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Agency
Regulatory Impact Analysis for the Proposed Standards of
Performance for Greenhouse Gas Emissions for New Stationary
Sources: Electric Utility Generating Units
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EPA-452/R-13-003
September 2013
Regulatory Impact Analysis for the Proposed Standards of Performance for Greenhouse Gas
Emissions for New Stationary Sources: Electric Utility Generating Units
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Health and Environmental Impacts Division
Research Triangle Park, NC
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CONTACT INFORMATION
This document has been prepared by staff from the Office of Air Quality Planning and
Standards, U.S. Environmental Protection Agency. Questions related to this document should be
addressed to Amanda Curry Brown, U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, C439-02, Research Triangle Park, North Carolina 27711 (email:
CurryBrown.Amanda@epa.gov).
ACKNOWLEDGEMENTS
In addition to EPA staff from the Office of Air Quality Planning and Standards,
personnel from the U.S. EPA Office of Atmospheric Programs and Office of Policy contributed
data and analysis to this document.
in
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ACRONYMS
AEO Annual Energy Outlook
BACT Best Available Control Technology
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
CFR Code of Federal Regulations
CH4 Methane
C02 Carbon Dioxide
CRF Capital Recovery Factor
CSAPR Cross State Air Pollution Rule
CT Combustion Turbines
CUA Climate Uncertainty Adder
DICE Dynamic Integrated Climate and Economy Model
DOE U.S. Department of Energy
EAB Environmental Appeals Board
EGR Enhanced Gas Recovery
ECU Electric Generating Unit
EIA U.S. Energy Information Administration
EMM Electricity Market Module
EO Executive Order
EOR Enhanced Oil Recovery
EPA U.S. Environmental Protection Agency
ER Enhanced Recovery
FERC Federal Energy Regulatory Commission
FGD Flue Gas Desulfurization
FOAK First of a Kind
FOM Fixed Operating and Maintenance
FR Federal Register
FRCC Florida Reliability Coordinating Council
FUND Framework for Uncertainty, Negotiation, and Distribution Model
IV
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GDP
GHG
GS
Gt
H2S
HFC
1AM
ICR
IGCC
IOU
IPCC
IPM
IRP
kWh
Ibs
LCOE
LNB
MATS
ME A
MGD
mg/L
mmBtu
MW
MWh
N20
NaOH
NATCARB
NEEDS
NEMS
NERC
NETL
NGCC
NOAK
NOX
NRC
Gross Domestic Product
Greenhouse Gas
Geologic Sequestration
Gigaton
Hydrogen Sulfide
Hydrofluorocarbons
Integrated Assessment Model
Information Collection Request
Integrated Gasification Combined Cycle
Investor Owned Utility
Intergovernmental Panel on Climate Change
Integrated Planning Model
Integrated Resource Plan
Kilowatt-hour
Pounds
Levelized Cost of Electricity
Low NOX Burners
Mercury and Air Toxics Standards
Monoethanolamine
Millions of Gallons per Day
Milligrams per Liter
Million British Thermal Units
Megawatt
Megawatt-hour
Nitrous Oxide
Sodium Hydroxide
National Carbon Sequestration Database and Geographic Information
System
National Electric Energy Data System
National Energy Modeling System
North American Electric Reliability Corporation
National Energy Technology Laboratory
Natural Gas Combined Cycle
Next of a Kind or Nth of a Kind
Nitrogen Oxide
National Research Council
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NSPS
NSR
NTTAA
OFA
OMB
PAGE
RFC
PM2.5
ppm
PRA
PSD
RCSP
RES
RFA
RGGI
RIA
RPS
SBREFA
SCC
SCPC
SCR
SF6
SIP
SO 2
Tcf
IDS
TSD
TSM
UMRA
U.S.C.
USGCRP
USGS
U.S. NRC
VCS
VOM
New Source Performance Standard
New Source Review
National Technology Transfer and Advancement Act
Overfire Air
Office of Management and Budget
Policy Analysis of the Greenhouse Gas Effect Model
Perfluorocarbons
Fine Particulate Matter
Parts per Million
Paperwork Reduction Act
Prevention of Significant Deterioration
Regional Carbon Sequestration Partnerships
Renewable Electricity Standards
Regulatory Flexibility Act
Regional Greenhouse Gas Initiative
Regulatory Impact Analysis
Renewable Portfolio Standards
Small Business Regulatory Enforcement Fairness Act
Social Cost of Carbon
Super Critical Pulverized Coal
Selective Catalytic Reduction
Sulfur Hexafluoride
State Implementation Plan
Sulfur Dioxide
Trillion Cubic Feet
Total Dissolved Solids
Technical Support Document
Transportation Storage and Monitoring
Unfunded Mandates Reform Act
U.S. Code
U.S. Global Change Research Program
U.S. Geological Survey
U.S. Nuclear Regulatory Commission
Voluntary Consensus Standards
Variable Operating and Maintenance
VI
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TABLE OF CONTENTS
Executive Summary 1-1
1.1 Background and Context of Proposed Rule 1-1
1.2 Summary of the Proposed Rule 1-2
1.3 Key Findings of Economic Analysis 1-3
Chapter 2 Introduction and Background 2-1
2.1 Introduction 2-1
2.2 Background for the Proposed ECU New Source GHG Standards 2-3
2.3 Organization of the Regulatory Impact Analysis 2-7
Chapter 3 Defining the Climate Change Problem and Rationale for Rulemaking 3-1
3.1 Overview of Climate Change Impacts from GHG Emissions 3-1
3.2 References 3-8
Chapter 4 Electric Power Sector Profile 4-1
4.1 Introduction 4-1
4.2 Power Sector Overview 4-1
4.3 Deregulation and Restructuring 4-6
4.4 Emissions of Greenhouse Gases from Electric Utilities 4-7
4.5 Carbon Dioxide Control Technologies 4-11
4.6 Geologic Sequestration 4-14
4.7 GHG and Clean Energy Regulation in the Power Sector 4-22
4.8 Revenues, Expenses, and Prices 4-27
4.9 Natural Gas Market 4-31
VII
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4.10 Electricity Demand and Demand Response 4-33
4.11 References 4-35
Chapter 5 Costs, Benefits, Economic, and Energy Impacts 5-1
5.1 Synopsis 5-1
5.2 Requirements of the Proposed GHG ECU NSPS 5-2
5.3 Power Sector Modeling Framework 5-3
5.4 Analyses of Future Generating Capacity 5-6
5.5 Levelized Cost of Electricity Analysis 5-17
5.6 Comparison of Emissions from Generation Technologies 5-34
5.7 Benefits of Reducing GHGs and Other Pollutants 5-35
5.8 Comparison of Health and Welfare Impacts from Generation
Technologies 5-42
5.9 Illustrative Analysis- Benefits and Costs across a Range of Gas Prices 5-46
5.10 Illustrative Analysis - Benefits and Costs of CCS Compared with
Conventional Coal 5-50
5.11 Impact of the Proposed Rule on Option Costs 5-52
5.12 Summary of Costs, Benefits, and Energy Impacts 5-54
5.13 Macroeconomic and Employment Impacts 5-54
5.14 References 5-54
Chapter 6 Statutory and Executive Order Analyses 6-1
6.1 Synopsis 6-1
6.2 Executive Order 12866, Regulatory Planning and Review, and Executive
Order 13563, Improving Regulation and Regulatory Review 6-1
6.3 Paperwork Reduction Act 6-2
6.4 Regulatory Flexibility Act 6-4
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6.5 Unfunded Mandates Reform Act (UMRA) 6-7
6.6 Executive Order 13132, Federalism 6-8
6.8 Executive Order 13045, Protection of Children from Environmental Health
Risks and Safety Risks 6-10
6.9 Executive Order 13211, Actions Concerning Regulations That Significantly
Affect Energy Supply, Distribution, or Use 6-10
6.10 National Technology Transfer and Advancement Act 6-10
6.11 Executive Order 12898: Federal Actions to Address Environmental Justice
in Minority Populations and Low-Income Populations 6-11
IX
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LIST OF TABLES
Table 1-1. Proposed Emission Limits 1-3
Table 2-1. Proposed Emission Limits 2-6
Table 4-1. Existing Electricity Generating Capacity by Energy Source, 2011 4-3
Table 4-2. Total U.S. Electric Power Industry Retail Sales in 2011 (Billion kWh) 4-3
Table 4-3. Electricity Net Generation in 2011 (Billion kWh) 4-4
Table 4-4. Coal Steam Electricity Generating Units, by Size, Age, Capacity, and
Thermal Efficiency (Heat Rate) 4-5
Table 4-5. Domestic Emissions of Greenhouse Gases, by Economic Sector (million
metric tonnes of CO2 equivalent) 4-9
Table 4-6. Greenhouse Gas Emissions from the Electricity Sector (Generation,
Transmission and Distribution), 2011 (million metric tonnes of C02 equivalent) 4-10
Table 4-7. Fossil Fuel Emission Factors in EPA Modeling Applications 4-12
Table 4-8. Total C02 Storage Resource 4-17
Table 4-9. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric
Utilities for 2010 ($millions) 4-30
Table 4-10. Projected Revenues by Service Category in 2015 for Public Power and
Investor- Owned Utilities (billions) 4-31
Table 5-1.Reference Case Unplanned Cumulative Capacity Additions (GW) 5-9
Table 5-2. 2011 U.S. Electricity Net Generation and Projections for 2020, 2025, and
2030 (Billion kWh) 5-11
Table 5-3. AEO 2013 Unplanned Cumulative Capacity Additions, GW (2020) 5-13
Table 5-4. National Delivered 2020 Fuel Prices by AEO 2013 Scenario
(2011$/MMBtu) 5-16
Table 5-5. Technology Cost and Performance (2011$) 5-21
Table 5-6. Levelized Natural Gas Prices by Select AEO 2013 Scenario (2011$/MMBtu) 5-26
Table 5-7. AEO 2013 Regional Capital Cost Scalars by Capacity Type 5-27
Table 5-8. LCOE Estimates with Minimum and Maximum AEO 2013 Regional Capital
Cost Scalars (2011$/MWh) 5-28
Table 5-9. LCOE Estimates For Minimum and Maximum AEO 2013 Regional Capital
Cost Scalars (2011$/MWh) 5-29
Table 5-10. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired
Generating Units 5-36
Table 5-11. Social Cost of C02, 2015-20503 (in 2011$) 5-40
Table 5-12. Monetized Health Co-Benefits Per Ton of PM2.5 Precursor Reductions in
2020 (in 2011$) 5-43
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Table 5-13. 2020 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from
Illustrative New Natural Gas Combined Cycle Generation Relative to New SCPC
or IGCC Coal Generation without CCS 5-45
Table 5-14. 2020 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from
Coal- Fired Generation with CCS meeting 1,100 Ibs/MWh Relative to New Coal-
Fired Generation Without CCS 5-47
Table 5-15. Illustrative Costs and 2020 Social Benefits for SCPC with Partial Capture
and Full Capture CCS Relative to SCPC without CCS (per MWh 2011$) 5-52
Table 5-16. Illustrative Costs and 2020 Social Benefits for IGCC with Partial Capture
and Full Capture CCS Relative to IGCC without CCS (per MWh 2011$) 5-52
Table 6-1. Potentially Regulated Categories and Entities 6-5
XI
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LIST OF FIGURES
Figure 4-1. Fossil Fuel-Fired Electricity Generating Facilities, by Size 4-6
Figure 4-2. Status of State Electricity Industry Restructuring Activities 4-8
Figure 4-3. Domestic Emissions of Greenhouse Gases, 2011 (million metric tonnes of
C02 equivalent) 4-9
Figure 4-4. GHG Emissions from the Power Sector Relative to Total Domestic GHG
Emissions (2011) 4-11
Figure 4-5. Post-Combustion C02 Capture for a Pulverized Coal Power Plant 4-14
Figure 4-6. Pre-Combustion C02 Capture for an IGCC Power Plant 4-15
Figure 4-7. Growth of U.S. Oil Production from C02-based EOR 4-21
Figure 4-8. U.S. C02 Storage Capacity and C02-EOR operations 4-22
Figure 4-9. National Average Retail Electricity Price (1960 - 2011) 4-29
Figure 4-10. Average Retail Electricity Price by State (cents/kWh), 2011 4-31
Figure 4-11. Natural Gas Spot Price, Annual Average (Henry Hub) 4-34
Figure 4-12. Electricity Growth Rate (3-Year Rolling Average) and Projections from
the Annual Energy Outlook 2013 4-35
Figure 5-1. Historical U.S. Power Plant Capacity Additions, by Technology, 1940-2011.... 5-10
Figure 5-2. National Delivered Natural Gas Prices by Select AEO 2013 Scenario
(2011$/MMBtu) 5-17
Figure 5-3. Illustrative Wholesale Levelized Cost of Electricity of Alternative New
Generation Technologies by Cost Component, EPA 5-24
Figure 5-4. Illustrative Wholesale Levelized Cost of Electricity of Alternative New
Generation Technologies Across Select Natural Gas Prices, EPA 5-25
Figure 5-5. Projected Real National Delivered Natural Gas Price for Select AEO 2013
Scenarios and Illustrative Path for > $10/MMBtu Levelized Cost 5-27
Figure 5-6. Levelized Regional Fuel Price from AEO 2013 Reference Case, 2020-2039
(2011$/MMBtu) 5-29
Figure 5-7. Levelized Cost of Electricity, Uncontrolled Coal and Coal with Full and
Partial CCS (1,100 Ibs/MWh gross) 5-32
Figure 5-8. Levelized Cost of Electricity, Nuclear and Coal with Partial CCS (1,100
Ibs/MWh gross) 5-33
Figure 5-9. Levelized Cost of Electricity Across a Range of Capacity Factors, CT and
NGCC ($2011/MWh at $3.84/MMBtu Levelized Natural Gas Price) 5-35
Table 5-10. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired
Generating Units 5-36
XII
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EXECUTIVE SUMMARY
This Regulatory Impact Analysis (RIA) discusses potential benefits, costs, and economic
impacts of the proposed Standards of Performance for Greenhouse Gas Emissions for New
Stationary Sources: Electric Utility Generating Units (herein referred to as the ECU New Source
GHG Standards).
1.1 Background and Context of Proposed Rule
The proposed ECU New Source GHG Standards will set emission limits for greenhouse
gas emissions (GHG) from new fossil fuel fired electric generating units (ECU) constructed in the
United States in the future. This rulemaking will apply to carbon dioxide (C02) emissions from
any affected fossil fuel-fired ECU that sells more than one-third of its potential electric output
and more than 219,000 megawatt-hours (MWh) net-electrical output to the grid on a three
year rolling average basis. The United States Environmental Protection Agency (EPA) is
proposing requirements for these sources because C02 is a GHG and fossil fuel-fired power
plants are the country's largest stationary source emitters of GHGs. As stated in the EPA's
Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of
the Clean Air Act (74 FR 66518) and summarized in Chapter 3 of this RIA, the anthropogenic
buildup of GHGs in the atmosphere is very likely the cause of most of the observed global
warming over the last 50 years.
On April 13, 2012, the EPA proposed new source performance standards for emissions
of carbon dioxide for new affected fossil fuel-fired EGUs (77 FR 22392). After consideration of
public comments received - totaling approximately 2.5 million - the EPA determined that
significant revisions in its proposed approach are warranted to tailor the required emission
limits to the different types of sources in the electricity sector. As such, the EPA is, in a separate
action, rescinding the original proposal and is re-proposing standards of performance for new
affected fossil fuel-fired EGUs.
The statutory authority for this action is Clean Air Act (CAA) section lll(b), which
addresses standards of performance for new, modified, and reconstructed sources. Today's
proposal applies to new sources, which are sources that "commence construction" after
publication of the proposal. Based on current information, the Wolverine project in Rogers City,
Michigan appears to be the only fossil fuel-fired boiler or integrated gasification combined cycle
(IGCC) ECU project presently under development without carbon capture and storage (CCS)
with an air permit that has not already commenced construction. We anticipate proposing
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standards for this project when we finalize today's action if the project has not yet commenced
construction and has not been canceled.
This rulemaking affects CAA section lll(b) new sources of GHG emissions from fossil
fuel-fired EGUs but does not address GHG emissions from existing sources. This rulemaking also
does not propose standards for modified or reconstructed sources. 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.1 EPA's finding of no new, unplanned conventional coal-fired capacity
(and therefore, no projected costs or quantified benefits) is robust beyond the analysis period
(past 2030 in both U.S. Energy Information Administration - EIA - and EPA baseline modeling
projections) and across a wide range of alternative potential market, technical, and regulatory
scenarios that influence power sector investment decisions. Sections 5.8 to 5.11 of this RIA
discuss the social costs and benefits of the proposed standards in any limited cases where new
coal plant builds are affected by the standard.
This rule is consistent with the Climate Action Plan announced by the President in June
2013 to cut the carbon pollution that causes climate change and affects public health. The
President directed EPA to work expeditiously to complete carbon pollution standards for new
power plants.2 It is also consistent with the President's goal to ensure that "by 2035 we will
generate 80 percent of our electricity from a diverse set of clean energy sources - including
renewable energy sources like wind, solar, biomass and hydropower, nuclear power, efficient
natural gas, and clean coal."3 Additionally, this rule demonstrates to other countries that the
United States is taking action to limit GHGs from its largest emissions sources, in line with our
intention to demonstrate global leadership. The impact of GHGs is global, and U.S. action to
reduce GHG emissions complements ongoing programs and efforts in other countries.
1.2 Summary of the Proposed Rule
This rule proposes emission standards for affected fossil fuel-fired units within existing
subparts - natural gas-fired stationary combustion turbines and fossil fuel-fired electric utility
steam generating units (boilers and IGCC). All affected new fossil fuel-fired EGUs would be
required to meet an output-based emission rate of a specific mass of C02 per MWh of
1 Conditions in the analysis year of 2022 are represented by a model year of 2020.
2 "The President's Climate Action Plan." June 2013. Available online at:
http://www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf
3 "Blueprint for a Secure Energy Future." March 30, 2011. Available online at:
http://www.whitehouse.gov/sites/default/files/blueprint secure energy future.pdf
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electricity generated energy output on a gross basis. These standards would be met on a 12-
operating month rolling average basis. The EPA is proposing standards of performance for
affected sources within the following subcategories: (1) natural gas-fired stationary combustion
turbines with a heat input rating to the turbine engine that is greater than 850 million British
Thermal units per hour (MMBtu/hr); (2) natural gas-fired stationary combustion turbines with a
heat input rating to the turbine engine that is less than or equal to 850 MMBtu/hr; and (3) all
fossil fuel-fired boilers and IGCC units. The respective emission limits are shown in table 1-1.
Table 1-1. Proposed Emission Limits
Source Emission Limit
(Ib CO2/MWh
Gross Basis)
Stationary natural gas-fired combustion turbine EGUs with a 1,000
heat input rating greater than 850 MMBtu/hr
Stationary natural gas-fired combustion turbine EGUs with a 1,100
heat input rating less than or equal to 850 MMBtu/hr
Fossil fuel-fired boilers and IGCCs 1,100
This action also proposes an alternative emission limit, available only to new fossil-fuel
fired boilers and IGCCs, which can be met over an 84-operating month rolling average basis.
The alternative emission limit will be between 1,000 and 1,050 Ib C02/MWh of gross energy
output.
1.3 Key Findings of Economic Analysis
As explained in detail in this document, energy market data and projections support the
conclusion that, even in the absence of this rule, existing and anticipated economic conditions
will lead electricity generators to choose new generation technologies that meet the proposed
standard without the need for additional controls. The base case modeling the EPA performed
for this rule (as well as modeling that the EPA has performed for other recent air rules) projects
that, even in the absence of this action, new fossil-fuel fired capacity constructed through 2022
and the years following will most likely be natural gas combined cycle capacity. Alternatively,
coal-fired capacity with partial CCS could also be built at costs similar to the costs power
companies are paying for other, lower C02-emitting, non-natural gas, baseload generation
technologies. Analyses performed both by the EPA and the EIA4 project that generation
technologies other than those utilizing coal (including natural gas-fired and renewable sources)
4 Annual Energy Outlook (AEO) 2009- 2013.
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are likely to be the technology of choice for new generating capacity due to current and
projected economic market conditions.
Therefore, based on the analysis presented in Chapter 5, the EPA anticipates that the
proposed ECU New Source GHG Standards will result in negligible C02 emission changes,
energy impacts, quantified benefits, costs, and economic impacts by 2022. Accordingly, the EPA
also does not anticipate this rule will have any impacts on the price of electricity, employment
or labor markets, or the US economy. Nonetheless, this rule may have several important
beneficial effects described below.
This NSPS would provide regulatory certainty that any new coal-fired power plant must
limit C02 emissions by implementing some form of partial capture and storage. Therefore, the
proposed regulation would provide an incentive for supporting research, development, and
investment into technology to capture and store C02. Rather than relying solely on dynamic
energy market conditions to limit emissions from new power plants, this rule provides
additional certainty to help incentivize innovation that would lead to lower C02 emissions in
the future. The proposed rule is also a prerequisite for the regulation of existing sources within
this source category under CAA section lll(d).
While sector-wide modeling does not project any new coal-fired EGUs without CCS to be
built in the absence of this proposal, we recognize that a few companies may choose to
construct coal or other solid fossil fuel-fired units. In Chapter 5 of this RIA we present an
analysis of the project-level costs of a new coal-fired unit with and without CCS, and estimate
the social benefits of requiring CCS on a new uncontrolled unit. We also present a sensitivity
analysis indicating that even in the unlikely event that market conditions change sufficiently to
make the widespread construction of new conventional coal-fired units economical from the
perspective of private investors, this rule would result in net benefits from avoided negative
health and environmental effects.
The rule will reduce regulatory uncertainty by defining requirements for emission limits
for GHG from new fossil fuel-fired ECU sources. In addition, the EPA intends this rule to send a
clear signal about the current and future status of CCS technology. Identifying partial
implementation of CCS technology as the best system of emission reductions (BSER) for coal-
fired power plants promotes further development of CCS, which is important for long-term C02
emission reductions. Particularly because the CCS technologies have had limited application to
date, additional CCS applications are expected to lead to improvements in these technologies'
performance and consequent reductions in their cost. Moreover, partial implementation of CCS
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is a viable C02 control for new coal-fired power plants as identified in the BSER determination.
Acknowledging that CCS is a viable control will encourage continued research, including, for
example, continued research collaboration between the U.S. and China.5'6
5 Statement by Department of Energy Secretary Steven Chu. Statement by Secretary Chu.
http://energy.gov/articles/building-clean-energy-partnerships-china-and-iapan.
6 Friedman, Dr. Julio S. "A U.S. - China CCS Roadmap." Lawrence Livermore National Laboratory Carbon
Management Program. http://www.nrcce.wvu.edu/cleanenergy/docs/Friedmann.pdf.
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CHAPTER 2
INTRODUCTION AND BACKGROUND
2.1 Introduction
In this action, the EPA seeks to set emission limits for GHGs, specifically C02, emitted
from fossil fuel-fired EGUs. This document presents the expected economic impacts of the
proposed ECU New Source GHG Standards rule through 2022, including some projections for
years up to 2030. Based on the analysis presented in Chapter 5, expected and anticipated
economic conditions will lead electricity generators to choose fuels and technologies that are
designed to meet the proposed standard without the need for additional capture or control,
even in the absence of the rule. As a result, this rule is expected to have no, or negligible, costs
or monetized benefits associated with it. This chapter contains background information on the
rule and an outline of the chapters of the report.
2.1.1 Statutory Requirement
Section 111 of the CAA requires performance standards for air pollutant emissions from
categories of stationary sources that may reasonably contribute to endangerment of public
health or welfare. In April 2007, the Supreme Court ruled in Massachusetts v. EPA that GHGs
meet the definition of an "air pollutant" under the CAA. This ruling clarified that the authorities
and requirements of the CAA apply to GHGs. As a result, the EPA must make decisions about
whether to regulate GHGs under certain provisions of the CAA, based on relevant statutory
criteria. The EPA issued a final determination that GHG emissions endanger both the public
health and the public welfare of current and future generations in the Endangerment and Cause
or Contribute Findings for Greenhouse Gases Under Section 202(a) of the CAA (74 FR 66,496;
Dec. 15, 2009). Because fossil fuel-fired EGUs contribute significantly to domestic C02
emissions, the EPA is proposing this action to regulate these emissions from new ECU sources
under section 111 of the CAA.
On April 13, 2012, the EPA proposed new source performance standards for emissions
of C02 for new affected fossil fuel-fired EGUs (77 FR 22392). After consideration of public
comments received - totaling approximately 2.5 million - the EPA determined that significant
revisions in its proposed approach are warranted to tailor the required emission limits to the
different types of sources in the electricity sector. As such, the EPA is, in a separate action,
rescinding the original proposal and is re-proposing standards of performance for new affected
fossil fuel-fired EGUs. This action addresses standards for new sources but does not address
standards for modified, reconstructed, or existing sources.
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2.1.2 Regulatory Analysis
In accordance with Executive Order 12866, Executive Order 13563, and EPA's Guidelines
for Preparing Economic Analyses, the EPA prepared this RIA for this "significant regulatory
action/'This rule is not anticipated to have an annual effect on the economy of $100 million or
more or adversely affect in a material way the economy, a sector of the economy, productivity,
competition, jobs, the environment, public health or safety, or State, local, or tribal
governments or communities and is therefore not an "economically significant rule." However,
under EO 12866 (58 FR 51,735, October 4, 1993), this action is a "significant regulatory action"
because it "raises novel legal or policy issues arising out of legal mandates." As a matter of
policy, the EPA has attempted to provide a thorough analysis of the potential impacts of this
rule, consistent with requirements of the Executive Orders.
This RIA addresses the potential costs and benefits of the new source emission limits
that are the focus of this action. The EPA does not anticipate that any costs or quantified
benefits will result from this proposed rule, if companies make the types of choices related to
new generation that the EPA's modeling, ElA's modeling and many utility IRP's indicate they are
likely to make. If some companies do choose to build new coal plants, there could be some
compliance costs. However, in these cases, the rule will result in net societal benefits under a
range of assumptions.
For new sources, the EPA and other energy modeling groups such as EIA1 do not project
that any new coal capacity without federally-supported CCS will be built in the analysis period.
This is due in part to the low levelized cost of base load NGCC capacity relative to coal capacity,
relatively low growth in electricity demand, and use of energy efficiency and renewable energy
resources. This conclusion holds under a range of sensitivity analyses as well as in the EPA's
baseline scenario. Furthermore, absent this rule, any new NGCC that may be built is expected
to have an annual emission rate in compliance with the standard. Because this rule does not
change these projections, it is expected to have no, or negligible, costs2 or quantified benefits
1 AEO 2009-2013.
2 Because of existing and anticipated trends in the marketplace, the EPA does not project that any EGUs expected
to be built within the time frame of our analysis will have to install additional controls to meet the standard.
Additionally, because new generators would already be required to monitor and report their CO2 emissions
under the information collection requirements contained in the existing part 75 and 98 regulations (40 CFR part
75 and 40 CFR part 98), any additional monitoring or reporting costs from this proposed rule should be
negligible. Costs are only incurred if there has been a violation of an emission standard caused by a malfunction
and a source chooses to assert an affirmative defense. The owner/operator must meet the burden of proving
all of the requirements in an affirmative defense. See Chapter 6 for more details on monitoring and reporting
costs.
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associated with it. Chapter 5 of this RIA also provides an illustrative analysis of the levelized cost
of electricity and health and environmental impacts associated with representative new
conventional coal and NGCC units, under a range of natural gas price assumptions. That
analysis, along with information on historical3 and projected4 gas prices, supports the
conclusion that this standard is highly likely to have no costs or benefits. While we do not
project any new coal-fired EGUs without CCS to be built in the absence of this proposal,
because some companies may choose to construct coal or other solid fossil fuel-fired units,
Chapter 5 also includes an analysis of the project-level costs of a unit with and without CCS, to
quantify the potential cost for a solid fossil fuel-fired unit with CCS. There is also a comparison
of the costs and benefits for the proposed standard that can be met using partial CCS and a
more stringent alternative requiring full CCS.
2.2 Background for the Proposed ECU New Source GHG Standards
2.2.1 Baseline and Years of Analysis
The rule on which this analysis is based proposes GHG emission limits for new EGUs. The
baseline for this analysis, which uses the Integrated Planning Model (IPM), includes state rules
that have been finalized and/or approved by a state's legislature or environmental agencies as
well as final federal rules. Additional legally binding and enforceable commitments for GHG
reductions considered in the baseline are discussed in Chapter 5 of this RIA.
All analysis is presented for compliance through the year 20225 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 rulemaking's analysis is primarily focused on projected impacts within
the current eight-year NSPS timeframe. EPA's finding of no new, unplanned conventional coal-
fired capacity (and therefore, no projected costs or quantified benefits) is robust beyond the
analysis period (past 2030 in both EIA and EPA baseline modeling projections) and across a wide
range of alternative potential market, technical, and regulatory scenarios that influence power
sector investment decisions.6 Sections 5.8 to 5.11 of this RIA discuss the social costs and
benefits of the proposed standards in any limited cases where new coal plant builds are
3 EIA. U.S. Natural Gas Prices. Available online at: http://www.eia.gov/dnav/ng/ng pri sum dcu nus a.htm.
4AEO 2009-2013.
5 Conditions in the analysis year of 2022 are represented by a model year of 2020.
6 For example, the low gas resource sensitivity scenario, one of the scenarios most favorable to new coal builds,
does not begin to show new conventional coal builds until 2027. The No GHG Concern case does show limited
amounts of conventional coal starting in 2023; however that model sensitivity case is unlikely to be reflected in
actual markets given that investors factor in risks associated with all possible future policies (under both
current authorities and potential legislation at the State and Federal levels) to reduce GHG emissions over the
multi-decade life of the plant.
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affected by the standard. Any estimates presented in this report represent annualized
estimates of the benefits and costs of the proposed ECU New Source GHG Standards rather
than the net present value of a stream of benefits and costs in these particular years of
analysis.7
2.2.2 Definition of Affected Sources
This action will directly regulate C02 emissions from affected EGUs that commence
construction after the issuance of this proposed rule. This rulemaking does not address GHG
emissions from existing, modified, or reconstructed sources.
2.2.2.1 New Sources
The statutory authority for this action is CAA section lll(b), which addresses standards
of performance for new, modified, and reconstructed sources. Today's proposal applies to new
sources, which are sources that "commence construction" after publication of the proposal.
Based on current information, the Wolverine project in Rogers City, Michigan appears to be the
only fossil fuel-fired boiler or IGCC ECU project presently under development without CCS with
an air permit that has not already commenced construction. We anticipate proposing
standards for this project when we finalize today's action if the project has not yet commenced
construction and has not been canceled. See the preamble for further discussion.
2.2.2.2 Modified Sources
A modification is any physical or operational change to a source that increases the
amount of any air pollutant emitted by the source or results in the emission of any air pollutant
not previously emitted. However, projects to install pollution controls required under other
CAA provisions are specifically exempted from the definition of "modifications" under 40 CFR
60.14(e)(5), even if they emit C02 as a byproduct. The significant majority of projects that the
EPA believes EGUs are most likely to undertake in the foreseeable future that could increase
the maximum achievable hourly rate of C02 emissions would be pollution control projects that
are exempt under this definition. The EPA is not proposing a standard of performance for
modifications at this time. As a result, existing sources that undertake modifications will
continue to be treated as existing sources and thus not subject to the requirements of this rule.
7 However, the CO2-related benefits, which are estimated using the social cost of carbon, vary depending on the
year in which the change in CO2 emissions occurs. The social cost of carbon increases over time because future
emissions are expected to produce larger incremental damages as physical and economic systems become
more stressed in response to greater climatic change. See Chapter 5 for details.
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2.2.2.3 Reconstructed Sources
The EPA's CAA section 111 regulations provide that reconstructed sources are to be
treated as new sources and, therefore, subject to new source standards of performance. The
regulations define reconstructed sources, in general, as existing sources: (i) that replace
components to such an extent that the capital costs of the new components exceed 50 percent
of the capital costs of an entirely new facility and (ii) for which compliance with standards of
performance for new sources is technologically and economically feasible (40 CFR 60.15).
Historically, very few power plants have undertaken reconstructions. We are not aware that
any power plants are presently planning any project that would meet the requirements for a
reconstruction. The EPA is not proposing a standard for reconstructions. As a result, sources
that undertake reconstruction will be treated as existing sources and thus not subject to the
requirements of this rule.
2.2.2.4 Existing Sources
For the purposes of this rule, an existing ECU is defined as any fossil fuel-fired
combustion unit that sells more than one-third of its potential electric output and more than
219,000 MWh net-electrical output to the grid on a three year rolling average basis and was in
operation or commenced construction on or before publication of the proposed rule. Existing
sources are not covered in this proposed rule.
2.2.3 Regulated Pollutant
This rule sets a limit for C02 emissions from affected sources. The EPA is proposing
these requirements because C02 is a GHG and fossil fuel-fired power plants are the country's
largest stationary source emitters of GHGs. In 2009, the EPA found that by causing or
contributing to climate change, GHGs endanger both the public health and the public welfare of
current and future generations.
The EPA is aware that other GHGs such as nitrous oxide (N20) (and to a lesser extent,
methane (CH4)) may be emitted from fossil-fuel-fired EGUs, especially from coal-fired
circulating fluidized bed combustors and from units with selective catalytic reduction and
selective non-catalytic reduction systems installed for nitrogen oxide (NOX) control. The EPA is
not proposing separate N20 or CH4 emission limits or an equivalent C02 emission limit because
of a lack of available data for these affected sources. Additional information on the quantity
and significance of emissions and on the availability of cost effective controls would be needed
before proposing standards for these pollutants.
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2.2.4 Emission Limits
This rule proposes emission standards for affected fossil fuel-fired units within existing
subparts - natural gas-fired stationary combustion turbines and fossil fuel-fired electric utility
steam generating units (boilers and IGCC units). The EPA is proposing standards of performance
for affected sources within the following subcategories: (1) natural gas-fired stationary
combustion turbines with a heat input rating to the turbine engine that is greater than 850
million MMBtu/hr; (2) natural gas-fired stationary combustion turbines with a heat input rating
to the turbine engine that is less than or equal to 850 MMBtu/hr; and (3) all fossil fuel-fired
boilers and IGCC units. The respective emission limits are shown in table 2-1.
Table 2-1. Proposed Emission Limits
Subcategory Emission Limit
(Ib CO2/MWh)
Stationary natural gas-fired combustion turbine EGUs with a 1,000
heat input rating greater than 850 MMBtu/hr
Stationary natural gas-fired combustion turbine EGUs with a 1,100
heat input rating less than or equal to 850 MMBtu/hr
Fossil fuel-fired boilers and IGCC 1,100
This action also proposes an alternative emission limit, available only to new fossil fuel-
fired boilers and IGCC units, which can be met over an 84-operating month rolling average
basis. The alternative emission limit will be between 1,000 and 1,050 Ib C02/MWh of gross
energy output.
2.2.5 Emission Reductions
As will be discussed in more detail in Chapter 5 of this RIA, the EPA anticipates that the
proposed ECU New Source GHG Standards will result in negligible changes in GHG emissions
over the analysis period (through 2022 and following years). Even in the absence of this rule,
the EPA expects that owners of new units will choose generation technologies that meet these
standards due to expected economic conditions in the marketplace.
2.3 Organization of the Regulatory Impact Analysis
This report presents the EPA's analysis of the potential benefits, costs, and other
economic effects of the proposed ECU New Source GHG Standards to fulfill the requirements of
an RIA. This RIA includes the following chapters:
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Chapter 3, Defining the Climate Change Problem and Rationale for the Rulemaking,
describes the effects of GHG emissions on climate and offers support for the EPA
undertaking this rulemaking.
Chapter 4, Electric Power Sector Profile, describes the industry affected by the rule.
Chapter 5, Costs, Benefits, Economic, and Energy Impacts, describes impacts of the
proposed rule.
Chapter 6, Statutory and Executive Order Impact Analyses, describes the small
business, unfunded mandates, paperwork reduction act, environmental justice, and
other analyses conducted for the rule to meet statutory and Executive Order
requirements.
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CHAPTER 3
DEFINING THE CLIMATE CHANGE PROBLEM AND RATIONALE FOR RULEMAKING
3.1 Overview of Climate Change Impacts from GHG Emissions
Through the implementation of CAA regulations, EPA addresses the negative
externalities caused by air pollution. In 2009, the EPA Administrator found that elevated
concentrations of greenhouse gases in the atmosphere may reasonably be anticipated both to
endanger public health and to endanger public welfare. It is these adverse impacts that make it
necessary for the EPA to regulate GHGs from ECU sources. This proposed rule is designed to set
emission limits for C02, in order to minimize the rate of increase of concentrations of these
gases in the atmosphere, and therefore reduce the risk of adverse effects.
This chapter summarizes the adverse effects on public health and public welfare
detailed in the 2009 Endangerment Finding.1 The major assessments by the U.S. Global Change
Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the
National Research Council (NRC) served as the primary scientific basis for these effects.
3.1.1 Public Health
Climate change threatens public health in a number of ways: direct temperature effects,
the effect of higher C02 on other characteristics of air quality, the potential for changes in
vector-borne diseases, and the potential for changes in the severity and frequency of extreme
weather events. Additionally, susceptible populations may be particularly at risk. Each of these
effects will be addressed in turn in this section, based on the 2009 Endangerment Finding.
Regarding direct temperature changes, it has already been observed that unusually hot
days and heat waves are becoming more frequent, and that unusually cold days are becoming
less frequent. Heat is already the leading cause of weather-related deaths in the United States.
In the future, severe heat waves are projected to intensify in magnitude and duration over the
portions of the United States where these events have already been observed. Heat waves are
associated with marked short-term increases in mortality. Hot temperatures have also been
associated with increased morbidity. If observed warming continues as projected, it will
increase heat related mortality and morbidity, especially among the elderly, young, and frail.
Different segments of the population are sensitive to these trends for different reasons. The
most sensitive to hot temperatures are older adults, the chronically sick, the very young, city-
1 Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act,
74 Fed. Reg. 66,496 (Dec. 15, 2009).
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dwellers, and those taking medications that disrupt thermoregulation. Others that are
demonstrated to be sensitive to this trend are the mentally ill, those lacking access to air
conditioning, those working or playing outdoors, and socially isolated persons. As warming
increases over time, these adverse effects would be expected to increase as the serious heat
events become more frequent, prolonged, and extreme.
Conversely, increases in temperature are also expected to lead to some reduction in the
risk of death related to extreme cold. However it is not clear whether reduced mortality in the
United States from cold would be greater or less than increased heat-related mortality in the
United States due to climate change. However, there is a risk that projections of cold-related
deaths, and the potential for decreasing their numbers due to warmer winters, can be
overestimated unless they take into account the tendency for deaths to increase in winter for
reasons which are not strongly associated with cold temperatures, such as influenza. To
illustrate the difficulty of measuring the total effect of these two related trends, the latest
USGCRP report (2009) refers to a study (Medina-Ramon and Schwartz, 2007) that analyzed daily
mortality and weather data in 50 U.S. cities from 1989 to 2000 and found that, on average, cold
snaps in the United States increased death rates by 1.6 percent, while heat waves triggered a
5.7 percent increase in death rates. While a single study is not conclusive, this study concludes
that increases in heat-related mortality due to global warming in the United States are likely to
be greater than decreases in cold-related mortality.
Climate change is expected to increase regional ozone pollution compared to what
ozone levels would be in the absence of climate change, with associated risks in respiratory
illnesses and premature death. In addition to human health effects, tropospheric ozone has
significant adverse effects on crop yields, pasture and forest growth, and the composition of
plant and animal species populations.
Peer reviewed modeling studies discussed in the EPA's Interim Assessment (2009) show
that modeled climate change causes increases in summertime ozone concentrations over
substantial regions of the country, though this was not uniform. Some areas showed little
change or slight decreases, though the decreases tend to be less pronounced than the
increases. The key metric for regulating U.S. air quality is the maximum daily 8-hour average
ozone concentration. For those regions that showed climate-induced increases, the increase in
2050, was in the range of 2 to 8 ppb, averaged over the summer season. The increases were
substantially greater than 2 to 8 ppb during the peak pollution episodes that tend to occur over
a number of days each summer. The overall effect of climate change was projected to increase
ozone levels, compared to what would occur without this climate change, over broad areas of
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the country, especially on the highest ozone days and in the largest metropolitan areas with the
worst ozone problems. Ozone decreases are projected to be less pronounced, and generally to
be limited to some regions of the country with smaller population.
In addition to impacts on heat-related mortality and air quality, there is also the
potential for increased deaths, injuries, infectious diseases, and stress-related disorders and
other adverse effects associated with social disruption and migration from more frequent
extreme weather. Vulnerability to these disasters depends on the attributes of the people at
risk and on broader social and environmental factors.
Increases in the frequency of heavy precipitation events are associated with increased
risk of deaths and injuries as well as infectious, respiratory, and skin diseases. Floods are low-
probability, high-impact events that can overwhelm physical infrastructure, human resilience,
and social organization. Floods cause impacts to health that include deaths, injuries, infectious
diseases, toxic contamination, and mental health problems.
Increases in tropical cyclone intensity (hurricanes and tropical storms) are linked to
increases in the risk of deaths, injuries, waterborne and food borne diseases, as well as post-
traumatic stress disorders. Storm surge is the major killer in coastal storms, and the risk of
death by drowning from surge will be heightened by the projected rising sea levels and
increased storm intensity. Flooding caused by intense cyclonic events can cause health impacts
including direct injuries as well as increased incidence of waterborne diseases.
According to the assessment literature, there will also likely be an increase in the spread
of serial episodes of food and water-borne pathogens among susceptible populations
depending on the pathogens' survival, persistence, habitat range and transmission under
changing climate and environmental conditions. Food borne diseases show some relationship
with temperature. The range of some zoonotic disease carriers, such as the Lyme disease-
carrying tick, may increase with temperature.
Climate change, including changes in C02 concentrations, could impact the production,
distribution, dispersion, and allergenicity of aeroallergens and the growth and distribution of
weeds, grasses, and trees that produce them. These changes in aeroallergens and subsequent
human exposures could affect the prevalence and severity of allergy symptoms. However, the
scientific literature does not provide definitive data or conclusions on how climate change
might impact aeroallergens and subsequently the prevalence of allergenic illnesses in the
United States. It has generally been observed that the presence of elevated C02 concentrations
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and temperatures stimulate plants to increase photosynthesis, biomass, water use efficiency,
and reproductive effort. The IPCC concluded that pollens are likely to increase with elevated
temperature and C02.
3.1.2 Public Welfare
As with public health, there are multiple pathways in which the greenhouse gas air
pollution and resultant climate change affect climate-sensitive economic sectors and
environmental media. These sectors include food production and agriculture; forestry; water
resources; sea level rise and coastal areas; energy, infrastructure, and settlements; and
ecosystems and wildlife. Impacts also arise from climate change occurring outside of the United
States, such as national security concerns for the United States that may arise as a result of
climate change impacts in other regions of the world. Each of these effects will be addressed in
turn in this section, based on the 2009 Finding.
Regarding food production and agriculture, elevated C02 concentrations can have a
stimulatory effect, as may modest temperature increases and a resulting longer growing
season. However, elevated C02 concentrations may also enhance pest and weed growth. In
addition, higher temperature increases, changing precipitation patterns and variability, and any
increases in ground-level ozone induced by higher temperatures, can work to counteract any
direct stimulatory carbon dioxide effect, as well as lead to their own adverse impacts. A
USGCRP report (2009) concluded that while for some crops such as grain and oilseed crops
there may be a beneficial effect overall in the next couple decades, as temperature rises, these
crops will increasingly begin to experience failure, especially if climate variability increases and
precipitation lessens or becomes more variable. Changes in the intensity and frequency of
extreme weather events such as droughts and heavy storms have the potential to have serious
negative impact on U.S. food production and agriculture. Changing precipitation patterns, in
addition to increasing temperatures and longer growing seasons, can change the demand for
irrigation requirements, potentially increasing irrigation demand.
With respect to livestock, higher temperatures will very likely reduce livestock
production during the summer season in some areas, but these losses will very likely be
partially offset by warmer temperatures during the winter season. The impact on livestock
productivity due to increased variability in weather patterns will likely be far greater than the
effects associated with an absolute change in average climatic conditions.
For the forestry sector there are similar factors to consider. There is the potential for
beneficial effects due to elevated concentrations of carbon dioxide, increased temperatures,
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and nitrogen deposition, but there is also the potential for adverse effects from increasing
temperatures, changing precipitation patterns, increased insects and disease, and the potential
for more frequent and severe extreme weather events. According to the science assessment
reports on which the Administrator relied for the 2009 Finding, climate change has very likely
increased the size and number of wildfires, insect outbreaks, and increased tree mortality in the
Interior West, the Southwest, and Alaska, and will continue to do so.
If existing trends in precipitation continue, it is expected that forest productivity will
likely decrease in the Interior West, the Southwest, eastern portions of the Southeast, and
Alaska, and that forest productivity will likely increase in the northeastern United States, the
Lake States, and in western portions of the Southeast. An increase in drought events will very
likely reduce forest productivity wherever such events occur.
The sensitivity of water resources to climate change is very important given the
increasing demand for adequate water supplies and services for agricultural, municipal, and
energy and industrial uses, and the current strains on this resource in many parts of the
country. According to the assessment literature, climate change has already altered, and will
likely continue to alter the water cycle, affecting where, when, and how much water is available
for all uses. With higher temperatures, the water-holding capacity of the atmosphere and
evaporation into the atmosphere increase, and this favors increased climate variability, with
more intense precipitation and more droughts.
Climate change is causing and will increasingly cause shrinking snowpack induced by
increasing temperature. In the western United States, there is already well-documented
evidence of shrinking snowpack due to warming. Earlier meltings, with increased runoff in the
winter and early spring, increase flood concerns and also result in substantially decreased
summer flows. This pattern of reduced snowpack and changes to the flow regime pose very
serious risks to major population regions, such as California, that rely on snowmelt-dominated
watersheds for their water supply. While increased precipitation is expected to increase water
flow levels in some eastern areas, this may be tempered by increased variability in the
precipitation and the accompanying increased risk of floods and other concerns such as water
pollution.
Climate change will likely further constrain already over-allocated water resources in
some regions of the United States, increasing competition among agricultural, municipal,
industrial, and ecological uses. Increased incidence of extreme weather and floods may also
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overwhelm or damage water treatment and management systems, resulting in water quality
impairments.
According to the assessment literature, sea level is rising along much of the U.S. coast
and the rate of change will very likely increase in the future, exacerbating the impacts of
progressive inundation, storm-surge flooding, and shoreline erosion. A large percentage of the
U.S. population lives in these coastal areas. The most vulnerable areas are the Atlantic and Gulf
Coasts, the Pacific Islands, and parts of Alaska. Cities such as New Orleans, Miami, and New
York are particularly at risk, and could have difficulty coping with the sea level rise projected by
the end of the century under a higher emissions scenario. Population growth and the rising
value of infrastructure increases the vulnerability of coastal areas to climate variability and
future climate change. Adverse impacts on islands present concerns for Hawaii and the U.S.
territories. Reductions in Arctic sea ice increases extreme coastal erosion in Alaska, due to the
increased exposure of the coastline to strong wave action. In the Great Lakes, where sea level
rise is not a concern, both extremely high and low water levels resulting from changes to the
hydrological cycle have been damaging and disruptive to shoreline communities.
Coastal wetland loss is being observed in the United States where these ecosystems are
squeezed between natural and artificial landward boundaries and rising sea levels. Up to 21
percent of the remaining coastal wetlands in the U.S. mid-Atlantic region are potentially at risk
of inundation between 2000 and 2100. Stress will increase on coastal habitats though the
interaction of climate change with development and pollution related to development.
Although increases in mean sea level over the 21st century and beyond are projected to
inundate unprotected, low-lying areas, the most devastating impacts are likely to be associated
with storm surge. Superimposed on expected rates of sea level rise, projected storm intensity,
wave height, and storm surge suggest more severe coastal flooding and erosion hazards. Higher
sea level provides an elevated base from which storm surges occur and diminishes the rate at
which low-lying areas drain, thereby increasing the risk of flooding from rainstorms. In New
York City and Long Island, flooding from a combination of sea level rise and storm surge could
be several meters deep. Projections suggest that the recurrence period of a 100-year flood
event in this area might be reduced to 4-60 years by the 2080s. Additionally, some major urban
centers in the United States, such as areas of New Orleans are situated in low-lying flood plains,
presenting increased risk from storm surges.
With respect to infrastructure, climate change vulnerabilities of industry, settlement,
and society are mainly related to changes in intensity and frequency of extreme weather events
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rather than to gradual climate change. Extreme weather events could threaten U.S. energy
infrastructure (transmission and distribution), transportation infrastructure (roads, bridges,
airports and seaports), water infrastructure, and other built aspects of human settlements.
Moreover, soil subsidence caused by the melting of permafrost in the Arctic region is a risk to
gas and oil pipelines, electrical transmission towers, roads, and water systems.
Within settlements experiencing climate change stressors, certain parts of the
population may be especially vulnerable based on their circumstances. These include the poor,
the elderly, the very young, those already in poor health, the disabled, those living alone,
and/or indigenous populations dependent on one or a few resources. In Alaska, indigenous
communities are likely to experience disruptive impacts, including shifts in the range or
abundance of wild species crucial to their livelihoods and well-being.
Climate change is exerting major influences on natural environments and biodiversity,
and these influences are generally expected to grow with increased warming. Observed
changes in the life cycles of plants and animals include shifts in habitat ranges, timing of
migration patterns, and changes in reproductive timing and behavior.
The underlying assessment literature finds with high confidence that substantial
changes in the structure and functioning of terrestrial ecosystems are very likely to occur with a
global warming greater than 2 to 3 °C above pre-industrial levels, with predominantly negative
consequences for biodiversity and the provisioning of ecosystem goods and services. With
global average temperature changes above 2 °C, many terrestrial, freshwater, and marine
species (particularly endemic species) are at a far greater risk of extinction than in the
geological past. Climate change and ocean acidification will likely impair a wide range of
planktonic and other marine calcifiers such as corals. Even without ocean acidification effects,
increases in sea surface temperature of about 1 to 3 °C are projected to result in more frequent
coral bleaching events and widespread coral mortality. In the Arctic, wildlife faces great
challenges from the effects of climatic warming, as projected reductions in sea ice will
drastically shrink marine habitat for polar bears, ice-inhabiting seals, and other animals.
Some common forest types are projected to expand, others are projected to contract,
and others, such as spruce-fir, are likely to disappear from the contiguous United States.
Changes in plant species composition in response to climate change can increase ecosystem
vulnerability to other disturbances, including wildfires and biological invasion. Disturbances
such as wildfires and insect outbreaks are increasing in the United States and are likely to
intensify in a warmer future with warmer winters, drier soils and longer growing seasons. The
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areal extent of drought-limited ecosystems is projected to increase 11 percent per °C warming
in the United States. In California, temperature increases greater than 2°C may lead to
conversion of shrubland into desert and grassland ecosystems and evergreen conifer forests
into mixed deciduous forests. Greater intensity of extreme events may alter disturbance
regimes in coastal ecosystems leading to changes in diversity and ecosystem functioning.
Species inhabiting salt marshes, mangroves, and coral reefs are likely to be particularly
vulnerable to these effects.
According to the USGCRP report of June 2009 and other sources, climate change
impacts in certain regions of the world may exacerbate problems that raise humanitarian,
trade, and national security issues for the United States.2 The IPCC identifies the most
vulnerable world regions as Africa, especially the sub-Saharan region, because of current low
adaptive capacity as well as climate change; small islands, due to high exposure of population
and infrastructure to risk of sea-level rise and increased storm surge; Asian mega-deltas due to
large populations and high exposure to sea level rise, storm surge, and river flooding; and the
Arctic, because of the effects of high rates of projected warming on natural systems. Climate
change has been described as a potential threat multiplier with regard to national security
issues. While some of these international risks do not readily lend themselves to precise
analyses or future projections, given the unavoidable global nature of the climate change
problem it is appropriate and prudent to consider how impacts in other world regions may
present risks to the U.S. population.
3.2 References
40 CFR Chapter I [EPA-HQ-OAR-2009-0171; FRL-9091-8] RIN 2060-ZA14, "Endangerment and
Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean
Air Act," Federal Register / Vol. 74, No. 239 / Tuesday, December 15, 2009 / Rules and
Regulations.
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.
2 "In an increasingly interdependent world, U.S. vulnerability to climate change is linked to the fates of other
nations. For example, conflicts or mass migrations of people resulting from food scarcity and other resource limits,
health impacts or environmental stresses in other parts of the world could threaten U.S. national security." (Karl et
ai, 2009).
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U.S. Environmental Protection Agency (2009). Assessment of the Impacts of Global Change on
Regional U.S. Air Quality: A Synthesis of Climate Change Impacts on Ground-Level Ozone.
An Interim Report of the U.S. EPA Global Change Research Program. U.S. Environmental
Protection Agency, Washington, DC, EPA/600/R-07/094.
U.S. Global Change Research Program (USGCRP). Global Climate Change Impacts in the United
States. Thomas R. Karl, Jerry M. Melillo, and Thomas C. Peterson, (eds.). Cambridge
University Press, 2009.
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CHAPTER 4
ELECTRIC POWER SECTOR PROFILE
4.1 Introduction
This chapter discusses important aspects of the power sector that relate to the
proposed ECU New Source GHG Standards, including the types of power-sector sources
affected by the proposal, and provides background on the power sector and EGUs. In addition,
this chapter provides some historical background on the EPA regulation of, and future
projections for, the power sector.
4.2 Power Sector Overview
The production and delivery of electricity to customers consists of three distinct
segments: generation, transmission, and distribution.
4.2.1 Generation
Electricity generation is the first process in the delivery of electricity to consumers. Most
of the existing capacity for generating electricity does so by creating heat to create high
pressure steam that is released to rotate turbines which, in turn, create electricity. The power
sector consists of over 18,000 generating units, comprising fossil-fuel-fired units, nuclear units,
and hydroelectric and other renewable sources dispersed throughout the country (see Table 4-
1).
These electric generating sources provide electricity for commercial, industrial, and
residential uses, each of which consumes roughly a quarter to a third of the total electricity
produced (see Table 4-2). Some of these uses are highly variable, such as heating and air
conditioning in residential and commercial buildings, while others are relatively constant, such
as industrial processes that operate 24 hours a day.
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Table 4-1. Existing Electricity Generating Capacity by Energy Source, 2011
Energy Source
Coal
Petroleum
Natural Gas
Other Gases
Nuclear
Hydroelectric Conventional
Wind
Solar Thermal and Photovoltaic
Wood and Wood-Derived Fuels
Geothermal
Other Biomass
Hydroelectric Pumped Storage
Other Energy Sources
Total
Number of
Generators
1,400
3,738
5,574
91
104
4,048
781
326
345
226
1,660
154
81
18,530
Generator
Nameplate
Capacity (MW)
343,757
57,537
477,387
2,202
107,001
78,194
45,982
1,564
8,014
3,500
5,192
20,816
1,697
1,153,149
Generator Net
Summer
Capacity (MW)
317,640
51,208
415,191
1,934
101,419
78,652
45,676
1,524
7,077
2,409
4,536
22,293
1,420
1,051,251
Source: Table 4.3, EIA Electric Power Annual, 2011
Note: This table presents generation capacity. Actual net generation is presented in Table 4-3.
Table 4-2. Total U.S. Electric Power Industry Retail Sales in 2011 (Billion kWh)
Sales/Direct Use Share of Total
(Billion kWh) End Use
Residential
Commercial
Retail Sales
Industrial
Transportation
Direct Use
Total End Use
1,423
1,328
991
8
133
3,883
37.9%
35.4%
26.4%
0.2%
3.5%
100%
Source: Table 2.2, EIA Electric Power Annual, 2011
In 2011, electric generating sources produced 3,949 billion kWh to meet electricity
demand. Roughly 70 percent of this electricity was produced through the combustion of fossil
fuels, primarily coal and natural gas, with coal accounting for the largest single share (see
Table 4-3).
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Table 4-3. Electricity Net Generation in 2011 (Billion kWh)
Coal
Petroleum
Natural Gas
Other Gases
Nuclear
Hydroelectric
Other
Total
Net Generation
(Billion kWh)
1,718
28
926
3
790
312
172
3,949
Fuel Source
Share
43.5%
0.7%
23.5%
0.1%
20.0%
7.9%
4.3%
100%
Source: Tables 3.2.A and 3.3.A, EIA Electric Power Annual, 2011
Note: Excludes generation from commercial and industrial sectors. Retail sales are not equal to net generation
because net generation includes net exported electricity and loss of electricity that occurs through
transmission and distribution.
Coal-fired generating units have historically supplied "base-load" electricity, the portion
of electricity loads which are continually present, and typically operate throughout the day.
Along with nuclear generation, these coal units meet the part of demand that is relatively
constant. Although much of the coal fleet operates as base load, there can be notable
differences across various facilities (see Table 4-4). For example, coal-fired units less than 100
megawatts (MW) in size compose 37 percent of the total number of coal-fired units, but only 6
percent of total coal-fired capacity. Gas-fired generation is better able to vary output and is the
primary option used to meet the variable portion of the electricity load and has historically
supplied "peak" and "intermediate" power, when there is increased demand for electricity (for
example, when businesses operate throughout the day or when people return home from work
and run appliances and heating/air-conditioning), versus late at night or very early in the
morning, when demand for electricity is reduced.
The evolving economics of the power sector, in particular the increased natural gas
supply and subsequent relatively low natural gas prices, have resulted in more gas being
utilized as base load energy in addition to supplying electricity during peak load. Projections of
new capacity and the impact of this rule on these new sources are discussed in more detail in
Chapter 5 of this RIA.
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Table 4-4. Coal Steam Electricity Generating Units, by Size, Age, Capacity, and Thermal
Efficiency (Heat Rate)
Unit Size Grouping
(MW)
0 to 25
>25 to 49
50 to 99
100 to 149
150 to 249
250 and up
Totals
No. Units
193
108
162
269
81
453
1,266
% of All
Units
15%
9%
13%
21%
6%
36%
Avg. Age
45
42
47
49
43
34
Avg. Net
Summer
Capacity
(MW)
15
38
75
141
224
532
Total Net
Summer
Capacity
(MW)
2,849
4,081
12,132
38,051
18,184
241,184
316,480
% Total
Capacity
1%
1%
4%
12%
6%
76%
Avg. Heat
Rate
(Btu/kWh)
11,154
11,722
11,328
10,641
10,303
10,193
Source: National Electric Energy Data System (NEEDS) v.4.10
Note: The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed
to a generation-weighted or capacity-weighted average heat rate.) A lower heat rate indicates a higher
level of fuel efficiency. Table is limited to coal-steam units online in 2010 or earlier, and excludes those
units with planned retirements.
4.2.2 Transmission
Transmission is the term used to describe the movement of electricity over a network of
high voltage lines, from electric generators to substations where power is stepped down for
local distribution. In the U.S. and Canada, there are three separate interconnected networks of
high voltage transmission lines,1 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
operator; in others, individual utilities coordinate the operations of their generation,
transmission, and distribution systems to balance their common generation and load needs.
1These three network interconnections are the western US and Canada, corresponding approximately to the area
west of the Rocky Mountains; eastern US and Canada, not including most of Texas; and a third network
operating in most of Texas. These are commonly referred to as the Western Interconnect Region, Eastern
Interconnect Region, and ERCOT, respectively.
4-4
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Facility Capacity (MW)
• 2510100
• 100to500
• 500101,000
• 1.000 to 2,000
• 2,000 to 3,700
Figure 4-1. Fossil Fuel-Fired Electricity Generating Facilities, by Size
Source: National Electric Energy Data System (NEEDS) 4.10
Note: This map displays facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capacity on-line by the
end of 2011. This includes planned new builds and planned retirements. In areas with a dense
concentration of facilities, some facilities may be obscured.
4.2.3 Distribution
Distribution of electricity involves networks of lower voltage lines and substations that
take the higher voltage power from the transmission system and step it down to lower voltage
levels to match the needs of customers. The transmission and distribution system is the classic
example of a natural monopoly, in part because it is not practical to have more than one set of
lines running from the electricity generating sources to substations or from substations to
residences and businesses.
Transmission has generally been developed by the larger vertically integrated utilities
that typically operate generation and distribution networks. Often distribution is handled by a
large number of utilities that purchase and sell electricity, but do not generate it. Over the last
couple of decades, several jurisdictions in the United States began restructuring the power
industry to separate transmission and distribution from generation, ownership, and operation.
As discussed below, electricity restructuring has focused primarily on efforts to reorganize the
industry to encourage competition in the generation segment of the industry, including
ensuring open access of generation to the transmission and distribution services needed to
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deliver power to consumers. In many states, such efforts have also included separating
generation assets from transmission and distribution assets to form distinct economic entities.
Transmission and distribution remain price-regulated throughout the country based on the cost
of service.
4.3 Deregulation and Restructuring
The process of restructuring and deregulation of wholesale and retail electric markets
has changed the structure of the electric power industry. In addition to reorganizing asset
management between companies, restructuring sought a functional unbundling of the
generation, transmission, distribution, and ancillary services the power sector has historically
provided, with the aim of enhancing competition in the generation segment of the industry.
Beginning in the 1970s, government policy shifted against traditional regulatory
approaches and in favor of deregulation for many important industries, including
transportation (notably commercial airlines), communications, and energy, which were all
thought to be natural monopolies (prior to 1970) that warranted governmental control of
pricing. However, deregulation efforts in the power sector were most active during the 1990s.
Some of the primary drivers for deregulation of electric power included the desire for more
efficient investment choices, the economic incentive to provide least-cost electric rates through
market competition, reduced costs of combustion turbine technology that opened the door for
more companies to sell power with smaller investments, and complexity of monitoring utilities'
cost of service and establishing cost-based rates for various customer classes.
The pace of restructuring in the electric power industry slowed significantly in response
to market volatility in California and financial turmoil associated with bankruptcy filings of key
energy companies. By the end of 2001, restructuring had either been delayed or suspended in
eight states that previously enacted legislation or issued regulatory orders for its
implementation (shown as "Suspended" in Figure 4-2 below). Eighteen other states that had
seriously explored the possibility of deregulation in 2000 reported no legislative or regulatory
activity in 2001 (EIA, 2003) ("Not Active" in Figure 4-2 below). Currently, there are 15 states
where price deregulation of generation (restructuring) has occurred ("Active" in Figure 4-2
below). Power sector restructuring is more or less at a standstill; there have been no recent
proposals to the Federal Energy Regulatory Commission (FERC) for actions aimed at wider
restructuring, and no additional states have recently begun retail deregulation activity.
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Electricity Restructuring by State
Figure 4-2. Status of State Electricity Industry Restructuring Activities
Source: EIA2010a.
4.4 Emissions of Greenhouse Gases from Electric Utilities
The burning of fossil fuels, which generates about 70 percent of our electricity
nationwide, results in emissions of greenhouse gases. The power sector is a major contributor
of C02 in particular, but also contributes to emissions of sulfur hexafluoride (SF6), CH4, and
N20. In 2011, the power sector accounted for 33 percent of total nationwide greenhouse gas
emissions, measured in C02 equivalent, a slight increase from its 30 percent share in 1990.
Table 4-5 and Figure 4-3 show the contributions of the power sector relative to other major
economic sectors. Table 4-6 and Figure 4-4 show the contributions of C02 and other GHGs from
the power sector.
4-7
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Table 4-5. Domestic Emissions of Greenhouse Gases, by Economic Sector (million metric
tonnes of CO2 equivalent)
Sector/Source
Electricity Generation
Transportation
Industry
Agriculture
Commercial
Residential
U.S. Territories
Total Emissions
1990
1,866
1,553
1,539
458
388
345
34
6,183
1995
1,992
1,697
1,558
511
391
367
41
6,557
2000
2,336
1,927
1,504
501
376
386
46
7,076
2005
2,446
2,012
1,416
517
374
371
58
7,195
2011
2,201
1,829
1,332
547
378
357
58
6,702
Source: EPA 2013
Electricity
Generation
2,201
33%
Figure 4-3. Domestic Emissions of Greenhouse Gases, 2011 (million metric tonnes of
equivalent)
Source: EPA 2013
4-8
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Table 4-6. Greenhouse Gas Emissions from the Electricity Sector (Generation, Transmission
and Distribution), 2011 (million metric tonnes of CO2 equivalent)
Source
Total Emissions
C02
CO2 from Fossil Fuel Combustion
Coal
Natural Gas
Petroleum
Geothermal
Incineration of Waste
Other Process Uses of Carbonates
CH4
Stationary Combustion*
Incineration of Waste
N2O
Stationary Combustion*
Incineration of Waste
SF6"
Electrical Transmission and Distribution
2,175.5
2,158.5
1,722.7
408.8
26.6
0.4
12.4
4.6
0.4
0.4
+
18.3
17.9
0.4
7.0
7.0
Total
2,201.2
Source: EPA 2013
* Includes only stationary combustion emissions related to the generation of electricity.
** SF6 is not covered by this rule, which specifically regulates GHG emissions from combustion.
+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.
The amount of C02 emitted during the combustion of fossil fuels varies according to the
carbon content and heating value of the fuel used (EIA, 2000) (see Table 4-7). Coal has higher
carbon content than oil or natural gas and, thus, releases more C02 during combustion. Coal
emits around 1.7 times as much carbon per unit of energy when burned as does natural gas
(EPA 2013).
4-9
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C02
lOther
Power Sector
SF6
N20
CH4
Figure 4-4. GHG Emissions from the Power Sector Relative to Total Domestic GHG Emissions
(2011)
Source: EPA 2013
4-10
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Table 4-7. Fossil Fuel Emission Factors in EPA Modeling Applications
Fuel Type Carbon Dioxide (Ibs/MMBtu)
Coal
Bituminous 205.2-206.6
Subbituminous 212.7-213.1
Lignite 213.5-217.0
Natural Gas 117.1
Fuel Oil
Distillate 161.4
Residual 161.4-173.9
Biomass* 195
Waste Fuels
Waste Coal 205.7
Petroleum Coke 225.1
Fossil Waste 321.1
Non-Fossil Waste 0
Tires 189.5
Municipal Solid Waste 91.9
Source: Documentation for IPM Base Case v.4.10. See also Table 9.9 of IPM Documentation.
Note: CO2 emissions presented here for biomass account for combustion only and do not reflect lifecycle
emissions from initial photosynthesis (carbon sink) or harvesting activities and transportation (carbon
source).
4.5 Carbon Dioxide Control Technologies
In the power sector there are currently only a few technical approaches available for
significantly reducing the C02 emissions of new fossil fuel combustion sources intended for
intermediate and baseload operations. These include the use of: CCS, highest efficiency designs
(e.g. supercritical or ultrasupercritical steam units, IGCC, or combined-cycle combustion-
turbine/steam-turbine units), and/or low-emitting fuels (e.g. natural gas rather than coal).
Daily peak electricity demands, involving operation for relatively few hours per year, are
often most economically met by simple-cycle combustion turbines (CT). Stationary CTs used for
power generation can be installed quickly, at relatively low capital cost. They can be remotely
started and loaded quickly, and can follow rapid demand changes. Full-load efficiencies of large
current technology CTs are 30-33 percent (high heating value basis), as compared to efficiencies
of 50 percent or more for new combined-cycle units that recover and use the exhaust heat
otherwise wasted from a CT . A simple-cycle CT's lower efficiency causes it to burn much more
fuel to produce a MWh of electricity than a combined-cycle unit. Thus, when burning natural
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gas its C02 emission rate per MWh could be 40-60 percent higher than a more efficient NGCC
unit.
Baseload electricity demand can be met with NGCC generation, coal and other fossil-
fired steam generation, and IGCC technology, as well as generation from sources that do not
emit C02, such as nuclear and hydro. IGCC employs the use of a "gasifier" to transform fossil
fuels into synthesis gas ("syngas") and heat. The syngas is used to fuel a combined cycle
generator, and the heat from the syngas conversion can produce steam for the steam turbine
portion of the combined cycle generator. Electricity can be generated through this IGCC
process somewhat more efficiently than through conventional boiler-steam generators.
Additionally, with gasification, some of the syngas can be converted into other marketable
products such as fertilizer, and C02 can be captured for use in EOR.
4.5.1 Carbon Capture and Storage
Carbon capture technology has been successfully applied since 1930 on several smaller
scale industrial facilities and is currently in the demonstration phase for power sector
applications. There are currently larger-scale projects under construction or in the advanced
planning stages. CCS can be achieved through either pre-combustion or post-combustion
capture of C02 from a gas stream associated with the fuel combusted. 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).
For post-combustion capture, C02 is stripped from the flue gas by passing the flue gas
through a liquid absorbent which selectively reacts with the gaseous carbon dioxide to remove
it from the combustion gas stream. The absorbent, upon saturation, transfers to a downstream
operation which regenerates the absorbent by desorbing the C02 back to gaseous form. The
absorbent recycles back into the process to repeat the capture cycle while the removed carbon
dioxide is compressed, sent to storage and sequestered. This process is illustrated for a
pulverized coal power plant in Figure 4-5. For post-combustion, a station's net generating
output could be 20-30 percent lower due to the energy needs of the capture process.
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Flue Gas
Flue Gas
Volume %
CO; 12-14%
N2 -65%
H2O -18%
O2 -2%
15Psi/150T
Air
Coal
Storage
Figure 4-5. Post-Combustion CO2 Capture for a Pulverized Coal Power Plant
Source: Interagency Task Force on Carbon Capture and Storage 2010
Pre-combustion capture is mainly applicable to IGCC facilities, where the fuel is
converted into gaseous components ("syngas") under heat and pressure and some percentage
of the carbon contained in the syngas is captured before combustion. For pre-combustion
technology, a significant amount of energy is needed to gasify the fuel(s). This process is
illustrated in Figure 4-6. Application of post-combustion CCS with IGCC can be designed to use
no water-gas shift, or single- or two-stage shift processes, to obtain varying percentages of C02
removal -from a "partial capture" percentage to 90 percent "full capture." Pre-combustion CCS
typically has a lesser impact on net energy output than does post-combustion CCS. For more
detail on the current state of CCS technology, see the "Report of the Interagency Task Force on
Carbon Capture and Storage" (2010).2
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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Shifted Syngas
H2 -50%
Sulfur
Figure 4-6. Pre-Combustion CO2 Capture for an IGCC Power Plant
Source: Interagency Task Force on Carbon Capture and Storage 2010
4.6 Geologic Sequestration
4.6.1 Availability of Geologic Sequestration
Geologic storage potential for C02 is widespread and available throughout the U.S. and
Canada. Geologic formations suitable for sequestration include depleted oil and gas fields,
deep coal seams, and saline formations. The Department of Energy's (DOE) National Energy
Technology Laboratory (NETL) estimates the current total C02 storage resource is
approximately 2,380 to 20,353 billion metric tons (2,625 to 22,435 billion tons) in the U.S. and
Canada.3 DOE's estimates are intended to be used as an initial assessment of potential geologic
storage. The assessments are intended to identify general geographical distribution of C02
storage resources. This resource estimation is volumetrically based on physically accessible
C02 storage in specific formations in sedimentary basins without consideration of injection
rates, regulations, economics, or surface land usage. Other types of geologic formations such
as organic rich shale and basalt may have the ability to store C02, and DOE is currently
The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of
Fossil Energy, National Energy Technology Laboratory (NETL).
4-14
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evaluating their potential future storage capacity. Potential sequestration sites must undergo
appropriate site characterization to ensure that the site can safely and securely store C02.
Estimates of C02 storage resources by state/province from the DOE report are provided
in Table 4-8. These state and province level estimates are obtained from DOE's National Carbon
Sequestration Database and Geographic Information System (NATCARB). Nearly every state in
the U.S. has or is in close proximity to carbon storage potential including vast areas offshore.
Information and methods used in estimating C02 storage resource can be found in the
"Methodology for Development of Geologic Storage Estimates for Carbon Dioxide" in Appendix
B of the Carbon Utilization and Storage Atlas.4 It should be noted that the assessment of U.S.
sequestration potential is an ongoing process. There is significant uncertainty in areas such as
the Atlantic offshore due to a relative paucity of data and other factors.
In addition, the Department of Interior's U.S. Geological Survey (USGS) recently
completed an evaluation of the technically accessible storage resource for carbon storage for
36 sedimentary basins in the onshore areas and State waters of the United States.5 The USGS
assessment estimates a range of 2,300 to 3,700 billion metric tons and a mean of 3,000 billion
metric tons of C02 storage potential across the United States. Technically accessible storage
resources are those that can be accessed using today's technology and pressurization and
injection techniques. For comparison, this amount is 500 times the 2011 annual U.S. energy-
related C02 emissions of 5.5 Gigatons (Gt)6 Areas that were assessed by the USGS for C02
storage compliment and are not identical to the areas assessed by DOE, NATCARB. The USGS
estimates are fractions of the total in-place resource that may be recoverable with
technological advances or unforeseen changes in economic factors. This partly explains the
difference between the USGS and DOE storage potential estimates. The USGS assessment
methodology for C02 storage resources focuses on the technically accessible resource, not a
total in-place resource volume. In addition, the USGS methodology is not an economic
assessment, nor does it incorporate engineering constraints in the estimation of the volume of
the resource. The methodology does not take into account potential storage formations with
salinities less than 10,000 ppm (parts per million; mg/L (milligrams per liter)) total dissolved
solids (TDS) which is the definitional limit the U.S. Environmental Protection Agency uses for
underground sources of drinking water. Similar to the DOE's storage resource assessment, the
4 Ibid.
5 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment
of geologic carbon dioxide storage resources-Summary: U.S. Geological Survey Factsheet 2013-3020,
6p.http://pubs.usgs.gov/fs/2013/3020/.
6 U.S. Energy Information Administration, 2012
4-15
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USGS methodology does not apply to site-specific evaluation of storage resources or capacity.7
The USGS assessment provides further evidence of the widespread availability C02 storage
reserves in the U.S. based on the comprehensive evaluation of the technically accessible
storage resource for carbon storage for 36 sedimentary basins in the onshore areas and State
waters of the United States.8
Table 4-8. Total CO2 Storage Resource9
Million Metric Tons*
State/Province
ALABAMA
ALASKA
ALBERTA
ARIZONA
ARKANSAS
BRITISH COLUMBIA
CALIFORNIA
COLORADO
CONNECTICUT
DELAWARE
DISTRICT OF COLUMBIA
FLORIDA
GEORGIA
HAWAII
IDAHO
ILLINOIS
INDIANA
IOWA
KANSAS
KENTUCKY
LOUISIANA
MAINE
MANITOBA
MARYLAND
MASSACHUSETTS
Low Estimate
122,490
8,640
41,840
130
6,180
910
33,890
37,610
40
102,740
145,340
40
10,020
32,020
10
10,880
2,920
169,500
1,720
1,860
High Estimate
694,380
19,750
131,230
1,170
63,670
3,860
420,630
357,190
40
555,010
159,050
390
116,820
68,210
50
86,340
7,650
2,103,980
3,520
1,930
7 Brennan, ST., Burruss, R.C., Merrill, M.D., Freeman, P.A., and Ruppert, L.F., 2010, A probabilistic assessment
methodology for the evaluation of geologic carbon dioxide storage: U.S. Geological Survey Open-File Report
2010-1127, 31 p., available online at http://pubs.usgs.gov/of/2010/1127.
8 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment
of geologic carbon dioxide storage resources-Summary: U.S. Geological Survey Factsheet 2013-3020,
6p.http://pubs.usgs.gov/fs/2013/3020/.
9 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of
Fossil Energy, National Energy Technology Laboratory (NETL).
4-16
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Table 4-8. Total CO2 Storage Resource, cont.
State/Province
MICHIGAN
MINNESOTA
MISSISSIPPI
MISSOURI
MONTANA
NEBRASKA
NEVADA
New Brunswick
NEW HAMPSHIRE
NEW JERSEY
NEW MEXICO
NEW YORK
Newfoundland &
Labrador
NORTH CAROLINA
NORTH DAKOTA
Northwest Territories
Nova Scotia
Offshore Federal Only
OHIO
OKLAHOMA
Ontario
OREGON
PENNSYLVANIA
PUERTO RICO
Quebec
RHODE ISLAND
SASKATCHEWAN
SOUTH CAROLINA
SOUTH DAKOTA
TENNESSEE
TEXAS
UTAH
VERMONT
VIRGINIA
WASHINGTON
WEST VIRGINIA
WISCONSIN
WYOMING
North America Total
Million Metric Tons*
Low Estimate High
19,050
145,010
10
84,580
23,770
0
42,760
4,640
1,340
67,090
489,840
13,460
56,950
6,810
22,100
38,690
30,100
8,760
430
443,800
25,470
440
36,620
16,650
0
72,690
2,379,840
Estimate
47,210
1,185,030
170
912,720
113,240
0
359,090
4,640
18,390
147,480
6,440,090
13,460
244,550
93,700
22,100
121,910
34,180
24,030
3,860
4,329,930
240,910
2,910
496,730
16,650
0
684,850
20,352,700
*States/Provinces with a "zero" value represent estimates of minimal CO2 storage resource, while states/provinces
with a blank represent areas that have not yet been assessed by the RCSPs
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4.6.2 Enhanced Oil and Gas Recovery in the U.S.
Geologic storage options also include use of C02 in enhanced oil recovery. Enhanced
recovery (ER), which includes both enhanced oil and gas recovery (EOR and EGR), refers to the
injection of fluids into a reservoir to increase oil and/or gas production efficiency. ER is typically
conducted at a reservoir after production yields have decreased from primary production.
Fluids commonly used for ER include brine, fresh water, steam, nitrogen, alkali solutions,
surfactant solutions, polymer solutions, and carbon dioxide. EOR using supercritical carbon
dioxide, sometimes referred to as carbon dioxide 'flooding' or C02-EOR, involves injecting
carbon dioxide into an oil reservoir to help mobilize the remaining oil and make it available for
recovery. The crude oil and C02 mixture is produced, and sent to a separator where the crude
oil is separated from the gaseous hydrocarbons and C02. The gaseous C02-rich stream then is
typically dehydrated, purified to remove hydrocarbons, recompressed, and reinjected into the
oil or natural gas reservoir to further enhance recovery. The DOE's Regional Carbon
Sequestration Partnerships (RCSPs) have documented the location of more than 225 billion
metric tons of C02 storage potential in oil and gas reservoirs across over 30 states.10
C02-EOR has been successfully used at many production fields throughout the U.S. to
increase oil recovery. The oil and natural gas industry in the United States has over 40 years of
experience of injection and monitoring of C02 in the deep subsurface for the purposes of
enhancing oil and natural gas production. This experience provides a strong foundation for the
injection and monitoring technologies that will be needed for successful deployment of CCS.
Although deep saline formations provide the most C02 storage opportunity (2,102 to 20,043
billion metric tons), oil and gas reservoirs are currently estimated to have 226 billion metric
tons of C02 storage resource.11 EPA anticipates that many early geologic sequestration (GS)
projects may be sited in active or depleted oil and gas reservoirs because these formations have
been previously well characterized for hydrocarbon recovery, likely already have suitable
infrastructure (e.g., wells, pipelines, etc.), and may be suitable for long term containment of
C02.
4.6.3 Trends in CO^EOR
C02-EOR is the fastest-growing EOR technique in the U.S., providing approximately 281,000
barrels of oil per day in the U.S. which equals about 6% percent of U.S. crude oil production.12'13
10 Ibid.
11 Ibid.
12 Oil and Gas Journal EOR Survey, April 2010.
13 Improving Domestic Energy Security and Lowering CO2 Emissions with "Next Generation" CO2-Enhanced Oil
Recovery (CO2-EOR), DOE/NETL-2011/1504, June 20, 2011.
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The vast majority of C02-EOR is conducted in oil reservoirs in the U.S. Permian Basin, which
extends through southwest Texas and southeast New Mexico. Other U.S. states where C02-
EOR is utilized are Alabama, Colorado, Illinois, Kansas, Louisiana, Michigan, Mississippi, New
Mexico, Oklahoma, Utah, and Wyoming. A well-established and expanding network of pipeline
infrastructure supports C02-EOR in these areas (Figure 4-8). The C02 supply for EOR operations
is largely obtained from underground formations or domes that contain C02. While natural
sources of C02 comprise the majority of C02 supplied for EOR operations, recent developments
targeting anthropogenic sources of C02 (e.g., ethanol plants, gas processing, refineries, power
plants) have expanded or led to planned expansions in existing infrastructure related to C02-
EOR.14 Several hundred miles of dedicated C02 pipeline is under construction, planned, or
proposed that would allow continued growth in C02 supply for EOR (see Figure 4-8).
Anthropogenic sources of C02 for EOR continue to increase as new projects are being
planned or implemented. Based on an evaluation of publicly available sources15, there are
currently 23 industrial source CCS projects in 12 states that are either operational, under-
construction, or actively being pursued which are or will supply captured C02 for the purposes
of EOR. This demonstrates that CCS projects associated with large point sources are occurring
due to a demand for C02 by EOR operations. Nationally, according to EPA's Greenhouse Gas
Reporting Program, approximately 60 million metric tons of C02 was received for injection to
enhanced oil recovery operations in 2011. A recent study by DOE found that the market for
captured C02 emissions from power plants created by economically feasible C02-EOR projects
would be sufficient to permanently store the C02 emissions from 93 large (1,000 MW) coal-
fired power plants operated for 30 years.16 There are also several state and Federal subsidy
programs that are in place that can make CCS more affordable.17 Based on all of these factors,
EPA anticipates opportunities to utilize C02-EOR operations for geologic storage to continue to
increase.
Based on a recent resource assessment by DOE, the application of next generation C02-
EOR technologies would significantly increase oil production areas, further expanding the
geographic extent and accessibility of C02-EOR operations in the U.S.1S Additionally, oil and gas
14 Ibid.
15 See technical supporting memo document (Docket EPA-HQ-OAR-2013-0495) Documentation for the Summary of
Carbon Dioxide Industrial Capture to Enhanced Oil Recovery Projects.
16 Improving Domestic Energy Security and Lowering CO2 Emissions with "Next Generation" CO2-Enhanced Oil
Recovery (CO2-EOR)", DOE/NETL-2011/1504, June 20, 2011.
17 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010).
18 Improving Domestic Energy Security and Lowering CO2 Emissions with "Next Generation" CO2-Enhanced Oil
Recovery (CO2-EOR)", DOE/NETL-2011/1504, June 20, 2011.
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fields now considered to be 'depleted' may resume operation because of increased availability
and decreased cost of anthropogenic carbon dioxide, thereby increasing the demand for and
accessibility of C02 utilization.
As demonstrated in this RIA, the use of C02 for EOR can significantly lower the cost of
implementing CCS. The opportunity to sell the captured C02 for EOR, rather than paying
directly for its long-term storage, strongly improves the overall economics of the new
generating unit. A commercial market for C02 creates a role for C02-EOR to continue CCS
deployment. According to the International Energy Agency, of the CCS projects under
construction or at an advanced stage of planning, 70% intend to use captured C02 to improve
recovery of oil in mature fields (enhanced oil recovery, C02-EOR).19 Further, smaller, non-
geologic sequestration markets exist for C02 as well, including food products, which can lower
the cost of CCS.
Figure 4-7. Growth of U.S. Oil Production from CO2-based EOR
Source: NETL2010
Tracking Clean Energy Progress 2013, International Energy Agency (IEA), Input to the Clean Energy Ministerial,
OECD/IEA2013.
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X
s
-T&»
Counties with activa CO2-EOR operations (EPA, GHG Reporting Progra
. Oil 4 Gas Reservoirs {Department of Energy. NATCARB)
Saline Formations (Department of Energy. NATCARB}
Unmineable Coal Areas (Department of Energy. NATCARB)
Existing CO? pipeline {Department of Transportation)
Under construction, nearly complete CO2 pipalme
Probable, planned, or under study CQ2 pipeline
O Primary natural CO2 sources {EPA, GHG Reporting Program)
Figure 4-8. U.S. CO2 Storage Capacity and CO2-EOR operations
Source: EPA 2013: Data sources: EPA's Greenhouse Gas Reporting Program; Department of Energy, NATCARB;
Department of Transportation, National Pipeline Management System.
4.6.4 Alternatives to Geologic Sequestration
EPA recognizes there may be other commercial applications or end-uses for captured
CO2 which creates C02 market incentives and potentially for a meeting performance standard
beyond injecting it underground for long-term containment. For example, alternatives to
geologic sequestration such as applications such as mineralization of C02 for the production of
precipitated calcium carbonate and some production process of cement have been identified as
potential alternatives to geologic sequestration. The CCS Task Force report notes that there are
several factors for determining the viability of C02 reuse, and there are currently significant
technical barriers to large scale commercial-scale reuse. First, rates of conversion must be
comparable to rates of C02 capture. Second, energy requirements for conversion must be low.
Third, potential volumes of reactants and/or products may limit the scale of reuse relative to
total emissions. Finally, reuse options need to consider the long-term fate of C02 and its
lifecycle emissions.20 The CCS Task Force also notes there are other potential commercial uses
1 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010).
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for captured C02, such as in food and beverage manufacturing, pulp and paper manufacturing,
the rubber and plastic industry, fire suppression, and refrigeration and cooling.
As noted in the preamble, however, EPA has not yet determined if such uses would be
applicable towards meeting the standard. Consideration of how these alternatives could meet
the performance standard involves understanding the ultimate fate of the captured C02 and
the degree to which the method permanently isolates the C02 from the atmosphere, as well as
existing methodologies to verify this permanent storage.
4.7 GHG and Clean Energy Regulation in the Power Sector
4.7.1 State Policies
Several states have also recently established emission performance standards or other
measures to limit emissions of GHGs from new EGUs that are comparable to this proposal in
this rulemaking.
In 2003, then-Governor George Pataki sent a letter to his counterparts in the Northeast
and Mid-Atlantic inviting them to participate in the development of a regional cap-and-trade
program addressing power plant C02 emissions. This program, known as the Regional
Greenhouse Gas Initiative (RGGI), began in 2009 and sets a regional C02 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 C02
emissions from all fossil-fired EGUs greater than 25 MW in participating states, and limits total
emissions to 91 million short tons in 2014. This emissions budget is reduced 2.5% annually
from 2015 to 2020.
In September 2006, California Governor Schwarzenegger signed into law Senate Bill
1368. The law limits long-term investments in baseload generation by the state's utilities to
power plants that meet an emissions performance standard jointly established by the California
Energy Commission and the California Public Utilities Commission. The Energy Commission has
designed regulations that establish a standard for new and existing baseload generation owned
by, or under long-term contract to publicly owned utilities, of 1,100 Ib C02/MWh.
In 2006 Governor Schwarzenegger also signed into law Assembly Bill 32, the Global
Warming Solutions Act of 2006. This act includes a multi-sector GHG cap-and-trade program
which covers approximately 85% of the state GHG emissions. EGUs are includes in phase I of
the program, which began in 2013. Phase II begins in 2020 and includes upstream sources. The
cap is based on a 2 percent reduction from total 2012 expected emissions, and declines 2
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percent annually through 2014, then 3 percent each year until 2020.
In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, which
established statewide GHG emissions reduction goals, and imposed an emission standard that
applies to any baseload electric generation that commenced operation after June 1, 2008 and is
located in Washington, whether or not that generation serves load located within the state.
Baseload generation facilities must initially comply with an emission limit of 1,100 Ib C02/MWh.
In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, which mandated that
facilities generating baseload electricity, whether gas- or coal-fired, must have emissions equal
to or less than 1,100 Ib C02/MWh, and prohibited utilities from entering into long-term
purchase agreements for baseload electricity with out-of-state facilities that do not meet that
standard. Natural gas- and petroleum distillate-fired facilities that are primarily used to serve
peak demand or to integrate energy from renewable resources are specifically exempted from
the performance standard.
In August 2011, New York Governor Cuomo signed the Power NY Act of 2011. This
regulation establishes C02 emission standards for new and modified electric generators greater
than 25 M W. The standards vary based on the type of facility: baseload facilities must meet a
C02 standard of 925 Ib/MWh or 120 Ib/MMBtu, and peaking facilities must meet a C02
standard of 1,450 Ibs/MWh or 160 Ibs/MMBtu.
Additionally, most states have implemented Renewable Portfolio Standards (RPS), or
Renewable Electricity Standards (RES). These programs are designed to increase the renewable
share of a state's total electricity generation. Currently 30 states and the District of Columbia
have enforceable RPS or other mandatory renewable capacity policies, and 7 states have
voluntary goals.21 These programs vary widely in structure, enforcement, and scope.
4.7.2 Federal Policies
In April 2007, the Supreme Court concluded that GHGs met the CAA definition of an air
pollutant, giving the EPA the authority to regulate GHGs under the CAA contingent upon an
agency determination that GHG emissions from new motor vehicles cause or contribute to air
pollution that may reasonably be anticipated to endanger public health or welfare. This
decision to regulate GHG emissions for motor vehicles set the stage for the determination of
whether other sources of GHG emissions, including stationary sources, would need to be
regulated as well.
21EIA2012a
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In response to the FY2008 Consolidated Appropriations Act (H.R. 2764; Public Law 110-
161), the EPA issued the Mandatory Reporting of Greenhouse Gases Rule (74 FR 5620) which
required reporting of GHG data and other relevant information from fossil fuel suppliers and
industrial gas suppliers, direct greenhouse gas emitters, and manufacturers of heavy-duty and
off-road vehicles and engines. The purpose of the rule was to collect accurate and timely GHG
data to inform future policy decisions. As such, it did not require that sources control
greenhouse gases, but sources above certain threshold levels must monitor and report
emissions.
In August 2007, the EPA issued a prevention of significant deterioration (PSD) permit to
Deseret Power Electric Cooperative, authorizing it to construct a new waste-coal-fired ECU near
its existing Bonanza Power Plant, in Bonanza, Utah. The permit did not include emissions
control requirements for C02. The EPA acknowledged the Supreme Court decision, but found
that decision alone did not require PSD permits to include limits on C02 emissions. Sierra Club
challenged the Deseret permit. In November 2008, the Environmental Appeals Board (EAB)
remanded the permit to the EPA to reconsider "whether or not to impose a C02 BACT (best
available control technology) limit in light of the 'subject to regulation' definition under the
CAA." The remand was based in part on EAB's finding that there was not an established EPA
interpretation of the regulatory phrase "subject to regulation."
In December 2008, the Administrator issued a memo indicating that the PSD Permitting
Program would apply to pollutants that are subject to either a provision in the CAA or a
regulation adopted by the EPA under the CAA that requires actual control of emissions of that
pollutant. The memo further explained that pollutants for which the EPA regulations only
require monitoring or reporting, such as the provisions for C02 in the Acid Rain Program, are
not subject to PSD permitting. Fifteen organizations petitioned the EPA for reconsideration,
prompting the agency to issue a revised finding in March 2009. After reviewing comments, the
EPA affirmed the position that PSD permitting is not triggered for a pollutant such as GHGs until
a final nationwide rule requires actual control of emissions of the pollutant. For GHGs, this
meant January 2011 when the first national rule limiting GHG emissions for cars and light trucks
was scheduled to take effect. Therefore, a permit issued after January 2, 2011, would have to
address GHG emissions.
The Administrator signed two distinct findings in December 2009 regarding greenhouse
gases under section 202(a) of the Clean Air Act. The endangerment finding indicated that
current and projected concentrations of the six key well-mixed greenhouse gases — C02, CH4,
N20, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and SF6 — in the atmosphere
4-24
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threaten the public health and welfare of current and future generations. These greenhouse
gases have long lifetimes and, as a result, become homogeneously distributed through the
lower level of the Earth's atmosphere (IPCC, 2001). This differentiates them from other
greenhouse gases that are not homogeneously distributed in the atmosphere. The cause and
contribute finding indicated that the combined emissions of these well-mixed greenhouse gases
from new motor vehicles and new motor vehicle engines contribute to the greenhouse gas
pollution which threatens public health and welfare. Both findings were published in the
Federal Register on December 15, 2009 (Docket ID EPA-HQ-OAR-2009-0171). These findings did
not themselves impose any requirements on any industry or other entities, but allowed the EPA
to regulate greenhouse gases under the CAA (see preamble section II.E for regulatory
background). This action was a prerequisite to implementing the EPA's proposed greenhouse
gas emission standards for light-duty vehicles, which was finalized in January 2010. Once a
pollutant is regulated under the CAA, it is subject to permitting requirements under the PSD
and Title V programs. The 2009 Endangerment Finding and a denial of reconsideration were
challenged in a lawsuit; on June 26, 2012, the DC Circuit Court upheld the Endangerment
Finding and the Reconsideration Denial, ruling that the Finding was neither arbitrary nor
capricious, was consistent with Massachusetts v. EPA, and was adequately supported by the
administrative record. The Court found that the EPA had based its decision on "substantial
scientific evidence," noted that the EPA's reliance on assessments was consistent with the
methods decision-makers often use to make a science-based judgment, and stated that "EPA's
interpretation of the governing CAA provisions is unambiguously correct."
In May 2010, the EPA issued the final Tailoring Rule which set thresholds for GHG
emissions that define when permits under the New Source Review and Title V Operating Permit
programs are required for new and existing industrial facilities. Facilities responsible for nearly
70 percent of the national GHG emissions from stationary sources, including EGUs, were
subject to permitting requirements under the rule. This rule was upheld by the D.C. Circuit in
2012.
The EPA entered into two proposed settlement agreements in December 2010 to issue
rules that will address greenhouse gas emissions from fossil fuel-fired power plants and
refineries. These two industrial sectors make up nearly 40 percent of the nation's greenhouse
gas emissions. On March 27, 2012, EPA proposed NSPS for new source natural gas, coal, and
other solid fossil-fired EGUs. After consideration of information provided in more than 2.7
million comments on this proposal, as well as consideration of continuing changes in the
electricity sector, the EPA determined that revisions in its proposed approach are warranted.
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This rule replaces that proposal. Existing source standards are not addressed in this action.
Details of the settlement agreements can be found on the EPA website.22
4.7.3 Proposed federal Policies, Non-GHG
EPA is reviewing public comment and developing final regulations for the following
three proposed rules, which will impact EGUs: Steam Electric Effluent Limitation Guidelines,
Cooling Water Intake Structures, and Coal Combustion Residuals (CCR). These three proposed
rules are summarized below. In general, most EPA rulemakings affecting the power sector
focus on existing sources. Therefore, few interactions are likely between other power sector
rules and this rule, which focuses only on new sources.
On June 7, 2013, EPA proposed a regulation that would strengthen the controls on
discharges from certain steam electric power plants by revising technology-based effluent
limitations guidelines and standards for the steam electric power generating point source
category. Existing steam electric power plants contribute 50-60 percent of all toxic pollutants
discharged to surface waters by all industrial categories currently regulated in the United States
under the Clean Water Act. Furthermore, power plant discharges to surface waters are
expected to increase as pollutants are increasingly captured by air pollution controls and
transferred to wastewater discharges. This proposal would reduce the amount of toxic metals
and other pollutants discharged to surface waters from power plants. EPA has proposed new
requirements for both existing and new generating units. EPA estimates that the compliance
costs for a new unit (capital and operations & maintenance) under the proposed standards
represent at most 1.5 percent of the annualized cost of building and operating a new 1,300 MW
coal-fired plant, with capital costs representing less than 1 percent of the overnight
construction costs, and annual O&M costs representing less than 5 percent of the cost of
operating a new plant.
Section 316(b) of the CWA, 33 U.S.C. 1326(b), requires that standards applicable to
point sources under sections 301 and 306 of the Act require that the location, design,
construction, and capacity of cooling water intake structures reflect the best technology
available to minimize adverse environmental impacts. In April 2011, EPA proposed new
standards to reduce injury and death of fish and other aquatic life caused by cooling water
intake structures at existing power plants and manufacturing facilities. The proposed rule would
subject existing power plants and manufacturing facilities withdrawing in excess of 2 million of
gallons per day (MGD) of cooling water to an upper limit on the number of fish destroyed
22 http://www.epa.gov/airquality/ghgsettlement.html
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through impingement, as well as site-specific entrainment mortality standards. Certain plants
that withdraw very large volumes of water would also be required to conduct studies for use by
the permit writer in determining site-specific entrainment controls for such facilities. Finally,
under the proposed rule, new generating units constructed at existing power plants would be
required to reduce the intake of cooling water associated with the new unit, to a level that
could be attained by using a closed-cycle cooling system. EPA is continuing the process of
addressing comments and finalizing the rule.
On June 21, 2010, EPA co-proposed regulations that included two approaches to
regulating the disposal of CCRs generated by electric utilities and independent power
producers. CCRs are residues from the combustion of coal in steam electric power plants and
include materials such as coal ash (fly ash and bottom ash) and flue gas desulfurization (FGD)
wastes. Under one proposed approach, EPA would list these residuals as "special wastes,"
when destined for disposal in landfills or surface impoundments, and would apply the existing
regulatory requirements established under Subtitle C of RCRA to such wastes. Under the second
proposed approach, EPA would establish new regulations applicable specifically to CCRs under
subtitle D of RCRA, the section of the statute applicable to solid (i.e., non-hazardous) wastes.
Under both approaches, CCRs that are beneficially used would remain exempt under the Bevill
exclusion. While the Agency is still evaluating all the available information and comments, and
while a final risk assessment for the CCR rule has not yet been completed, reliance on the data
and analyses discussed in the preamble to the recent Steam Electric ELG proposal may have the
potential to lower the CCR rule risk assessment results by as much as an order of magnitude. If
this proves to be the case, EPA's current thinking is that, the revised risks, coupled with the ELG
requirements that the Agency may promulgate, and the increased Federal oversight such
requirements could achieve, could provide strong support for a conclusion that regulation of
CCR disposal under RCRA Subtitle D would be adequate.
4.8 Revenues, Expenses, and Prices
Due to lower retail electricity sales, total utility operating revenues declined in 2011 to
$281 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008
levels in 2011, operating expenses were appreciably lower and as a result, net income also rose
in comparison to both 2009 and 2010 (see Table 4-9). Recent economic events have put
downward pressure on electricity demand, thus dampening electricity prices and consumption
(utility revenues), but have also reduced the price and cost of fossil fuels and other expenses.
Electricity sales and revenues associated with the generation, transmission, and distribution of
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electricity are expected to rebound and increase modestly by 2015, when revenues are
projected to be roughly $359 billion (see Table 4-10).
Table 4-9 shows that investor-owned utilities (lOUs) earned income of about 11.9
percent compared to total revenues in 2011. Based on ElA's Annual Energy Outlook 2013, Table
4-10 shows that the power sector is projected to derive revenues of $359 billion in 2015.
Assuming the same income ratio from lOUs (with no income kept by public power), and using
the same proportion of power sales from public power as observed in 2011, the EPA projects
that the power sector will expend over $320 billion in 2015 to generate, transmit, and
distribute electricity to end-use consumers.
Over the past 50 years, real retail electricity prices have ranged from around 7 cents per
kWh in the early 1970s, to around 11 cents, reached in the early 1980s. Generally, retail
electricity prices do not change rapidly and do not display the variability of other energy or
commodity prices, although the frequency at which these prices change varies across different
types of customers. Retail rate regulation has largely insulated consumers from the rising and
falling wholesale electricity price signals whose variation in the marketplace on an hourly, daily,
and seasonal basis is critical for driving lowest-cost matching of supply and demand. In fact, the
real price of electricity today is lower than it was in the early 1960s and 1980s (see Figure 4-9).
0
1960
1970
1980
1990
2000
2010
Figure 4-9. National Average Retail Electricity Price (1960 - 2011)
Source: EIA2013
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Table 4-9. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities
for 2010 ($millions)
Utility Operating Revenues
Electric Utility
Other Utility
Utility Operating Expenses
Electric Utility
Operation
Production
Cost of Fuel
Purchased Power
Other
Transmission
Distribution
Customer Accounts
Customer Service
Sales
Admin, and
General
Maintenance
Depreciation
Taxes and Other
Other Utility
Net Utility Operating Income
2009
276,124
249,303
26,822
244,243
219,544
154,925
118,816
40,242
67,630
10,970
6,742
3,947
5,203
3,857
178
15,991
14,092
20,095
29,081
24,698
31,881
2010
285,512
260,119
25,393
253,022
234,173
166,922
128,831
44,138
67,284
17,409
6,948
4,007
5,091
4,741
185
17,120
14,957
20,951
31,343
18,849
32,490
2011
280,520
255,573
24,946
247,118
228,873
161,460
122,520
42,779
61,447
18,294
6,876
4,044
5,180
5,311
185
17,343
15,772
22,555
29,086
18,245
33,402
Source: Table 8.3, EIA Electric Power Annual, 2011
Note: This data does not include information for public utilities.
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Table 4-10. Projected Revenues by Service Category in 2015 for Public Power and Investor-
Owned Utilities (billions)
Generation
Transmission
Distribution
Total
$207
$40
$111
$359
Source: EIA2013
Note: Data are derived by taking either total electricity use (for generation) or sales (transmission and
distribution) and multiplying by forecasted prices by service category from Table 8 of EIA AEO 2013
(Electricity Supply, Disposition, Prices, and Emissions).
On a state-by-state basis, retail electricity prices vary considerably. The Northeast and
California have average retail prices that can be as much as double those of other states (see
Figure 4-10).
Average Price (cents per kilowatthour)
6.44-7,80
^B 7.88-8.78
I | 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 9.90 cents.
Source: U.S. Energy Information Administration, Annual Energy Review -
Electricity Section, Table 4, September 27, 2012.
Figure 4-10. Average Retail Electricity Price by State (cents/kWh), 2011
Source: EIA 2012
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4.9 Natural Gas Market
The natural gas market in the United States has historically experienced significant price
volatility from year to year, between seasons within a year, and can undergo major price swings
during short-lived weather events (such as cold snaps leading to short-run spikes in heating
demand). Over the last decade, gas prices (both Henry Hub prices and delivered prices to the
power sector) have ranged from below $3 to nearly $10/mmBtu on an annual average basis
(see Figure 4-11). During that time, the daily price of natural gas reached as high as
$15/mmBtu. Recent forecasts of natural gas availability have also experienced considerable
revision as new sources of gas have been discovered and have come to market, although there
continues to be some uncertainty surrounding the precise quantity of the resource base.
Current and projected natural gas prices are considerably lower than the prices
observed over the past decade, largely due to advances in hydraulic fracturing and horizontal
drilling techniques that have opened up new shale gas resources and substantially increased
the supply of economically recoverable natural gas. According to AEO 2012 (EIA 2012):
Shale gas refers to natural gas that is trapped within shale formations. Shales are
fine-grained sedimentary rocks that can be rich sources of petroleum and natural
gas. Over the past decade, the combination of horizontal drilling and hydraulic
fracturing has allowed access to large volumes of shale gas that were previously
uneconomical to produce. The production of natural gas from shale formations
has rejuvenated the natural gas industry in the United States.
The U.S. Energy Information Administration's Annual Energy Outlook 2012 (Early
Release) estimates that the United States possessed 2,214 trillion cubic feet (Tcf) of
technically recoverable natural gas resources as of January 1, 2010. Natural gas from
proven and unproven shale resources accounts for 542 Tcf of this resource estimate.
Many shale formations, especially the Marcellus, are so large that only small portions of
the entire formations have been intensively production-tested. Consequently, the
estimate of technically recoverable resources is highly uncertain, and is regularly
updated as more information is gained through drilling and production. At the 2010 rate
of U.S. consumption (about 24.1 Tcf per year), 2,214 Tcf of natural gas is enough to
supply over 90 years of use. Although the estimate of the shale gas resource base is
lower than in the prior edition of the Outlook, shale gas production estimates increased
between the 2011 and 2012 Outlooks, driven by lower drilling costs and continued
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drilling in shale plays with high concentrations of natural gas liquids and crude oil, which
have a higher value in energy equivalent terms than dry natural gas.23
ElA's projections of natural gas conditions did not change substantially in AEO 2013
from the AEO 2012, and EIA is still forecasting abundant reserves consistent with the above
findings. Recent historical data reported to EIA is also consistent with these trends, with 2012
being the highest year on record for domestic natural gas production.24 The average delivered
natural gas price to the power sector was $3.44 per MMBtu in 2012, down from $4.78/MMBtu
in 2011.25
EIA projections of future natural gas prices assume trends that are consistent with
historical and current market behavior, technological and demographic changes, and current
laws and regulations.26 Depending on actual conditions, there may be significant variation from
the price projected in the reference case and the price observed. To address this uncertainty,
EIA issues a range of alternative cases, including cases with higher and lower economic growth,
which address many of the uncertainties inherent in the long-term projections. The EPA
describes the AEO 2013 reference case and a number of relevant alternative cases in the
analyses in Chapter 5.
23 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
24 http://www.eia.gov/dnav/ng/hist/n9010us2a.htm
25 http://www.eia.gov/dnav/ng/hist/n3045us3A.htm; Assumes that 1 TCP = 1.023 MMBtu natural gas
(http://www.eia. gov/tools/faqs/faq.cfm?id=45&t=8)
26EIA2010b.
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Natural Gas Spot Price, Annual Average (Henry Hub)
12
10
3
4-1
CO
c
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consumption. Fourth, other policies, such as energy efficiency standards at the state and
Federal level, have helped address certain market failures. These broader changes have altered
the outlook for future electricity growth (see Figure 4-10).
-2%
IS 50 1960 1970 1980 1990 2000 2010 2020 2030 2040
Figure 4-7. Electricity Growth Rate (3-Year Rolling Average) and Projections from the Annual
Energy Outlook 2013
Source: EIA 2009, EIA 2013
Energy efficiency initiatives have become more common, and investments in energy
efficiency are projected to continue to increase for the next 5 to 10 years, driven in part by the
growing number of states that have adopted energy efficiency resource standards. These
investments, and other energy efficiency policies at both the state and federal level, create
incentives to reduce electricity consumption and peak load. According to EIA, demand-side
management provided actual peak load reductions of 33.3 GW in 2010. For context, the current
coal fleet is roughly 314 GW of capacity.
Demand for electricity, especially in the short run, is not very sensitive to changes in
prices and is considered relatively price inelastic, although some demand reduction does occur
in response to price. With that in mind, the EPA modeling does not typically incorporate a
"demand response" in its electric generation modeling (Chapter 5) to the increases in electricity
prices typically projected for EPA rulemakings. Electricity demand is considered to be constant
in EPA modeling applications and the reduction in production costs that would result from
lower demand is not considered in the primary analytical scenario that is modeled. This leads to
some overstatement in the private compliance costs that the EPA estimates for rules where
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compliance costs are anticipated for a rulemaking. Note that this NSPS is not anticipated to
create compliance costs for projected new ECU sources.
4.11 References
Brennan, ST., Burruss, R.C., Merrill, M.D., Freeman, P.A., and Ruppert, L.F. A probabilistic
assessment methodology for the evaluation of geologic carbon dioxide storage: U.S.
Geological Survey Open-File Report 2010-1127. 2010. Available online at
http://pubs.usgs.gov/of/2010/1127.
Interagency Task Force on Carbon Capture and Storage. Report of the Interagency Task Force on
Carbon Capture and Storage. August 2010. Available online at:
http://www.epa.gov/climatechange/downloads/CCS-Task-Force-Report-2010.pdf.
Intergovernmental Panel on Climate Change. Climate Change 2001: The Scientific Basis. 2001.
Available online at:
http://www.grida.no/publications/other/ipcc tar/?src=/climate/ipcc tar/wgl/218.htm.
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/.
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). Improving Domestic Energy Security and
Lowering C02 Emissions with "Next Generation" C02-Enhanced Oil Recovery (C02-EOR).
June 20, 2011. DOE/NETL-2011/1504. Available online at:
http://www.netl.doe.gov/energy-
analyses/refshelf/PubDetails.aspx?Action=View&Publd=391.
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.
Oil and Gas Journal. Enhanced Oil Recovery Survey. 2010. Volume 108, Issue 14, April 19, 2010.
p.41.
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.
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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.
U.S. Energy Information Administration (U.S. EIA). AEO 2010 Retrospective Review. 2010b.
Available online at: http://www.eia.gov/forecasts/aeo/retrospective/.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010c.
Available online at: http://www.eia.gov/oiaf/archive/aeolO/index.html.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Review 2010. 2010d. Available
online at: http://www.eia.gov/totalenergy/data/annual/pdf/aer.pdf.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2011. 2011. Available
online at: http://www.eia.gov/forecasts/archive/aeoll/.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2012 (Early Release).
2012. Available online at: http://www.eia.gov/forecasts/aeo/.
U.S. Energy Information Administration (U.S. EIA). Today in Energy: s Most states have
Renewable Portfolio Standards. 2012a. Available online at:
http://www.eia. gov/todayinenergv/detail.cfm?id=4850.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available
online at: http://www.eia.gov/forecasts/aeo/.
U.S. Environmental Protection Agency (U.S. EPA). Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2011. April 2013. Available online at:
http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-lnventorv-2013-
Main-Text.pdf.
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U.S. Geological Survey Geologic (USGS) National assessment of geologic carbon dioxide storage
resources-Summary: U.S. Geological Survey Factsheet 2013-3020. 2013. Available
online at: http://pubs.usgs.gov/fs/2013/3020/.
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CHAPTER 5
COSTS, BENEFITS, ECONOMIC, AND ENERGY IMPACTS
5.1 Synopsis
This chapter reports the compliance cost, benefits, economic, and energy impact
analyses performed for the proposed ECU New Source GHG Standards. EPA analyzed and
assessed a wide range of potential scenarios and outcomes, using a detailed power sector
model, other government projections for the power sector, and additional economic
assessments and analysis to determine the potential impacts of this action.
The primary finding of this assessment is that in the absence of this proposed rule, all
projected unplanned1 capacity additions affected by this proposal during the analysis period
would already be compliant with the rule's requirements (e.g., combined cycle natural gas, low
capacity factor natural gas combustion turbine, and small amounts of coal with CCS supported
by Federal and State funding). The analysis period is defined as through 20222 to reflect that
CAA Section lll(b) requires that the NSPS be reviewed every eight years. EPA's conclusion was
based on:
• EIA power sector modeling projections
• EPA power sector modeling projections
• Electric utility integrated resource planning (IRP) documents
• Projected new EGUs reported by industry to EIA
EPA's finding of no new, unplanned conventional coal-fired capacity is robust beyond
the analysis period (past 2030 in both EIA and EPA baseline modeling projections) and across a
wide range of alternative potential market, technical, and regulatory scenarios that influence
power sector investment decisions. As a result, the proposed 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 EPA does not project any new coal-fired EGUs
without CCS to be built in the absence of this proposal, this chapter presents an analysis of the
project-level costs of building new coal-fired capacity with and without CCS to demonstrate
1 Unplanned capacity represents projected capacity additions that are not under construction.
2IPM output for other years has been made available in the docket and is discussed where appropriate throughout
the document.
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that a requirement of partial CCS would not preclude new coal construction. An additional
illustrative analysis, presented at the end of this chapter, shows that even in the unlikely event
that new, noncompliant ECU capacity would be built in the absence of this rule the proposed
ECU New Source GHG Standards would provide net social benefits under a range of
assumptions.
5.2 Requirements of the Proposed GHG ECU NSPS
In this action, the EPA is proposing standards of performance for two basic categories of
new units that have not commenced construction: (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 size and operational criteria.
The EPA is proposing standards of performance for affected sources within the following
subcategories: (1) natural gas-fired stationary combustion turbines with a heat input rating to
the turbine engine that is greater than 850 MMBtu/hr; (2) natural gas-fired stationary
combustion turbines with a heat input rating to the turbine engine that is less than or equal to
850 MMBtu/hr; and (3) all fossil fuel-fired boilers and IGCC units. All affected new fossil fuel-
fired EGUs would be required to meet an output-based emission rate of a specific mass of C02
per MWh of electricity generated energy output on a gross basis. New natural gas-fired
stationary combustion turbines with a heat input rating greater than 850 MMBtu/hr would be
required to meet a standard of 1,000 Ib C02/MWh of gross energy output. New natural gas-
fired stationary combustion turbines with a heat input rating less than or equal to 850
MMBtu/hr would be required to meet a standard of 1,100 Ib C02/MWh of gross energy output.
New fossil fuel-fired boilers and IGCC units would be required to meet a standard of 1,100 Ib
C02/MWh of gross energy output. These standards would be met on a 12-operating month
rolling average basis. An alternative emission limit, available only to new fossil-fired boilers and
IGCC units, can be met over an 84-operating month rolling average basis. The alternative
emission limit will be between 1,000 and 1,050 Ib C02/MWh of gross energy output.
The proposed action applies to sources based on electric sales. More specifically, a
facility is covered if it sells more than 1/3 of its potential electric output and more than 219,000
MWh net electric output to the grid. The proposed definition does not explicitly exclude simple
cycle combustion turbines, but as a practical matter, it is generally expected not to apply as
most simple cycle combustion turbines sell less than 1/3 of their potential electric output. For
potential combustion turbines that anticipate selling more than 1/3 of their potential electric
output, there are more cost effective and lower emitting technologies that could be
constructed consistent with the proposed standards as will be demonstrated later in this
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chapter. Please refer to the preamble for additional detail concerning affected sources and
standards of performance.
5.3 Power Sector Modeling Framework
5.3.1 Modeling Overview
Over the last decade, EPA has conducted extensive analyses of regulatory actions
impacting the power sector. These efforts support the Agency's understanding of key policy
variables and provide the framework for how the Agency estimates the costs and benefits
associated with its actions. Current forecasts for the utilization of new and existing generating
capacity are a key input into informing the design of EPA's proposal. Given excess capacity
within the existing fleet and relatively low forecasts of electricity demand growth, there is
limited new capacity - of any type - expected to be constructed over the next decade. A small
number of new coal-fired power plants have been built in recent years; however, EPA does not
expect the construction of any new, unplanned, conventional coal-fired capacity through the
analysis period. This conclusion is based in part on the Agency's own power sector modeling
utilizing IPM as well as ElA's Annual Energy Outlook 2013 (AEO 2013) projections.
IPM, developed by ICF Consulting, is a state-of-the-art, peer reviewed, dynamic linear
programming model that can be used to project power sector behavior under future business
as usual conditions and examine prospective air pollution control policies throughout the
United States for the entire electric power system. EPA used IPM to project likely future
electricity market conditions with and without the proposed rule. In addition to IPM, EPA has
closely examined the AEO 2013 from the EIA.
To produce the AEO, EIA employs the National Energy Modeling System (NEMS), an
energy-economy modeling system of the United States. According to EIA:3
"NEMS projects the production, imports, conversion, consumption, and prices of
energy, subject to assumptions on macroeconomic and financial factors, world energy markets,
resource availability and costs, behavioral and technological choice criteria, cost and
performance characteristics of energy technologies, and demographics."
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
3 http://www.eia.gov/oiaf/aeo/overview/
5-3
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cost, cost of utility and nonutility technologies, expected load shapes, fuel markets, regulations,
and other factors. ElA's AEO projections independently support EPA's conclusions in that it
projects no new generation capacity being constructed through the analysis period that would
not already meet the level of the standard even in the absence of the standard. Both sets of
modeling results are presented in Section 5.4.
5.3.2 The Integrated Planning Model
IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S.
electric power sector. It provides forecasts of least cost capacity expansion, electricity dispatch,
and emission control strategies while meeting energy demand and environmental,
transmission, dispatch, and reliability constraints. EPA has used IPM for over two decades to
better understand power sector behavior under future business as usual conditions and
evaluate the economic and emission impacts of prospective environmental policies. The model
is designed to reflect electricity markets as accurately as possible.4 EPA uses the best available
information from utilities, industry experts, gas and coal market experts, financial institutions,
and government statistics as the basis for the detailed power sector modeling in IPM. The
model documentation provides additional information on the assumptions discussed here as
well as all other model assumptions and inputs.5
Although the Agency typically focuses on broad system effects when assessing the
economic impacts of a particular policy, EPA's application of IPM includes a detailed and
sophisticated regional representation of key power sector variables and its organization. When
considering which new units are most cost effective to build and operate, the model considers
the relative economics of various technologies based on a wide spectrum of current and future
considerations, including capital costs, operation and maintenance costs, fuel costs, utility
sector regulations, and emission profiles. The capital costs for new units account for regional
differences in labor, material, and construction costs. These regional cost differentiation factors
are based on assumptions used in the ElA's AEO.
As part of IPM's assessment of the relative economic value of building a new power
plant, the model incorporates a detailed representation of the fossil-fuel supply system that is
used to forecast equilibrium fuel prices, a key component of new power plant economics. The
model includes an endogenous representation of the North American natural gas supply system
through a natural gas module that reflects full supply/demand equilibrium of the North
http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html
5 http://www.epa.gov/airmarkt/progsregs/epa-ipm/BaseCasev410.htmltfdocumentation
5-4
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American gas market. This module consists of 114 supply, demand, and storage nodes and 14
liquefied natural gas regasification facility locations that are tied together by a series of linkages
(i.e., pipelines) that represent the North American natural gas transmission and distribution
network.
IPM also endogenously models the coal supply and demand system throughout the
continental U.S., and reflects non-power sector demand and imports/exports. IPM reflects 84
coal supply curves, 12 coal sulfur grades, and the coal transport network, which consists of
1,230 linkages representing rail, barge, and truck and conveyer linkages. The coal supply curves
in IPM, which are publicly available6, were developed during a thorough bottom-up, mine-by-
mine approach that depicts the coal choices and associated supply costs that power plants will
face over the modeling time horizon. The IPM documentation outlines the methods and data
used to quantify the economically recoverable coal reserves, characterize their cost, and build
the 84 coal supply curves. The coal supply curves were developed in consultation with Wood
Mackenzie, one of the leading energy consulting firms and specialists in coal supply. These
curves have been independently reviewed by industry experts and have been made available
for public review on several occasions over the past two years during other rulemaking
processes.
EPA has used IPM extensively over the past two decades to analyze options for reducing
power sector emissions. Recently, the model has been used to forecast the costs, emission
changes, and power sector impacts for the Clean Air Interstate Rule (CAIR), Cross-State Air
Pollution Rule (CSAPR), and the Mercury and Air Toxics Standards (MATS).7
The model undergoes periodic formal peer review, which includes separate expert
panels for both the model itself and EPA's key modeling input assumptions.8 The rulemaking
process also provides opportunity for expert review and comment by a variety of stakeholders,
including owners and operators of the electricity sector that is represented by the model, public
interest groups, and other developers of U.S. electricity sector models. EPA is required to
respond to significant comments submitted regarding the inputs used in IPM, its structure, and
application. The feedback that the Agency receives provides a highly detailed check for key
input assumptions, model representation, and modeling results. IPM has received extensive
review by energy and environmental modeling experts in a variety of contexts. For example, in
6 v4.10 of the coal supply curves may be found in Appendix 9-4 of http://www.epa.gov/airmarkt/progsregs/epa-
ipm/BaseCasev410.html#documentation
7 All of the IPM projections conducted for this rulemaking are available at EPA's website and in the public docket.
8 http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html
5-5
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the late 1990's, the Science Advisory Board reviewed IPM as part of the CAA Amendments
Section 812 prospective studies that are periodically conducted.9 The model has also
undergone considerable interagency scrutiny when it has been used to conduct over one dozen
legislative analyses (performed at Congress' request) over the past decade. In addition,
Regional Planning Organizations throughout the U.S. have extensively examined IPM as a key
element in the state implementation plan (SIP) process for achieving the National Ambient Air
Quality Standards. The Agency has also used the model in a number of comparative modeling
exercises sponsored by Stanford University's Energy Modeling Forum over the past 15 years.
IPM has also been employed by states (e.g., for 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 used the model extensively to inform issues related to ozone in the
northeastern U.S. This groundbreaking work set the stage for the NOX SIP call, which has
helped reduce summer NOX emissions and the formation of ozone in densely populated areas
in the northeast.
5.4 Analyses of Future Generating Capacity
5.4.1 Base Case Power Sector Modeling Projections
EPA conducted analysis and modeling in support of the April 2012 ECU GHG New Source
Standards proposal, and concluded that new unplanned noncompliant base load power plants
are not expected to be economic well beyond the analysis period. EPA conducted an analysis of
the economic impacts by modeling a base case scenario of future electricity market conditions.
EPA's IPM modeling relied on the AEO 2010 for the electric demand forecast for the U.S. and
employed a set of EPA assumptions regarding fuel supplies, the performance and cost of
electric generation technologies, pollution controls, and numerous other parameters.10 The
base case accounts for the effects of the finalized MATS and CSAPR rules, and New Source
Review settlements and state rules through December 2010 impacting sulfur dioxide (S02),
NOX, directly emitted particulate matter and C02.n
The most current EIA projections are reflected in AEO 2013 and are summarized in the
following tables alongside the EPA projections. New coal-fired capacity through 2030 in the
9 http://www.epa.gov/air/sect812/
10 http://www.epa.gov/airmarkt/progsregs/epa-ipm/proposedEGU GHG NSPS.html
11 The legal status of CSAPR and CAIR has no impact on this proposal's evaluation, as neither CSAPR nor CAIR
significantly influences the type of new capacity additions projected to be economic.
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AEO 2013 reference case is entirely CCS-equipped and would be in compliance with this
proposal (0.3 GW). The projected CCS-equipped capacity is assumed to occur in response to
existing Federal, State, and local incentives for the technology.12 According to the AEO 2013 -
which represents existing policies and regulations influencing the power sector - the vast
majority of new, unplanned generating capacity is forecast to be either natural gas-fired or
renewable.13 The economics favoring new natural gas combined cycle (NGCC) additions instead
of conventional coal are robust under a range of sensitivity cases examined in the AEO 2013.
Sensitivity cases that separately examine higher economic growth, lower coal prices, no risk
premium for greenhouse gas emissions liability from conventional coal, and lower oil and
natural gas resources also forecast zero unplanned additions of coal-fired capacity without CCS
in the analysis period. Recent previous versions of the AEO came to similar conclusions. Based
on these previous AEO analyses, DOE concluded that "the low capital expense, technical
maturity, and dispatchability of natural gas generation are likely to dominate investment
decisions under current policies and projected prices."14
In comparing the EPA and EIA modeling projections reported here, the most important
variables influencing the choice of technology for new generating capacity are more favorable
to new coal-fired capacity in the EPA analysis. For example, electric demand in 2020 was
assumed to be 4,305 billion kWh (taken from AEO 2010) in EPA's modeling projections, which is
over 4% higher than electric demand in AEO 2013.15 Projected fuel prices for natural gas and
coal are also more favorable to new coal-fired capacity relative to new NGCC capacity in the
EPA analysis than in the AEO 2013 projections.
12 These programs include the Emergency Economic Stabilization Act of 2008, the American Reinvestment and
Recovery Act of 2009 (which assisted in funding for such programs as the Clean Coal Power Initiative through
DOE and tax credits for Clean Energy Manufactures through DOE and the Treasury Department), as well as
loans provided by USDA for CO2 capture projects.
13 http://www.eia.gov/forecasts/aeo/chapter legs regs.cfm
14 Department of Energy (2011). Report on the First Quadrennial Technology Review. Available at
http://enerdv.Qov/sites/prod/files/QTR report.pdf.
15 In a long-term power sector modeling framework, calendar years are typically grouped into model run years. In
EPA's IPM projections reported in this chapter, 2020 is the run year that is representative of results from
calendar years 2017-2024. Consequently, the chapter often presents 2020 projections and results from EPA
and EIA as opposed to projections for the last year of the analysis period (2022).
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Table 5-1. Reference Case Unplanned Cumulative Capacity Additions (GW)
Capacity Type
Conventional Coal
Coal with CCS
Natural Gas CC
Natural Gas CT
Nuclear
Renewables16
Distributed Generation
Total
EPA
2020
0
2
7.0
3.0
0
26.9
0
38.9
2020
0
0.3
3.1
15.4
0
3.7
0.9
23.4
AEO 2013
2025
0
0.3
17.4
28.0
0
6.4
1.9
54.1
2030
0
0.3
48.2
43.3
0
10.5
3.1
105.4
Notes: The sum of the table values in each column may not match the total figure due to rounding.
Source: EPA 2020 projection from IPM run by EPA, 2011; EIA 2020-2030 projection from EIA Annual Energy Outlook 2013
The capacity projections of EIA and EPA represent a continuation of current trends,
where natural gas-fired capacity has been the technology of choice for base load and
intermediate load power generation over the last few years (see Figure 5-2), due in large part
to its significant levelized cost of electricity17 (LCOE) advantage over coal-fired generating
technologies. A greater discussion of the relative LCOE of different generating technologies is
provided beginning in Section 5.5.
16 Renewable projections are higher in the EPA reference case due largely to EPA's 2011 modeling projections
predating AEO 2013 projections; therefore, all renewable builds that occurred in the interim would be
accounted for in AEO 2013 as 'planned' capacity and are omitted from the table above. The overall amount of
total renewable capacity by 2020 is largely similar.
17The levelized cost of electricity is an economic assessment of the cost of electricity from a new generating unit or
plant, including all the costs over its lifetime: initial investment, operations and maintenance, cost of fuel, and
cost of capital.
5-8
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• Nuclear
• Coal
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Figure 5-1. Historical U.S. Power Plant Capacity Additions, by Technology, 1940-2011
Source: Form EIA-860 (2011)
Note: Renewables include hydro, geothermal, biomass, solar, and wind energy technologies.
In addition to new builds, increased electricity demand is expected to be partially
fulfilled by increased utilization of existing generating capacity. Generation projections are the
result of least-cost economic modeling both in IPM and AEO 2013, and reflect the most cost-
effective dispatch and investment decisions modeled, given a variety of variables and
constraints. Even without the deployment of unplanned conventional coal-fired capacity, U.S.
electricity demand will continue to be met by a diverse mix of electricity generation sources
with coal projected to continue to provide the largest share of electricity (39% of total 2020
generation in AE02013 and 46% in EPA's projections), as displayed in Table 5-2.
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Table 5-2. 2011 U.S. Electricity Net Generation and Projections for 2020, 2025, and 2030
(Billion kWh)
Coal
Oil
Natural Gas
Nuclear
Hydroelectric
Non-Hydro Renewables
Other
Total
Historical
2011
1,718
15
926
790
318
164
18
3,949
EPA
2020
1,976
Negligible
869
840
286
289
45
4,305
2020
1,640
15
1,078
885
289
270
5
4,182
AEO 2013
2025
1,707
16
1,127
912
291
295
9
4,356
2030
1,745
16
1,221
908
292
310
13
4,506
Source: Historical data from Form EIA-860, 2011. EPA 2020 projection from IPM run by EPA, 2011; EIA 2020-2030 projection
from EIA Annual Energy Outlook 2013Notes: Net summer generating capacity. The sum of the table values in each column may
not match the total figure due to rounding. "Non-Hydro Renewables" include biomass, geothermal, solar, and wind electric
generation capacity. The capacity of a generating unit that is co-firing gas in a coal boiler is split in this table between
"pulverized coal" and "Oil/Gas Steam" proportionally by fuel use.
It has been previously noted that since the time of the IPM Base Case analysis,
projections for key market variables are now less favorable to the development of coal-fired
capacity. State and regional regulations have necessarily evolved since EPA's 2011 modeling
projections, most notably regulations of GHG emissions from the power sector and state
renewable portfolio standards (RPS):
• State regulations addressing CO? emissions - Several states have adopted
measures to address emissions of C02 from the power sector. These approaches
include flexible market-based programs like California's Assembly Bill 32 and the
RGGI in the Northeast, and specific GHG performance standards for new power
plants in California, Oregon, New York, and Washington.
• State Renewable Portfolio Standards (RPS) - According to EIA, 30 states and the
District of Columbia have an enforceable RPS, or similar laws.18 There are eight
other States that have voluntary goals.19 These measures, in conjunction with
Federal financial incentives, are key drivers of the significant growth in new
renewable energy seen over the past few years and expected over the next
decade.
18 http://www.eia.gov/forecasts/aeo/legs_regs_all.cfm#state
19 http://www.dsireusa.org/rpsdata/index.cfm
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• 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.20 In general, these plans confirm the expectation that utilities
anticipate that any new sources of generation will be from renewables, in
response to state and federal regulations and incentives, and natural gas prices.
Furthermore, these plans reflect an expectation of relatively low demand growth
due, in part, to policies and regulations to reduce the electricity consumption
such as energy efficiency regulations and policies, evolution of the Smart Grid,
and demand response measures.
Any recently adopted state and local climate or related electricity sector regulations that
are not included in the IPM Base Case analysis, California's AB 32 for example, also make the
development of coal-fired capacity less favorable.
5.4.2 Alternative Scenarios from AEO 2013
Power sector modeling that projects no new, unplanned, conventional coal-fired
capacity in the analysis period have been demonstrated to be robust under a range of
alternative assumptions that influence the industry's decisions to build new power plants. For
example, EIA typically supplements the AEO with scenarios that explore key market, technical,
and regulatory issues. Of the 26 scenarios contained in the AEO 2013, none projected
unplanned, conventional coal capacity in the analysis period, including the four scenarios that
may be considered most favorable to the development of coal-fired capacity displayed below:21
20 E.g., http://www.pacificpower.net/about/irp.html
21 AEO 2013 scenario definitions: High Economic Growth increases annual real GDP growth by 0.4%; Low Coal Cost
assumes greater regional productivity growth rates and lower wages, equipment, and transportation costs for
the coal industry; Low Oil and Gas Resource reduces the ultimate estimated recovery of shale gas, tight gas,
and tight oil by 50%; No GHG Concern removes the perceived risk of incurring costs under a future GHG policy
from market investment decisions.
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Table 5-3. AEO 2013 Unplanned Cumulative Capacity Additions, GW (202022)
Capacity Type
Conventional Coal
Coal with CCS
Natural Gas
Nuclear
Non-Hydro Renewables
Other
Total
Reference
0
0.3
18.5
0
3.7
0.9
23.4
High
Growth
0
0.3
19.5
0
13.5
0.6
33.9
Low Coal
Cost
0
0.3
17.6
0
5.0
0.8
23.8
Low Gas
Resource
0
0.3
13.7
0
5.2
0.2
19.3
NoGHG
Concern
0
0.3
17.8
0
4.1
0.8
23.1
5.4.3 Power Sector Fuel Price Dynamics and Trends
As mature technologies, the cost and performance characteristics of conventional coal-
fired capacity and NGCC are projected by EPA to be relatively stable over time in comparison to
emerging generation technologies.23 Therefore, expectations of future fuel prices play a key
role in determining the overall cost competitiveness of conventional coal versus NGCC.
Current and projected natural gas prices are considerably lower than observed
prices over the past decade. This is largely due to advances in hydraulic fracturing and
horizontal drilling techniques that have opened up new shale gas resources and
substantially increased the supply of economically recoverable natural gas. According to
EIA:
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.
Of the natural gas consumed in the United States in 2011, about 95% was
produced domestically; thus, the supply of natural gas is not as dependent on foreign
producers as is the supply of crude oil, and the delivery system is less subject to
interruption. The availability of large quantities of shale gas should enable the United
22 The 2020 run year represents conditions out through 2022, consistent with the eight year NSPS review cycle.
23 http://www.epa.gov/airmarkt/progsregs/epa-ipm/docs/v410/Chapter4.pdf
5-12
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States to consume a predominantly domestic supply of gas for many years and produce
more natural gas than it consumes.
The U.S. Energy Information Administration's Annual Enemy Outlook 2013 Early
Release projects U.S. natural gas production to increase from 23.0 trillion cubic feet in
2011 to 33.1 trillion cubic feet in 2040, a 44% increase. Almost all of this increase in
domestic natural gas production is due to projected growth in shale gas production,
which grows from 7.8 trillion cubic feet in 2011 to 16.7 trillion cubic feet in 2040.24
Recent historical data reported to EIA is also consistent with these trends, with 2012
being the highest year on record for domestic natural gas production.25 The average delivered
natural gas price to the power sector was $3.44 per MMBtu in 2012, down from $4.78/MMBtu
in 2011.26
Increases in the natural gas resource base have led to fundamental changes in the
outlook for natural gas. While sources may disagree on the absolute level of increases from
shale resources, there is general agreement that recoverable natural gas resources will be
substantially higher for the foreseeable future than previously anticipated, exerting downward
pressure on natural gas prices.27'28 EPA and EIA modeling incorporates the impact of these
additional resources on the forecasts of the price of natural gas used by electric generating
units. The increases in the natural gas resource base are reflected not only in current natural
gas prices and projections (e.g., AEO 2013), but also in current capacity planning by utilities and
electricity producers across the country. The North American Electric Reliability Corporation's
(NERC) Long Term Reliability Assessment, which is based on utility plans for new capacity over a
10-year period, reinforces this consensus by stating that "gas-fired generation [is] the primary
choice for new capacity."29
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
24 http://www.eia.gov/energy_in_brief/article/about_shale_gas.cfm
25 http://www.eia.gov/dnav/ng/hist/n9010us2a.htm
26 http://www.eia.gov/dnav/ng/hist/n3045us3A.htm; Assumes that 1 TCP = 1.023 MMBtu natural gas
27
(http://www.eia. gov/tools/faqs/faq.cfm?id=45&t=8)
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).
EIA. 2013. U.S. Crude Oil and Natural Gas Proved Reserves, 2011.
http://www.eia.gov/naturalgas/crudeoilreserves/pdf/uscrudeoil.pdf
29 NERC, Long-Term Reliability Assessments for 2012. New capacity includes both planned and conceptual
resources as defined by NERC.
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capital investments, while utilizing scenario testing to account for broader fuel market
uncertainties. Short-term fuel price volatility is not the most relevant factor in this context
because new power plants have asset lives measured in decades, not in months or years, and
new capacity investment decisions are based on long-run expected prices, not month-to-
month, or even year-to year, variations in fuel prices. Shorter-term prices will affect how units
are dispatched, but these potential dispatch impacts are considered with other factors over a
longer time horizon and factored into the choice of which type of plant to build. In contrast,
the uncertainty surrounding long-term fuel prices will exert significantly greater influence on
the technology selected for new capacity additions. In a modeling context with perfect
foresight, this longer term uncertainty may be evaluated by the scenario testing presented
throughout this analysis.
In addition to major changes in the gas supply outlook, there have been notable changes
in the coal supply outlook. Coal costs have generally increased over the past few years due
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.30
Taken together, current and expected natural gas and coal market trends are
contributing to a fundamental shift in the economic conditions for new power plant
development that utilities and developers have recognized and responded to in planning.31
5.4.4 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 5-5.
30 http://www.eia.gov/forecasts/aeo/assumptions/pdf/coal.pdf
31 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.
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Table 5-4. National Delivered 2020 Fuel Prices by AEO 2013 Scenario (2011$/MMBtu)
Scenario32
Reference
High Growth
Low Growth
High Coal Cost
Low Coal Cost
High Gas/Oil Resource
Low Gas/Oil Resource
Natural Gas
5.00
5.45
4.64
5.26
4.85
3.60
6.18
Coal
2.52
2.57
2.47
2.93
2.17
2.47
2.78
However, given that power plants are long-lived assets, capacity planning decisions are
necessarily undertaken with a forward view of expected market and regulatory conditions. In
producing the AEO 2013, EIA capacity expansion projections are informed by a lifecycle cost
analysis over a 30-year period in which the expectations of future prices are consistent with the
projections realized in the model (i.e. the model executes decisions with perfect foresight of
future market, technical, and regulatory conditions). Therefore, the fuel price that informs
capacity expansion decisions in 2020 is not the 2020 price, but the entire future fuel price
stream. For example, Figure 5-6 displays ElA's natural gas price projections for the Reference
Case and several scenarios through 2040.
32 AEO 2013 scenario definitions: High Economic Growth increases annual real GDP growth by 0.4%; Low Economic
Growth decreases real GDP growth by 0.6%; High Coal Cost assumes lower regional productivity growth rates
and higher wages, equipment, and transportation costs for the coal industry; Low Coal Cost assumes greater
regional productivity growth rates and lower wages, equipment, and transportation costs for the coal industry;
High Oil and Gas Resource expands the ultimate estimated recovery of shale gas, tight gas, and tight oil by
100%; Low Oil and Gas Resource reduces the ultimate estimated recovery of shale gas, tight gas, and tight oil by
50%.
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12
10
•Reference
•High growth
Low growth
•High coal cost
•Low coal cost
•High resource
Low resource
No GHG concern
2015
2020
2025
2030
2035
2040
Figure 5-2. National Delivered Natural Gas Prices by Select AEO 2013 Scenario
(2011$/MMBtu)
Natural gas prices are expected to increase after 2020 in all scenarios33; however, rising
natural gas prices through 2040 - including in ElA's low gas/oil resource scenario - are still not
sufficient to support new, conventional coal-fired generation in the analysis period (i.e.,
through 2022), demonstrating that natural gas prices at currently low levels are not required to
persist for NGCC to maintain its economic advantage over coal-fired technologies.
While the uniformity of EIA scenarios in projecting no new, unplanned, conventional
coal-fired capacity through the analysis period is compelling, the scenario projections cannot
fully illustrate the extent of the economic advantage that NGCC maintains over conventional
coal - only that the advantage remains intact across a broad range of market and technical
scenarios. To identify potential market conditions that could fully erode the private cost
advantages of NGCC over conventional coal during the analysis period the following section
adopts a static, engineering cost analysis.
Coal prices are also expected to rise in all scenarios.
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5.5 Levelized Cost of Electricity Analysis
5.5.1 Overview of the Concept of Levelized Cost of Electricity
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 as well as alternative AEO 2013 scenarios, the proposed ECU New Source GHG
Standards are not projected to result in any emission reductions, monetized benefits, or costs.
Despite this conclusion, it is important to supplement the power sector modeling
projections to quantify the robustness of the economic advantage of new NGCC relative to new
coal without CCS. To achieve this task, EPA will rely on the concept of LCOE. LCOE is a widely
used metric that represents the cost, in dollars per output, of building and operating a
generating facility over the entirety of its economic life. Evaluating competitiveness on the
basis of LCOE is particularly useful in establishing cost comparisons between generation types
with similar operating characteristics but with different cost and financial characteristics. The
typical cost components associated with LCOE include capital, fixed operating and maintenance
(FOM), variable operating and maintenance (VOM), and fuel.
The levelized capital cost is the result of the annualized capital cost spread over the
annual output of the generation facility. The annualized capital cost (expressed in $/kw-yr) is
the product of the $/kW capital cost and the capital recovery factor (CRF). A CRF may be
calculated using the project's interest rate (i) and book life (n).34
The levelized capital and FOM costs may be calculated by taking the annualized capital
and FOM (expressed in $/kW-yr) and spreading the expense over the annual generation of the
facility using the expected average annual capacity factor (the percent of full load at which a
unit would produce its actual annual generation if it operated for 8760 hours).
The VOM, which is already expressed in terms of cost per unit output, may be presented
with or without fuel expense. The fuel expense is typically the largest component of VOM (non-
fuel components to VOM include start-up fuel, consumables, inspections, etc.) and for certain
capacity types - such as NGCC - fuel expense may represent the majority of the LCOE. To
calculate a levelized fuel cost, it is necessary to introduce the concept of a levelized fuel price.
34 The interest rate assumed for NGCC projects is 9.06%; the interest rate assumed for coal-fired projects is 9.57%.
Both types of projects are assumed to have a 30-year book life, resulting in a capital recovery factor of 9.78%
for NGCC projects and 10.23% for coal-fired projects.
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Because levelized costs consider the entire lifecycle of the facility, the levelized fuel
price calculates the single value payments necessary to reflect the stream of annual delivered
fuel prices over the economic life of the facility at a given discount rate.35 Levelizingfuel prices
recognizes the necessity to consider the trajectory of fuel costs over the facility's entire
economic life.
It should be noted that there are other important considerations beyond LCOE that
impact power plant investment decisions. New power plant developers must consider the
particular demand characteristics in any particular region, the existing mix of generators,
operational flexibility of different types of generation, prevailing and expected electricity prices,
and other potential revenue opportunities (e.g., the capacity value of a particular unit, where
certain power markets have mechanisms to compensate units for availability to maintain
reliability, sale of co-products, etc.). Broader system-wide power sector modeling - such as the
analyses conducted by EPA and scenarios conducted by EIA - is able to more effectively capture
these considerations.
5.5.2 Cost and Performance of Technologies
The NGCC and coal-fired generation technology cost and performance assumptions that
form the basis for the LCOE analysis in this chapter are sourced from the DOE's NETL.36 NETL
cost and performance characteristics were selected for coal-fired technologies because the
NETL estimates were unique in the detail of their cost and performance estimates for a range of
C02 capture levels for both new super critical pulverized coal (SCPC) and IGCC facilities.37'38 The
C02 capture sensitivity analysis included an evaluation of the cost, performance, and
35 As an illustration of applying a discount rate to a stream of future fuel prices, the levelized fuel price will be less
than the mean fuel price if prices are increasing; equal to the mean if fuel prices are constant; and greater than
the mean if fuel prices are declining. The weighting of nearer-term prices through the application of a discount
rate is consistent with modeling economic behavior. EPA utilized a 5% discount rate to calculate levelized fuel
prices, a value consistent with the discount rate embedded in IPM.
36 http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf
37 All potential build types are compliant with all current environmental regulations, including EPA's Mercury and
Air Toxics Standards (MATS).
38 For an emerging technology like CCS, costs can be estimated for a "first-of-a-kind" (FOAK) plant or an "nth-of-a-
kind" (NOAK) plant, the latter of which has lower costs due to the "learning by doing" and risk reduction
benefits that result from serial deployments as well as from continuing research, development and
demonstration projects. The estimates provided in Table 5-5 for a new NGCC unit and for a SCPC plant without
CO2 capture are based on mature technologies and are thus NOAK costs. For plants that utilize technologies
that are not yet fully mature, such the IGCC or any plant that includes CO2 capture, the cost estimates in Table
5-5 represent a plant that is somewhere between FOAK and NOAK, sometimes referred to as "next-of-a-kind".
Because there are a number of projects currently under development, the EPA believes it is reasonable to focus
on the next-of-a-kind costs provided in Table 5-5. See the preamble for additional discussion.
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environmental profile of these facilities under different configurations that were tailored to
achieve a specific level of carbon capture. EPA selected NETL cost and performance
characteristics for NGCC to ensure that the cost comparisons between NGCC and coal-fired
technologies - the primary comparison made in this chapter - represented a single, internally
consistent framework. For technologies where NETL cost and performance estimates were not
available or sufficiently recent - such as for nuclear and simple cycle CT - EPA adopted ElA's
AEO 2013 estimates of LCOE.
To represent a new SCPC facility, NETL assumed a new boiler with a combination of low-
NOx burners (LNB) with overfire air (OFA) and a selective catalytic reduction (SCR) system for
NOx control. The plant was assumed to have a fabric filter and a wet limestone FGD scrubber
for particulate matter and S02 control, respectively. For configurations including CCS, the plant
was assumed to have a sodium hydroxide (NaOH) polishing scrubber to ensure that the flue gas
entering the C02 capture system has a S02 concentration of 10 ppmv or less. The SCPC w/ CCS
plant configurations were equipped with Fluor's Econamine FG PlusSM process for post-
combustion C02 capture via temperature swing absorption with a monoethanolamine (MEA)
solution as the chemical solvent.
Specific to the partial capture configurations for SCPC, the NETL study identified two
options. The first option identified was to process the entire flue gas stream through the MEA
capture system, but at reduced solvent circulation rates. The second option was to maintain the
same high solvent circulation rate and stripping steam requirement as would be used for full
capture, but only treat a portion of the total flue gas stream. The NETL report determined that
this "slip stream" approach was the most economical because a reduction in flue gas flow rate
will: (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce the size of
the C02 absorption columns; and (3) trim the cooling water requirement of the direct contact
cooling system.39 The "slip stream" approach - which leads to lower capital and operating costs
- was adopted by EPA for cost and performance estimates under partial capture.
For a new IGCC ECU, the NETL study evaluated a number of IGCC plant configurations.
EPA adopted the configurations presented as the most viable - from both an economic and
technological perspective - for the no capture, partial capture, and full capture cases. The no
C02 capture case employed an IGCC that used the two-stage acid gas (Selexol™) process for
acid gas control (i.e., hydrogen sulfide (H2S) and C02) but no WGS reactor. The 25 percent C02
39 NETL based this determination primarily upon literature review. Please refer to page 2 of
http://www.netl.doe.gov/energy-analvses/pubs/Gerdes-08022011.pdf
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capture case utilized the same two-stage Selexol™ unit to maximize C02 capture from the
unshifted syngas. To achieve higher C02 capture levels - including full capture - the IGCC was
assumed to be configured with a two-stage WGR with bypass and the two-stage acid gas
(Selexol™) scrubbing system.40 In summary, the technology cost and performance
characteristics utilized by EPA in developing the LCOE estimates provided in this chapter are
listed below in Table 5-7.
Table 5-5. Technology Cost and Performance (2011$)
Capacity Type
NGCC
SCPC
SCPC w/ Partial CCS
(1,100 Ibs/MWh
gross)
SCPC w/Full CCS
(200 Ibs/MWh gross)
IGCC
IGCC w/ Partial CCS
(1,100 Ibs/MWh
gross)
IGCC w/ Full CCS
(150 Ibs/MWh gross)
Total Overnight
Capital Cost ($/kw)
891
2,452
3,301
4,391
2,969
3,274
4,086
Fixed Operations
& Maintenance
($/kw-yr)
26.7
70.6
90.7
116.6
94.8
103.2
125.6
Variable
Operations &
Maintenance
($/MWh)
1.8
7.7
10.5
14.1
9.3
10.1
12.1
2020 Fuel
Cost
($/MMBtu)
5.00
2.94
2.94
2.94
2.94
2.94
2.94
Net Plant
HHV
Efficiency
(%)
50.2
39.3
34.5
28.4
39.0
37.3
32.6
Notes: The coal assumed is a bituminous coal with a sulfur content of 2.8% (dry) at a price of $2.94/MMBtu, consistent with the
NETL analysis from which technology cost and performance as well as fuel price was sourced.41 The natural gas price is the 2020
price from ElA's AEO 2013 Reference Case. NETL explains that there are a range of future potential costs that are up to 15%
below, or 30% above the central estimate provided in Table 5-5.), 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.
For additional detail and discussion on the specific technology configurations selected for this analysis, please
refer to the preamble.
http://www.netl.doe.gov/energy-analyses/pubs/BaselineCostUpdate.pdf
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5.5.3 Levelized Cost of Electricity of New Generation Technologies
This section presents four LCOE comparisons42:
1. NGCC to Uncontrolled Coal - to demonstrate the cost advantages of NGCC over a
range of natural gas prices and regional market conditions.
2. Uncontrolled Coal to Coal with partial CCS - to demonstrate that any requirement
for CCS could be accommodated and would not, based on the cost increment of
constructing and operating the CCS portion, preclude new coal construction.
3. Coal with partial CCS to Nuclear-to demonstrate that the overall cost of building
coal with partial CCS is not fundamentally different than the overall cost of
constructing a nuclear facility.
4. NGCC to CT - to demonstrate the unlikelihood of a new combustion turbine being
built with the expectation of exceeding a 33% annual capacity factor and thus being
covered by this proposal.
It should be noted that the LCOE comparisons presented in this section only represent
the cost to the generator and do not reflect the additional social costs that are associated with
emissions of greenhouse gases or other air pollutants. A broader consideration of the health
and welfare impacts of emissions from these technologies is considered beginning in Section
5.7.
Additionally, it is important to note that both EIA and EPA apply a climate uncertainty
adder (CUA) - represented by a three percent increase to the weighted average cost of capital -
to new, conventional coal-fired capacity types. EIA developed the CUA to address differences in
how investments in new capacity are evaluated in power sector models as compared to
resource planning exercises commonly conducted by the industry. While baseline power sector
modeling scenarios may not specify potential future GHG regulatory requirements, investors in
the industry typically incorporate some expectation of a future cost to limit C02 emissions in
resource planning evaluations that influence investment decisions.43 Therefore, the CUA
reflects the additional risk typically assigned by project developers and utilities to GHG-
42 '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.
43 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
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intensive projects in a context of climate uncertainty. When comparing private investment
costs, EPA believes the inclusion of the CUA in LCOE estimates is consistent with the industry's
current planning and evaluation framework for future projects (demonstrable through IRPs and
public utility commission orders) and is therefore necessary to adopt in evaluating the
behavioral response to the cost competitiveness of alternative generating technologies.44
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."45
Therefore, EPA recognizes the application of the CUA is context dependent - as a part of the
planning process it is appropriately applied in an evaluative sense to prospective projects, and
then removed once a project transitions from planning to execution. Although a perspective
that omits the CUA is inconsistent with the purposes of the analysis contained in this section
(i.e., analyzing the project characteristics and market conditions that would lead a developer or
utility to select a certain project, not determine what the actual project costs would be once
that project selection is made), LCOE estimates for uncontrolled coal-fired projects are
presented both with and without the CUA. All LCOE estimates of coal-fired facilities with CCS
(partial or full) are presented without the CUA.
5.5.4 Levelized Cost of Electricity of NGCC and Uncontrolled Coal
EPA's base LCOE estimates for NGCC, SCPC, and IGCC are displayed below by cost
component (capital, FOM, VOM, fuel) and assume a construction date of 2020:
44 For example, a 2011 Synapse Report lists 15 utilities that adopted a value for CO2 in their integrated resource
planning, http://www.synapse-energy.com/Downloads/SynapsePaper.2011-02.0.2011-Carbon-
Paper.A0029.pdf. In addition to utilities, several state commissions have mandated the inclusion of a cost of
CO2 in long-term planning (e.g., Minnesota utilities must adopt a price beginning in 2017).
45 http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
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•IO-
CS
fM
120
100
80
60
40
20
112
I Fuel
VO&M
IFO&M
I Capital
NGCC SCPC(w/CUA) SCPC (w/o IGCC (w/CUA) IGCC (w/o
CUA) CUA)
Figure 5-3. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation
Technologies by Cost Component, EPA46
Notes: The coal assumed is a bituminous coal with a sulfur content of 2.8% (dry) at a price of $2.94/MMBtu,
consistent with the NETL analysis from which technology cost and performance was sourced . The $2.94/MMBtu
delivered coal price is assumed for all years; therefore, the price serves as both the 2020 fuel cost as well as the
levelized fuel cost over any future period of time. This assumption produces a 20-year levelized coal price consistent
with the AE02013 Reference Case's $2.79/MMBtu projection average delivered price to the electricity sector for all
coals. A capacity factor of 85 percent is assumed across all technologies. For comparison, EIA estimates levelized
costs under AEO 2013 assumptions for SCPC and IGCC are $99/MWh and $122/MWh, respectively, including a 3%
CUA and excluding transmission investment costs. The levelized costs presented above are based on NETL
assumptions and will necessarily differ from AEO 2013 levelized costs for a variety of reasons, including cost and
performance characteristics, financial assumptions, and fuel input prices. The LCOE for NGCC assumes a
$6.11/MMBtu levelized natural gas price - additional information on this assumption is provided later in this section
(see Table 5-6).
On a levelized cost basis, NGCC is significantly cheaper than all of the uncontrolled coal-
fired options, including those options that assume no CUA. In addition to the disparity in LCOE
totals, the cost composition exhibits fundamental differences between natural gas- and coal-
' Although EPA believes that this cost data is broadly representative of the economics between new coal and new
natural gas facilities, this analysis assumes representative new units and does not reflect the full array of new
generating sources that could potentially be built. To the extent that other types of new units that would be
affected by this rule are built, they may exhibit different costs than those presented here. For example, new
conventional coal facilities of a size smaller than what is assumed in the base estimate would tend to exhibit a
relatively higher LCOE, while some technologies could potentially display a lower LCOE if- all else equal - fuel
could be obtained at a lower price than that assumed in this analysis (such as may be the case for petroleum
coke or waste coal facilities). These potential differences do not fundamentally change the analysis presented
in this chapter.
http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf
! http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
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fired facilities, with NGCC dominated by fuel expense and the levelized cost of coal-fired
technologies driven by capital expense. Consequently, this section will explore the impact of
changes in natural gas price and the capital costs of coal-fired facilities to better quantify the
magnitude of the relative cost advantage NGCC exhibits over coal-fired alternatives.
The figure below presents the LCOE of an NGCC facility at three levelized natural gas
price levels. For reference, the base LCOE estimates for SCPC and IGCC are included as well.49
•10-
iH
!H
a
120
100
80
60
40
20
NGCC NGCC NGCC
($6.11/MMBtu) ($7.5/MMBtu) ($10/MMBtu)
SCPC (w/ CUA) IGCC (w/ CUA)
Figure 5-4. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation
Technologies Across Select Natural Gas Prices, EPA
It is only when natural gas prices exceed $10/MMBtu on a levelized basis (in 2011
dollars) that new coal-fired generation without CCS approaches parity with NGCC in terms of
LCOE (none of the EPA sensitivities or AEO 2013 scenarios described in this chapter project
national average natural gas prices near that level).50 To achieve a $10/MMBtu levelized price
Some new units could be designed to combust waste coal or petroleum coke (pet coke), which may be affected
by this rule. These technologies could exhibit different local economics, particularly in the delivered price of fuel.
From a capital and operating perspective, EPA believes the cost and performance of these units are broadly similar
and therefore well represented by new, conventional coal-fired facilities (i.e. SCPC).
50 As noted earlier in this chapter, investment decisions require consideration of fuel price projections over long
periods of time; similarly, the power sector modeling cited here make fuel price projections over long periods
of time. Neither these modeling projections nor these LCOE calculations are meant to suggest that the gas
price could not reach as high as $10/MMBtu at any given point in time; the point is that these analyses do not
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in 2020 would require a significantly more pessimistic natural gas outlook than what is
contained in AEO's low natural gas resource scenario. To illustrate, Table 5-6 report the
levelized natural gas prices (initial year of 2020) for both a 20-year period (to accommodate the
end of ElA's modeling projections in 2040) and 30-year period (calculated by continuing the
projected level of price increases through 2050).
Table 5-6. Levelized Natural Gas Prices by Select AEO 2013 Scenario (2011$/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)
6.11
6.69
5.64
6.51
6.00
4.09
7.63
30- Year AEO-Based
Projection
(2020-2049)
6.79
7.30
6.32
7.28
6.74
4.40
8.50
Note: Discount rate of 5%, consistent with IPM assumptions. The 30-year natural
gas price is calculated by applying the price increase from 2039 to 2040 in all subsequent
years through 2049.
To achieve a price that exceeds $10/MMBtu on a 20-year levelized basis in 2020 would
require a natural gas price projection more than 30% higher than ElA's low resource scenario in
all years - see Figure 5-5 below. This elevated natural gas price would result in a
$10.15/MMBtu average annual price in 2030 ($16.23/MMBtu nominal) and a $13.66/MMBtu
price in 2039 ($27.27/MMBtu nominal).51
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.
51 Nominal prices assuming an annual inflation rate of 2.5%.
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•Required Natural Gas Price
for>$10/MMBtu Levelized
on a 20-Year Basis
•Low resource
Reference
•High resource
Figure 5-5. Projected Real National Delivered Natural Gas Price for Select AEO 2013
Scenarios and Illustrative Path for > $10/MMBtu Levelized Cost
To conclude the comparison of NGCC with uncontrolled coal-fired alternatives, it is
important to note that the LCOE calculations are based on assumptions regarding the average
national cost of generation at new facilities. It is known that there is significant spatial variation
in the costs of new generation due to design differences, labor wage and productivity
differences, and delivered fuel prices among other potential factors.52
For example, EIA utilizes capital cost scalars to capture regional differences in labor,
material, and construction costs. The minimum and maximum capital cost scalars across all
regions in AEO 2013 for SCPC, IGCC, and NGCC build options are presented below in Table 5-7:53
Table 5-7. AEO 2013 Regional Capital Cost Scalars by Capacity Type
Capacity Type
SCPC
IGCC
NGCC
Minimum Capital
Cost Scalar
0.885
0.908
0.893
Maximum Capital Cost
Scalar
1.152
1.136
1.205
52 http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf
53 Excluding the New York City and Long Island areas, as well as those areas of the country that prohibit the
development of new, uncontrolled coal-fired facilities.
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Applying the regional capital cost scalars displayed above to the base LCOE estimates
developed earlier in this section produces only a small change in the relative competitiveness of
the technologies as seen in Table 5-8.
Table 5-8. LCOE Estimates with Minimum and Maximum AEO 2013 Regional Capital Cost
Scalars (2011$/MWh)
Capacity Type
SCPC
IGCC
NGCC
Reference (w/ 3%
CUA)
92
112
59
Minimum Capital
Cost Scalar
86
106
58
Maximum Capital
Cost Scalar
100
120
62
The LCOE of SCPC in the lowest capital cost region still results in an LCOE that is ~40%
higher than an NGCC located in the most expensive capital cost region. IGCC remains more
than 70% higher under a similar adjustment. In addition to the relatively small changes in LCOE
displayed above, the relative movement in LCOE that can be attributed to regional variations in
capital cost is further muted by the fact that a high or low capital cost region for coal-fired build
types is projected to be a high or low capital cost region for gas-fired build types. Due to its
capital-intensive nature, the most favorable regions for development of new coal-fired capacity
over NGCC are the lowest cost areas - an assumption that only narrows NGCC's LCOE
advantage by $5/MWh for both SCPC and IGCC. To completely negate the base $33/MWh
LCOE advantage of NGCC over SCPC solely with a reduction in coal-fired capital costs, overnight
capital costs for SCPC would have to be reduced from $2,452/kW to ~$800/kW; IGCC overnight
capital costs would have to be reduced to~$500/kW.
The other primary driver in determining the regional impact on competitiveness of new
build options is delivered fuel prices. As part of the AEO, EIA releases electric power
projections - including fuel prices - for each of the 22 Electricity Market Module (EMM)
regions. The two regions with the highest projected 2020 natural gas prices in the AEO 2013
are the Western Electricity Coordinating Council/Southwest ('Southwest') and the Florida
Reliability Coordinating Council (FRCC). The 20-year levelized natural gas and coal price
forecasts (2020-2039) in the AEO 2013 reference case are displayed in Figure 5-6 for both
regions.
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00
FRCC
WECC-Southwest
I Natural Gas BCoal
Figure 5-6. Levelized Regional Fuel Price from AEO 2013 Reference Case, 2020-2039
(2011$/MMBtu)54
While the FRCC region experiences the highest overall natural gas prices, the Southwest
region realizes a greater $/MMBtu differential between coal and natural gas prices under the
AEO projections; the impact on the LCOE of SCPC, IGCC, and NGCC is reported in Table 5-9 for
both sets of fuel prices.
Table 5-9. LCOE Estimates For Minimum and Maximum AEO 2013 Regional Capital Cost
Scalars (2011$/MWh)
Capacity Type
SCPC (w/ 3% CUA)
IGCC (w/ 3% CUA)
NGCC
Reference (w/ 3%
CUA)
92
112
59
FRCC Fuel Prices
97
117
65
Southwest Fuel
Prices
89
109
62
Due to the greater fuel price differential, the more favorable region for the
development of coal-fired facilities from an LCOE perspective is the Southwest, where the
regional fuel prices reduce the LCOE advantage of NGCC to $27/MWh over SCPC and $47/MWh
over IGCC.
Assuming 5% discount rate.
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In conclusion, even the most favorable combination of regional variability in capital
costs and delivered fuel prices represented by EIA are insufficient to support new, unplanned,
conventional coal-fired capacity in the analysis period.
5.5.5 Levelized Cost of Electricity of Uncontrolled Coal and Coal with Carbon Capture and
Storage (CCS)
The power sector continues to move away from the construction of coal-fired power
plants in favor of natural gas-fired power plants due, in part, to the significant LCOE differential
explored in the previous section. Even so, it is possible that a limited number of conventional
coal-fired power plants might be constructed in the analysis period. In these circumstances, EPA
believes that any requirement for CCS could be accommodated and would not, based on the
incremental cost of the CCS portion of the new unit, preclude the construction of the new coal-
fired facility.55
One factor in this determination is the availability of ER opportunities for new coal-fired
facilities. ER, which includes both EOR and EGR, refers to the injection of fluids into a reservoir
to increase oil and/or gas production efficiency. C02-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 C02. 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 C02 storage
opportunity (2,102 to 20,043 billion metric tons), oil and gas reservoirs are estimated to have
226 billion metric tons of C02 storage resource.56
The use of C02 for EOR can significantly lower the cost of implementing CCS. The
opportunity to sell the captured C02 rather than paying directly for its long-term storage,
greatly improves the economics of the new generating unit. According to the International
Energy Agency, of the CCS projects under construction or at an advanced stage of planning,
70% intend to use captured C02 to improve recovery of oil in mature fields, including Southern
Company's Kemper County Energy Facility, Summit Power's Texas Clean Energy Project, and the
Hydrogen Energy California Project.
55 The preamble provides a complete list of existing sources that have demonstrated CCS as well as new coal-fired
facilities that will utilize CCS and are very near to completion.
U.S. Department of Energy Nati
Storage Atlas, Fourth Edition.
56 U.S. Department of Energy National Energy Technology Laboratory (2012). United States Carbon Utilization and
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There are two EOR opportunities presented in Figure 5-16 - 'High' and 'Low.' The high
EOR opportunity assumes a C02 sale price of $40 per metric ton; the low EOR opportunity
assumes a C02 sale price of $20 per metric ton.57 For either opportunity, it is assumed that the
facility is only responsible for the costs of transmitting the captured C02 to the fence line, as is
currently the practice.58 Costs for the transportation, storage, and monitoring (TSM) of C02 are
included in this analysis. For non-EOR applications, TSM costs of ~$5-$15 dollars per ton of C02
are applied based on the level of capture.59 Figure 5-7 compares the LCOE for uncontrolled coal
to coal with partial CCS both with and without EOR. Although this proposal has determined
partial CCS is BSER for affected coal-fired facilities, the LCOE associated with full capture is
presented as well for illustrative purposes.
57 The High and Low CO2 sale prices utilized by EPA are consistent with NETL's Base Case and Low Case sale prices,
respectively (http://www.netl.doe.gov/energy-analyses/pubs/storing%20co2%20w%20eor_final.pdf). In
addition, this range is broadly consistent with the CO2 sale price data collected by the Department of Interior
for projects located on federal lands (http://statistics.onrr.gov/ReportTool.aspx). Prices are expressed in 2011$
and the price is expected to be static over time.
58 For EOR applications the point of sale is typically the facility fence line, in which case the coal facility operator
will avoid the TSM cost. Consequently, the economic benefit of EOR may be greater than simply the price paid
for CO2.
59 This range is broadly consistent with estimates provided by NETL (http://www.netl.doe.gov/energy-
analyses/pubs/QGESS_CO2T%26S_Rev2_20130408.pdf) and the Global CCS Institute
(http://www.globalccsinstitute.com/publications/economic-assessment-carbon-capture-and-storage-
technologies-2011-update).
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160
140
120
100
3 so
fM
60
40
20
I Uncontrolled (w/ CUA)
Uncontrolled (w/o CUA)
I Partial CCS
I Partial CCS - Low EOR
Partial CCS - High EOR
I Full CCS
I Full CCS - Low EOR
Full CCS-High EOR
SCPC
IGCC
Figure 5-7. Levelized Cost of Electricity, Uncontrolled Coal and Coal with Full and Partial
CCS (1,100 Ibs/MWh gross)
NOTE: EIA estimated LCOE under AEO 2013 assumptions for full capture SCPC+CCS is estimated at a LCOE
of $134 without EOR. No estimate is provided for IGCC+CCS or partial capture technologies.60
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 existing or under construction C02 pipelines). Provision of electric power does
not require coal-fired facilities to be co-located with the demand it is intended to serve. Please
refer to Chapter 4 for a more detailed discussion of ER, including its geographic availability,
expected future growth, and overall impact on the economics of CCS.
5.5.6 Levelized Cost of Electricity of Coal with Carbon Capture and Storage and Nuclear
There are five nuclear units currently under construction in the United States - Vogtle
Units 3 and 4, Summer Units 2 and 3, and Watts Bar 2 - as well as nine active applications
under U.S. Nuclear Regulatory Commission (NRC) review covering an additional 14 potential
units. The addition of Units 3 and 4 at Georgia Power's Plant Vogtle will be the first new
nuclear units built in the United States in 30 years. Although it is unlikely that all of the
proposed nuclear projects will be built, the renewed interest in new nuclear facilities - despite
persistently high capital costs - is driven by a host of factors, including climate and air quality
1 http://www.eia. gov/forecasts/aeo/electricity_generation.cfm
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concern, the value attached to fuel diversity, regional or local base load capacity needs, and
supportive regulatory environments.
As shown in Figure 5-8 on an LCOE basis, the cost of new nuclear is similar to the cost of
new coal with partial CCS without EOR. Factoring in the revenues associated with the low EOR
opportunity ($20 per ton of C02 and no transportation storage and monitoring - TSM -
obligation) reduces the cost of coal with CCS to levels that are 6-10% lower than new nuclear;
assuming a high EOR opportunity ($40 per ton of C02 and no TSM obligation) reduces the cost
of SCPC with CCS and IGCC with CCS to 18% and 9% below new nuclear, respectively. The
current activity related to new nuclear development at a cost that is broadly similar to coal with
CCS is a demonstration of the industry's willingness to develop higher cost projects that
produce low-emitting base load capacity that contributes to fuel diversity.
120
Nuclear SCPC+CCS SCPC+CCS SCPC+CCS
(Low EOR) (High EOR)
IGCC+CCS IGCC+CCS IGCC+CCS
(Low EOR) (High EOR)
Figure 5-8. Levelized Cost of Electricity, Nuclear and Coal with Partial CCS (1,100 Ibs/MWh
gross)
5.5.7 Levelized Cost of Simple Cycle Combustion Turbine and Natural Gas Combined Cycle
CTs fulfill a fundamentally different function in power sector operations than that of
NGCC and coal-fired facilities. CTs are designed to start quickly in order 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
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electricity (cost per kWh) at higher capacity factors and consequently are typically utilized at
levels well below the proposed threshold for sources affected by the proposed ECU New
Source GHG Standards (1/3 of potential electric output). Instead, these units are most often
built to ensure reserve margins are met during peak periods (typically in the summer), and in
some instances are able to generate additional revenues by selling capacity into power
markets. Thus, in practice, EPA expects that potential CT units would not meet the applicability
threshold in this proposed action and would not be subject to any standard.
Mirroring real world behavior, relatively low levels of CT generation are projected in
both EPA and EIA modeling frameworks. AEO 2013 projects a capacity factor for CTs of less than
20% in all regions and in all years. EPA's IPM modeling projects a capacity factor for individual
new CTs of 8.5% or less in all simulation years. Thus, these potential new units do not meet the
applicability threshold for this proposal, and there is no projected cost or emissions impact on
new CT units.
To illustrate the economic impracticality of utilizing combustion turbines in an
intermediate and base load mode of operation, Figure 5-18 displays the LCOE estimates for a CT
and NGCC at increasing capacity factors. The estimates utilize the AE02013 Reference Case
natural gas price for 2014 (representative of the lowest - and therefore most favorable to the
relative levelized cost of a CT - natural gas price during the analysis period).
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5% 10% 15% 20% 25% 30% 35% 40% 45% 50%
Capacity Factor
^—NGCC ^—CT
Figure 5-9. Levelized Cost of Electricity Across a Range of Capacity Factors, CT and NGCC
($2011/MWh at $3.84/MMBtu Levelized Natural Gas Price)
In the LCOE figure above, utilizing a CT for generation is less expensive than an NGCC
only at capacity factors of less than 20%.61 If expected utilization is greater than 20%, it can
reasonably be expected that a utility or developer would seek to deploy NGCC over CT for a
host of economic, environmental, and technical reasons. Unanticipated short term utilization
of CTs above a 33% capacity factor would not be expected to alter this dynamic as utilization is
evaluated over a 3-year averaging period to determine the applicability of the proposed
standards.
5.6 Comparison of Emissions from Generation Technologies
As discussed earlier in this chapter, NGCC units are on average expected to be more
economical to build and operate than new coal units. These natural gas units also have lower
emission profiles for C02 and criteria air pollutants than new coal units. While the proposed
ECU New Source GHG Standards is anticipated to have negligible costs or quantified benefits
under a range of likely market conditions, it is instructive to consider the differences in
emissions of C02 and other air pollutants between the two types of units.
CT cost, performance, and financial assumptions from AEO 2013.
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As Table 5-19 below shows, emissions from a typical new NGCC unit are significantly
lower than those from a new coal unit.62 For example, a typical new supercritical pulverized
coal facility that burns bituminous coal in compliance with new utility regulations (e.g., MATS)
would have considerably greater C02, S02, NOX, toxic metals, acid gases, and particulate
emissions than a comparable natural gas combined cycle facility. A typical natural gas
combined cycle unit emits two million metric tons less C02 per year than a typical new
conventional coal unit, as well as 2,000 fewer short tons S02 and about 1,200 fewer short tons
of NOX each year. Importantly, these differences in emissions assume a new coal unit that
complies with all applicable final regulations, including MATS. Reductions in S02 emissions are a
particularly significant driver for monetized health benefits, as S02 is a precursor to the
formation of particulates in the atmosphere, and particulates are associated with premature
death and other serious health effects. Further information on these pollutants' health effects
is included in the next subsection.
Table 5-10. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired
Generating Units
Natural Gas CC
SCPC SCPC+CCS (1,100
Ibs/MWh Gross)
IGCC IGCC+CCS (1,100
Ibs/MWh Gross)
Emission Emission Emission Emission
Emissions Rate Emissions Rate Emissions Rate Emissions Rate
(tons/ (Ibs/ (tons/ (Ibs/ (tons/ (Ibs/ (tons/ (Ibs/
Emissions
Emission
Rate
(Ibs/
year) MWh year) MWh year) MWh year) MWh (tons/year) MWh
net)
net)
net)
net)
net)
S02
NOX
CO 2
10
130
1.7
million
0.0041
0.060
800
1,700
1,400
4.0
million
0.74
0.61
1,800
1,100
1,500
2.7
million
0.48
0.69
1,200
23
1,200
3.8
million
0.010
0.52
1,700
30
1,200
3.0 million
0.013
0.52
1,400
Notes: S02 and NOX in short tons, C02 in metric tons. Values rounded to two significant digits. Emission characteristics are
based on, and thus consistent with the cost and performance assumptions of, the illustrative units described in LCOE analysis
above (e.g., that these are base load units running at 85 percent capacity factor, all coal units are assumed to be using
bituminous coal with a sulfur content of 2.8% dry, etc.). Here we further assume all units are of the same capacity (600 MW
net). Utilizing a consistent net capacity metric across plant types requires a higher gross capacity for those types with greater
need for auxiliary power. The tons of emissions associated with a facility are driven by gross capacity.
5.7 Benefits of Reducing GHGs and Other Pollutants
Society is not only affected by differences in the private generating costs of different
technologies, it also experiences the benefit or the burden of relative differences in emissions
Estimated emissions of CO2, SO2, and NOX for the illustrative new coal and natural gas combined cycle units
could vary depending on a variety of assumptions including heat rate, fuel type, and emission controls, to name
a few.
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produced by these generation technologies. As such, the appropriate social welfare
comparison should also account for the health, ecological and other emissions impacts of
different generation technologies. In particular, emissions of C02 and other pollutants lead to
additional social costs of these technologies. Any relative differences in these emissions
between newly built electric generating technologies would translate into relative climate-
related and human health benefits. This section provides a general discussion about how the
climate-related and human health benefits of emission reductions are estimated.
5.7.1 Social Cost of Carbon
The social cost of carbon (SCC) is a metric that estimates the monetary value of impacts
associated with marginal changes in C02 emissions in a given year. It is intended to include (but
is not limited to) changes in net agricultural productivity, human health, property damages
from increased flood risk, and the value of ecosystem services due to climate change. It is
typically used to assess the avoided damages, i.e. benefits, of rulemakings that achieve
marginal reductions in C02 emissions. This analysis applies SCC to illustrate the value of the
difference in C02 emissions among different generation technologies discussed in Section 5.5.
The federal government typically uses the SCC to estimate the social benefits of C02
reductions from regulatory actions that impact cumulative global emissions. An interagency
process that included the EPA and other executive branch entities used three integrated
assessment models (lAMs) to develop SCC estimates and selected four global values for use in
regulatory analyses. Three values are based on the average SCC from the three lAMs, at
discount rates of 5, 3, and 2.5 percent. SCCs at several discount rates are included because the
literature shows that the SCC is quite sensitive to assumptions about the discount rate, and
because no consensus exists on the appropriate rate to use in an intergenerational context
(where costs and benefits are incurred by different generations). The fourth value is the 95th
percentile of the SCC from all three models at a 3 percent discount rate. It is included to
represent higher-than-expected impacts from temperature change further out in the tails of the
SCC distribution (representing less likely, but potentially catastrophic, outcomes). The SCC
Technical Support Document (SCC TSD) provides a complete discussion of the methods used to
develop these estimates.63
63 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support Document: Social Cost of Carbon for Regulatory
Impact Analysis Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon, with
participation by Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture,
Department of Commerce, Department of Energy, Department of Transportation, Environmental Protection
Agency, National Economic Council, Office of Energy and Climate Change, Office of Management and Budget,
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The federal government recently updated these estimates, using new versions of each
integrated assessment model and published them in May 2013. The 2013 process did not revisit
the 2010 interagency modeling decisions (e.g., with regard to the discount rate, reference case
socioeconomic and emission scenarios or equilibrium climate sensitivity). Rather,
improvements in the way damages are modeled are confined to those that have been
incorporated into the latest versions of the models by the developers themselves and used in
peer-reviewed publications. The model updates that are relevant to the SCC estimates include:
an explicit representation of sea level rise damages in the Dynamic Integrated Climate and
Economy (DICE) and Policy Analysis of the Greenhouse Effect (PAGE) models; updated
adaptation assumptions, revisions to ensure damages are constrained by GDP, updated
regional scaling of damages, and a revised treatment of potentially abrupt shifts in climate
damages in the PAGE model; an updated carbon cycle in the DICE model; and updated damage
functions for sea level rise impacts, the agricultural sector, and reduced space heating
requirements, as well as changes to the transient response of temperature to the buildup of
GHG concentrations and the inclusion of indirect effects of methane emissions in the Climate
Framework for Uncertainty, Negotiation, and Distribution (FUND) model.64
The SCC estimates from the updated versions of the models are higher than those
reported in the 2010 TSD, which were used in the April 2012 ECU New Source GHG Standards
RIA. By way of comparison, the four 2020 SCC estimates reported in the 2010 TSD and used in
the April 2012 ECU New Source GHG Standards proposal were $7, $28, $44 and $86 per metric
ton (2011$). The corresponding four updated SCC estimates for 2020 are $13, $46, $69, and
$138 per metric ton (2011$).65'66
Office of Science and Technology Policy, and Department of Treasury (February 2010). Also available at
http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf
64 Docket ID EPA-HQ-OAR-2013-0495, Technical Support Document: Technical Update of the Social Cost of Carbon
for Regulatory Impact Analysis Under Executive Order 12866, Interagency Working Group on Social Cost of
Carbon, with participation by Council of Economic Advisers, Council on Environmental Quality, Department of
Agriculture, Department of Commerce, Department of Energy, Department of Transportation, Environmental
Protection Agency, National Economic Council, Office of Energy and Climate Change, Office of Management
and Budget, Office of Science and Technology Policy, and Department of Treasury (May 2013). Also available at
http://www.whitehouse.gov/sites/default/files/omb/inforeg/social cost of carbon for ria 2013 update.pdf
65 The 2010 and 2013 TSDs present SCC in $2007. The estimates were adjusted to $2011 using GDP Implicit Price
Deflator, http://www.gpo.gov/fdsvs/pkg/ECONI-2013-02/pdf/ECONI-2013-02-Pg3.pdf.
66 The 2010 SCC TSD concluded that a global measure of the benefits from reducing U.S. emissions is preferable.
The development of a domestic SCC is greatly complicated by the relatively few region- or country-specific
estimates of SCC in the literature. See Interagency Working Group on Social Cost of Carbon. 2010. Technical
Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866.
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When attempting to assess the incremental economic impacts of carbon dioxide
emissions, the analyst faces a number of serious challenges. A report from the National
Academies of Science (NRC 2009) points out that any assessment will suffer from uncertainty,
speculation, and lack of information about (1) future emissions of greenhouse gases, (2) the
effects of past and future emissions on the climate system, (3) the impact of changes in climate
on the physical and biological environment, and (4) the translation of these environmental
impacts into economic damages.67 As a result, any effort to quantify and monetize the harms
associated with climate change will raise serious questions of science, economics, and ethics
and should be viewed as provisional.
The 2010 SCC TSD noted a number of limitations to the SCC analysis, including the
incomplete way in which the integrated assessment models capture catastrophic and non-
catastrophic impacts, their incomplete treatment of adaptation and technological change,
uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding
risk aversion. Current integrated assessment models do not assign value to all of the important
physical, ecological, and economic impacts of climate change recognized in the climate change
literature because of a lack of precise information on the nature of damages and because the
science incorporated into these models understandably lags behind the most recent research.
The limited amount of research linking climate impacts to economic damages makes the
interagency modeling exercise even more difficult.
While the new versions of the models used to estimate the values presented below
offer some improvements in these areas, further work remains warranted. Accordingly, the EPA
and other agencies continue to engage in research on modeling and valuation of climate
impacts with the goal to improve these estimates. Additional details are provided in the SCC
TSDs.
Table 5-11 presents the updated global SCC estimates for the years 2015 to 2050. In
order to calculate the dollar value for emission reductions, the SCC estimate for each emissions
year would be applied to changes in C02 emissions for that year, and then discounted back to
the analysis year using the same discount rate used to estimate the SCC.68 The SCC increases
67 National Research Council (2009). Hidden Costs of Energy: Unpriced Consequences of Energy Production and Use.
National Academies Press. See docket ID EPA-HQ-OAR-2009-0472-11486.
68 This analysis considered the climate impacts of only CO2 emission change, as the U.S. Interagency Working
Group on the Social Cost of Carbon has thus far only considered estimates for the social cost of CO2. While CO2
is the dominant GHG emitted by the sector, we recognize the representative facilities within these comparisons
may also have different emission rates for other climate forcers which will serve a minor role in determining
the overall social cost of generation.
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over time because future emissions are expected to produce larger incremental damages as
physical and economic systems become more stressed in response to greater climate change.
Note that the interagency group estimated the growth rate of the SCC directly using the three
integrated assessment models rather than assuming a constant annual growth rate. This helps
to ensure that the estimates are internally consistent with other modeling assumptions.
Table 5-11. Social Cost of CO2, 2015-20503 (in 2011$)
Year
2015
2020
2025
2030
2035
2040
2045
2050
5% Average
$13
$13
$15
$17
$20
$22
$26
$29
Discount
3% Average
$41
$46
$51
$55
$61
$66
$70
$76
Rate and Statistic
2.5% Average
$62
$69
$75
$81
$86
$93
$98
$105
3%
95th percentile
$116
$138
$154
$170
$188
$205
$220
$236
a The SCC values vary depending on the year of CO2 emissions and are defined in real terms. These SCC values are
stated in $/metricton.
5.7.2 Health Co-Benefits of SO2 and NOX Reductions
Reducing power sector C02 under this rule would also result in reductions of S02 and
NOX emissions, which in turn would yield health benefits (we refer to these additional benefits
as "co-benefits"). S02 is a precursor for fine particulate matter (PM2.5) formation while NOX is a
precursor for PM2.5 and ground-level ozone formation. As such, reductions of S02 and NOX
would in turn lower overall ambient concentrations of PM2.5 and ozone. Reducing exposure to
PM2.5 and ozone is associated with significant human health benefits including avoided
mortality and morbidity. Researchers have associated PM2.5 and ozone exposure with adverse
health effects in numerous toxicological, clinical, and epidemiological studies (U.S. EPA, 2009;
U.S. EPA, 2013b). Health effects associated with exposure to PM2.5 include premature mortality
for adults and infants, cardiovascular morbidity such as heart attacks and hospital admissions,
and respiratory morbidity such as asthma attacks, bronchitis, hospital and emergency room
visits, work loss days, restricted activity days, and respiratory symptoms. Health effects
associated with exposure to ozone include premature mortality and respiratory morbidity such
as hospital admissions, emergency room visits, and school loss days. In addition to human
health co-benefits associated with PM2.5 and ozone exposure, reducing S02 and NOX emissions
under this rule would result in reduced health impacts from direct exposure to these pollutants.
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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).
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 RIA for MATS (U.S. EPA,
2011).
The avoided incidences of health effects and monetized value of health or non-health
improvements that result from S02 and NOX emissions reductions depend on the location of
those reductions. However, when assessing the co-benefits of differences in emissions from
different generation technologies in the following sections, the EPA does not assert a specific
location for the new unit. As a result, the EPA does not have the data to perform a full health
impact assessment for a specific modeled scenario.69 Instead, the EPA relied on a national-
average benefit per-ton (BPT) method to estimate PM2.5-related health impacts of S02 and NOX
emissions. The BPT approach provides an estimate of the total monetized human health
benefits (the sum of premature mortality and morbidity) of reducing one ton of PM2.5 precursor
(i.e., NOX and S02) from the sector. To develop the BPT estimates used in this analysis the EPA
utilized detailed air quality modeling of power sector S02 and NOX emissions along with the
BenMAP model70 to estimate the benefits of air quality improvements using projected 2020
population, baseline incidence rates, and economic factors.
The S02- and N0x-related BPT estimates utilized in this analysis are derived from the
Technical Support Document (TSD) on estimating the BPT of reducing PM2.5 and its precursors
(U.S. EPA, 2013a). These BPT values are estimated in a methodologically consistent manner
with those reported in Fann et al. (2012). They differ from those reported in Fann et al. (2012)
as they reflect the health impact studies and population data updated in the benefits analysis of
the final PM NAAQS RIA (U.S. EPA, 2012). The recalculation of the Fann et al. (2012) BPT values
based on the updated data from the PM NAAQS RIA (U.S. EPA, 2012) is described in the TSD
(U.S. EPA, 2013a).
69 If the EPA conjectured a location for a particular new unit it may be possible to perform a full health impact
assessment of different technologies at that location. Doing so for a number of locations is beyond the scope of
this analysis and would be better captured in sector-wide modeling. For more information on the EPA's
methods for conducting health impact assessments, please refer to Chapters of the final PM NAAQS RIA. (U.S.
EPA, 2012)
70 Available at http://www.epa.gov/air/benmap.
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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 S02 and NOX are accounted for in this assessment. For more
information about unquantified health and non-health co-benefits of S02 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 the emissions of other air and
water pollutants between the different generating technologies, including, for example,
directly-emitted PM.
As we do not conjecture a specific location for the new units being compared, this RIA is
unable to include the type of detailed uncertainty assessment found in the PM NAAQS RIA (U.S.
EPA, 2012). However, the results of the uncertainty analyses presented in the PM NAAQS RIA
can provide some information regarding the uncertainty inherent in the benefits results
presented in this analysis. In addition to these uncertainties, use of BPT estimates come with
additional uncertainty. Specifically, all national-average BPT estimates reflect a specific
geographic distribution of 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, or other factors that might lead to an
over-estimate or under-estimate of the actual benefits associated with PM2.5 precursors in a
specific location. These estimates are purely illustrative as the EPA does not assert a specific
location for the illustrative electricity generation technologies and is therefore unable to
specifically determine the population that would be affected by their emissions. Therefore, the
benefits for any specific unit can be different than the estimates shown here.
Notwithstanding these limitations, reducing one thousand tons of annual S02 from U.S.
power sector sources has been estimated to yield between 4 and 9 incidences of premature
mortality avoided and monetized PM2.5-related health benefits (including these incidences of
premature mortality avoided) between $38 million and $85 million in 2020 (2011$) using a 3%
discount rate or between $34 million and $76 million (2011$) using a 7% discount rate.
Additionally, reducing one thousand tons of annual NOX from U.S. EGUs has been estimated to
yield up to 1 incidence of premature mortality avoided and monetized PM2.5-related health
benefits (including these incidences of premature mortality avoided) of between $5.5 million
and $12 million in 2020 (2011$) using a 3% discount rate or between $5.0 million and $11
million (2011$) using a 7% discount rate. For each pollutant, the range of estimated benefits for
each discount rate is due to the EPA's use of two alternative primary estimates of PM2.5-related
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mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a higher primary
estimate based on Lepeule et al. (2012).
Table 5-12. Monetized Health Co-Benefits Per Ton of PM2.5 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
PM2.5 Precursor
NOX
$5,5000
$12,000
$5,000
$11,000
a As described in Section 5.7.2, the SO2- and NOX-related BPT estimates are from the Technical Support Document
on Estimating the Benefit Per Ton of Reducing PM2.5 from 17 Sectors (U.S. EPA, 2013a) and are adjusted to 2011$.
5.8 Comparison of Health and Welfare Impacts from Generation Technologies
As previously discussed in this chapter, the emissions of GHGs and other pollutants
associated with new sources of electricity generation are greater for coal-fired units than for
natural gas combined cycle units (even when accounting for compliance with MATS). Reducing
the emissions associated with electricity generation results in both climate and human health
and non-health benefits.
To consider the social benefits associated with the adoption of lower emitting new
generation technologies, we determine the differences in emissions in the illustrative emission
profiles between technologies in Table 5-10 and apply the 2020 social benefit values discussed
in Section 5.7. Specifically, we multiply the difference in C02 emissions between two
technologies by the estimates of the SCC, multiply the difference in S02 and NOX emissions by
the PM2.5-related S02 and NOX BPT estimates, and add those values to get a measure of 2020
social benefits of the adoption of lower emitting generation technology. We subsequently
divide by the number of MWh underlying the emission estimates to derive the social benefits
per unit of generation.
Only the direct emissions of C02, S02, and NOX are considered in this illustrative
exercise. Other air and water pollutants emitted by these technologies and emissions from the
extraction and transport of the fuels used by these technologies are not considered. For
example, coal has higher mercury emissions than natural gas, but the relative benefits from the
difference in mercury emissions are not considered. Furthermore, there may be differences in
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upstream greenhouse gas emissions (in particular, methane) from different technologies but
those were not quantified for this assessment.
Table 5-13 reports the 2020 incremental climate and health benefits associated with an
illustrative new NGCC plant relative to illustrative new SCPC and IGCC coal plants, given
different mortality risk studies and assumptions about the discount rate. These incremental
benefits should be relatively invariant across natural gas prices and other economic factors.
Depending on the discount rate and mortality risk study used, 2020 incremental benefits
associated with generation from a representative new natural gas combined cycle unit relative
to a new coal unit are $6.6 to $95 per MWh (2011$).71
The precise social benefits associated with reduced C02 emissions, which are the focus
of this rule, depend on the specific fuels used but do not depend on the location of generation
because the location of C02 emissions does not influence their impact on the evolution of
global climate conditions. As with the relative investment costs of a new coal unit and a new
natural gas combined cycle system, the precise incremental health co-benefits associated with
lower emissions depend on the location under consideration and the specific fuels that would
be used. An ideal benefit-cost analysis would account for these local circumstances (and
consider alternative sources of generation).
However, these factors will not change the qualitative conclusion. There will always be
incremental climate and human health benefits associated with a new natural gas combined
cycle unit relative to a new coal unit, independent of the location.
71 Different discount rates are applied to SCC than to the other benefit estimates because CO2 emissions are long-
lived and subsequent damages occur over many years. Moreover, several rates are applied to SCC because the
literature shows that it is sensitive to assumptions about discount rate and because no consensus exists on the
appropriate rate to use in an intergenerational context. The SCC interagency group centered its attention on
the 3 percent discount rate but emphasized the importance of considering all four SCC estimates. See the 2010
SCC TSD. Docket ID EPA-HQ-OAR-2009-0472-114577 or
http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf
for details.
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Table 5-13. 2020 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Illustrative
New Natural Gas Combined Cycle Generation Relative to New SCPC or IGCC Coal
Generation without CCS72
SCPC IGCC
CO2-Related Benefits using SCC
5% Discount Rate $5.6 $5.4
3% Discount Rate $20 $19
2.5% Discount Rate $31 $29
3% Discount Rate (95th percentile) $61 $58
PM2 s-Related Co-Benefits from SO2 and NOX Reductions
3% discount rate
Krewski et al. (2009) $15 $1.4
Lepeule et al. (2012) $35 $3.1
7% discount rate
Krewski et al. (2009) $14 $1.2
Lepeule etal. (2012) $31 $2.8
Combined CO2-Related and PM2 5-Related Benefits
Discount Rate Applied to PM2.5-Related Benefits
(range based on adult mortality function)
SCC Discount Rate
5% Discount Rate
3% Discount Rate
2.5% Discount Rate
3% Discount Rate (95th percentile)
3%
$21 to $40
$36 to $55
$46 to $65
$76 to $95
7%
$20 to $37
$34 to $52
$44 to $62
$75 to $92
3%
$6.7 to $8.5
$21 to $22
$30 to $32
$59 to $61
7%
$6.6 to $8.2
$20 to $22
$30 to $32
$59 to $60
Notes: The emission rates and operating characteristics of the units being compared in this table are reported in Table 5.10. Benefits are
estimated for a 2020 analysis year. The range of benefits within each SCC value and discount rate for PM2.5-related benefits pairing
reflects the use of two core estimates of PM25-related premature mortality. The EPA has evaluated the range of potential impacts per
MWh by combining all SCC values with health benefits values at the 3 percent and 7 percent discount rates. To be consistent with
concepts of intergenerational discounting, values for health benefits, which occur within a generation, would only be combined with SCC
values using a lower discount rate, e.g. the 7 percent health benefit estimates would be combined with 5 percent or lower SCC values,
but the 3 percent health benefit would not be combined with the 5 percent SCC value. While the 5 percent SCC and 3 percent health
benefit estimate falls within the range of values we analyze, this individual estimate should not be used independently in an analysis, as it
is represents a combination of discount rates that is unlikely to occur. Combining the 3 percent SCC values with the 3 percent health
benefit values assumes that there is no difference in discount rates between intragenerational and intergenerational impacts.
72 The benefits presented here are estimated on an output basis to enable easier comparisons and to illustrate the potential
impacts of moving from new coal without CCS to new NGCC. This analysis assumes representative new units and does
not reflect the full array of new generating sources that could potentially be built (e.g., a comparison of a small new
conventional coal plant with a small natural gas plant, or a comparison of a waste coal or petroleum coke facility to a
natural gas plant of a comparable size and capacity factor). However, the incremental benefits associated with other
facilities that could be built, and which would be subject to this proposal, would not change noticeably (i.e., these new
facilities would be subject to emissions standards for other pollutants and would emit similar levels of SO2, NOX, and
CO2, on an output basis) except for differences in local conditions, as discussed previously.
73 The range of estimated benefits for each discount rate is due to the EPA's use of two alternative primary estimates of
PM2.5-related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a higher primary estimate
based on Lepeule et al. (2012).
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The conclusion from this analysis is that there are significant environmental and health
benefits associated with electricity generation from a representative new NGCC unit relative to
a new conventional coal unit. Other studies of the social costs of coal and natural gas fired
generation provide similar findings (Muller et. al., 2011; NRC, 2009).74
As explained previously, the power sector continues to move away from the
construction of coal-fired power plants in favor of natural gas-fired power plants due, in part, to
the significant cost differential. Even so, it is possible that a limited number of unplanned coal-
fired power plants will be constructed during the analysis period. In these circumstances, units
built with CCS in place of conventional coal-fired units would result in relative climate and
human health and non-health benefits. Table 5-14 reports the 2020 incremental benefits
associated with an illustrative new coal-fired plant with CCS relative to illustrative new SCPC
and IGCC coal plants, given different mortality risk studies and assumptions about the discount
rate. Depending on the coal-fired generation type, discount rate, and mortality risk study used,
2020 incremental benefits associated with generation from a representative new coal-fired unit
with CCS relative to a new coal unit without CCS are $2.0 to $45 per MWh (2011$).75
74 Muller et al. 2011 conclude that, "coal-fired power plants have air pollution damages larger than their value
added", while the same is not true for natural gas plants (see Table 5). However, these comparisons are based
on typical existing coal and natural gas units, including natural gas boilers, and are not sensitive to location
(although the underlying analysis in the study does account for differences in the location of existing units
when estimating damages). The NRC 2009 study shows that only the most polluting natural gas units may cause
greater damages than even the least polluting existing coal plants (compare Tables 2-9 and 2-15). However, the
NRC comparison does not compare new units located in the same place, and so some of the natural gas units
with the greatest damages may be attributable to their location, and includes natural gas steam boilers, which
have a higher emission rates per unit of generation than natural gas combined cycle units.
75 Different discount rates are applied to SCC than to the other benefit estimates because CO2 emissions are long-
lived and subsequent damages occur over many years. Moreover, several rates are applied to SCC because the
literature shows that it is sensitive to assumptions about discount rate and because no consensus exists on the
appropriate rate to use in an intergenerational context. The SCC interagency group centered its attention on
the 3 percent discount rate but emphasized the importance of considering all four SCC estimates. See the 2010
SCC TSD 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 5-14. 2020 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Coal-
Fired Generation with CCS meeting 1,100 Ibs/MWh Relative to New Coal-Fired
Generation Without CCS
CO2-Related Benefits using SCC
5% Discount Rate
3% Discount Rate
2.5% Discount Rate
3% Discount Rate (95th percentile)
SCPC
$3.2
$11
$17
$34
IGCC
$2.1
$7.5
$11
$23
PM2.5-Related Benefits from SO2 and NOX Reductions
3% discount rate
Krewski et al. (2009) $4.7 *
Lepeuleetal. (2012) $11 *
7% discount rate
Krewski et al. (2009) $4.2 *
Lepeuleetal. (2012) $9.5 *
Combined CO2-Related and PM2.5-Related Benefits
Discount Rate Applied to PM2.5-Related Benefits
(range based on adult mortality function)
SCC Discount Rate
5% Discount Rate
3% Discount Rate
2.5% Discount Rate
3% Discount Rate (95th percentile)
3%
$7.9 to $14
$16 to $22
$22 to $28
$39 to $45
7%
$7.4 to $13
$16 to $21
$22 to $27
$39 to $44
3%
$2.0 to $2.0
$7.4 to $7.5
$11 to $11
$22 to $23
7%
$2.0 to $2.1
$7.4 to $7.5
$11 to $11
$22 to $23
*IGCC with CCS results in a small S02 emissions increase when compared to IGCC without CCS. As a result, there would be a
negligible health disbenefit associated with these emissions increases.
Notes: Benefits are estimated for a 2020 analysis year. The range of benefits within each SCC value and discount rate for PM2.5-
related benefits pairing reflects the use of two core estimates of PM2.5-related premature mortality. The EPA has evaluated
the range of potential impacts per MWh by combining all SCC values with health benefits values at the 3 percent and 7 percent
discount rates. To be consistent with concepts of intergenerational discounting, values for health benefits, which occur within a
generation, would only be combined with SCC values using a lower discount rate, e.g. the 7 percent health benefit estimates
would be combined with 5 percent or lower SCC values, but the 3 percent health benefit would not be combined with the 5
percent SCC value. While the 5 percent SCC and 3 percent health benefit estimate falls within the range of values we analyze,
this individual estimate should not be used independently in an analysis, as it is represents a combination of discount rates that
is unlikely to occur. Combining the 3 percent SCC values with the 3 percent health benefit values assumes that there is no
difference in discount rates between intragenerational and intergenerational impacts.
5.9 Illustrative Analysis - Benefits and Costs across a Range of Gas Prices
As the analysis in Sections 5.4 and 5.5 demonstrated, under a wide range of likely
electricity market conditions - including the EPA and EIA baseline scenarios as well as multiple
alternative scenarios - the EPA projects that the industry will choose to construct new units
76 The range of estimated benefits for each discount rate is due to the EPA's use of two alternative primary
estimates of PM2.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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that already meet the standards of this proposed rulemaking, regardless of this proposal. In this
section, we consider the unlikely scenario where construction of new supercritical coal capacity
without CCS occurs during the analysis period in the absence of the rule. The analysis in this
section indicates that in this scenario, which implies that the proposed ECU New Source GHG
Standards would result in costs to the investor, but would lead to greater climate and human
health benefits and is highly likely to provide net benefits to society as a whole.77
The starting point for this analysis is the illustrative comparison (presented in Section
5.5.4) of the relative LCOE of representative new SCPC and IGCC coal EGUs and representative
NGCC units.78 This comparison demonstrates a significant difference in the LCOE between the
coal-fired and natural gas-fired generating technologies. The estimated LCOE for a
representative NGCC unit is roughly $33 and $38 per MWh less than for a representative new
SCPC or IGCC coal unit, respectively (see Figure 5-3).79 This is consistent with the EPA's
projection, discussed at length in this chapter, that the proposed ECU New Source GHG
Standards are not projected to impose any costs (or generate quantified net benefits) under
current and likely future market conditions.
To supplement this determination, this section presents an analysis of three relevant
ranges within the distribution of future natural gas prices that can be classified as likely gas
prices, unexpectedly high natural gas prices, and unprecedented natural gas prices. Because the
cost of natural gas is a significant share of the LCOE for NGCC, we evaluate how changes in
natural gas prices affect differences in private and social cost of new technologies. In general,
this analysis shows that there would likely be a net social benefit,80 even under scenarios with
higher than expected gas prices, if new NGCC units were built in place of new coal-fired units as
a result of this policy. Under some conditions, higher natural gas prices may result in a net
social cost, holding all other parameters constant and disregarding social benefits that we are
77 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.
78 By fixing generation in this comparison, we are assuming that both technologies generate the same benefits in
the form of electricity generating services. We assume in the discussion that the benefit of electricity
production to consumers outweighs the private and social investment cost. However, at particularly high fuel
prices this might not be the case. For a discussion of when comparing the levelized costs of different generating
technologies provides informative results and when it does not see, for example, Joskow 2010 and 2011.
79 LCOE of NGCC relative to SCPC with 3% CUA and IGCC without 3% CUA.
80 The benefits estimated in this section are based on a single year (2020) of emissions from different generating
technologies. Due to data limitations, we are not able to estimate annualized benefits from the stream of
emissions over the lifetime of the generating technologies. This results in a conservative comparison of
benefits to costs where LCOE represents annualized lifetime costs of generating technologies.
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unable to monetize.81 Additionally, given certain market conditions, some operators may
choose to construct a new coal-fired unit with CCS. The relative private costs and social benefits
of a new coal-fired unit with CCS are discussed in Section 5.10.
5.9.1 Likely Natural Gas Prices
As shown earlier, it is only when natural gas prices reach $10.94/MMBtu on a levelized
basis (in 2011 dollars) that new coal-fired generation without CCS becomes competitive in
terms of its cost of electricity. None of the EPA sensitivities or AE02013 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.82
5.9.2 Unexpectedly High Natural Gas Prices
At natural gas prices above $10.94/mmBtu, the private levelized cost of electricity for a
representative new SCPC unit falls below that of a new NGCC unit. Therefore, at anticipated
levelized fuel prices above that price level some new SCPC coal units might be constructed in
the absence of this proposed rulemaking, provided there is sufficient demand and new coal
without CCS is competitive with other generating technologies.83 In this scenario, there would
be some compliance cost if a new NGCC unit or a coal-fired unit with CCS were built as a result
of the standard. However, generation from either a new NGCC unit or a coal-fired unit with CCS
would also have incremental environmental and health benefits by reducing global warming
pollution and particulate matter (as a result of S02 and NOX emissions) relative to generation
from a new coal unit.
For average annual natural gas prices greater than $10.94/mmBtu, the resulting
emission reduction benefits of building NGCC will outweigh the costs of constructing an NGCC
unit in lieu of a coal plant without CCS - indicating that the standard would yield net benefits
81 The net cost scenario is unlikely to occur over our analysis period and for a significant period beyond. For
example, high economic growth would increase both natural gas and coal prices at the same time - making it
harder to alter the underlying cost advantage of NGCC generation. It is important to note that this analysis is
limited in the types of benefits and costs considered, given that it does not address the life-cycle pollution
associated with fossil fuels along with the limitations of current SCC estimates. As previously discussed, the
current SCC estimates do not capture all important all of the physical, ecological, and economic impacts of
climate change recognized in the climate change literature. Despite our attempts to quantify and monetize as
many of the co-benefits as possible, the health and welfare co-benefits are not fully quantified or monetized in
this assessment. For more information about unquantified health and welfare co-benefits please refer to tables
5-2 and 6-2 of the PM NAAQS RIA (U.S. EPA, 2012), respectively.
82 ElA's projected natural gas price for 2022 in its reference scenario for AEO2013 is $5.31 (in 2011 dollars). ElA's
"Low oil and gas resource" scenario projects an average delivered electricity sector gas price of $6.64/mmBtu
(in 2011 dollars) in 2022.
83 See section 5.5 for a discussion of how local conditions and other factors may influence the LCOE comparison.
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for the analysis year. For example, at an average annual gas price of $ll/MMBtu, the
illustrative NGCC unit would generate power for approximately $l/MWh more than an SCPC
coal unit on a levelized basis,84 and result in incremental benefits from emissions of $20 to
$95/MWh (see analysis of 2020 relative benefits of NGCC: table 5-13).85 The net benefit of this
scenario would be $19 to $95/MWh.86 As illustrated in section 5.10, if an SCPC coal unit with
CCS (as opposed to an NGCC unit) were built instead of an SCPC coal unit without CCS, the CCS
equipped unit would result in an incremental cost of $18/MWh and incremental benefits from
emissions of $7.4 to $45/MWh relative to an SCPC unit without CCS (see analysis of 2020
relative benefits of CCS: table 5-14). The net impact of this scenario would range from a net
cost of Sll/MWh to a net benefit of $27/MWh.
For context, a natural gas price level of $10/MMBtu (in 2011 dollars) is higher than any
annual natural gas price to the electric power sector since at least 1996, when the EIA data
series stops.87 In addition, the highest projected average annual natural gas price during the
analysis period in any of the AE02013 scenarios cited in this chapter is $6.64/MMBtu in the Low
Oil and Gas Resource scenario. Further, the continued development of unconventional natural
gas resources in the U.S. suggests that gas prices would actually tend to be towards the lower
end of the historical range. As discussed above, none of the EIA sensitivity cases (which account
for future fuel prices for both gas and coal) show scenarios where noncompliant coal becomes
more economic than NGCC before 2020.
5.9.3 Unprecedented Natural Gas Prices
At extremely high natural gas prices, the generating costs of coal without CCS would be
sufficiently lower than the cost of new natural gas that the net benefit of the standard in a
given year could be negative (i.e., a net cost) under some ranges of benefit estimates. For
example, at gas prices of $14/MMBtu, the illustrative NGCC unit would generate power for
roughly $21 and $16/MWh more than conventional SCPC and IGCC coal units, respectively but
result in social benefits from lower emissions of $20 to $95/MWh and $6.6 to $61/MWh
relative to the SCPC and IGCC coal units, respectively (see analysis of 2020 relative benefits of
NGCC: table 5-13). If an NGCC unit were built as a result of the standard, the resulting net
84 Assuming an increase of $6.80/MWh in the cost of gas generation for every $l/MMBtu increase in natural gas
prices.
85 Assuming that coal prices do not increase along with natural gas prices as they historically have.
86 The higher value of net benefits calculated here is equal to the higher value of incremental benefits due to
rounding.
5ee: http://
to the electricity sector for the past 16 years (since 1997).
87 See: http://www.eia.gov/dnav/ng/hist/n3045us3A.htm. EIA reports average annual delivered natural gas prices
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impact would range from a net social cost of $1.5/MWh to a net social benefit of $74/MWh
relative to SCPC and from a net social cost of $9.5/MWh to a net social benefit of $45/MWh
relative to IGCC.
As noted in the previous subsection, natural gas prices at these levels would be
unprecedented as they have not been observed as long as EIA has collected data on natural gas
prices. As a result, the EPA believes that the probability of natural gas prices reaching average
annual levels at which this standard would generate net social costs under some ranges of
benefit estimates is extremely small.
We emphasize that differences in generating costs, plant design, local factors, and the
relative differences between fuels costs can all have major impacts on the precise
circumstances under which this standard would be projected to have no costs, net social
benefits or net social costs. However, based on historical and expected average annual gas
prices, we project that this standard is most likely to have negligible costs, and, if it does result
in costs, it is also likely to produce positive, although modest, net social benefits. The
probability that this proposed standard would result in net social costs is exceedingly low.
5.10 Illustrative Analysis - Benefits and Costs of CCS Compared with Conventional Coal
The previous section evaluated the social benefit of an investor constructing a new
NGCC unit in lieu of an uncontrolled unit in response to the proposed rule. If an operator chose
to construct a new coal unit, this proposed rule would result in some costs in order to build a
unit with partial CCS. However, there would also be climate and other benefits resulting from
reductions in C02, S02, and NOX emissions.88 For each coal-fired generation type, SCPC and
IGCC, the EPA analyzed the cost and 2020 emission impacts for the proposed emission limit
using partial capture, plus a more stringent full capture scenario. Consistent with the LCOE
estimates provided earlier in this chapter, the partial capture CCS scenarios achieve the
proposed emissions rate of 1,100 Ib C02/MWh gross output. The full capture CCS scenarios
achieve an emissions rate of 200 Ib C02/MWh and 150 Ib C02/MWh for SCPC and IGCC,
respectively. Tables 5-15 and 5-16 show the costs and 2020 net benefits per MWh of each of
these scenarios relative to a no capture scenario.
In the near term, any new coal-fired ECU with CCS would most likely be located in areas
amenable to using the captured C02 in EOR operations. This is because EOR provides a revenue
88 When comparing the private costs of different technologies, we account for the CUA in the investor decision
making, but when we compare the difference in the social costs of these technologies (i.e., the private cost plus
the cost associated with their emissions) the CUA is not included.
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stream that is not available for other forms of geologic storage. For example, the Texas Clean
Energy project89 is planning to capture 90% of the C02 and sell it for EOR. To evaluate the
potential revenues from EOR we estimate the revenue in each scenario if C02 could be sold for
$20 to $40/ton based on assumptions used by NETL in evaluating the EOR opportunities.90
Table 5-15. Illustrative Costs and 2020 Social Benefits for SCPC with Partial Capture and Full
Capture CCS Relative to SCPC without CCS (per MWh 2011$)
Additional LCOEofCCS3
Revenue from EOR (Low - High EOR)
Additional LCOE, net of EOR
Value of Monetized Benefits for 2020 Emissions
Partial CCS
$29
$14 to $22
$15 to $7
Full CCS
$66
$32 to $54
$34 to $12
SCC 5% with Krewski 3% to SCC 3% (95th) with Lepeule 3%b $7.9 to $45 $22 to $120
Net Monetized Benefits for 2020 Emissions
Without EOR Revenue -$21 to $16 -$44 to $59
With EOR Revenue -$7.1 to $38 -$12 to $110
3 LCOE of SCPC without CCS does not include 3% CUA.
b Benefits are estimated for a 2020 analysis year. Values shown are calculated using different discount rates. Four
estimates of the SCC in the year 2020 were used: $13, $46, and $69 per metric ton (average SCC at discount rates of
5, 3, and 2.5 percent, respectively) and $138 per metric ton (95th percentile SCC at 3 percent). The average SCC at 5
percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate.
See RIA 5.7.1 for complete discussion about these estimates.
Table 5-16. Illustrative Costs and 2020 Social Benefits for IGCC with Partial Capture and Full
Capture CCS Relative to IGCC without CCS (per MWh 2011$)
Additional LCOEofCCS3
Revenue from EOR (Low - High EOR)
Additional LCOE, net of EOR
Value of Monetized Benefits for 2020 Emissions
Partial CCS
$12
$8 to $12
$4 to $0
Full CCS
$39
$27 to $45
$12 to -$6
SCC 5% with Krewski 3% to SCC 3% (95th) with Lepeule 3%b $2 to $22 $8.3 to $94
Net Monetized Benefits for 2020 Emissions
Without EOR Revenue -$10 to $11 -$31 to $55
With EOR Revenue -$2 to $23 -$3.7 to $100
a LCOE of IGCC without CCS does not include 3% CUA.
b Benefits are estimated for a 2020 analysis year. Values shown are calculated using different discount rates. Four
estimates of the SCC in the year 2020 were used: $13, $46, and $69 per metric ton (average SCC at discount rates of
5, 3, and 2.5 percent, respectively) and $138 per metric ton (95th percentile SCC at 3 percent). The average SCC at 5
percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate.
See RIA 5.7.1 for complete discussion about these estimates.
http://www.texascleanenergyproiect.com/
90 http://www.netl.doe.gov/energy-analvses/pubs/storing%20co2%20w%20eor final.pdf
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The EPA estimated the benefits associated with avoided C02, S02, and NOX emissions
using the methods described previously in this chapter. Similarly, the cost estimates EPA used
are described previously in this chapter. As before, it is important to note that these
comparisons omit additional benefits that may be associated with the abatement of
greenhouse gas emissions.
5.11 Impact of the Proposed Rule on Option Costs
Consistent with EPA's practice in evaluating the benefits and costs of significant rules,
Section 5.5 of this chapter uses detailed electricity sector modeling of expected market
conditions, along with alternative scenario analysis, to demonstrate, that under a broad range
of conditions, new EGUs expected to be built in the period of analysis would be in compliance
with this proposed rule, even in the absence of this rule. As a result, the quantifiable benefits
and costs of the proposed ECU New Source GHG Standards are zero in the analysis period. This
analysis is extended in Sections 5.9 through 5.10 to acknowledge unexpected conditions that
could occur during the period of analysis in which the construction of a new coal unit without
CCS 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 proposed rule
instead. This section further extends, and draws on, those analyses to discuss, qualitatively,
how EPA views the potential social benefits and costs of the proposed ECU New Source GHG
Standards.
When there is uncertainty about future conditions that could impact an investment
decision, investors place a value on retaining the ability to choose from a range of different
investments. This is referred to as "option value." Any cost of this proposed rule is the
investor's loss of the option value associated with the ability to build new coal units without
CCS. In the future, as uncertainty in market conditions is resolved investors will respond to
expected electricity demand based on the available choice set, taking as given other market and
regulatory constraints. The cost that society incurs when the choices available to the investors
are restricted is represented by the least cost option value associated with the choices that are
eliminated (Dixit and Pindyck, 1994; Trigeorgis, 1996). This option value is determined by the
likelihood that the restricted choices would be exercised absent the policy, the social cost of
substitutes, and the value of being able to adjust diversity of fuels that can be used by the
generating fleet.91 If it is highly unlikely that the restricted choices would be exercised in the
91 The option value associated with constructing new coal-fired capacity without partial CCS as part of a portfolio
that hedges against uncertainty in future fuel prices will be conditional upon the current composition of the
fleet. If the current stock was constructed in expectation of relative fuel prices that more strongly favored
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absence of the policy, or substitutes are available at a minimal incremental cost, then the
option value will be negligible, and therefore so to will be the social cost of the restriction.
In the case of this proposal, the choice set for firms that generate and sell electricity is
not being significantly restricted. The proposal eliminates the option to construct new
uncontrolled coal units, for which there are other generating substitutes, including renewables,
natural gas, and coal with CCS.92 The value of this option is conditional upon the likelihood that
it would be exercised during the analysis period and the cost of available substitutes. As
discussed in Section 5.9 it is highly unlikely that over the analysis period there will be enough
expansion in relative fuel prices (i.e. natural gas prices relative to coal) to make new coal-fired
EGUs cost competitive. Therefore, the option value, from the perspective of society, associated
with allowing investors to construct a new coal fired ECU is currently expected to be minimal.
As a result, any impact this proposal may have on the option value will be minimal as well.
If current conditions were significantly different and there existed a higher probability
that the option to build a new coal-fired unit without SCC might be exercised during the
analysis period, the impact on the option value will be primarily driven by the incremental cost
of increasing utilization at existing units, investing in cost-saving energy efficiency or
constructing a new unit with a substitute fuel (e.g., renewables, natural gas, etc.). Because
investors retain the ability to construct coal with CCS, the effect on the option value will be
equal to the incremental cost of CCS.93 Additionally, this is based not on the cost of CCS today,
but the expected cost of CCS in the future. If market conditions were to deviate significantly
from expectations such that the likelihood of investors constructing new coal units with CCS
increased, so would research and development spending on the technology, thereby driving
down its expected costs.
It is difficult to precisely estimate the option cost of this proposed rule given the
numerous sources of uncertainty that influence investment decisions in the electricity sector
and existing modeling tools. However, the analysis reported in this chapter has considered
important variables that influence investment decisions in the electricity sector and found that
across a wide range of potential outcomes this rule would have no quantifiable costs.
Furthermore, considering the additional analysis in sections 5.9 and 5.10 and the discussion
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.
92 By definition the option value associated with coal without partial CCS will be less than the option value
associated with the ability to construct and operate any type of new coal fired unit..
icluding any additional costs associated with differences in electricity transmission, coal delivery, etc.
associated with a coal unit with CCS being constructed in lieu of the construction of a non-compliant unit.
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above, the option cost of the rule is concluded to be small and bounded by the cost of CCS.
Additionally, if conditions arise that would have lead to the construction of coal-fired units
without CCS absent the proposed rule, the quantifiable social benefits of limiting the
construction of those units likely exceed the cost. However, as discussed throughout this RIA,
when considering the most likely outcomes, the proposed rule is anticipated to yield no
monetized benefits and impose negligible costs over the analysis period.
5.12 Summary of Costs, Benefits, and Energy Impacts
Under a wide range of electricity market conditions - including EPA's baseline scenario
as well as multiple sensitivity analyses - EPA projects that the industry will choose to construct
new units that already meet these standards, regardless of this proposal. As a result, EPA
anticipates that the proposed ECU New Source GHG Standards will result in negligible C02
emission changes, energy impacts, benefits or costs for new units constructed by 2020.
Likewise, the Agency does not anticipate any notable impacts on the price of electricity or
energy supplies. Additionally, for the reasons described above, the proposed rule is not
expected to raise any reliability concerns, since reserve margins will not be impacted and the
rule does not impose any requirements on existing facilities.
5.13 Macroeconomic and Employment Impacts
These proposed ECU New Source GHG Standards is not anticipated to change GHG
emissions for newly constructed electric generating units, and is anticipated to impose
negligible costs or monetized benefits. EPA typically presents the economic impacts to
secondary markets (e.g., changes in industrial markets resulting from changes in electricity
prices) and impacts to employment or labor markets associated with proposed rules based on
the estimated compliance costs and other energy impacts, which serve as an input to such
analyses. However, since the EPA does not forecast a change in behavior relative to the
baseline in response to this proposed rule, there are no notable macroeconomic or
employment impacts expected as a result of this proposed rule.
5.14 References
Dixit, Avinash and Pindyck, Robert. Investment Under Uncertainty. 1994. Princeton University
Press.
Fann, N., K.R. Baker, C.M. Fulcher. 2012. Characterizing the PM2.5-related health benefits of
emission reductions for 17 industrial, area and mobile emission sectors across the U.S.
Environment International, Volume 49, 15 November 2012, Pages 141-151, ISSN 0160-
4120, http://dx.doi.0rg/10.1016/i.envint.2012.08.017.
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Joskow, P.L. 2010. Comparing the Cost of Intermittent and Dispatchable Electricity Generating
Technologies. MIT Center for Energy and Environmental Policy Research Working Paper
10-013.
P.L. Joskow. 2011. Comparing the Costs of Intermittent and Dispatchable Electricity Generating
Technologies. American Economic Review, vol. 101:238-41.
Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz,
and W.H. White. 2009. "Reanalysis of the Harvard Six Cities Study and the American
Cancer Society Study of Particulate Air Pollution and Mortality." Special Report to the
Health Effects Institute. Cambridge, MA. July.
Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. "Chronic Exposure to Fine Particles and
Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009."
Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.
Malik, N.S. 2010, November 1. NextEra CEO sees clean energy standards replacing recent
climate proposals [Radio transcript]. Dow Jones News [Online]. Available: Dow Jones
Interactive Directory: Publications Library.
Mufson, S. 2011, January 2. Coal's burnout. The Washington Post. Retrieved from
http://www.washingtonpost.com/newssearch.
Muller, N.Z., R. Mendelsohn, and W. Nordhaus. 2011. Environmental Accounting for Pollution in
the United States Economy. American Economic Review. 101:1649-1675.
National Energy Technology Laboratory (NETL). Cost and Performance of PC and IGCC Plants for
a Range of Carbon Dioxide Capture. Revised Sept. 16, 2013. Available online at:
http://www.netl.doe.gov/energv-analyses/pubs/Gerdes-08022011.pdf.
Rosenberg, M. 2011, September/October. "The Reign of Cheap Gas." EnergyBiz Magazine.
Retrieved from http://www.energybiz.com/magazine/article/234577/reign-cheap-gas.
Tong, S. 2010, November 1. Placing Bets on Clean Energy. [Radio transcript]. American Public
Media: Marketplace [Online]. Available: Marketplace Programs on Demand.
National Petroleum Council. 2011. Prudent Development: Realizing the Potential of North
America's Abundant Natural Gas and Oil Resources. Available online at:
http://www.npc.org/reports/rd.html.
National Research of Council (NRC). 2009. Hidden Costs of Energy: Unpriced Consequences of
Energy Production and Use. National Academies Press: Washington, D.C.
Trigeorgis, Lenos. Real Options: Managerial Flexibility and Strategy in Resource Allocation.
1996. The MIT Press.
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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). 2008. Integrated Science Assessment for
Oxides of Nitrogen and Sulfur-Ecological Criteria National (Final Report). National
Center for Environmental Assessment, Research Triangle Park, NC. EPA/600/R-08/139.
December. Available on the Internet at
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485.
U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for
Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for
Environmental Assessment - RTP Division. December. Available on the Internet at
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.
U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis for the Final
Mercury and Air Toxics Standards. Office of Air Quality Planning and Standards,
Research Triangle Park, NC. December. Available on the Internet at
http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the
Final Revisions to the National Ambient Air Quality Standards for Particulate Matter.
Office of Air Quality Planning and Standards, Research Triangle Park, NC. December.
Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2013a. Technical Support Document
Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of
Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on
the Internet at:
http://www.epa.gov/airquality/benmap/models/Source Apportionment BPT TSD 1 3
1 13.pdf.
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 6
STATUTORY AND EXECUTIVE ORDER ANALYSES
6.1 Synopsis
This chapter presents discussion and analyses relating to Executive Orders and statutory
requirements relevant to the proposed ECU New Source GHG Standards. We discuss analyses
conducted to meet the requirements of Executive Orders 12866 and 13563, as well as potential
impacts to affected small entities required by the Regulatory Flexibility Act (RFA), as amended
by the Small Business Regulatory Enforcement Fairness Act (SBREFA). We also discuss the
requirements of the Unfunded Mandates Reform Act of 1995 (UMRA) and assess the impact of
the proposed rule on state, local and tribal governments and the private sector, along with the
analysis conducted to comply with the Paperwork Reduction Act (PRA). In addition, we address
the requirements of Executive Order (EO) 13045: Protection of Children from Environmental
Health and Safety Risks; EO 13132: Federalism; EO 13175: Consultation and Coordination with
Indian Tribal Governments; EO 12898: Federal Actions to Address Environmental Justice in
Minority Populations and Low-Income Populations; EO 13211: Actions that Significantly Affect
Energy Supply, Distribution, or Use; and the National Technology Transfer and Advancement
Act (NTTAA).
6.2 Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563,
Improving Regulation and Regulatory Review
Under EO 12866 (58 FR 51,735, October 4, 1993), this action is a "significant regulatory
action" because it "raises novel legal or policy issues arising out of legal mandates."
Accordingly, the EPA submitted this action to the Office of Management and Budget (OMB) for
review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any
changes made in response to OMB recommendations have been documented in the docket for
this action.
In addition, the EPA prepared an analysis of the potential costs and benefits associated
with this action. This analysis is contained in this RIA. Based on the analysis presented in
Chapter 5, the EPA believes this rule will have negligible compliance costs associated with it,
over a range of likely sensitivity conditions, because electric power companies would choose to
build new EGUs that comply with the regulatory requirements of this proposal even in the
absence of the proposal given existing and expected market conditions. The EPA does not
project any new coal-fired EGUs without CCS to be built in the absence of this proposal.
However, because some companies may choose to construct coal or other solid fossil fuel-fired
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units, this RIA also analyzes project-level costs of a unit with and without CCS, to quantify the
potential cost for a solid fossil fuel-fired unit with CCS and estimate the social benefits of
requiring CCS on a new uncontrolled unit.
6.3 Paperwork Reduction Act
The information collection requirements in this proposed rule have been submitted for
approval to the Office of Management and Budget under the Paperwork Reduction Act, 44
U.S.C. 3501 et seq. The information collection requirements are not enforceable until OMB
approves them. The Information Collection Request (ICR) document prepared by the EPA has
been assigned EPA ICR tracking number 2465.02 and OMB control number 2060-0685.
This proposed action will impose minimal new information collection burden on
affected sources beyond what those sources are already subject to under the authorities of CAA
parts 75 and 98. OMB has previously approved the information collection requirements
contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under
the provisions of the PRA, 44 U.S.C. 3501etsecj. and has assigned OMB control numbers 2060-
0626 and 2060-0629, respectively. Apart from certain reporting costs based on requirements in
the NSPS General Provisions (40 CFR part 60, subpart A), which are mandatory for all
owners/operators subject to CAA section 111 national emission standards, there are no new
information collection costs, as the information required by this proposed rule is already
collected and reported by other regulatory programs. The recordkeeping and reporting
requirements are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information
submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR
part 2, subpart B.
The EPA believes that electric power companies will choose to build new EGUs that
comply with the regulatory requirements of this proposal because of existing and expected
market conditions. The EPA does not project any new coal-fired EGUs that commence
construction after this proposal to commence operation over the 3-year period covered by this
ICR. We estimate that 17 new affected NGCC units will commence operation during that time
period. As a result of this proposal, those units will be required to prepare a summary report,
which includes reporting of emissions and downtime every 3 months.
When a malfunction occurs, sources must report them according to the applicable
reporting requirements of 40 CFR part 60, subparts Da and KKKK or subpart TTTT 60.5530. An
affirmative defense to civil penalties for exceedances of emission limits that are caused by
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malfunctions is available to a source if it can demonstrate that certain criteria and requirements
are satisfied. The criteria ensure that the affirmative defense is available only where the event
that causes an exceedance of the emission limit meets the narrow definition of malfunction1
and where the source took necessary actions to minimize emissions. In addition, the source
must meet certain notification and reporting requirements. For example, the source must
prepare a written root cause analysis and submit a written report to the Administrator
documenting that it has met the conditions and requirements for assertion of the affirmative
defense.
To provide the public with an estimate of the relative magnitude of the burden
associated with an assertion of affirmative defense, the EPA has estimated what the
notification, record keeping, and reporting requirements associated with the assertion of the
affirmative defense might entail. The EPA's estimate for the required notification, reports, and
records, including the root cause analysis, associated with a single incident totals approximately
$3,141, and is based on the time and effort required of a source to review relevant data,
interview plant employees, and document the events surrounding a malfunction that has
caused an exceedance of an emission limit. The estimate also includes time to produce and
retain the record and reports for submission to the EPA. The EPA provides this illustrative
estimate of this burden, because these costs are only incurred if there has been a violation, and
a source chooses to take advantage of the affirmative defense.
Given the variety of circumstances under which malfunctions could occur, as well as
differences among sources' operation and maintenance practices, we cannot reliably predict
the severity and frequency of malfunction-related excess emissions events for a particular
source. It is important to note that the EPA has no basis currently for estimating the number of
malfunctions that would qualify for an affirmative defense. Current historical records would be
an inappropriate basis, as this rule applies only to sources built in the future. Of the number of
excess emissions events that may be reported by source operators, only a small number would
be expected to result from a malfunction, and only a subset of excess emissions caused by
malfunctions would result in the source choosing to assert an affirmative defense. Thus, we
believe the number of instances in which source operators might be expected to avail
themselves of the affirmative defense will be extremely small. In fact, we estimate that there
will be no such occurrences for any new sources subject to 40 CFR part 60, subpart Da or KKKK
1 Malfunction means any sudden, infrequent, and not reasonably preventable failure of air pollution control and
monitoring equipment, process equipment, or a process to operate in a normal or usual manner which causes,
or has the potential to cause, the emission limitations in an applicable standard to be exceeded. Failures that
are caused in part by poor maintenance or careless operation are not malfunctions.
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over the 3-year period covered by this ICR. We expect to gather information on such events in
the future, and will revise this estimate as better information becomes available.
The annual information collection burden for this collection consists only of reporting
burden as explained above. The reporting burden for this collection (averaged over the first 3
years after the effective date of the standards) is estimated to be $15,570 and 396 labor hours.
This estimate includes quarterly summary reports which include reporting of emissions and
downtime. All burden estimates are in 2010 dollars, consistent with the information collection
request. Average burden hours per response are estimated to be 8 hours. The total number of
respondents over the 3-year ICR period is estimated to be 36. Burden is defined at 5 CFR
1320.3(b).
An agency may not conduct or sponsor, and a person is not required to respond to, a
collection of information unless it displays a currently valid OMB control number. The OMB
control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9.
To comment on the Agency's need for this information, the accuracy of the provided
burden estimates, and any suggested methods for minimizing respondent burden, the EPA has
established a public docket for this rule, which includes this ICR, under Docket ID number EPA-
HQ-OAR-2013-0495. Submit any comments related to the ICR to the EPA and OMB. See
ADDRESSES section at the beginning of this notice for where to submit comments to the EPA.
Send comments to OMB at the Office of Information and Regulatory Affairs, Office of
Management and Budget, 725 17th Street, NW, Washington, DC 20503, Attention: Desk Officer
for EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days
after publication in the Federal Register, a comment to OMB is best assured of having its full
effect if OMB receives it by 30 days after publication in the federal register. The final rule will
respond to any OMB or public comments on the information collection requirements contained
in this proposal.
6.4 Regulatory Flexibility Act
The RFA generally requires an agency to prepare a regulatory flexibility analysis of any
rule subject to notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities. Small entities include
small businesses, small organizations, and small governmental jurisdictions.
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For purposes of assessing the impacts of this rule on small entities, small entity is
defined as:
(1) A small business that is defined by the Small Business Administration's regulations at
13 CFR 121.201 (for the electric power generation industry, the small business size standard is
an ultimate parent entity defined as having a total electric output of 4 million MWh or less in
the previous fiscal year. The NAICS codes for the affected industry are in Table 6-1 below);
(2) A small governmental jurisdiction that is a government of a city, county, town, school
district, or special district with a population of less than 50,000; and
(3) A small organization that is any not-for-profit enterprise which is independently
owned and operated and is not dominant in its field.
Table 6-1. Potentially Regulated Categories and Entities3
Category NAICS Code Examples of Potentially Regulated Entities
Industry 221112 Fossil fuel electric power generating units.
State/Local b
221112 Fossil fuel electric power generating units owned by municipalities.
Government
a Include NAICS categories for source categories that own and operate electric power generating units (includes boilers and
stationary combined cycle combustion turbines).
State or local government-owned and operated establishments are classified according to the activity in which they are
engaged.
After considering the economic impacts of this proposed rule on small entities, the
Administrator of EPA certifies that this action will not have a significant economic impact on a
substantial number of small entities.
We do not include an analysis of the illustrative impacts on small entities that may result
from implementation of this proposed rule by states because we anticipate negligible
compliance costs over a range of likely scenarios as a result of this proposal. Thus the cost-to-
sales ratios for any affected small entity would be zero costs as compared to annual sales
revenue for the entity. The EPA believes that electric power companies will choose to build new
EGUs that comply with the regulatory requirements of this proposed rule because of existing
and expected market conditions. (See the Chapter 5 for further discussion of sensitivities.) The
EPA does not project any new coal-fired EGUs without CCS to be built. Accordingly, there are no
anticipated economic impacts as a result of this proposed rule.
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Nevertheless, the EPA is aware that there is substantial interest in this rule among small
entities (municipal and rural electric cooperatives). In light of this interest, prior to the April 13,
2012 proposal (77 FR 22392), the EPA determined to seek early input from representatives of
small entities while formulating the provisions of this proposed regulation. Such outreach is
also consistent with the President's January 18, 2011 Memorandum on Regulatory Flexibility,
Small Business, and Job Creation, which emphasizes the important role small businesses play in
the American economy. This process enabled the EPA to hear directly from these
representatives, at a very preliminary stage, about how it should approach the complex
question of how to apply Section 111 of the CAA to the regulation of GHGs from these source
categories. The EPA's outreach regarded planned actions for new and existing sources, but only
new sources will be affected by this proposed action.
The EPA conducted an initial outreach meeting with small entity representatives on
April 6, 2011. The purpose of the meeting was to provide an overview of recent EPA proposals
impacting the power sector. Specifically, overviews of the Transport Rule, the Mercury and Air
Toxics Standards, and the Clean Water Act 316(b) Rule proposals were presented.
The EPA conducted outreach with representatives from 20 various small entities that
potentially would be affected by this rule. The representatives included small entity
municipalities, cooperatives, and private investors. We distributed outreach materials to the
small entity representatives; these materials included background, an overview of affected
sources and GHG emissions from the power sector, an overview of CAA section 111, an
assessment of C02 emissions control technologies, potential impacts on small entities, and a
summary of the listening sessions. We met with eight of the small entity representatives, as
well as three participants from organizations representing power producers, on June 17, 2011,
to discuss the outreach materials, potential requirements of the rule, and regulatory areas
where the EPA has discretion and could potentially provide flexibility.
A second outreach meeting was conducted on July 13, 2011. We met with nine of the
small entity representatives, as well as three participants from organizations representing
power producers. During the second outreach meeting, various small entity representatives
and participants from organizations representing power producers presented information
regarding issues of concern with respect to development of standards for GHG emissions.
Specifically, topics suggested by the small entity representatives and discussed included: boilers
with limited opportunities for efficiency improvements due to New Source Review (NSR)
complications for conventional pollutants; variances per kilowatt-hour and in heat rates over
monthly and annual operations; significance of plant age; legal issues; importance of future
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determination of carbon neutrality of biomass; and differences between municipal government
electric utilities and other utilities.
While formulating the provisions of this proposed regulation, the EPA also considered
the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule
(77 FR 22392). We invite comments on all aspects of the proposal and its impacts, including
potential adverse impacts, on small entities.
6.5 Unfunded Mandates Reform Act (UMRA)
This proposed rule does not contain a Federal mandate that may result in expenditures
of $100 million or more for State, local, or tribal governments, in the aggregate, or the private
sector in any one year. The EPA believes this proposed rule will have negligible compliance
costs associated with it over a range of likely sensitivity conditions because electric power
companies will choose to build new EGUs that comply with the regulatory requirements of this
proposed rule because of existing and expected market conditions. (See Chapter 5 for further
discussion of sensitivities.) The EPA does not project any new coal-fired EGUs without CCS to be
built. Thus, this proposed rule is not subject to the requirements of sections 202 or 205 of
UMRA.
This proposed rule is also not subject to the requirements of section 203 of UMRA
because it contains no regulatory requirements that might significantly or uniquely affect small
governments.
In light of the interest in this rule among governmental entities, the EPA initiated
consultations with governmental entities while formulating the provisions of the proposed
regulation (77 FR 22392, April 13, 2012). The EPA invited the following 10 national
organizations representing state and local elected officials to a meeting held on April 12, 2011,
in Washington DC: 1) National Governors Association; 2) National Conference of State
Legislatures, 3) Council of State Governments, 4) National League of Cities, 5) U.S. Conference
of Mayors, 6) National Association of Counties, 7) International City/County Management
Association, 8) National Association of Towns and Townships, 9) County Executives of America,
and 10) Environmental Council of States. These 10 organizations representing elected state and
local officials have been identified by the EPA as the "Big 10" organizations appropriate to
contact for purposes of consultation with elected officials. The purposes of the consultation
were to provide general background on the proposal, answer questions, and solicit input from
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state/local governments. The EPA's consultation regarded planned actions for new and existing
sources, but only new sources will be affected by this proposed action.
During the meeting, officials asked clarifying questions regarding CAA section 111
requirements and efficiency improvements that would reduce C02 emissions. In addition, they
expressed concern with regard to the potential burden associated with impacts on state and
local entities that own/operate affected utility boilers, as well as on state and local entities with
regard to implementing the rule. Subsequent to the April 12, 2011 meeting, the EPA received a
letter from the National Conference of State Legislatures. In that letter, the National
Conference of State Legislatures urged the EPA to ensure that the choice of regulatory options
maximizes benefit and minimizes implementation and compliance costs on state and local
governments; to pay particular attention to options that would provide states with as much
flexibility as possible; and to take into consideration the constraints of the state legislative
calendars and ensure that sufficient time is allowed for state actions necessary to come into
compliance.
While formulating the provisions of this proposed regulation, the EPA also considered
the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule
(77 FR 22392).
6.6 Executive Order 13132, Federalism
This proposed action does not have federalism implications. It will not have substantial
direct effects on the States, on the relationship between the national government and the
States, or on the distribution of power and responsibilities among the various levels of
government, as specified in EO 13132. This action will not impose substantial direct compliance
costs on state or local governments nor will it preempt state law. Thus, Executive Order 13132
does not apply to this action. Prior to the April 13, 2012 proposal (77 FR 22392), the EPA
consulted with state and local officials in the process of developing the proposed rule to permit
them to have meaningful and timely input into its development. The EPA's consultation
regarded planned actions for new and existing sources, but only new sources will be affected by
this action. The UMRA discussion in this chapter includes a description of the consultation. The
EPA met with 10 national organizations representing state and local elected officials to provide
general background on the proposal, answer questions, and solicit input from state/local
governments. The UMRA discussion in the preamble includes a description of the consultation.
While formulating the provisions of this proposed regulation, the EPA also considered the input
provided in the over 2.5 million public comments on the April 13, 2012 proposed rule (77 FR
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22392). In the spirit of EO 13132, and consistent with EPA policy to promote communications
between the EPA and state and local governments, the EPA specifically solicits comment on this
proposed action from state and local officials.
6.7 Executive Order 13175, Consultation and Coordination with Indian Tribal
Governments
This action does not have tribal implications, as specified in Executive Order 13175 (65
FR 67249, November 9, 2000). It would neither impose substantial direct compliance costs on
tribal governments, nor preempt Tribal law. This proposed rule would impose requirements on
owners and operators of new EGUs. The EPA is aware of three coal-fired EGUs located in Indian
Country but is not aware of any EGUs owned or operated by tribal entities. The EPA notes that
this proposal does not affect existing sources such as the three coal-fired EGUs located in Indian
Country, but addresses C02 emissions for new ECU sources only. Thus, Executive Order 13175
does not apply to this action.
Although Executive Order 13175 does not apply to this action, EPA consulted with tribal
officials in developing this action. Because the EPA is aware of Tribal interest in this proposed
rule, prior to the April 13, 2012 proposal (77 FR 22392), the EPA offered consultation with tribal
officials early in the process of developing the proposed regulation to permit them to have
meaningful and timely input into its development. The EPA's consultation regarded planned
actions for new and existing sources, but only new sources would be affected by this proposed
action.
Consultation letters were sent to 584 tribal leaders. The letters provided information
regarding the EPA's development of NSPS and emission guidelines for EGUs and offered
consultation. A consultation/outreach meeting was held on May 23, 2011, with the Forest
County Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa Reservation,
and the Leech Lake Band of Ojibwe. Other tribes participated in the call for information
gathering purposes. In this meeting, the EPA provided background information on the GHG
emission standards to be developed and a summary of issues being explored by the agency.
Tribes suggested that the EPA consider expanding coverage of the GHG standards to include
combustion turbines, lowering the 250 MMBtu per hour heat input threshold so as to capture
more EGUs, and including credit for use of renewables. The tribes were also interested in the
scope of the emissions averaging being considered by the agency (e.g., over what time period,
across what units) for a possible existing source standard. In addition, the EPA held a series of
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listening sessions on the proposed action. Tribes participated in a session on February 17, 2011
with the state agencies, as well as in a separate session with tribes on April 20, 2011.
While formulating the provisions of this proposed regulation, the EPA also considered
the input provided in the over 2.5 million public comments on the April 13, 2012 proposed rule
(77 FR 22392).
The EPA will also hold additional meetings with tribal environmental staff to inform
them of the content of this proposal, as well as provide additional consultation with tribal
elected officials where it is appropriate. We specifically solicit additional comment on this
proposed rule from tribal officials.
6.8 Executive Order 13045, Protection of Children from Environmental Health Risks and
Safety Risks
The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those
regulatory actions that concern health or safety risks, such that the analysis required under
section 5-501 of the Order has potential to influence the regulation. This action is not subject to
EO 13045 because it is based solely on technology performance.
6.9 Executive Order 13211, Actions Concerning Regulations That Significantly Affect
Energy Supply, Distribution, or Use
This proposed action is not a "significant energy action" as defined in Executive Order
13211 (66 FR 28355, May 22, 2001), because it is not likely to have a significant adverse effect
on the supply, distribution, or use of energy. This proposed action is anticipated to have
negligible impacts on emissions, costs or energy supply decisions for the affected electric utility
industry.
6.10 National Technology Transfer and Advancement Act
Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 15 U.S.C. 272 note) directs
the EPA to use Voluntary Census Standards (VCS) in their regulatory and procurement activities
unless to do so would be inconsistent with applicable law or otherwise impractical. VCS are
technical standards (e.g., materials specifications, test methods, sampling procedures, business
practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA
directs the EPA to provide Congress, through annual reports to the OMB, with explanations
when an agency does not use available and applicable VCS.
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This proposed rulemaking involves technical standards. The EPA proposes to use the
following standards in this proposed rule: D5287-08 (Standard Practice for Automatic Sampling
of Gaseous Fuels), D4057-06 (Standard Practice for Manual Sampling of Petroleum and
Petroleum Products), and D4177-95 (2010) (Standard Practice for Automatic Sampling of
Petroleum and Petroleum Products). The EPA is proposing use of Appendices B, D, F, and G to
40 CFR part 75; these Appendices contain standards that have already been reviewed under the
NTTAA.
The EPA welcomes comments on this aspect of the proposed rulemaking and,
specifically, invites the public to identify potentially-applicable VCS and to explain why such
standards should be used in this action.
6.11 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority
Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive
policy on environmental justice. Its main provision directs Federal agencies, to the greatest
extent practicable and permitted by law, to make environmental justice part of their mission by
identifying and addressing, as appropriate, disproportionately high and adverse human health
or environmental effects of their programs, policies, and activities on minority populations and
low-income populations in the U.S.
This proposed rule limits GHG emissions from new fossil fuel-fired EGUs by establishing
national emission standards for C02. The EPA has determined that this proposed rule will not
result in disproportionately high and adverse human health or environmental effects on
minority, low-income, and indigenous populations because it increases the level of
environmental protection for all affected populations without having any disproportionately
high and adverse human health or environmental effects on any population, including any
minority, low-income, or indigenous populations.
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United States Office of Air Quality Planning and Standards Publication No. EPA-452/R-13-003
Environmental Protection Health and Environmental Impacts Division September 2013
Agency Research Triangle Park, NC
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