net efficiencies for currently available potentially impacted aeroderivative simple cycle
combustion turbines range from approximately 32 percent for smaller designs to 39 percent for
the largest intercooled designs. The efficiencies of industrial frame units range from 30 percent
for smaller designs to 36 percent for the largest units.57 The EPA therefore expects any CT unit
built in the period of analysis to be classified as a non-base load unit.
4.6 Macroeconomic and Employment Impacts58
These final ECU New Source GHG Standards are anticipated to result in negligible
emission changes in the electricity sector in the analysis period, and therefore are anticipated
to impose negligible costs or quantified benefits. The EPA typically analyzes impacts on
56 CT cost, performance, and financial assumptions from AEO 2014.
57 These efficiency values follow the methodology the EPA has historically used and are based on the higher
heating value (HHV) of the fuel. Low heating value efficiency values would be somewhat higher.
58 The employment analysis in this RIA is part of the EPA's ongoing effort to "conduct continuing evaluations of
potential loss or shifts of employment which may result from the administration or enforcement of [the Act]"
pursuant to CAA section 321(a).
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employment or labor markets associated with rules based on the estimated compliance costs
and other energy impacts (e.g., changes in electricity prices), 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 rule, there are no notable macroeconomic or employment impacts
expected as a result of this rule.
4.7 References
Fann, N., K.R. Baker, C.M. Fulcher. 2012. Characterizing the PM2.5-related health benefits of
emission reductions for 17 industrial, area and mobile emission sectors across the U.S.
Environment International, Volume 49, 15 November 2012, Pages 141-151, ISSN 0160-
4120, http://dx.doi.0rg/10.1016/i.envint.2012.08.017.
Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz,
and W.H. White. 2009. "Reanalysis of the Harvard Six Cities Study and the American
Cancer Society Study of Particulate Air Pollution and Mortality." Special Report to the
Health Effects Institute. Cambridge, MA. July.
Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. "Chronic Exposure to Fine Particles and
Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009."
Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.
Malik, N.S. 2010, November 1. NextEra CEO sees clean energy standards replacing recent
climate proposals [Radio transcript]. Dow Jones News [Online]. Available: Dow Jones
Interactive Directory: Publications Library.
Mufson, S. January 2, 2011. "Coal's Burnout.' The Washington Post. Retrieved from:
http://www.washingtonpost.com/newssearch.National Energy Technology Laboratory
(NETL). Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide
Capture. Revised Sept. 16, 2013. Available online at: http://www.netl.doe.gov/energv-
analyses/pubs/Gerdes-08022011.pdf.
National Energy Technology Laboratory (NETL). Cost and Performance Baseline for Fossil Energy
Plants Supplement: Sensitivity to C02 Capture Rate in Coal-Fired Power Plants. June 22,
2015. Available online at: http://www.netl.doe.gov/research/energv-analvsis/energv-
baseline-studies.
Rosenberg, M. 2011, September/October. "The Reign of Cheap Gas." EnergyBiz Magazine.
Retrieved from http://www.energybiz.com/magazine/article/234577/reign-cheap-gas.
Tong, S. 2010, November 1. Placing Bets on Clean Energy. [Radio transcript]. American Public
Media: Marketplace [Online]. Available: Marketplace Programs on Demand.
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National Petroleum Council. 2011. Prudent Development: Realizing the Potential of North
America's Abundant Natural Gas and Oil Resources. Available online at:
http://www.npc.org/reports/rd.html.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010. Available
online at: http://www.eia.gov/oiaf/archive/aeolO/index.html.
U.S. Energy Information Administration (U.S. ElAa). Annual Energy Outlook 2014. 2014.
Available online at: http://www.eia.gov/forecasts/aeo/.
U.S. Energy Information Administration (U.S. EIA). U.S. Crude Oil and Natural Gas Proved
Reserves, 2013Available online at:
http://www.eia.gov/naturalgas/crudeoilreserves/pdf/usreserves.pdf
U.S. Energy Information Administration (U.S. ElAb). Assumptions to the Annual Energy Outlook
2014. 2014. Available online at:
http://www.eia.gov/forecasts/aeo/assumptions/pdf/0554(2014).pdfU.S. Environmental
Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis for the Final Mercury
and Air Toxics Standards. Office of Air Quality Planning and Standards, Research Triangle
Park, NC. December. Available on the Internet at
http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the
Final Revisions to the National Ambient Air Quality Standards for Particulate Matter.
Office of Air Quality Planning and Standards, Research Triangle Park, NC. December.
Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2013a. Technical Support Document
Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of
Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on
the Internet at:
http://www.epa.gov/airquality/benmap/models/Source Apportionment BPT TSD 1 3
1 13.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2013b. Integrated Science Assessment for
Ozone and Related Photochemical Oxidants. EPA/600/R-10/076F. Research Triangle
Park, NC: U.S. EPA. February. Available on the Internet at
http://oaspub.epa.gov/eims/eimscomm.getfile7p download id=511347.
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CHAPTER 5
ANALYSIS OF ILLUSTRATIVE BENEFIT-COST SCENARIOS FOR NEW SOURCES
5.1 Synopsis
The previous chapter of this regulatory impact analysis (RIA) presents the U.S.
Environmental Protection Agency's (EPA) analysis and projections from the U.S. Energy
Information Administration (EIA) that support the conclusion that the ECU New Source
Standards1 will result in negligible costs and benefits in the period of analysis. The EPA
recognizes that this conclusion is based on underlying expected economic conditions (e.g., fuel
prices) and assumptions about considerations investors would weigh in deciding whether to
build new non-compliant coal-fired power plants. Extending the analysis in the previous chapter
that considers those factors in evaluating the robustness of the findings from the sectoral
perspective, this chapter presents the results of several illustrative analyses that show, under a
range of alternative conditions, the potential costs and benefits of these standards for
individual investments that provide base load dispatchable generation. We evaluate conditions
under which different generator types are constructed in lieu of a non-compliant supercritical
coal unit and estimate the benefit of adopting the investment that is compliant with the
standards. This also allows us to consider the costs and benefits of a situation where an
operator chooses to build a new coal-fired unit that is compliant with the standard.
While the analysis in Chapter 4 focuses on national level conditions, the analysis in this
chapter explores the potential impacts to individual investments. The analysis in this chapter
finds that under unlikely conditions in which the EPA's conclusions regarding the future
economic competitiveness of new non-compliant coal-fired units relative to other new
generation technologies no longer apply, or in specific situations where an operator chooses to
build a coal-fired unit, that the quantifiable benefits of the standards outweigh the costs under
a range of assumptions.
5.2 Comparison of Emissions from Generation Technologies
As discussed in Chapter 4, natural gas combined cycle (NGCC) units are on average
expected to be more economical to build and operate than new coal units (see section 4.5).
Therefore, as our point of departure for comparing the costs and benefits of an individual
investment decision, we evaluate the private cost of a new NGCC unit that is compliant with the
finalized standards with the private cost of a new, non-compliant conventional supercritical
1 The standards for modified and reconstructed sources are addressed in Chapter 6.
5-1
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pulverized coal (SCPC) coal-fired unit.2 When evaluating the costs and benefits associated with
these standards, it is also important to understand the difference in emissions associated with
these units. In addition to being more economical, new NGCC units have lower emission
profiles for CCh and criteria air pollutants than new coal units. For example, a typical new SCPC
facility that burns bituminous coal in compliance with current utility regulations (e.g., the
Mercury and Air Toxics Standards (MATS)) would have considerably greater CCh, sulfur dioxide
(S02), nitrogen dioxide (NOX), toxic metals, acid gases, and particulate emissions than a
comparable NGCC facility.
Table 5-1 shows that emissions of these pollutants from a typical new NGCC unit are
significantly lower than those from a new coal-fired unit.3 The emission characteristics are
based on, and thus consistent with, the cost and performance assumptions of the illustrative
units described in the levelized cost of electricity (LCOE) analysis in section 4.5. That is, these
are base load units of the same net capacity operating at an 85 percent capacity factor, the coal
unit is assumed to be using bituminous coal with a sulfur content of 2.8 percent dry, they are in
compliance with current utility regulations (e.g., the MATS), etc. The typical new NGCC unit
would emit about 1.9 fewer million tons of CCh per year than the typical new SCPC unit, as well
as roughly 1,700 fewer tons of SCh and about 1,300 fewer tons of NOX per year than the SCPC
unit. Table 5-1 also provides comparable information for a representative integrated
gasification combined cycle (IGCC) unit providing the same amount of electricity and using the
same coal. The new IGCC unit would emit less CCh, SCh and NOX than a typical coal-fired SCPC
unit, but has higher emissions of each of these pollutants than a new NGCC unit. Reductions in
SCh emissions are a particularly significant driver for monetized health benefits, as SCh is a
precursor to the formation of particulates in the atmosphere, and particulates are associated
with premature death and other serious health effects. NOx is both an ozone precursor, and is
associated with formation of secondary fine nitrate PM2.5. Both ozone and fine nitrate PM2.5
are associated with significant adverse health effects, including premature mortality. Further
information on these pollutants' health and welfare effects is described in Chapter 3.
Table 5-1 also shows the representative coal units' emissions of these same pollutants
when meeting the promulgated standard of performance of 1,400 Ib CCh/MWh. Two compliant
2 As discussed in section 4.4.1 and in the preamble, we expect new NGCC capacity built in the period of analysis
will be compliant with the standard even in the absence of the standard. As a result, there are no compliance
costs anticipated for new NGCC units.
3 Estimated emissions of CC>2, SOz, and NOx for the illustrative new coal and NGCC units could vary depending on a
variety of assumptions including heat rate, fuel type, and emission controls, amongst others.
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SCPC units are presented: one uses carbon capture and storage (CCS) and another that co-fires
natural gas. The compliant IGCC unit is assumed to co-fire natural gas. For the compliant SCPC
unit using CCS, in addition to reductions of CCh, SCh emissions would also decrease due to the
need to scrub acid gases to very low levels prior to carbon capture in order to prevent
degradation of the solvent involved in the capture process.4 The NOx emission rate, measured
on a net-basis, is slightly lower for non-compliant units than both compliant SCPC units. This is
because there is a fuel efficiency loss associated with both compliance technologies and
because NOx emission rate standards for new sources are on a gross-basis. While we account
for these increases in the NOx emission rate in the analysis below, in some cases, NOx emissions
from fossil-fired sources are also subject to mass limits on the total NOx emissions across EGUs
(e.g. in states subject to the Cross-State Air Pollution Rule annual NOx program), so these
emissions may be offset by NOx reductions from other generating units.
4 See NETL 2015 at 161.
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Table 5-1. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired
Generating Units
Nature I Gas CC
SCPC
SCPC+Partial CCS
(1,400 Ib/MWh
Gross)
SCPC+Co-Fire Nat
Gas
IGCC
IGCC+Co-Fire Nat
Gas
S02
NOx
C02
Emissions
84
130
1.6
million
Emission
Rate
0.0041
0.061
800
Emissions
1,500
1,500
3.5
million
Emission
Rate
0.71
0.74
1,700
Emissions
1,200
1,500
3.1
million
Emission
Rate
0.61
0.75
1,500
Emissions
1,500
1,500
3.0
million
Emission
Rate
0.71
0.74
1,500
Emissions
18
1,100
3.5
million
Emission
Rate
0.0087
0.52
1,700
Emissions
18
1,100
3.4
million
Emission
Rate
0.0087
0.52
1,700
Notes: Emissions from NETL 2015. Emissions are in short tons/year and Emission Rates are in net Ib/MWh. Values rounded to two significant digits. Emission
characteristics are based on, and thus consistent with the cost and performance assumptions of, the illustrative units described in LCOE analysis in section 4.5
(i.e., these are base load units running at 85 percent capacity factor, all coal units are assumed to be using bituminous coal with a sulfur content of 2.8 percent
dry, etc.). The tons of emissions are estimated for a coal-fired facility that achieves the gross-output standard of 1,400 Ib/MWh and presented in this table on a
net output basis. For the post-combustion CCS system assumed in the SCPC case, acidic gases (e.g., SCh, HCI) need to be scrubbed to very low levels prior to
going to the CCS system to avoid degradation of the solvent. Therefore, SC>2 emissions are lower in the case of the SCPC unit with partial CCS. See preamble for
discussion about the format of the standard. Here we further assume all units are of the same capacity (600 MW net).
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5.3 Comparison of Health and Climate Impacts from Generation Technologies
As discussed in the previous section, the emissions of GHGs and other pollutants
associated with new sources of electricity generation are greater for coal-fired units than for
NGCC units. Reducing the emissions associated with electricity generation results in climate,
human health, and non-health benefits.
To consider the health and climate benefits associated with the adoption of lower
emitting new generation technologies, we apply the 2022 benefit values discussed in Chapter 3
to the differences in illustrative emission profiles between the technologies in Table 5-1.1
Specifically, we multiply the difference in CCh emissions between two technologies by the
estimates of the social cost of carbon dioxide (SC-CCh) (Table 3-1), multiply the difference in
SCh and NOx emissions by the PM2.5-related SCh and NOx benefit per ton (BPT) estimates (Table
3-2), and add those values to get a measure of the 2022 benefits attributable to differences in
emissions of adopting the lower emitting new generation technology. We subsequently divide
by the amount of generation (in MWh) underlying the annual emissions estimates to derive the
benefits attributable to the differences in emissions per unit of generation.
Only the direct emissions of CCh, SCh, and NOx are considered in this illustrative
exercise. Other air and water pollutants emitted by these technologies and emissions from the
extraction and transport of the fuels used by these technologies are not considered. For
example, coal has higher mercury emissions than natural gas, but the relative benefits from the
difference in mercury emissions are not considered. A similar example of emissions not
considered are those of directly emitted PIVh.s. Furthermore, there may be differences in
upstream greenhouse gas emissions (in particular, methane) from different technologies which
were not quantified for this assessment.
Table 5-2 reports the 2022 incremental climate and health benefits associated with a
new NGCC unit relative to a new coal-fired SCPC and IGCC units, given different mortality risk
studies and assumptions about the discount rate. These benefits are based on the emissions
presented in Table 5-1. The benefits presented in Table 5-2 are estimated on an output basis to
enable easier comparisons to the potential costs of investing in a new non-compliant coal-fired
1 Due to data limitations, we are not able to estimate annualized benefits from the stream of emissions over the
lifetime of the generating technologies. Because the benefit per-ton of emission reductions increases overtime,
due in part to population growth, the single year estimate results in a conservative comparison of benefits to
costs where LCOE represents annualized lifetime costs of generating technologies.
5-5
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unit relative to a new NGCC unit. These incremental benefits should be relatively invariant
across natural gas prices and other economic factors. Depending on the discount rate and
mortality risk study used, 2022 incremental benefits associated with generation from a
representative new NGCC unit relative to a new coal-fired SCPC or IGCC unit are $7.0 to $91 per
MWh (2011$).2
The health and non-health benefits associated with reduced emissions can depend on a
number of factors, including the specific fuels combusted and the location of the emissions.
While the benefits of reduced CCh emissions do not depend on the location of generation
because the location of CCh emissions does not influence their impact on the evolution of
global climate conditions, the precise incremental health co-benefits will be location specific
and depend on the specific fuels used. However, these factors will not change the qualitative
conclusion. There will be incremental climate and human health benefits associated with a new
NGCC unit relative to a new coal-fired unit, independent of the location.
2 Different discount rates are applied to SC-CCh than to the other benefit estimates because CCh emissions are
long-lived and subsequent damages occur over many years. Moreover, several rates are applied to SC-CCh
because the literature shows that it is sensitive to assumptions about discount rate and because no consensus
exists on the appropriate rate to use in an intergenerational context. The SC-CCb interagency working group
centered its attention on the 3 percent discount rate but emphasized the importance of considering all four SC-
CO2 estimates. See the 2010 SC-CO2 TSD. Docket ID EPA-HQ-OAR-2009-0472-114577 or
http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdffor
details.
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Table 5-2. Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Illustrative New
Natural Gas Combined Cycle Generation Relative to New Non-Compliant SCPC or IGCC
Coal Generation in 20221
SCPC IGCC
COz-Related Benefits using SC-CO2
5% Discount Rate $5.7 $5.8
3% Discount Rate $19 $19
2.5% Discount Rate $28 $28
3% Discount Rate (95th percentile) $56 $57
Total PM2.5-Related Co-Benefits from SO2 and NOX Changes
3% discount rate
Krewski et al. (2009) $15 $1.3
Lepeule etal. (2012) $34 $3.0
7% discount rate
Krewski et al. (2009) $14 $1.2
Lepeule etal. (2012) $31 $2.7
Combined COz-Related and PM2.5-Related Benefits
Discount Rate Applied to PM2.s-Related Benefits
(range based on adult mortality function)
SC-CO2 Discount Rate
5% Discount Rate
3% Discount Rate
2.5% Discount Rate
3% Discount Rate (95th percentile)
3%
$21 to $40
$34 to $53
$43 to $62
$72 to $91
7%
$19 to $37
$33 to $50
$42 to $59
$70 to $87
3%
$7.1 to $8.8
$20 to $22
$30 to $31
$59 to $60
7%
$7.0 to $8.5
$20 to $22
$30 to $31
$58 to $60
Notes: The emission rates and operating characteristics of the units being compared in this table are reported in Table 5.1. Benefits are
estimated for a 2022 analysis year. The range of benefits within each SC-C02 value and discount rate for PM2.5-related benefits pairing
reflects the use of two core estimates of PM2.5-related premature mortality.2 The EPA has evaluated the range of potential impacts per
MWh by combining all SC-C02 values with health benefits values at the 3 percent and 7 percent discount rates. Combining the 3 percent
SC-C02 values with the 3 percent health benefit values assumes that there is no difference in discount rates between intragenerational
and intergenerational impacts. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor
reductions (Table 3-2), which are representative of 2022.
1 This analysis assumes representative new units and does not reflect the full array of new generating sources that could
potentially be built (e.g., a comparison of a small new conventional coal-fired unit with a small natural gas-fired unit, or
a comparison of a waste coal or petroleum coke-fired unit to a natural gas-fired unit of a comparable size and capacity
factor). However, the damages associated with other units that could be built, and which would be subject to this rule,
would not change noticeably (i.e., these new facilities would be subject to emissions standards for other pollutants and
would emit similar levels of SCh, NOx, and CCh, on an output basis) except for differences in location, as discussed
previously.
2 The range of estimated benefits for each discount rate is due to the EPA's use of two alternative primary estimates of
PIVh.s-related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a higher primary estimate
based on Lepeule et al. (2012).
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The conclusion from this analysis is that there are significant environmental and health
benefits associated with electricity generation from a representative new NGCC unit relative to
a new non-compliant coal-fired unit. Other studies of the social costs of coal and natural gas-
fired generation provide similar findings (Muller et. al., 2011; NRC, 2009).l
As explained previously, the power sector has moved away from the construction of
coal-fired power plants in favor of other generation (e.g., natural gas-fired power plants) due, in
part, to the significant cost differential. Even so, it is possible that a limited number of currently
unplanned coal-fired power plants would be constructed through 2022. In these circumstances,
the construction of compliant coal-fired units in place of non-compliant coal-fired units would
result in relative climate and human health and non-health benefits. Table 5-3 reports the 2022
incremental benefits associated with a new SCPC coal-fired unit with CCS relative to a new SCPC
coal-fired unit, given different mortality risk studies and assumptions about the discount rate.
The values are calculated based on the emissions presented in Table 5-1. Depending on the
discount rate used and mortality risk study used, 2022 incremental benefits associated with
generation from a representative new SCPC coal-fired unit with CCS relative to a new SCPC unit
without CCS are $3.1 to $18 per MWh (2011$), factoring in the disbenefit from a small increase
in NOX emissions.2 These incremental benefits will be referenced in the analyses presented in
subsequent sections.
1 Muller et al. 2011 conclude that, "coal-fired power plants have air pollution damages larger than their value
added", while the same is not true for natural gas plants (see Table 5 in Muller et al.). However, these
comparisons are based on typical existing coal and natural gas units, including natural gas boilers, and are not
sensitive to location (although the underlying analysis in the study does account for differences in the location
of existing units when estimating damages). The NRC 2009 study shows that only the most polluting natural gas
units may cause greater damages than even the least polluting existing coal plants (compare Tables 2-9 and 2-
15 in NRC 2009). However, the NRC comparison does not compare new units located in the same place, and so
some of the natural gas units with the greatest damages may be attributable to their location, and includes
natural gas steam boilers, which have a higher emission rates per unit of generation than NGCC units. Despite
these caveats, the finding of these two studies are consistent with the findings in this section.
2 Different discount rates are applied to SC-CCh than to the other benefit estimates because CC>2 emissions are
long-lived and subsequent damages occur over many years. Moreover, several rates are applied to SC-CCh
because the literature shows that it is sensitive to assumptions about discount rate and because no consensus
exists on the appropriate rate to use in an intergenerational context. The SC-CCh interagency group centered its
attention on the 3 percent discount rate but emphasized the importance of considering all four SC-CCh
estimates. See the 2010 SC-CO2TSD for details. Docket ID EPA-HQ-OAR-2009-0472-114577 or
http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf.
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Table 5-3. Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Compliant
Coal-Fired Generation with CCS meeting 1,400 Ib/MWh Standard Relative to New
Non-Compliant Coal-Fired Generation in 2022
SCPC
COz-Related Benefits using SC-CO2
5% Discount Rate $1.3
3% Discount Rate $4.4
2.5% Discount Rate $6.6
3% Discount Rate (95th percentile) $13
Total PM2.5-Related Benefits from SO2 and NOX Changes
3% discount rate
Krewski et al. (2009) $1.9
Lepeuleetal. (2012) $4.3
7% discount rate
Krewski et al. (2009) $1.7
Lepeuleetal. (2012) $3.9
Combined COz-Related and PM2.5-Related Benefits
Discount Rate Applied to
PM2.5-Related Benefits
(range based on adult
mortality function)
SC-CO2 Discount Rate 3% 7%
5% Discount Rate $3.2 to $5.6 $3.1 to $5.2
3% Discount Rate $6.3 to $8.7 $6.1 to $8.3
2.5% Discount Rate $8.5 to $11 $8.3 to $10
3% Discount Rate (95th percentile) $15 to $18 $15 to $17
Notes: Benefits are estimated for a 2022 analysis year. The range of benefits within each SC-C02 value and discount rate for
PM2.5-related benefits pairing reflects the use of two core estimates of PIVh.s-related premature mortality.3 The EPA has
evaluated the range of potential impacts per MWh by combining all SC-C02 values with health benefits values at the 3 percent
and 7 percent discount rates. Combining the 3 percent SC-C02 values with the 3 percent health benefit values assumes that
there is no difference in discount rates between intragenerational and intergenerational impacts. PIVh.s-related co-benefits are
estimated using 2020 monetized health benefits-per-ton of PIVh.s precursor reductions (Table 3-2), which are representative of
2022.
3 The range of estimated benefits for each discount rate is due to the EPA's use of two alternative primary
estimates of PIVh.s-related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a
higher primary estimate based on Lepeule et al. (2012).
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Table 5-4 reports the 2022 incremental benefits associated with a new compliant coal-
fired unit co-firing natural gas relative to a new non-compliant coal-fired unit, given different
mortality risk studies and assumptions about the discount rate. The values are calculated based
on the emissions presented in Table 5-1. Depending on whether the unit is SCPC or IGCC, the
discount rate used, and mortality risk study used, 2022 incremental benefits associated with
generation from a representative new coal-fired unit co-firing natural gas relative to a new coal-
fired unit that does not co-fire natural gas are 0.25 to $14 per MWh (2011$).4 These
incremental benefits will be used in the analyses presented in subsequent sections.
4 Different discount rates are applied to SC-CCh than to the other benefit estimates because CC>2 emissions are
long-lived and subsequent damages occur over many years. Moreover, several rates are applied to SC-CCh
because the literature shows that it is sensitive to assumptions about discount rate and because no consensus
exists on the appropriate rate to use in an intergenerational context. The SC-CCh interagency group centered its
attention on the 3 percent discount rate but emphasized the importance of considering all four SC-CCh
estimates. See the 2010 SC-CO2TSD for details. Docket ID EPA-HQ-OAR-2009-0472-114577 or
http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf.
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Table 5-4. Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Compliant
Coal-Fired Generation with Co-Firing Natural Gas Relative to New Non-Compliant
Coal-Fired Generation in 2022
SCPC Co-Firing Natural Gas IGCC Co-Firing Natural Gas
COz-Related Benefits using SC-CO2
5% Discount Rate $1.5 $0.25
3% Discount Rate $4.8 $0.82
2.5% Discount Rate $7.2 $1.2
3% Discount Rate (95th percentile) $14 $2.5
Total PMz.s-Related Benefits from SO2 and NOX Changes
3% discount rate
Krewski et al. (2009)
Lepeuleetal.(2012)
7% discount rate
Krewski et al. (2009)
Lepeuleetal.(2012) - -
Combined COz-Related and PM2.5-Related Benefits
Discount Rate Applied to PM2.s-Related Benefits
(range based on adult mortality function)
SC-CO2 Discount Rate
5% Discount Rate
3% Discount Rate
2.5% Discount Rate
3% Discount Rate (95th percentile)
3%
$1.5
$4.8
$7.2
$14
7%
$1.5
$4.8
$7.2
$14
3%
$0.25
$0.82
$1.2
$2.5
7%
$0.25
$0.82
$1.2
$2.5
Notes: Benefits are estimated for a 2022 analysis year. The range of benefits within each SC-C02 value and discount rate for
PM2.5-related benefits pairing reflects the use of two core estimates of PIVh.s-related premature mortality.5 The EPA has
evaluated the range of potential impacts per MWh by combining all SC-C02 values with health benefits values at the 3 percent
and 7 percent discount rates. Combining the 3 percent SC-C02 values with the 3 percent health benefit values assumes that
there is no difference in discount rates between intragenerational and intergenerational impacts. PM2.5-related co-benefits are
estimated using 2020 monetized health benefits-per-ton of PIVh.s precursor reductions (Table 3-2), which are representative of
2022.
5.4 Illustrative Analysis - Benefits and Costs of New Source Standards across a Range of
Gas Prices
As the analysis in Chapter 4 demonstrated, under a wide range of likely electricity
market conditions - including the EPA base case and EIA reference case scenarios as well as
multiple alternative scenarios - it is expected that the industry will choose to construct new
5 The range of estimated benefits for each discount rate is due to the EPA's use of two alternative primary
estimates of PIVh.s-related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a
higher primary estimate based on Lepeule et al. (2012).
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units that already meet the standards of this rulemaking in the baseline. Section 4.5.4 further
explored how much higher natural gas prices would need to be to favor new non-compliant
coal generation over new NGCC generation. In this section, we continue that analysis by
considering the potential impacts of the regulation on benefits if key assumptions regarding
natural gas prices were to change during the analysis period. The analysis in this section
indicates that in this scenario, the standards for new sources would result in increased private
costs, but would also lead to climate and human health benefits, and is highly likely to result in
net benefits to society as a whole.6
Furthermore, this section, as in section 4.5.4, demonstrates that local fuel prices must
be significantly different than regional differences already captured in IPM and ElA's modeling
of private investment costs to favor the construction of a new non-compliant coal-fired unit
over a new NGCC unit to serve a particular load. Section 4.5.4 describes how regional
conditions and other factors may influence the LCOE comparison, and how these regional
differences are already captured in the electricity sector modeling in support of this rule. The 64
different regions in IPM reflect the administrative structure of regional transmission
organizations (RTOs) and independent system operators (ISOs).7 However, there may be local
conditions within those regions which differ meaningfully from the broader regional conditions.
The analysis in this section evaluates how substantially divergent those local conditions must be
from representative conditions for non-compliant coal generation to be the fossil fuel-fired
technology of choice to serve demand.
The starting point for this analysis is the illustrative comparison (presented in Section
4.5) of the relative LCOE of representative new coal-fired SCPC and IGCC EGUs and
representative NGCC units.8 That comparison demonstrated a significant difference in the LCOE
6 EO 13563 states that each agency must "propose or adopt a regulation only upon a reasoned determination that
its benefits justify its costs (recognizing that some benefits are hard to quantify)." While the presence of net
social benefits for a given regulatory option is not the only condition necessary for optimal regulatory design, it
does signify that the regulatory option is welfare improving for society.
7 Further disaggregation of the NERC assessment regions and RTOs allows a more accurate characterization of the
operation of the U.S. power markets by providing the ability to represent transmission bottlenecks across RTOs
and ISOs, as well as key transmission limits within them.
8 By fixing generation in this comparison, we are assuming that both technologies generate the same benefits in
the form of electricity generating services. We assume in the discussion that the benefit of electricity
production to consumers outweighs the private and social investment cost. However, a caveat of our
comparison is that at particularly high fuel prices this might not be the case (that is, at high costs for both
technologies, it may not be worthwhile to construct either technology). 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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between the coal-fired and natural gas-fired generating technologies. The estimated LCOE for a
representative NGCC unit is roughly $34 and $43 per MWh less than for a representative new
coal-fired SCPC or IGCC unit, respectively (see Figure 4-3).9 This is consistent with the EPA's
expectation that the new source standards for steam units are not projected to impose any
appreciable costs or quantified benefits under current and likely future market conditions, as
discussed in Chapter 4. The emissions associated with these technologies, and the benefits in
terms of reduced damages of operating the new NGCC unit in lieu of the new non-compliant
coal unit, are reported in the previous section.
To supplement this conclusion, this section identifies three relevant ranges within the
distribution of future natural gas prices that can be classified as likely gas prices, unexpectedly
high natural gas prices, and unprecedented natural gas prices. Because the cost of natural gas is
a significant share of the LCOE for NGCC units, we evaluate how changes in natural gas prices
affect differences in the relative private costs of new technologies. We identify the natural gas
price when the private costs, which are inclusive of the CUA for the SCPC, suggest that a new
non-compliant coal unit may be adopted by an investor in lieu of a new NGCC unit. We then
compare the social costs of these technologies, which is inclusive of both the private costs of
these technologies and the damages from these technologies but exclusive of the CUA, at this
natural gas price.10 We then identify the natural gas price when the social cost of investing in
the new non-compliant coal unit is plausibly less than the social cost of the new NGCC unit.
In general, this analysis shows that there would likely be a net social benefit, even under
scenarios with higher than expected gas prices, if new compliant NGCC units were built in place
of new non-compliant coal-fired units as a result of this rule.11 Under some conditions, higher
natural gas prices may result in a net social cost of constructing and operating new natural gas
in lieu of non-compliant coal, holding all other parameters constant and disregarding social
9 The reported decrease in the LCOE from adopting NGCC are relative to the SCPC with 3 percent carbon
uncertainty adder (CUA) and IGCC without 3 percent CUA. The CUA is described in Chapter 4.
10 When forecasting the behavior of private actors in choosing between different technologies based on expected
future costs, we account for a CUA, but when comparing the difference in costs of illustrative new units after
construction, such as in the analysis of the social costs of these technologies (i.e., the private cost plus the cost
associated with their emissions), the CUA is not included. The CUA is described in section 4.5.3. The private cost
of these technologies may differ from the social cost of these technologies for reasons other than their
associated emissions, as described at the end of Section 5.5.
11 As previously noted, the benefits estimated in this section are based on a single year (2022) of emissions from
different generating technologies. Due to data limitations, we are not able to estimate annualized benefits from
the stream of emissions over the lifetime of the generating technologies. This results in a conservative
comparison of benefits to costs where LCOE represents annualized lifetime costs of generating technologies.
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benefits that we are unable to monetize.12 However, even under these unlikely conditions these
finalized standards may yield social net benefits as there may be other technologies to serve
demand that would have a lower social cost than a new non-compliant coal unit.
5.4.1 Likely Natural Gas Prices
As shown in Chapter 4, it is only when natural gas prices exceed $ll/MMBtu on a
levelized basis (in 2011 dollars) that the representative new non-compliant SCPC unit likely
becomes competitive with new NGCC in terms of its cost of electricity produced. As discussed in
Chapter 4, none of the AE02014 scenarios approach this natural gas price level on either a
forward looking 20-year levelized price basis or on an average annual price basis at any point
during the analysis period.13
5.4.2 Unexpectedly High Natural Gas Prices
At natural gas prices above $ll/MMBtu, the private LCOE for a new SCPC unit may fall
below that of a new NGCC unit.14 Therefore, in the event of such unexpectedly high levelized
fuel prices, some new SCPC units might be constructed in the absence of this final rulemaking,
provided that coal price do not rise at the same time, there is sufficient demand for electricity,
and new non-compliant SCPC units are competitive with other new and existing generating
technologies other than NGCC units. In this scenario, we expect some compliance costs if a new
NGCC unit (or a compliant coal-fired unit) were to be built in lieu of the non-compliant coal
unit. However, generation from a new NGCC unit would also have incremental environmental
12 As described below, an outcome where there are net social costs is unlikely to occur over our analysis period and
for a significant period beyond. However, even a situation where natural gas prices are significantly higher,
such as very high economic growth, would increase both natural gas and coal prices at the same time - making
it harder to alter the underlying cost advantage of NGCC generation. Furthermore, even in the situation where
we report net social costs, it is important to recall that the analysis is limited in the types of benefits and costs
considered, given that it does not account for the emissions associated with the production and delivery of
natural gas and coal, the limitations of current SC-CCh estimates, and the limited accounting of non-CCb
emissions benefits. As previously discussed, the current SC-CCh estimates do not capture all important all of the
physical, ecological, and economic impacts of climate change recognized in the climate change literature.
Despite our attempts to quantify and monetize as many of the co-benefits as possible, the health and welfare
co-benefits are not fully quantified or monetized in this assessment. For more information about unquantified
health and welfare co-benefits please refer to tables 5-2 and 6-2 of the PM NAAQS RIA (U.S. EPA, 2012),
respectively.
13 As reported in Table 4-6, The projected delivered electricity sector natural gas price for 2020 assuming a 5
percent discount rate in the AEO 2014 reference scenario is $6.53/MMBtu (2011$). In the "Low oil and gas
resource" it is $8.45/MMBtu (2011$).
14 As noted above, the private LCOE of the non-compliant SCPC unit is inclusive of the CUA. Also as noted above,
the CUA is removed for comparisons of the social costs of generating technology.
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and health benefits as it emits less CCh SCh, and NOX than generation from a new non-
compliant SCPC unit (as may a compliant coal-fired unit; see Section 5.5).
For levelized natural gas prices of $ll/MMBtu and somewhat higher, the resulting
emission reduction benefits of building an NGCC unit, rather than a non-compliant SCPC unit,
will outweigh the increase in costs of an NGCC unit over a non-compliant SCPC unit. This
observation indicates that the standard for new fossil steam sources would yield net benefits in
the analysis year. For example, at a levelized gas price of $12/MMBtu, the NGCC unit would
generate electricity for approximately $17/MWh more than the non-complaint SCPC unit on a
levelized basis,15 and result in incremental benefits from emissions reductions of $19 to
$91/MWh (see analysis of 2022 relative benefits of NGCC: Table 5-2). The net benefit of this
scenario would be $2.2 to $73/MWh.
For context, even a natural gas price of $10/MMBtu (in 2011 dollars) is higher than any
national average annual natural gas price faced by the electric power sector since at least 1996,
when the EIA historic data series begins.16 The continued development of unconventional
natural gas resources in the U.S. suggests that annual gas prices may actually tend to be
towards the lower end of the historical range. In addition, the highest projected average
levelized natural gas price for 2020 of any of the AEO 2014 scenarios cited in Chapter 4 is
$8.45/MMBtu (2011$), which occurs in the Low Oil and Gas Resource scenario (see Table 4-6).
As discussed in Chapter 4, none of the EIA sensitivity cases (which account for future fuel prices
for both gas and coal) show scenarios where non-compliant coal-fired units become more
economic than NGCC units in the period of analysis.
5.4.3 Unprecedented Natural Gas Prices
At extremely high natural gas prices, the LCOE for a non-compliant SCPC unit could be
sufficiently lower than the cost of a new NGCC unit, such that the net benefit of the new fossil
steam standard in a given year could be negative (i.e., a net cost), at least under some ranges of
benefit estimates. For example, at a very high17 levelized gas price of $14/MMBtu, the NGCC
unit would generate electricity for roughly $31/MWh more than the illustrative non-compliant
15 The LCOE of the representative NGCC unit increases by $6.80/MWh for every $l/MMBtu increase in natural gas
prices.
16 See: http://www.eia.gov/dnav/ng/hist/n3045us3A.htm. EIA reports average annual delivered natural gas prices
to the electricity sector for the past 16 years (since 1997).
17 For context, between 2009 and 2014 the national annual average nominal price of natural gas delivered for
electricity generation ranged from $3.58/MMBtu to $5.30/MMBtu. The 6 year average was $4.76/MMBtu,
roughly 1/3 the illustrative high price of $14/MMBtu.
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SCPC, but result in social benefits from lower emissions of $19 to $91/MWh relative to the non-
compliant SCPC unit (see analysis of 2022 relative benefits of NGCC: Table 5-2). If the NGCC unit
were built in lieu of the SCPC unit as a result of the new fossil steam standard, the impact would
range from a net social cost of $ll/MWh to a net social benefit of $60/MWh relative to the
SCPC unit.18
Depending on which discount rates are used to estimate benefits, it is possible that the
standard would result in a net cost (i.e., costs exceed benefits). However, as noted in the
previous subsection, natural gas prices at these levels would be unprecedented. As a result, the
EPA believes that the probability of levelized natural gas prices reaching levels at which this
standard would generate net social costs is extremely small.
We emphasize that differences in generating costs, plant design, local factors, and the
relative differences between fuels costs can all affect the precise circumstances under which
the new steam fossil standard would be projected to have no costs, net social benefits or net
social costs. However, based on historical and expected gas prices, we project that the new
fossil steam standard is most likely to have negligible costs because firms will invest in
technology that will comply with the standard in the baseline, and, if it does result in costs, it is
also likely to produce positive, although modest, net social benefits. Furthermore, these results,
complemented by the analysis in Chapter 4 on regional differences in levelized costs of these
technologies, indicate that local differences in the cost of these technologies must be
significantly different from representative conditions for non-compliant coal generation to be
the technology of choice to serve demand. Therefore the probability that this finalized standard
would result in net social costs is exceedingly low.
5.5 Illustrative Analysis - Benefits and Costs of Non-Compliant Coal and Compliant Coal
As discussed in detail in the previous section and in Chapter 4, it is unlikely that a new
non-compliant coal-fired unit would be constructed in the analysis period. The power sector
continues to move away from the construction of coal-fired power plants in favor of natural
gas-fired power plants due, in part, to the significant LCOE differential explored in the previous
section. Even so, an operator may have reasons to choose to construct a conventional coal-fired
power plant. (For example, some comments received on the 2012 and 2014 proposed
regulations suggested that an operator may find it desirable to construct a new coal-fired ECU
for the purpose of diversifying its generation fleet across fuels to hedge against uncertainty in
5 As noted above, the CUA is removed for comparisons of the social costs of generating technology.
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fuel markets.) In these circumstances, the EPA believes that any need for CCS could be
accommodated and would not, based on the incremental cost of the CCS portion of the new
unit, preclude the construction of the new coal-fired facility. One factor in determining that
needing CCS would not preclude the construction of the new facility is the availability of
Enhanced Oil Recovery (EOR) opportunities for new coal-fired facilities.19
This section evaluates the impacts that might occur if an investor, which otherwise
wanted to construct a new non-compliant coal unit, chose to instead construct a new compliant
coal-fired unit in response to the new fossil steam standard. In this scenario, this decision
would result in some costs in order to build a unit with partial CCS or co-fire with natural gas.20
However, there would also be climate and other benefits resulting from changes in C02and
S02.
For each coal-fired generation type, SCPC and IGCC, the EPA analyzed the cost of
constructing these units and emission impacts of meeting the new source standards in 2022.
While partial CCS is considered the best system of emission reductions (BSER) for these SCPC
units, it would also be possible to meet the standard without CCS through co-firing natural gas,
which is also analyzed.
The cost of CCS used to support this rule assumes that the geologic sequestration of C02
will be in deep saline formations and accounts for the cost of doing so, but the EPA also
recognizes the potential for sequestering C02 for EOR. For non-EOR applications,
transportation, storage, and monitoring (TS&M) costs of $5-$15 dollars per ton of C02 are
applied based on the level of capture. This range is consistent with estimates provided by NETL
and the Global CCS Institute.21
19 The potential availability of EOR was not used in the EPA's evaluating the reasonableness of cost in determining
the best system of emissions reduction (BSER).
20 In this section we do not include a CUA for the illustrative new non-compliant SCPC and IGCC units as we are
assuming that the investor will install construct and operate a new coal fired plant regardless. Furthermore, as
in the previous section, when comparing the difference in costs of illustrative new units after construction, such
as in the analysis of the social costs of these technologies (i.e., the private cost plus the cost associated with
their emissions), the CUA is not included.
21 http://www.netl. doe.gov/energy-analyses/pubs/QGESS_CO2T%26S_Rev2_20130408.pdf
http://www.globalccsinstitute.com/publications/economic-assessment-carbon-capture-and-storage-
technologies-2011-update.
Note that NETL assumes 100 kilometers (62 miles) of pipeline, but points out that, of the 500 largest existing CCh
point sources, 95 percent are located within 100 kilometers (62 miles) miles of a potential geologic storage
reservoir. Therefore it is reasonable to assume that a new source can be similarly located.
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EOR refers to the injection of gases and/or fluids into a reservoir to increase oil
production efficiency. CCh-EOR has been successfully used at many production fields
throughout the United States. The oil and natural gas industry in the United States has over 40
years of experience in injection and monitoring of CCh. This experience provides a strong
foundation for the technologies used in the deployment of CCS on coal-fired electric generating
units. Although deep saline formations provide the most CCh storage opportunity (at least
2,243 billion tons), oil and gas reservoirs are estimated to have 228 billion tons of CCh storage
The use of CCh for EOR can significantly lower the cost of implementing CCS. The
opportunity to sell the captured CCh rather than paying directly for its long-term storage,
greatly improves the economics of the new generating unit. According to the International
Energy Agency, of the CCS projects in operation (e.g., Boundary Dam Energy Project,
Saskatchewan, Canada) or under construction or at an advanced stage of planning, 70 percent
intend to use captured CCh to improve recovery of oil in mature fields, including Mississippi
Power's Kemper County Energy Facility, NRG Energy's W.A. Parish Petra Nova CCS Project,
Summit Power's Texas Clean Energy Project, and the Hydrogen Energy California Project. The
Texas Clean Energy project is planning to capture 90 percent of the CCh and sell it for EOR.23
Therefore, in the near term, new coal-fired EGUs with CCS may be located in areas
amenable to using the captured C02 in EOR operations because these formations have been
previously well characterized for hydrocarbon recovery, likely already have suitable
infrastructure (e.g., wells, pipelines, etc.), and have an associated economic benefit of
increasing oil well productivity. Furthermore, the EPA believes the opportunity to engage in
EOR opportunities is not significantly limited by the location of those opportunities or the
current C02 pipeline infrastructure (12 states currently have active EOR operations). Provision
of electric power does not require coal-fired facilities to be co-located with the demand it is
intended to serve. Please refer to Chapter 2 for a more detailed discussion of EOR, including its
geographic availability, expected future growth, and overall impact on the economics of CCS.
There are two EOR opportunities evaluated in this section - 'High' and 'Low.' The high
EOR opportunity assumes a C02 sale price of $36 per ton; the low EOR opportunity assumes a
C02 sale price of $18 per ton based on assumptions used by NETL in evaluating potential EOR
22 U.S. Department of Energy National Energy Technology Laboratory (2012). United States Carbon Utilization and
Storage Atlas, Fourth Edition.
23 http://www.texascleanenergyproiect.com/
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opportunities.24 For either opportunity, it is assumed that the facility is only responsible for the
costs of transmitting the captured CCh to the fence line, as is currently the practice.25 Costs for
TS&M of CCh, however, are real costs that must be borne by someone. Whether the facility, the
pipeline owner or the eventual user (i.e., oil field producer) of the CCh bear the TS&M cost
could be negotiated, with the outcome varying in different situations. We expect that when CCh
is sold for EOR applications, the buyer rather than the ECU operator will likely bear those costs.
However, for the purposes of this analysis, the TS&M costs are included for both EOR and non-
EOR applications, recognizing that this likely slightly overstates the cost to the operator in
circumstances where CCh is sold for EOR.
Figure 5-1 compares the LCOE for a non-compliant coal to a compliant coal unit with
partial CCS both with and without EOR. With the exception of the LCOE costs accounting for
EOR, these costs were provided in Table 4-5. We see in Figure 5-1 that if a limited number of
non-compliant coal-fired power plants would have been constructed in the analysis period the
adoption of CCS could be accommodated and would not, based on the incremental cost of the
CCS portion of the new unit, preclude the construction of the new coal-fired facility.
Furthermore, Figure 5-1 shows the LCOE analysis estimate that a non-compliant coal unit could
achieve a 1,400 Ib/MWh emission rate by co-firing with 34 percent natural gas (at a levelized
cost of $34.40/MWh) at an SCPC unit, or with 6 percent natural gas at an IGCC unit.
24 The High and Low CCh sale prices utilized by the EPA are consistent with NETL's Base Case and Low Case sale
prices, respectively (http://www.netl.doe.gov/energy-analyses/pubs/storing%20co2%20w%20eor_final.pdf).
In addition, this range is broadly consistent with the CO2 sale price data collected by the Department of Interior
for projects located on federal lands (http://statistics.onrr.gov/ReportTool.aspx). Prices are expressed in 2011$
and the price is expected to be static over time. Prices were converted from metric to short tons using a factor
of 0.90718474.
25 For EOR applications the point of sale is typically the facility fence line, in which case the coal facility operator
will avoid the TS&M cost. Consequently, the economic benefit of EOR to the investor in the coal plant may be
greater than simply the price paid for
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SCPC
IGCC
I Uncontrolled (w/o CUA) • Uncontrolled (w CUA)
I No CCS, 1400 Ibs/MWh via NG Cofiring • Partial CCS (1400 Ibs/MWh) no EOR
I Partial CCS (1400 Ibs/MWh) $18 EOR Partial CCS (1400 Ibs/MWh) $36 EOR
Figure 5-1. Levelized Cost of Electricity, Uncontrolled Coal and Coal with Partial
CCS (1,400 Ib/MWh gross). 2011$
Notes:
(1) Cost data from NETL 2015, adjusted for EOR revenue and co-firing where applicable.
(2) NETL uses a high-risk financial structure resulting in a capital charge factor (CCF) of 0.124 to evaluate
the costs of all cases with CO2 capture (non-capture case uses a conventional financial structure with
a CCF of 0.116).
(3) A non-compliant 550 MW (net capacity) unit SCPC requires NG co-firing at 34% to achieve a 1,400
Ib/MWh CC>2 emission rate. A non-compliant 620 MW (net) IGCC unit requires 6 percent NG co-firing.
LCOE costs for co-firing were estimated assuming a levelized $6.19/MMBtu price of delivered gas.
(4) The partial control alternatives that achieve 1,400 Ib/MWh using CCS without EOR include the cost of
TS&M.
Tables 5-5 and 5-6 show the costs and 2022 net benefits (benefits minus private
compliance costs) per MWh of adopting compliant coal in lieu of non-compliant coal. The EPA
estimates of the benefits or disbenefits associated with changes in CCh, SCh, and NOx emissions
using the methods described in Table 5-3. The cost estimates used are reported in Figure 5-1.
As before, it is important to note that these comparisons omit additional benefits that may be
associated with the abatement of greenhouse gas emissions and other benefits associated with
reducing criteria pollutant emissions.
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Table 5-5. Illustrative 2022 Costs and Benefits for Compliant SCPC with Partial Capture or
with Co-Firing Natural Gas Relative to Non-Compliant SCPC (per MWh 2011$)
SCPC
SCPC with Co-Firing
Partial CCS Natural Gas
Additional LCOEa $17 $9.8
Revenue from EOR (Low-High EOR) $4.2 to $7.1 *
Additional LCOE, net of EOR $9.6 to $13 *
Value of Monetized Benefits for 2022 Emissions
SC-C02 5% with Krewski 3% to SC-C02 3% (95th) with
Lepeule3%b $3.2 to $18 $1.5 to $14
Net Monetized Benefits
Without EOR Revenue -$13 to $0.84 -$8.3 to $4.7
With EOR Revenue -$9.3 to $7.9 *=
a For this comparison the LCOE of the representative SCPC without CCS or co-firing natural gas does not include 3
percent CUA.
b Benefits are estimated for a 2022 analysis year. Values shown are calculated using different discount rates. Four
estimates (average SC-CCh at discount rates of 5, 3, and 2.5 percent, respectively, and 95th percentile SC-CCb at 3
percent) of the SC-CO2 in the year 2022 were used. See Table 3-1 for the SC-CO2 estimates. =The average SC-CO2 at
5 percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest
estimate. See section 3.2 for complete discussion of these estimates. PlVh.s-related co-benefits are estimated using
2020 monetized health benefits-per-ton of Plvh.s precursor reductions (Table 3-2), which are representative of 2022.
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Table 5-6. Illustrative 2022 Costs and Benefits for Compliant IGCC with Co-Firing Natural
Gas Relative to Non-Compliant IGCC (per MWh 2011$)
IGCC Co-Firing
Natural Gas
Additional LCOEa $2.0
Revenue from EOR (Low-High EOR) *
Additional LCOE, net of EOR *
Value of Monetized Benefits for 2022 Emissions
SC-C02 5% with Krewski 3% to SC-C02 3% (95th) with Lepeule
3%b $0.25 to $2.5
Net Monetized Benefits
Without EOR Revenue $-1.8 to $0.45
With EOR Revenue *_
a For this comparison the LCOE of the representative IGCC co-firing natural gas does not include 3 percent CUA.
b Benefits are estimated for a 2022 analysis year. Values shown are calculated using different discount rates. Four
estimates (average SC-CCh at discount rates of 5, 3, and 2.5 percent, respectively, and 95th percentile SC-CCb at 3 percent)
of the SC-CCh in the year 2022 were used. See Table 3-1 for the SC-CO2 estimates. =The average SC-CCh at 5 percent
produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate. See Section
3.2 for complete discussion of these estimates. Plvh.s-related co-benefits are estimated using 2020 monetized health
benefits-per-ton of Plvh.s precursor reductions (Table 3-2), which are representative of 2022.
As shown in Chapter 4, current market conditions indicate that a unit compliant with the
standards is currently the most economical investment, even in the baseline. The costs
reported in Tables 5-5 and 5-6 represent the compliance costs to a hypothetical investor who,
in the baseline, would choose to build a non-compliant fossil-fired steam power plant and, in
compliance with the standard, still constructs the plant but now in such a way that reduces the
plant's emissions. In short, the compliance costs are the expenditures that the investor would
make in order to comply with the standard. The underlying premise of this example is that the
profit from the plant exceeds the additional cost of compliance to the investor; otherwise the
investor would not be expected to make the investment. If the profit were less than the
compliance costs then the investor's lost profits would be the private costs. For this reason, if
the investor makes a different compliance decision other than those assumed in Table 5-5 and
5-6 the private costs will be lower, and therefore, the compliance costs presented in Table 5-5
and 5-6 would be an upper bound to the private costs borne by the hypothetical investor.
As explained in OMB's Circular A4 and the EPA's Guidelines for Economic Analysis, social
costs, and not private costs, are the appropriate metric for the benefit-cost analysis in this RIA.
Social costs represents the total burden that a regulation or action will impose on the economy.
It is defined as the sum of all opportunity costs incurred as a result of a regulation or action
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where an opportunity cost is the value lost to society of any goods and services that will not be
produced and consumed as a result of a regulation. The opportunity cost of a regulation or
activity is measured by the prices of the goods and services used in response to the regulation
or required for that activity. Therefore, when a resource is used in response to a regulation or
for an activity, it has a social cost associated with it.
The costs in Tables 5-5 and 5-6 could be taken to approximate the social cost of an
individual investor complying with the standard, assuming that investor would chose to
construct a compliant fossil-fired steam power plant rather than making an alternative
investment. However, detailed behavioral models of the electricity sector (such as IPM) that
take into many of the important criteria for investment decisions over time show that this
investment decision does not hold across the economy. Therefore, these estimates are unlikely
to be representative of the social costs of this rule. The conclusions presented in Chapter 4 -
that costs of the rule are likely to be negligible - represent the best approximation of the
overall cost to society.
5.6 Impact of the New Source Standards Considering the Cost of Lost Option Value
Consistent with the EPA's practice in evaluating the benefits and costs of significant
rules, Chapter 4 uses detailed electricity sector modeling of expected market conditions to
demonstrate that new EGUs expected to be built in the period of analysis would be in
compliance with this final rule, even in the absence of this rule. As a result in the analysis
period, as measured in those deterministic settings, the cost are expected to be negligible and
there are no quantified benefits. That analysis is extended in this chapter to consider
unexpected conditions in which the construction of a new non-compliant coal-fired unit would
be desirable from the perspective of an individual investor and evaluates the costs and benefits
of constructing a generating technology that complies with the final rule instead. This section
further extends, and draws on, those analyses to discuss, qualitatively, the potential benefits
and costs of the standards from the perspective of an uncertain future.
Firms operating in the power sector have a set of options available to address increases
in electricity demand, such as increasing the utilization of existing generating capacity,
implementing energy efficiency programs to mitigate demand growth, or investing in new
generating capacity. Within the category of investing in new generating capacity they are able
to select amongst a set of generating technologies and energy sources. Uncertainty about
future conditions that could impact the profitability of these different investment options
means that retaining flexibility to react to future conditions and choose the most profitable
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investments has value to firms. The value associated with retaining flexibility and being able to
select the most profitable investments in the future is referred to as "option value."26 This rule
does not impose a direct cost on firms by requiring them to take a specific action, instead the
cost of this rule for firms is the lost option value associated with losing the ability to build a new
fossil steam or combustion turbine ECU with an emissions rate above their respective
standards.
This option value is determined, in part, by the likelihood that the restricted choices
would have been exercised in the future absent the policy and the cost of available substitutes.
Since the analysis in Chapter 4 estimates that new combustion turbines forecast in the baseline
that meet the applicability criteria will already meet the standards this discussion focuses on
new fossil steam EGUs. As discussed in Chapter 4, it is highly unlikely that over the analysis
period there will be enough expansion in relative fuel prices (e.g., natural gas prices relative to
coal) to make a typical new fossil steam ECU cost competitive with available substitutes (e.g.,
NGCC, investing in energy efficiency program). Even in the unlikely event that this occurs, the
incremental cost of constructing a compliant fossil steam ECU with partial CCS or an alternative
compliance pathway will represent an upper bound on the costs to the firm due to the
availability of substitute generation sources which might be able to provide a similar service at
a lower cost. Given both of these reasons, the low likelihood of the restricted options being
exercised in the baseline and availability of cost effective substitutes, on average the lost option
value for firms is likely to be small.
Furthermore, as shown in the preceding sections, even in situations where an investor
would find it desirable to invest in a new, non-compliant ECU over available alternatives in the
baseline, the health and environmental benefits of restricting the choice set may be higher than
the costs to the firm. Therefore it will also be the case that expected benefits from preventing
new EGUs with an emissions rate above the respective standards, will likely be higher than the
lost option value.
A similar perspective may be applied to assessing the costs of this rule. There are at
least two notable differences when assessing the lost option value from society's perspective
relative to the firm's perspective. First, from society's perspective the cost is lower because the
available substitution possibilities may be greater for society than for a single firm as they are
not bound by the conditions of a single firm but activities that may be pursued by all electricity
26 We refer the interested reader to Dixit and Pindyck (1994) and Trigeorgis (1996) for more information on the
concept of option value in the context of firms' investment choices.
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producers and consumers at large. Second, the value of adding a single new ECU for the
purpose of diversifying the generation fleet across fuels to hedge against uncertainty in fuel
markets, will likely be lower for society at large than for a single firm with a generating fleet
that is relatively less coal-intensive than the entirety of the generating fleet.27 Both of these
differences suggest that the cost of lost option value from society's perspective is lower than
what is already likely to a minimal cost of lost option value for a particular firm.
It is difficult to precisely estimate the lost option value associated with this final rule
given the numerous sources of uncertainty that influence investment decisions in the electricity
sector and the existing modeling tools. However, the analysis reported in this chapter and the
previous chapter has considered important variables that influence investment decisions in the
electricity sector and found that across a wide range of potential outcomes this rule would have
negligible costs. Furthermore, considering the additional analysis in this chapter and the
discussion above, the cost of the lost option value of the rule is concluded to be small.
Additionally, if conditions arise that would have led to the construction of non-compliant EGUs
absent the final rule, the quantifiable benefits of limiting the construction of those units likely
exceeds the cost (even though not all benefits are captured). However, as discussed throughout
this RIA, when considering the most likely outcomes, the new source standards are anticipated
to yield no quantified benefits and impose negligible costs over the analysis period.
5.7 References
Dixit, Avinash and Pindyck, Robert. Investment Under Uncertainty. 1994. Princeton University
Press.
Joskow, P.L. 2010. Comparing the Cost of Intermittent and Dispatchable Electricity Generating
Technologies. MIT Center for Energy and Environmental Policy Research Working Paper
10-013.
Joskow, P.L. 2011. Comparing the Costs of Intermittent and Dispatchable Electricity Generating
Technologies. American Economic Review, vol. 101:238-41.
27 The option value associated with constructing a new EGU associated with a specific fuel source as part of a
portfolio to hedge against uncertainty in future relative fuel prices will be conditional upon the current
composition of the firm's generation portfolio. If the current stock was constructed in expectation of relative
fuel prices that more strongly favored higher emitting fuels, then the composition of the generating fleet may
already be too heavily weighted toward the ability to use those fuels, given the current expected distribution of
relative fuel prices. Furthermore, the possibility to hedge against changes in fuel prices may be pursued by
other means, such as risk contracts, and thus is not limited to the construction of generation sources with
particular fuel sources.
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Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz,
and W.H. White. 2009. "Reanalysis of the Harvard Six Cities Study and the American
Cancer Society Study of Particulate Air Pollution and Mortality." Special Report to the
Health Effects Institute. Cambridge, MA. July.
Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. "Chronic Exposure to Fine Particles and
Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009."
Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.
Muller, N.Z., R. Mendelsohn, and W. Nordhaus. 2011. Environmental Accounting for Pollution in
the United States Economy. American Economic Review. 101:1649-1675.
National Energy Technology Laboratory (NETL). Cost and Performance of PC and IGCC Plants for
a Range of Carbon Dioxide Capture. Revised Sept. 16, 2013. Available online at:
http://www.netl.doe.gov/energv-analyses/pubs/Gerdes-08022011.pdf.
National Energy Technology Laboratory (NETL). Cost and Performance Baseline for Fossil Energy
Plants Supplement: Sensitivity to C02 Capture Rate in Coal-Fired Power Plants. June 22,
2015. Available online at: http://www.netl.doe.gov/research/energv-analvsis/energy-
baseline-studies.
National Research of Council (NRC). 2009. Hidden Costs of Energy: Unpriced Consequences of
Energy Production and Use. National Academies Press: Washington, D.C.
Trigeorgis, Lenos. Real Options: Managerial Flexibility and Strategy in Resource Allocation.
1996. The MIT Press.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010. Available
online at: http://www.eia.gov/oiaf/archive/aeolO/index.html.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available
online at: http://www.eia.gov/forecasts/aeo/.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the
Final Revisions to the National Ambient Air Quality Standards for Particulate Matter.
Office of Air Quality Planning and Standards, Research Triangle Park, NC. December.
Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.
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CHAPTER 6
MODIFIED AND RECONSTRUCTED SOURCE IMPACTS
6.1 Introduction
In addition to the standards for new sources analyzed in Chapter 4 and Chapter 5, this
action also sets standards under Clean Air Act Section lll(b) for units that modify or
reconstruct. For the reasons discussed in this chapter, the EPA also believes that the standards
for modified and reconstructed fossil fuel-fired EGUs will result in minimal compliance costs,
because we expect few lll(b) modified or reconstructed EGUs in the period of analysis
(through 2022).
6.2 Reconstructed Sources
The new source performance standard (NSPS) provisions (40 CFR part 60, subpart A)
define a "reconstruction" as the replacement of components of an existing facility to an extent
that (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital
cost that would be required to construct a comparable entirely new facility, and (2) it is
technologically and economically feasible to meet the applicable standards. Historically, we are
only aware of one ECU that has notified the EPA that it has reconstructed under the
reconstruction provision of section lll(b). As a result, we anticipate that few EGUs will
undertake reconstruction in the period of analysis. For this reason, the standards will not result
in any significant emission reductions, costs, or quantified benefits in the period of analysis.
Likewise, the EPA does not anticipate any impacts on the price of electricity or energy supply.
The rule is not expected to raise any resource adequacy concerns, since reserve margins will
not be impacted and the rule does not impose any additional requirements on existing facilities
not triggering the reconstruction provision. There are no notable macroeconomic or
employment impacts expected as a result of these standards.
Due to the extremely limited data available on reconstructions, it is not possible to
conduct a representative illustrative analysis of what costs and benefits might result from this
rule in the unlikely case that a unit were to reconstruct.
6.3 Modified Sources
Historically, few EGUs have notified the EPA that they have modified under the
modification provision of section lll(b). The EPA's current regulations define an NSPS
"modification" as a physical or operational change that increases the source's maximum
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achievable hourly rate of emissions, but specifically exempt from that definition projects that
entail the installation of pollution control equipment or systems.
The EPA expects that most of the actions EGUs are likely to take in the foreseeable
future that could be classified as NSPS "modifications" would qualify as pollution control
projects. In many cases, those projects are likely to involve the installation of add-on control
equipment needed to meet Clean Air Act (CAA) requirements for criteria and air toxics air
pollutants. Any associated carbon dioxide (CCh) emissions increases would likely be small and
would occur as a chemical byproduct of the operation of the control equipment. In other cases,
those projects would involve equipment changes to improve fuel efficiency to meet state
requirements for implementation of the CAA section lll(d) rulemaking for existing sources and
would have the effect of increasing a source's maximum achievable hourly emission rate (Ib
CCh/hr), even while decreasing its actual output based emission rate (Ib CCh/MWh). Because all
of these actions would be treated as pollution control projects under the EPA's current NSPS
regulations, they would be specifically exempted from the definition of modification.
Given the limited information that we have about past modifications, the EPA has
concluded that it lacks sufficient information to establish standards of performance for all types
of modifications at steam generating units at this time. Instead, the EPA has determined that it
is appropriate to establish standards of performance at this time for large-scale modifications
of steam generating units, such as major facility upgrades involving the reconstruction or
replacement of steam turbines and other equipment upgrades that result in substantial
increases in a unit's potential hourly CCh emissions rate. The EPA does not have sufficient
information at this time to predict the full array of actions that existing steam generating units
may undertake, including those in response to applicable requirements under an approved CAA
section lll(d) plan. Additionally, it is not possible to predict which, if any, of these actions may
result in increases in potential CCh hourly emissions. Nevertheless, the EPA expects that, to the
extent actions are undertaken by existing steam generating units, the magnitude of the
increases in potential hourly CCh emissions associated with the vast majority of such changes
would generally be small and therefore would generally not be subject to the standards of
performance for modified steam generating units finalized in this action.
Based on this information, we anticipate that few EGUs will take actions that would be
considered NSPS modifications and subject to the standards of performance finalized in this
action during the period of analysis. For this reason, the standards will result in minimal
emission reductions, costs, or quantified benefits in the period of analysis. Likewise, the Agency
does not anticipate any impacts on the price of electricity or energy supplies. This rule is not
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expected to raise any resource adequacy concerns, since reserve margins will not be impacted
and the rule does not impose any additional requirements on existing facilities not triggering
the NSPS modification provision. There are no notable macroeconomic or employment impacts
expected as a result of these standards.
Due to the limited data available on past modifications and the diversity of existing units
that could potentially modify, it is not possible to conduct a representative illustrative analysis
of what costs and benefits might result from this rule in the unlikely case that a unit were to
take an action that would be classified as a modification.
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CHAPTER 7
STATUTORY AND EXECUTIVE ORDER REVIEWS
7.1 Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563,
Improving Regulation and Regulatory Review
This final action is a significant regulatory action that was submitted to the Office of
Management and Budget (OMB) for review. It is a significant regulatory action because it raises
novel legal or policy issues arising out of legal mandates. Any changes made in response to
OMB recommendations have been documented in the established dockets for this action under
Docket ID No. EPA-HQ-OAR-2013-0495 (Standards of Performance for Greenhouse Gas
Emissions from New Stationary Sources: Electric Utility Generating Units) and Docket ID No.
EPA-HQ-OAR-2013-0603 (Carbon Pollution Standards for Modified and Reconstructed
Stationary Sources: Electric Utility Generating Units). This RIA includes an economic analysis of
the potential costs and benefits associated with this action.
The EPA does not anticipate that this final action will result in any notable compliance
costs. Specifically, we believe that the standards for newly constructed fossil fuel-fired EGUs
(electric utility steam generating units and natural gas-fired stationary combustion turbines) will
have negligible costs associated with it over a range of likely sensitivity conditions because
electric power companies will choose to build new EGUs that comply with the regulatory
requirements of this action even in the absence of the action, because of existing and expected
market conditions. (See Chapter 5 for further discussion of sensitivities). The EPA does not
project any new coal-fired steam generating units without CCS to be built in the absence of this
action. However, because some companies may choose to construct coal or other fossil fuel-
fired EGUs, the RIA also analyzes project-level costs of a unit with and without CCS, to quantify
the potential cost for a fossil fuel-fired ECU with CCS. As noted previously, the monetized
benefits exceed the compliance costs under a range of assumptions.
The EPA also believes that the standards for modified and reconstructed fossil fuel-fired
EGUs will result in minimal compliance costs, because, as previously stated, the EPA expects
few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis
(through 2022). In Chapter 6, we discuss factors that limit our ability to quantify the costs and
benefits of the standards for modified and reconstructed sources.
7.2 Paperwork Reduction Act (PRA)
The information collection activities in this final action have been submitted for
approval to OMB under the PRA. The Information Collection Request (ICR) document that the
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EPA prepared has been assigned EPA ICR number 2465.03. Separate ICR documents were
prepared and submitted to OMB for the proposed standards for newly constructed EGUs (EPA
ICR number 2465.02) and the proposed standards for modified and reconstructed EGUs (EPA
ICR number 2506.03). Because the CCh standards for newly constructed, modified, and
reconstructed EGUs will be included in the same new subpart (40 CFR part 60, subpart Mil)
and are being finalized in the same action, the ICR document for this action includes estimates
of the information collection burden on owners and operators of newly constructed, modified,
and reconstructed EGUs. Estimated cost burden is based on 2013 Bureau of Labor Statistics
(BLS) labor cost data. Thus, all burden estimates are in 2013 dollars. Burden is defined at 5 CFR
1320.3(b). You can find a copy of the ICR in the dockets for this action (Docket ID Numbers EPA-
HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), and it is briefly summarized here. The
information collection requirements are not enforceable until OMB approves them.
The recordkeeping and reporting requirements in this final action are specifically
authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant
to the recordkeeping and reporting requirements for which a claim of confidentiality is made is
safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B.
An agency may not conduct or sponsor, and a person is not required to respond to, a
collection of information unless it displays a currently valid OMB control number. The OMB
control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB
approves this ICR, the Agency will announce that approval in the Federal Register and publish a
technical amendment to 40 CFR part 9 to display the OMB control number for the approved
information collection activities contained in this final action.
7.2.1 Newly constructed EGUs
This final action will impose minimal new information collection burden on owners and
operators of affected newly constructed fossil fuel-fired EGUs (steam generating units and
stationary combustion turbines) beyond what those sources would already be subject to under
the authorities of CAA parts 75 and 98. OMB has previously approved the information
collection requirements contained in the existing part 75 and 98 regulations (40 CFR part 75
and 40 CFR part 98) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et
seq. and has assigned OMB control numbers 2060-0626 and 2060-0629, respectively. Apart
from certain reporting costs to comply with the emission standards under the rule, there are no
new information collection costs, as the information required by the standards for newly
constructed EGUs is already collected and reported by other regulatory programs.
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The EPA believes that electric power companies will choose to build new EGUs that
comply with the regulatory requirements of the rule because of existing and expected market
conditions. The EPA does not project any newly constructed coal-fired steam generating units
that commenced construction after proposal (January 8, 2014) to commence operation over
the 3-year period covered by this ICR. We estimate that 12 affected newly constructed natural
gas combined cycle units and 25 affected newly constructed natural gas-fired simple-cycle
combustion turbines will commence operation during that time period. As a result of this final
action, owners or operators of those newly constructed units will be required to prepare a
summary report, which includes reporting of emissions and downtime, every 3 months.
7.2.2 Modified and Reconstructed EGUs
This final action is not expected to impose an information collection burden under the
provisions of the PRA on owners and operators of affected modified and reconstructed fossil
fuel-fired EGUs (steam generating units and stationary combustion turbines). As previously
stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions
in the period of analysis. Specifically, the EPA believes it unlikely that fossil fuel-fired electric
utility steam generating units or stationary combustion turbines will take actions that would
constitute NSPS modifications or reconstructions as defined under the EPA's NSPS regulations.
Accordingly, the standards for modified and reconstructed EGUs are not anticipated to impose
any information collection burden over the 3-year period covered by this ICR. We have
estimated, however, the information collection burden that would be imposed on an affected
ECU if it was modified or reconstructed.
Although not anticipated, if an ECU were to modify or reconstruct, this final action
would impose minimal information collection burden on those affected EGUs beyond what they
would already be subject to under the authorities of CAA 40 CFR parts 75 and 98. As described
above, the OMB has previously approved the information collection requirements contained in
the existing part 75 and 98 regulations. Apart from certain reporting costs to comply with the
emission standards under the rule, there would be no new information collection costs, as the
information required by the final rule is already collected and reported by other regulatory
programs.
As stated above, although the EPA expects few sources will trigger either the NSPS
modification or reconstruction provisions, if an ECU were to modify or reconstruct during the 3-
year period covered by this ICR, the owner or operator of the ECU will be required to prepare a
summary report, which includes reporting of emissions and downtime, every 3 months. The
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annual reporting burden for such a unit is estimated to be $1,333 and 16 labor hours. There are
no annualized capital costs or O&M costs associated with burden for modified or reconstructed
EGUs.
7.2.3 Information Collection Burden
The annual information collection burden for newly constructed, modified, and
reconstructed EGUs consists only of reporting burden as explained above. The annual reporting
burden for this collection (averaged over the first 3 years after the effective date of the
standards) is estimated to be $60,997 and 651 labor hours. There are no annualized capital
costs or O&M costs associated with burden for newly constructed, modified, or reconstructed
EGUs. Average burden hours per response are estimated to be 7 hours. The total number of
respondents over the 3-year ICR period is estimated to be 62.
7.3 Regulatory Flexibility Act (RFA)
EPA certifies that this final action will not have a significant economic impact on a
substantial number of small entities under the RFA. In making this determination, the impact of
concern is any significant adverse economic impact on small entities. An agency may certify
that a rule will not have a significant economic impact on a substantial number of small entities
if the rule relieves regulatory burden, has no net burden or otherwise has a positive economic
effect on the small entities subject to the rule.
7.3.1 Newly constructed EGUs
The EPA believes that electric power companies will choose to build new fossil fuel-fired
electric utility steam generating units or natural gas-fired stationary combustion turbines that
comply with the regulatory requirements of the final rule because of existing and expected
market conditions. The EPA does not project any new coal-fired steam generating units without
CCS to be built. We expect that any newly constructed natural gas-fired stationary combustion
turbines will meet the standards. We do not include an analysis of the illustrative impacts on
small entities that may result from implementation of the final rule because we anticipate
negligible compliance costs over a range of likely sensitivity conditions as a result of the
standards for newly constructed EGUs. Thus the cost-to-sales ratios for any affected small
entity would be zero costs as compared to annual sales revenue for the entity. Accordingly,
there are no anticipated economic impacts as a result of the standards for newly constructed
EGUs. We have therefore concluded that this final action will have no net regulatory burden for
all directly regulated small entities.
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7.3.2 Modified and Reconstructed EGUs
The EPA expects few fossil fuel-fired electric utility steam generating units to trigger the
NSPS modification provisions in the period of analysis. An NSPS modification is defined as a
physical or operational change that increases the source's maximum achievable hourly rate of
emissions. The EPA does not believe that there are likely to be EGUs that will take actions that
would constitute modifications as defined under the EPA's NSPS regulations.
In addition, the EPA expects few reconstructed fossil fuel-fired electric utility steam
generating units or natural gas-fired stationary combustion turbines in the period of analysis.
Reconstruction occurs when a single project replaces components or equipment in an existing
facility and exceeds 50 percent of the fixed capital cost that would be required to construct a
comparable entirely new facility.
In Chapter 6, we discuss factors that limit our ability to quantify the costs and benefits
of the standards for modified and reconstructed sources. However, we do not anticipate that
the rule would impose significant costs on those sources, including any that are owned by small
entities.
7.4 Unfunded Mandates Reform Act (UMRA)
This final action does not contain an unfunded mandate of $100 million or more as
described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small
governments.
The EPA believes the final rule will have negligible compliance costs on owners and
operators of newly constructed EGUs over a range of likely sensitivity conditions because
electric power companies will choose to build new fossil fuel-fired electric utility steam
generating units or natural gas-fired stationary combustion turbines that comply with the
regulatory requirements of the rule because of existing and expected market conditions. The
EPA does not project any new coal-fired steam generating units without CCS to be built and
expects that any newly constructed natural gas-fired stationary combustion turbines will
meet the standards.
As previously stated, the EPA expects few fossil fuel-fired electric utility steam
generating units or natural gas-fired stationary combustion turbines to trigger the
modification or reconstruction provisions in the period of analysis. In Chapter 6, we discuss
factors that limit our ability to quantify the costs and benefits of the standards for modified
and reconstructed sources. However, we do not anticipate that the rule would impose
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significant costs on those sources.
We have therefore concluded that the standards for newly constructed, modified, and
reconstructed EGUs do not impose enforceable duties on any state, local or tribal governments,
or the private sector, that may result in expenditures by state, local and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any one year. We have also
concluded that this action does not have regulatory requirements that might significantly or
uniquely affect small governments. The threshold amount established for determining whether
regulatory requirements could significantly affect small governments is $100 million annually
and, as stated above, we have concluded that the final action will not result in expenditures of
$100 million or more in any one year. Specifically, the EPA does not project any new coal-fired
steam generating units without CCS to be built and expects that any newly constructed natural
gas-fired stationary combustion turbines will meet the standards. Further, the EPA expects few
fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion
turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis.
7.5 Executive Order 13132, Federalism
This final action does not have federalism implications. It will not have substantial direct
effects on the states, on the relationship between the national government and the states, or
on the distribution of power and responsibilities among the various levels of government. The
EPA believes that electric power companies will choose to build new fossil fuel-fired electric
utility steam generating units or natural gas-fired stationary combustion turbines that comply
with the regulatory requirements of the final rule because of existing and expected market
conditions. In addition, as previously stated, the EPA expects few modified or reconstructed
fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion
turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis.
We, therefore, anticipate that the final rule will impose minimal compliance costs.
7.6 Executive Order 13175, Consultation and Coordination with Indian Tribal
Governments
This final action does not have tribal implications as specified in Executive Order 13175.
The final rule will impose requirements on owners and operators of newly constructed,
modified, and reconstructed EGUs. The EPA is aware of three facilities with coal-fired steam
generating units, as well as one facility with natural gas-fired stationary combustion turbines,
located in Indian Country, but is not aware of any EGUs owned or operated by tribal entities.
We note that because the rule addresses CCh emissions from newly constructed, modified, and
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reconstructed EGUs, it will affect existing EGUs such as those located at the four facilities in
Indian Country only if those EGUs were to take actions constituting modifications or
reconstructions as defined under the EPA's NSPS regulations. As previously stated, the EPA
expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of
analysis. Thus, the rule will neither impose substantial direct compliance costs on tribal
governments nor preempt Tribal law. Accordingly, Executive Order 13175 does not apply to this
action.
Nevertheless, because the EPA is aware of Tribal interest in carbon pollution standards
for the power sector and, consistent with the EPA Policy on Consultation and Coordination with
Indian Tribes, the EPA offered consultation with tribal officials during development of this rule.
Prior to the April 13, 2012 proposal (77 FR 22392), the EPA sent consultation letters to the
leaders of all federally recognized tribes. Although only newly constructed, modified, and
reconstructed EGUs will be affected by this action, the EPA's consultation regarded planned
actions for new and existing sources. The letters provided information regarding the EPA's
development of NSPS and emission guidelines for EGUs and offered consultation. A
consultation/outreach meeting was held on May 23, 2011, with the Forest County Potawatomi
Community, the Fond du Lac Band of Lake Superior Chippewa Reservation, and the Leech Lake
Band of Ojibwe. A description of that consultation is included in the preamble to the proposed
standards for new EGUs (79 FR 1501, January 8, 2014).
The EPA also offered consultation to the leaders of all federally recognized tribes after
the proposed action for newly constructed EGUs was signed on September, 20, 2013. On
November 1, 2013, the EPA sent letters to tribal leaders that provided information regarding
the EPA's development of carbon pollution standards for new, modified, reconstructed and
existing EGUs and offered consultation. No tribes requested consultation regarding the
standards for newly constructed EGUs.
In addition to offering consultation, the EPA also conducted outreach to tribes during
development of this rule. The EPA held a series of listening sessions prior to proposal of GHG
standards for newly constructed EGUs. Tribes participated in a session on February 17, 2011,
with the state agencies, as well as in a separate session with tribes on April 20, 2011. The EPA
also held a series of listening sessions prior to proposal of GHG standards for modified and
reconstructed EGUs and GHG emission guidelines for existing EGUs. Tribes participated in a
session on September 9, 2013, together with the state agencies, as well as in a separate tribe-
only session on September 26, 2013. In addition, an outreach meeting was held on September
9, 2013, with tribal representatives from some of the federally recognized tribes. The EPA also
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met with tribal environmental staff with the National Tribal Air Association, by teleconference,
on July 25, 2013, and December 19, 2013. Additional detail regarding this stakeholder outreach
is included in the preamble to the proposed emission guidelines for existing EGUs (79 FR 34830,
June 18, 2014).
7.7 Executive Order 13045, Protection of Children from Environmental Health Risks and
Safety Risks
This action is not subject to Executive Order 13045 because it is not economically
significant as defined in Executive Order 12866. While the action is not subject to Executive
Order 13045, the EPA believes that the environmental health or safety risk addressed by this
action has a disproportionate effect on children. Accordingly, the agency has evaluated the
environmental health and welfare effects of climate change on children.
C02 is a potent greenhouse gas that contributes to climate change and is emitted in
significant quantities by fossil fuel-fired power plants. As stated above, the EPA believes the
final rule will have negligible effects on owners and operators of newly constructed EGUs over a
range of likely sensitivity conditions because electric power companies will choose to build new
fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion
turbines that comply with the regulatory requirements of the rule because of existing and
expected market conditions. However, Chapter 5 of this RIA also analyzes project-level costs of
a unit with and without CCS, to quantify the potential cost for a fossil fuel-fired unit with CCS.
Under these scenarios, the rule would result in substantial reductions of both C02, and also fine
particulate matter such that net quantifiable benefits exceed regulatory costs under a range of
scenarios. Under these same scenarios, this rule would have a positive effect for children's
health.
The assessment literature cited in the EPA's 2009 Endangerment Finding concluded that
certain populations and lifestages, including children, the elderly, and the poor, are most
vulnerable to climate-related health effects. The assessment literature since 2009 strengthens
these conclusions by providing more detailed findings regarding these groups' vulnerabilities
and the projected impacts they may experience.
These assessments describe how children's unique physiological and developmental
factors contribute to making them particularly vulnerable to climate change. Impacts to
children are expected from heat waves, air pollution, infectious and waterborne illnesses, and
mental health effects resulting from extreme weather events. In addition, children are among
those especially susceptible to most allergic diseases, as well as health effects associated with
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heat waves, storms, and floods. Additional health concerns may arise in low income
households, especially those with children, if climate change reduces food availability and
increases prices, leading to food insecurity within households.
More detailed information on the impacts of climate change to human health and
welfare is provided in Section II.A of the preamble.
7.8 Executive Order 13211, Actions Concerning Regulations That Significantly Affect
Energy Supply, Distribution, or Use
This final action is not a "significant energy action" because it is not likely to have a
significant adverse effect on the supply, distribution, or use of energy. The EPA believes that
electric power companies will choose to build new fossil fuel-fired electric utility steam
generating units or natural gas-fired stationary combustion turbines that comply with the
regulatory requirements of the final rule because of existing and expected market conditions. In
addition, as previously stated, the EPA expects few fossil fuel-fired electric utility steam
generating units or natural gas-fired stationary combustion turbines to trigger the NSPS
modification or reconstruction provisions in the period of analysis. Thus, this action is not
anticipated to have notable impacts on emissions, costs or energy supply decisions for the
affected electric utility industry.
7.9 National Technology Transfer and Advancement Act
This final action involves technical standards. The following voluntary consensus
standards are used in the final rule: American Society for Testing and Materials (ASTM)
Methods D388-12 (Standard Classification of Coals by Rank), D396-13c (Standard Specification
for Fuel Oils), D975-14 (Standard Specification for Diesel Fuel Oils), D3699-13b (Standard
Specification for Kerosene), D6751-12 (Standard Specification for Biodiesel Fuel Blend Stock
(B100) for Middle Distillate Fuels), D7467-13 (Standard Specification for Diesel Fuel Oil,
Biodiesel Blend (B6to B20)), and American National Standards Institute (ANSI) Standard C12.20
(American National Standard for Electricity Meters - 0.2 and 0.5 Accuracy Classes). The rule also
requires use of Appendices A, B, D, F and G to 40 CFR part 75; these Appendices contain
standards that have already been reviewed under the NTTAA.
7.10 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority
Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive
policy on environmental justice. Its main provision directs federal agencies, to the greatest
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extent practicable and permitted by law, to make environmental justice part of their mission by
identifying and addressing, as appropriate, disproportionately high and adverse human health
or environmental effects of their programs, policies, and activities on minority populations and
low-income populations in the U.S. The EPA defines environmental justice as the fair treatment
and meaningful involvement of all people regardless of race, color, national origin, or income
with respect to the development, implementation, and enforcement of environmental laws,
regulations, and policies. The EPA has this goal for all communities and persons across this
Nation. It will be achieved when everyone enjoys the same degree of protection from
environmental and health hazards and equal access to the decision-making process to have a
healthy environment in which to live, learn, and work.
Leading up to this rulemaking the EPA summarized the public health and welfare effects
of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment Finding, the
Administrator considered climate change risks to minority or low-income populations, finding
that certain parts of the population may be especially vulnerable based on their circumstances.
Populations that were found to be particularly vulnerable to climate change risks include the
poor, the elderly, the very young, those already in poor health, the disabled, those living alone,
and/or indigenous populations dependent on one or a few resources. See Sections F and G,
above, where the EPA discusses Consultation and Coordination with Tribal Governments and
Protection of Children. The Administrator placed weight on the fact that certain groups,
including children, the elderly, and the poor, are most vulnerable to climate-related health
effects.
The record for the 2009 Endangerment Finding summarizes the strong scientific
evidence that the potential impacts of climate change raise environmental justice issues is
found in the major assessment reports by the U.S. Global Change Research Program (USGCRP),
the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council
(NRC) of the National Academies that the potential impacts of climate change raise
environmental justice issues. These reports concluded that poor communities can be especially
vulnerable to climate change impacts because they tend to have more limited adaptive
capacities and are more dependent on climate-sensitive resources such as local water and food
supplies. In addition, Native American tribal communities possess unique vulnerabilities to
climate change, particularly those impacted by degradation of natural and cultural resource
within established reservation boundaries and threats to traditional subsistence lifestyles.
Tribal communities whose health, economic well-being, and cultural traditions depend upon
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the natural environment will likely be affected by the degradation of ecosystem goods and
services associated with climate change.
The 2009 Endangerment Finding record also specifically noted that Southwest native
cultures are especially vulnerable to water quality and availability impacts. Native Alaskan
communities already experiencing disruptive impacts, including coastal erosion and shifts in the
range or abundance of wild species crucial to their livelihoods and well-being. The most recent
assessments continue to strengthen scientific understanding of climate change risks to minority
and low-income populations in the United States.1 The new assessment reports provides more
detailed findings regarding these populations' vulnerabilities and projected impacts they may
experience. In addition, the most recent assessment reports provide new information on how
some communities of color may be uniquely vulnerable to climate change health impacts in the
United States. These reports find that certain climate change related impacts—including heat
waves, degraded air quality, and extreme weather events—have disproportionate effects on
low-income and some communities of color, raising environmental justice concerns. Existing
health disparities and other inequities in these communities increase their vulnerability to the
health effects of climate change. In addition, the assessment reports also find that climate
change poses particular threats to health, wellbeing, and ways of life of indigenous peoples in
the United States.
As the scientific literature presented above and in the Endangerment Finding illustrates,
low income communities and some communities of color are especially vulnerable to the
health and other adverse impacts of climate change.
1 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United
States: The Third National Climate Assessment. U.S. Global Change Research Program, 841 pp.
IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects.
Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate
Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, I.E. Bilir, M. Chatterjee, K.L Ebi, Y.O.
Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and LL White (eds.)].
Cambridge University Press, 1132 pp.
IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects.
Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate
Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, I.E. Bilir, M. Chatterjee, K.L Ebi, Y.O.
Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and LL White (eds.)].
Cambridge University Press, 688 pp.
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The EPA believes the human health or environmental risk addressed by this final action
will not have potential disproportionately high and adverse human health or environmental
effects on minority, low-income or indigenous populations. The final rule limits GHG emissions
from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam
generating units and natural gas-fired stationary combustion turbines by establishing national
emission standards for
The EPA has determined that the final rule will not result in disproportionately high and
adverse human health or environmental effects on minority, low-income or indigenous
populations because the rule is not anticipated to notably affect the level of protection
provided to human health or the environment. The EPA believes that electric power companies
will choose to build new fossil fuel-fired electric utility steam generating units and natural gas-
fired stationary combustion turbines that comply with the regulatory requirements of the final
rule because of existing and expected market conditions. The EPA does not project any new
coal-fired steam generating units without CCS to be built and expects that any newly built
natural gas-fired stationary combustion turbines will meet the standards. In addition, as
previously stated, the EPA expects few fossil fuel-fired electric utility steam generating units or
natural gas-fired stationary combustion turbines to trigger the NSPS modification or
reconstruction provisions in the period of analysis. This final rule will ensure that, to whatever
extent there are newly constructed, modified, and reconstructed EGUs, they will use the best
performing technologies to limit emissions of C02.
7.11 Congressional Review Act (CRA)
This final action is subject to the CRA, and the EPA will submit a rule report to each
House of the Congress and to the Comptroller General of the United States. This action is not a
"major rule" as defined by 5 U.S.C. 804(2).
7-12
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United States Office of Air Quality Planning and Standards Publication No. EPA-452/R-15-005
Environmental Protection Health and Environmental Impacts Division August 2015
Agency Research Triangle Park, NC
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