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                                                               EPA-452/R-15-005
                                                                    August 2015





Regulatory Impact Analysis for the Final Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                     U.S. Environmental Protection Agency
                 Office of Air Quality Planning and Standards
                   Health and Environmental Impacts Division
                          Research Triangle Park, NC
                                       
                              CONTACT INFORMATION
      This document has been prepared by staff from the Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency. Questions related to this document should be addressed to Amanda Curry Brown, U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina 27711 (email: CurryBrown.Amanda@epa.gov). 

                               ACKNOWLEDGEMENTS
In addition to EPA staff from the Office of Air Quality Planning and Standards, personnel from the U.S. EPA Office of Atmospheric Programs and Office of Policy contributed data and analysis to this document.
 Acronyms
AEO			Annual Energy Outlook
ANSI			American National Standards Institute
ASTM			American Society for Testing and Materials
BPT			Benefit-per-Ton
BSER			Best System of Emissions Reduction
Btu			British Thermal Units
CAA			Clean Air Act
CAIR			Clean Air Interstate Rule
CCR			Coal Combustion Residuals
CCS			Carbon Capture and Sequestration or Carbon Capture and Storage
CESA			Clean Energy States Alliance
CFR			Code of Federal Regulations
CH4			Methane
CO2			Carbon Dioxide
CO2e			Carbon Dioxide Equivalent 
CRA			Congressional Review Act
CRF			Capital Recovery Factor
CSAPR			Cross-State Air Pollution Rule
CT			Combustion Turbines
CUA			Climate Uncertainty Adder
DOE			U.S. Department of Energy
EGU			Electric Generating Unit
EIA			U.S. Energy Information Administration
ELG			Effluent Limitation Guidelines
EMM			Electricity Market Module
EO			Executive Order
EOR			Enhanced Oil Recovery
EPA			U.S. Environmental Protection Agency
FERC			Federal Energy Regulatory Commission
FOM			Fixed Operating and Maintenance
FR			Federal Register
FRCC			Florida Reliability Coordinating Council
GDP			Gross Domestic Product
GHG			Greenhouse Gas
GS			Geologic Sequestration
GW			Gigawatt
GWh			Gigawatt-hours
IAM			Integrated Assessment Model
ICR			Information Collection Request
IGCC			Integrated Gasification Combined Cycle
IOU			Investor Owned Utility
IPCC			Intergovernmental Panel on Climate Change
IPM			Integrated Planning Model
IPP			Independent Power Producers
IRP			Integrated Resource Plan
IWG			Interagency Working Group
kWh			Kilowatt-hour
lb			Pound or Pounds
LCOE			Levelized Cost of Electricity
MATS			Mercury and Air Toxics Standards
MMBtu		Million British Thermal Units
MW			Megawatt
MWh			Megawatt-hour
N2O			Nitrous Oxide
NATCARB		National Carbon Sequestration Database and Geographic Information 				System
NCA3			Third National Climate Assessment
NEEDS			National Electric Energy Data System
NEMS			National Energy Modeling System
NERC			North American Electric Reliability Corporation
NETL			National Energy Technology Laboratory
NGCC			Natural Gas Combined Cycle
NOAK			Nth of a Kind
NODA			Notice of Data Availability
NOX			Nitrogen Oxide
NRC			National Research Council
NSPS			New Source Performance Standard
NTTAA			National Technology Transfer and Advancement Act
OMB			Office of Management and Budget
PM2.5			Fine Particulate Matter
PM NAAQS		National Ambient Air Quality Standards for Particulate Matter
PRA			Paperwork Reduction Act 
RES			Renewable Electricity Standards
RFA			Regulatory Flexibility Act
RGGI			Regional Greenhouse Gas Initiative
RIA			Regulatory Impact Analysis
RPS			Renewable Portfolio Standards
SC-CO2			Social Cost of Carbon
SCPC			Super Critical Pulverized Coal
SF6			Sulfur Hexafluoride
SIP			State Implementation Plan
SO2			Sulfur Dioxide
Tcf			Trillion Cubic Feet
TkWh			Trillion Kilowatt-Hours
TSD			Technical Support Document
TS&M			Transportation Storage and Monitoring
UMRA			Unfunded Mandates Reform Act
U.S.C.			U.S. Code
USGCRP		U.S. Global Change Research Program
USGS			U.S. Geological Survey
VOM			Variable Operating and Maintenance
Contents
Acronyms	iv
Executive Summary	ES-1
ES.1	Background and Context of Final Rule	ES-1
ES.2 	Summary of the Final Rule	ES-2
ES.3 	Key Findings of Economic Analysis	ES-3
Chapter 1 Introduction and Background	1-1
1.1	Introduction	1-1
1.1.1 	Legal Basis for this Rulemaking	1-1
1.1.2	Regulatory Analysis	1-3
1.2	Background for the Final EGU New, Modified, and Reconstructed Source GHG Standards	1-5
1.2.1	Baseline and Years of Analysis	1-5
1.2.2	Definition of Affected EGUs	1-6
1.2.3	Regulated Pollutant	1-7
1.2.4	Emission Limits	1-7
1.2.5	Emission Reductions	1-8
1.3	Organization of the Regulatory Impact Analysis	1-9
Chapter 2 Electric Power Sector Profile	2-1
2.1 	Introduction	2-1
2.2 	Power Sector Overview	2-1
2.2.1 	Generation	2-1
2.2.2 	Transmission	2-9
2.2.3 	Distribution	2-10
2.3 	Sales, Expenses, and Prices	2-10
2.3.1 Electricity Prices	2-11
2.3.2 Prices of Fossil Fuels Used for Generating Electricity	2-16
2.3.3 Changes in Electricity Intensity of the U.S. Economy Between 2002 to 2012	2-17
2.4 	Deregulation and Restructuring	2-19
2.5	Emissions of Greenhouse Gases from Electric Utilities	2-23
2.6 	Carbon Dioxide Control Technologies	2-26
2.6.1 	Carbon Capture and Storage	2-28
2.7 	Geologic and Geographic Considerations for Geologic Sequestration	2-32
2.7.2 	Availability of Geologic Sequestration in Deep Saline Formations	2-36
2.7.3	Availability of CO2 Storage via Enhanced Oil Recovery	2-36
2.8	State Policies on GHG and Clean Energy Regulation in the Power Sector	2-38
2.9 	Revenues and Expenses	2-40
2.10 	Natural Gas Market	2-41
2.11 	References	2-45
Chapter 3 Benefits of Reducing Greenhouse Gas Emissions and Other Pollutants	3-1
3.1	Overview of Climate Change Impacts from GHG Emissions	3-1
3.2	Social Cost of Carbon	3-2
3.3	Health Co-Benefits of SO2 and NOx Reductions	3-8
3.4	References	3-12
Chapter 4 Costs, Economic, and Energy Impacts of the New Source Standards	4-1
4.1	Synopsis	4-1
4.2	Requirements of the Final GHG EGU NSPS	4-2
4.3	Power Sector Modeling Framework	4-3
4.3.1	Modeling Overview	4-3
4.3.2	The Integrated Planning Model	4-4
4.4	Analyses of Future Generating Capacity	4-7
4.4.1	Base Case Power Sector Modeling Projections	4-7
4.4.2	Alternative Scenarios from AEO 2014	4-13
4.5	Levelized Cost of Electricity Analysis	4-20
4.5.1	Overview of the Concept of Levelized Cost of Electricity	4-20
4.5.2	Cost and Performance of Technologies	4-21
4.5.3	Levelized Cost of Electricity of New Generation Technologies	4-24
4.5.4	Levelized Cost of Electricity of NGCC and Non-compliant Coal	4-26
4.5.5	Levelized Cost of Simple Cycle Combustion Turbine and Natural Gas Combined Cycle	4-34
4.6	Macroeconomic and Employment Impacts	4-35
4.7	References	4-36
Chapter 5 Analysis of Illustrative Benefit-Cost Scenarios For New Sources	5-1
5.1	Synopsis	5-1
5.2	Comparison of Emissions from Generation Technologies	5-1
5.3	Comparison of Health and Climate Impacts from Generation Technologies	5-5
5.4	Illustrative Analysis  -  Benefits and Costs of New Source Standards across a Range of Gas Prices	5-11
5.4.1	Likely Natural Gas Prices	5-14
5.4.2	Unexpectedly High Natural Gas Prices	5-14
5.4.3	Unprecedented Natural Gas Prices	5-15
5.5	Illustrative Analysis  -  Benefits and Costs of Non-Compliant Coal and Compliant Coal	5-16
5.6	Impact of the New Source Standards Considering the Cost of Lost Option Value	5-23
5.7	References	5-25
Chapter 6 Modified and Reconstructed Source Impacts	6-1
6.1	Introduction	6-1
6.2	Reconstructed Sources	6-1
6.3	Modified Sources	6-1
Chapter 7 Statutory and Executive Order Reviews	7-1
7.1 	Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, Improving Regulation and Regulatory Review	7-1
7.2 	Paperwork Reduction Act (PRA)	7-1
7.2.1	Newly constructed EGUs	7-2
7.2.2	Modified and Reconstructed EGUs	7-3
7.2.3	Information Collection Burden	7-4
7.3 	Regulatory Flexibility Act (RFA)	7-4
7.3.1	Newly constructed EGUs	7-4
7.3.2 	Modified and Reconstructed EGUs	7-5
7.4 	Unfunded Mandates Reform Act (UMRA)	7-5
7.5 	Executive Order 13132, Federalism	7-6
7.6 	Executive Order 13175, Consultation and Coordination with Indian Tribal Governments	7-6
7.7 	Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks	7-8
7.8 	Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use	7-9
7.9 	National Technology Transfer and Advancement Act	7-9
7.10	Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations	7-9
7.11	Congressional Review Act (CRA)	7-12



                                       
             EO 12866_111(b) New-Mods 2060-AQ91 RIA Final_07312015
 
 Executive Summary
This Regulatory Impact Analysis (RIA) discusses potential benefits, costs, and economic impacts of the Final Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units (herein referred to as the EGU New, Modified, and Reconstructed Source GHG Standards).
ES.1	Background and Context of Final Rule
The final EGU New, Modified and Reconstructed Source GHG Standards will set emission limits for greenhouse gas emissions (GHG) from newly constructed, modified, and reconstructed fossil fuel-fired electricity generating units (EGUs). These limits will apply to carbon dioxide (CO2) emissions from any affected fossil fuel-fired EGU. The United States Environmental Protection Agency (EPA) is finalizing requirements for these sources because CO2 is an air pollutant under the Clean Air Act, section 111 (a) and (b) of the Act authorize the EPA to establish standards of performance for air pollutants emitted from source categories like the one here listed by the EPA because the source category causes, or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare.  Fossil fuel-fired power plants are the country's largest stationary source emitters of GHGs. As stated in the EPA's Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act (CAA) (74 FR 66518), and summarized in Chapter 3 of this RIA, the anthropogenic buildup of GHGs in the atmosphere is the cause of most of the observed global warming over the last 50 years.  
On June 25, 2013, in conjunction with the announcement of his Climate Action Plan, President Obama issued a Presidential Memorandum directing the EPA to issue a proposal to address carbon pollution from new power plants by September 30, 2013, and to issue "standards, regulations, or guidelines, as appropriate, which address carbon pollution from modified, reconstructed, and existing power plants." On September 20, 2013, pursuant to authority in CAA section 111(b), EPA Administrator Gina McCarthy signed proposed carbon pollution standards for newly constructed fossil fuel-fired power plants (79 FR 1430, January 8, 2014). 
The EPA subsequently issued a Notice of Data Availability (NODA), soliciting comment on its initial interpretation of provisions in the Energy Policy Act of 2005 and the Internal Revenue Code, and also soliciting comment on a Technical Support Document, which addressed these provisions' relationship to the factual record supporting the proposed rule (79 FR 10750, February 26, 2014).   
On June 2, 2014, Administrator McCarthy signed proposed standards of performance, also pursuant to CAA section 111(b), to limit emissions of CO2 from modified and reconstructed fossil fuel-fired electric utility steam generating units and stationary combustion turbines (79 FR 34959, June 18, 2014).
In this action, the EPA is finalizing standards of performance to limit emissions of CO2 from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units and stationary combustion turbines. Consistent with the requirements of CAA section 111(a) and (b), these standards reflect the degree of emission limitation achievable through the application of the best system of emission reduction (BSER) that the EPA has determined has been adequately demonstrated for each type of unit.
ES.2 	Summary of the Final Rule 
The EPA has determined that the BSER for newly constructed steam generating units is a supercritical pulverized coal (SCPC) unit using post-combustion partial carbon capture and storage (CCS) technology to meet an emission limitation of 1,400 lb CO2/MWh-gross. The standard for steam generating units that conduct modifications resulting in a potential hourly increase in CO2 emissions (mass per hour) of more than 10 percent is a unit-specific emission limitation consistent with each modified unit's best one-year historical performance during the years from 2002 to the time of the modification. For reconstructed steam generating units, the BSER is the most efficient demonstrated generating technology for these types of units (i.e., meeting a standard of performance consistent with a reconstructed boiler using most efficient steam conditions available, even if the boiler was not originally designed to do so). 
The BSER for primarily natural gas-fired stationary combustion turbines expected to serve intermediate and base load power demand is the use of well-designed, well-maintained, and well-operated natural gas combined cycle (NGCC) technology. These units will be required to meet an emission standard of 1,000 lb CO2/MWh-gross output (or 1,030 lb CO2/MWh of net energy output). For non-base load and multi-fuel-fired units, BSER is the use of clean fuels.
The BSER determination and final standards for each affected EGU are shown in Table ES-1. The applicability of these standards based on the capacity and operation of a source are described in the preamble for this final rule.  The final standards for all source categories will be met on a 12-operating month rolling average basis. 
ES.3 	Key Findings of Economic Analysis 
CAA Section 111(b) requires that the new source performance standards (NSPS) be reviewed every eight years.  As a result, this rulemaking's analysis is primarily focused on projected impacts within the current eight-year NSPS timeframe. As explained in detail in this document, energy market data and projections support the conclusion that, even in the absence of this rule, expected economic conditions will lead electricity generators to choose new generation technologies that meet the standards without the need for additional controls. 
The base case modeling the EPA performed for this rule and for other recent air rules projects that, even in the absence of this action, new fossil-fuel fired capacity constructed through 2022 and the years following will most likely be NGCC capacity that complies with the final standards. Analyses performed both by the EPA and the Energy Information Administration (EIA) project that new compliant natural gas-fired units and renewable sources are likely to be the technologies of choice for new generating capacity due to current and projected economic market conditions. 








Table ES-1. Summary of BSER and Final Standards for Affected EGUs
                                 Affected EGU
                                     BSER
                                   Standard
Newly Constructed Fossil Fuel-Fired Steam Generating Units
          Efficient new SCPC utility boiler implementing partial CCS
                            1,400 lb CO2/MWh-gross
Modified Fossil Fuel-Fired Steam Generating Units
Most efficient generation at the affected EGU achievable through a combination of best operating practices and equipment upgrades
Sources making modifications
resulting in an increase in CO2 hourly emissions of more than 10 percent are required to meet a unit-specific emission limit determined by the unit's best historical annual CO2 emission rate (from 2002 to the date of the modification); the emission limit will be no more stringent than:

1. 1,800 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h.
                                      OR
                                       
2. 2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Reconstructed Fossil Fuel-Fired Steam Generating Units
           Most efficient generating technology at the affected EGU.
1. 1,800 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h.
                                      OR
                                       
2. 2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Newly Constructed and Reconstructed Natural Gas-Fired Stationary Combustion Turbines
Efficient NGCC technology for natural gas-fired base load units and clean fuels for non-base load and multi-fuel-fired units.
   1.    1,000 lb CO2/MWh-gross or 1,030 lb CO2/MWh-net for base load natural gas-fired units. 
                         
   2.    120 lb CO2/MMBtu for non-base load natural gas-fired units.
   3.    120 to 160 lb CO2/MMBtu for multi-fuel-fired units.
Historically, the EPA has been notified of very few modifications (for criteria pollutants) or reconstructions under the NSPS provisions. As such, the EPA anticipates few covered units will trigger the reconstruction or modification provisions in the period of analysis. 
 Therefore, based on the analysis presented in Chapter 4 of this RIA, the EPA anticipates that the EGU New, Modified, and Reconstructed Source GHG Standards will result in negligible CO2 emission changes, energy impacts, quantified benefits, costs, and economic impacts by 2022. Accordingly, the EPA also does not anticipate this rule will have any significant impacts on the price of electricity, employment or labor markets, or the U.S. economy. 
Although the primary conclusion of the analysis presented in this RIA is that the standards for newly constructed EGUs will result in negligible costs and benefits, the EPA has also performed several illustrative analyses, in Chapter 5, that show the potential impacts of the rule if certain key assumptions were to change. This analysis finds that under conditions that deviate from current projections about natural gas prices, the monetized benefits of the standards to society likely outweigh the costs of the standards. The analysis also presents the costs and benefits that would occur in the unlikely case where assumptions about economic conditions do not change but an operator chooses to construct new coal-fired capacity. In that analysis, monetized benefits outweigh costs under a range of assumptions.
The final standards provide the benefit of regulatory certainty that any new coal-fired power plant must limit CO2 emissions to the level of the standard of performance: 1,400 lb CO2/MWh.  The final standards also reduce regulatory uncertainty by defining the requirements to limit emissions of CO2 from new, modified, and reconstructed fossil fuel-fired steam generating sources. 
In addition, the EPA intends this rule to send a clear signal about the current and future status of CCS technology.  Additional CCS applications are expected to lead to improvements in this technology's performance and consequent reductions in its cost. Identifying post-combustion partial CCS technology as the BSER for coal-fired power plants promotes further development and encourages continued research of CCS, [,]  which is important for long-term CO2 emission reductions.  
The final standards also provide regulatory certainty for stationary combustion turbines that, along with new renewable sources, are expected to be the primary technology options to provide new generating capacity in the analysis period. Any new stationary combustion turbines must be well-designed, well-maintained, and well-operated. 


 Chapter 1
Introduction and Background
1.1	Introduction
In this action, the U.S. Environmental Protection Agency (EPA) is adopting emission limits for greenhouse gases (GHGs), specifically carbon dioxide (CO2), emitted from fossil fuel-fired EGUs. This document presents the expected economic impacts of the Electricity Generating Unit (EGU) New, Modified, and Reconstructed Source GHG Standards rule through 2022, including some projections for years up to 2030. Based on the analysis presented in Chapter 4, the current forecast of economic conditions (e.g., price of natural gas) will lead electricity generators to choose fuels and technologies that will meet the final standards for new sources without the need for additional control, even in the absence of the rule. As a result, the final new source standards are expected to have no, or negligible, costs or quantified benefits associated with them. However, should forecast economic conditions change or operators choose to construct new coal-fired capacity, we project that emission reductions associated with the standard may result in monetized benefits exceeding the cost of control, and would also provide unquantified benefits. (See Chapter 5.)  The EPA has reached a similar conclusion for the final reconstruction and modification provisions.  Based on historical information that has been reported to the EPA, we anticipate few covered units will trigger the reconstruction or modification provisions in the period of analysis.  As a result, we anticipate negligible costs or benefits associated with those standards. This chapter contains background information on the rule and an outline of the chapters of the report.
1.1.1 	Legal Basis for this Rulemaking
Section 111 of the Clean Air Act (CAA) requires performance standards for air pollutant emissions from categories of stationary sources which are listed by the EPA because they may reasonably contribute to the endangerment of public health or welfare. In April 2007, the Supreme Court ruled in State of Massachusetts v. EPA that GHGs meet the definition of an "air pollutant" under the CAA. This ruling clarified that the authorities and requirements of the CAA apply to GHGs. As a result, the EPA is authorized to make decisions about whether to regulate GHGs under certain provisions of the CAA, based on relevant statutory criteria. Because CO2 is an air pollutant emitted from a source category the EPA has listed for purposes of section 111, the EPA may establish standards under section 111 (a) and (b) for CO2 for this source category.  In 2009, the EPA issued a final determination that emissions of certain specified GHGs endanger both the public health and the public welfare of current and future generations in the Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the CAA (74 FR 66,496; Dec. 15, 2009), and has explained in detail how emissions of CO2 from this source category cause or contribute significantly to air pollution that endangers health and welfare.  As described in Chapter 2, this source category contributes more CO2 than any other domestic stationary source. 
On June 25, 2013, in conjunction with the announcement of his Climate Action Plan, President Obama issued a Presidential Memorandum directing the EPA to issue a proposal to address carbon pollution from new power plants by September 30, 2013, and to issue "standards, regulations, or guidelines, as appropriate, which address carbon pollution from modified, reconstructed, and existing power plants." On September 20, 2013, pursuant to authority in CAA section 111(b), EPA Administrator Gina McCarthy signed proposed carbon pollution standards for newly constructed fossil fuel-fired power plants (79 FR 1430, January 8, 2014). 
The EPA subsequently issued a Notice of Data Availability (NODA), soliciting comment on its initial interpretation of provisions in the Energy Policy Act of 2005 and the Internal Revenue Code, and also soliciting comment on a Technical Support Document, which addressed these provisions' relationship to the factual record supporting the proposed rule (79 FR 10750, February 26, 2014). 
On June 2, 2014, Administrator McCarthy signed proposed standards of performance, also pursuant to CAA section 111(b), to limit emissions of CO2 from modified and reconstructed fossil fuel-fired electric utility steam generating units and stationary combustion turbines (79 FR 34959, June 18, 2014).
In this action, the EPA is finalizing standards of performance to limit emissions of CO2 from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units and stationary combustion turbines. Consistent with the requirements of CAA section 111(b), these standards reflect the degree of emission limitation achievable through the application of the best system of emission reduction (BSER) that the EPA has determined has been adequately demonstrated for each type of unit.
1.1.2	Regulatory Analysis 
In accordance with Executive Order (EO) 12866, EO 13563, and the EPA's Guidelines for Preparing Economic Analyses, the EPA prepared this Regulatory Impact Analysis (RIA) for this "significant regulatory action." This rule is not anticipated to have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or state, local, or tribal governments or communities and is therefore not an "economically significant rule." However, under EO 12866 (58 FR 51,735, October 4, 1993), this action is a "significant regulatory action" because it "raises novel legal or policy issues arising out of legal mandates." As a matter of policy, the EPA has attempted to provide a thorough analysis of the potential impacts of this rule, consistent with requirements of the Executive Orders.
This RIA addresses the potential costs and benefits of the new, modified, and reconstructed source emission limits that are the focus of this action. As described in Chapter 4, the EPA does not anticipate any costs or quantified benefits will result from the new source standards if utilities and project developers make the type of choices related to new generation sources that are forecast by the EPA's and EIA's models and that many publicly available utility integrated resource plans (IRPs) indicate  are likely.  However, if future economic conditions (e.g., natural gas prices) differ from these forecasts and utilities would have constructed new coal-fired units in the baseline, there could be some compliance costs. In these cases, the EPA's analysis shows that the rule will result in net benefits under a range of assumptions. 
For new sources the EPA and EIA, through their models, project that new fossil-fired electric utility steam generating units and natural gas-fired stationary combustion turbines that meet the applicability criteria would meet the respective standards under this rule in the baseline where no such standards are implemented. Some limited new coal-fired units with federally-supported carbon capture and storage (CCS) are included in the modeling, though these units are expected to be compliant with the applicable standards under this rule. Because this rule does not change these forecasts, it is expected to have no, or negligible, costs, or quantified benefits.
New non-compliant coal-fired units are not expected to be constructed in the baseline, due in part to the low cost of constructing and operating new NGCC units relative to the cost of new coal-fired units, relatively low forecast growth in electricity demand, and an expectation that the growth in end-use energy efficiency and renewable energy resources will continue. The expectation that no new non-compliant coal-fired units will be constructed in the baseline, and therefore that the promulgated standard of performance would not be a factor in decisions to construct, holds under a range of alternative baseline scenarios. 
Natural gas-fired combustion turbine units intended to serve as intermediate and base load generators constructed in the baseline are expected to be compliant with the standard, due in part to the cost-effectiveness of constructing and operating new combined cycle units relative to the cost of new simple cycle units. Absent significantly lower natural gas prices, the cost of electricity generated by combined cycle units operating at intermediate and base load capacity are lower than simple cycle units operating at the same capacity factor.
Chapter 5 complements and extends the sector level analysis by examining conditions (e.g., significantly higher natural gas prices) in which conclusions regarding the future economic competitiveness of new non-compliant coal-fired units relative to other new generation technologies may differ from those in the sector-wide analysis. The analysis evaluates the cost and benefits of adopting different competing generating technologies to serve base load demand at an individual facility level. When considering a wide range of natural gas price assumptions, along with information on historical and projected gas prices, this illustrative facility-level analysis supports the conclusion that these final standards are highly likely to incur no costs or quantified benefits. Furthermore, the analysis examines the costs and benefits that would occur in the unlikely case where an investor might choose to construct new coal-fired capacity, and shows that the result is a net monetized benefit under a range of assumptions.   
As described in Chapter 6, the EPA has reached a similar conclusion for the reconstruction and modification provisions for both steam generating units and stationary combustion turbines.  The EPA has historically been notified of few modifications or reconstructions under the NSPS provisions and, as such, anticipates few covered units will trigger the NSPS reconstruction or modification provisions in the period of analysis. As a result, we do not anticipate any significant costs or benefits associated with this rule. 
1.2	Background for the Final EGU New, Modified, and Reconstructed Source GHG Standards
1.2.1	Baseline and Years of Analysis
The standards on which this analysis is based set GHG emission limits for new, modified, and reconstructed fossil fuel-fired EGUs. The baseline for this analysis, which uses the Integrated Planning Model (IPM), includes state rules that have been finalized and/or approved by a state's legislature or environmental agency as well as final federal rules. Additional legally binding and enforceable commitments for GHG reductions considered in the baseline are discussed in Chapter 4 of this RIA. 
All analyses are presented for compliance through the year 2022 and all estimates are presented in 2011 dollars. CAA Section 111(b) requires that the NSPS be reviewed every eight years.  As a result, this analysis is primarily focused on projected impacts within the current eight-year NSPS timeframe.  The EPA's finding of no new non-compliant units (and therefore, no projected costs or quantified benefits) is robust beyond the analysis period (past 2030) in both the IPM base case and the EIA's Annual Energy Outlook 2014 Reference Case modeling projections. Furthermore, this finding is robust in the analysis period across a wide range of alternative potential market, technical, and regulatory scenarios that influence power sector investment decisions evaluated by EIA.  Chapter 5 complements and extends the sector level analysis by examining conditions (e.g., significantly high natural gas prices) in which these conclusions regarding the future economic competitiveness of new non-compliant coal-fired units relative to other new generation technologies may differ. The analysis evaluates the cost and benefits of adopting different competing generating technologies to serve base load demand at an individual facility level.
 Benefits and costs presented in the illustrative analyses in Chapter 5 of this RIA represent estimates from emission reductions under the finalized standards in a particular year. The latent and/or ongoing damages associated with pollution from these sources in a particular analysis year are discounted to the analysis year.  The benefits and costs presented do not represent the net present value of a stream of benefits and costs due to emission reductions over time. 
1.2.2	Definition of Affected EGUs
1.2.2.1	New Sources
The statutory authority for this action is CAA section 111(b), which addresses standards of performance for new, modified, and reconstructed sources. The final standards for newly constructed fossil fuel-fired EGUs apply to those sources that commenced construction on or after January 8, 2014. 
1.2.2.2	Modified Sources
A modification is any physical or operational change to a source that increases the amount of any air pollutant emitted by the source or results in the emission of any air pollutant not previously emitted. The final standards for modified fossil fuel-fired steam generating units apply to those sources that make modifications resulting in an increase of hourly CO2 emissions of more than 10 percent on or after June 18, 2014. However, projects to install pollution controls required under other CAA provisions are specifically exempted from the definition of "modifications" under 40 CFR 60.14(e)(5), even if they emit CO2 as a byproduct. 
1.2.2.3 Reconstructed Sources
The EPA's CAA section 111 regulations provide that reconstructed sources are to be treated as new sources and, therefore, subject to new source standards of performance. The regulations define reconstructed sources, in general, as existing sources: (i) that replace components to such an extent that the capital costs of the new components exceed 50 percent of the capital costs of an entirely new facility and (ii) for which compliance with standards of performance for new sources is technologically and economically feasible (40 CFR 60.15). The final standards for reconstructed fossil fuel-fired EGUs apply to those sources that reconstruct on or after June 18, 2014.
1.2.3	Regulated Pollutant
These final standards set limits for emissions of CO2 from affected EGUs. The EPA is aware that other GHGs such as nitrous oxide (N2O) and to a lesser extent, methane (CH4), may be emitted from fossil-fuel-fired EGUs, especially from coal-fired circulating fluidized bed combustors and from units with selective catalytic reduction and selective non-catalytic reduction systems installed for nitrogen oxide (NOX) control. The EPA is not setting separate N2O or CH4 emission limits or an equivalent CO2 emission limit because of a lack of available data for these affected EGUs. Additional information on the quantity and significance of emissions and on the availability of cost effective controls would be needed before setting standards for these pollutants.
1.2.4	Emission Limits
The EPA has determined that the BSER for newly constructed steam generating units is a supercritical pulverized coal (SCPC) unit with post-combustion partial CCS technology.  The standard of performance achievable using that BSER is 1,400 lb CO2/MWh-gross. The standard for modified steam generating units that conduct modifications resulting in a potential hourly increase in CO2 emissions (mass per hour) of more than 10 percent is a unit-specific emission limitation consistent with each modified unit's best one-year historical performance during the years from 2002 to the time of the modification. For reconstructed steam generating units, the BSER is the most efficient demonstrated generating technology for these types of units (i.e., meeting a standard of performance consistent with a reconstructed boiler using most efficient steam conditions available, even if the boiler was not originally designed to do so). 
The BSER for new and reconstructed primarily natural gas-fired combustion turbines expected to serve intermediate and base load is the use of well-designed, well-maintained, and well-operated natural gas combined cycle (NGCC) technology. The standard of performance achievable using that BSER is 1,000 lb/CO2/MWh-gross.
The applicability of these standards is based on the capacity and operation of a source and is described in the preamble for this final rule.  The final standards will be met on a 12-operating month rolling average basis. The BSER determination and final standards for each affected EGU are shown in Table 1-1.
Table 1-1. Summary of BSER and Final Standards for Affected EGUs
                                 Affected EGU
                                     BSER
                                   Standard
Newly Constructed Fossil Fuel-Fired Steam Generating Units
          Efficient new SCPC utility boiler implementing partial CCS
                            1,400 lb CO2/MWh-gross
Modified Fossil Fuel-Fired Steam Generating Units
Most efficient generation at the affected EGU achievable through a combination of best operating practices and equipment upgrades
Sources making modifications
resulting in an increase in CO2 hourly emissions of more than 10 percent are required to meet a unit-specific emission limit determined by the unit's best historical annual CO2 emission rate (from 2002 to the date of the modification); the emission limit will be no more stringent than:

1. 1,800 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h.
                                      OR
                                       
2. 2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Reconstructed Fossil Fuel-Fired Steam Generating Units
           Most efficient generating technology at the affected EGU.
1. 1,800 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h.
                                      OR
                                       
2. 2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Newly Constructed and Reconstructed Natural Gas-Fired Stationary Combustion Turbines
Efficient NGCC technology for natural gas-fired base load units and clean fuels for non-base load and multi-fuel-fired units.
   1.    1,000 lb CO2/MWh-gross or 1,030 lb CO2/MWh-net for base load natural gas-fired units.                       
   2.    120 lb CO2/MMBtu for non-base load natural gas-fired units.
   3.    120 to 160 lb CO2/MMBtu for multi-fuel-fired units.

1.2.5	Emission Reductions
As will be discussed in more detail in Chapter 4 of this RIA, the EPA anticipates that the EGU New, Modified, and Reconstructed Source GHG Standards will result in negligible changes in GHG emissions over the analysis period. The EPA expects that owners of new units will choose generation technologies that meet these standards in the baseline due to expected economic conditions in the marketplace. Based on historical precedent, the EPA anticipates few covered units will trigger the NSPS reconstruction or modification provisions in the period of analysis. As a result, we do not anticipate any significant costs or monetized benefits associated with this rule.
1.3	Organization of the Regulatory Impact Analysis
	This report presents the EPA's analysis of the potential benefits, costs, and other economic effects of the EGU New, Modified, and Reconstructed Source GHG Standards to fulfill the requirements of an RIA. This RIA includes the following chapters:
Chapter 2, Electric Power Sector Profile, describes the industry affected by the rule. 
Chapter 3, Benefits of Reducing GHGs and Other Pollutants, describes the effects of emissions on climate and health and provides background information to support the benefits analysis.
Chapter 4, Costs, Economic, and Energy Impacts of the New Source Standards, describes impacts of the rule for new sources.
Chapter 5, Analysis of Illustrative Benefit-Cost Scenarios for New Sources, describes additional analyses examining potential impacts under a range of scenarios.
Chapter 6, Modified and Reconstructed Sources, describes the potential impacts of the standards for modified and reconstructed sources.
Chapter 7, Statutory and Executive Order Impact Analyses, describes the small business, unfunded mandates, paperwork reduction act, environmental justice, and other analyses conducted for the rule to meet statutory and Executive Order requirements. 
          
 Chapter 2
Electric Power Sector Profile
2.1 	Introduction
This chapter discusses important aspects of the power sector that relate to the EGU New, Modified and Reconstructed Source GHG Standards, including the types of electricity generating units (EGUs) affected by the regulation, and provides background on the power sector and EGUs. In addition, this chapter provides some historical background on trends in the past decade in the power sector, as well as about existing U.S. Environmental Protection Agency (EPA) regulation of the power sector.
In the past decade there have been significant structural changes in the both the mix of generating capacity and in the share of electricity generation supplied by different types of generation. These changes are the result of multiple factors in the power sector, including normal replacements of older generating units with new units, changes in the electricity intensity of the U.S. economy, growth and regional changes in the U.S. population, technological improvements in electricity generation from both existing and new units, changes in the prices and availability of different fuels, and substantial growth in electricity generation by renewable and unconventional methods. Many of these trends will continue to contribute to the evolution of the power sector. The evolving economics of the power sector, in particular the increased natural gas supply and subsequent relatively low natural gas prices, have resulted in more gas being utilized as base load energy in addition to supplying electricity during peak load. This chapter presents data on the evolution of the power sector from 2002 through 2012. Projections of new capacity and the impact of this rule on these new sources are discussed in more detail in Chapter 4 of this Regulatory Impact Assessment (RIA).
2.2 	Power Sector Overview
The production and delivery of electricity to customers consists of three distinct segments: generation, transmission, and distribution. 
2.2.1 	Generation
Electricity generation is the first process in the delivery of electricity to consumers. There are two important aspects of electricity generation: capacity and net generation. Generating capacity refers to the maximum amount of production from an EGU in a typical hour, typically measured in megawatts (MW) or gigawatts (1 GW = 1,000 MW).  Electricity generation refers to the amount of electricity actually produced by EGUs, measured in kilowatt-hours (kWh) or gigawatt-hours (GWh = 1 million kWh). In addition to producing electricity for sale to the grid, generators perform other services important to reliable electricity supply, such as providing backup generating capacity in the event of unexpected changes in demand or unexpected changes in the availability of other generators. Other important services provided by generators include facilitating the regulation of the voltage of supplied generation.
Individual EGUs are not used to generate electricity 100 percent of the time.  Individual EGUs are periodically not needed to meet the regular daily and seasonal fluctuations of electricity demand. Furthermore, EGUs relying on renewable resources such as wind, sunlight, and surface water to generate electricity are routinely constrained by the availability of adequate wind, sunlight, or water at different times of the day and season. Units are also unavailable during routine and unanticipated outages for maintenance.  These factors result in the mix of generating capacity types available (i.e., the share of capacity of each type of EGU) being substantially different than the mix of the share of total electricity produced by each type of EGU in a given season or year. 
Most of the existing capacity generates electricity by creating heat to generate high pressure steam that is released to rotate turbines which, in turn, create electricity. Natural gas combined cycle (NGCC) units have two generating components operating from a single source of heat.  The first cycle is a gas-fired turbine, which generates electricity directly from the heat of burning natural gas. The second cycle reuses the waste heat from the first cycle to generate steam, which is then used to generate electricity from a steam turbine.  Other EGUs generate electricity by using water or wind to rotate turbine, and a variety of other methods also make up a small, but growing, share of the overall electricity supply. The generating capacity includes fossil-fuel-fired units, nuclear units, and hydroelectric and other renewable sources (see Table 2-1). Table 2-1 also shows the comparison between the generating capacity in 2002 and 2012.
In 2012, the power sector consisted of over 19,000 generating units with a total capacity of 1,168 GW, an increase of 188 GW (or 19 percent) from the capacity in 2002 (980 GW). The 188 GW increase consisted primarily of natural gas fired EGUs (134 GW) and wind generators (55 GW), with substantially smaller net increases and decreases in other types of generating units. 

Table 2-1.         Existing Electricity Generating Capacity by Energy Source, 2002 and 2012
 
                                     2002
                                     2012
                          Change Between '02 and '12
                                 Energy Source
                       Generator Nameplate Capacity (MW)
                               % Total Capacity
                       Generator Nameplate Capacity (MW)
                               % Total Capacity
                                  % Increase
                        Nameplate Capacity Change (MW)
                         % of Total Capacity Increase
Coal
                                                                        338,199
                                                                            35%
                                                                        336,341
                                                                            29%
                                                                            -1%
                                                                         -1,858
                                                                            -1%
Natural Gas[1]
                                                                        352,128
                                                                            36%
                                                                        485,957
                                                                            42%
                                                                            38%
                                                                        133,829
                                                                            71%
Nuclear
                                                                        104,933
                                                                            11%
                                                                        107,938
                                                                             9%
                                                                             3%
                                                                          3,005
                                                                             2%
Hydro
                                                                         96,344
                                                                            10%
                                                                         99,099
                                                                             8%
                                                                             3%
                                                                          2,755
                                                                             1%
Petroleum
                                                                         66,219
                                                                             7%
                                                                         53,789
                                                                             5%
                                                                           -19%
                                                                        -12,430
                                                                            -7%
Wind
                                                                          4,531
                                                                           0.5%
                                                                         59,629
                                                                           5.1%
                                                                          1216%
                                                                         55,098
                                                                            29%
Other Renewable
                                                                         14,208
                                                                           1.5%
                                                                         20,986
                                                                           1.8%
                                                                          47.7%
                                                                          6,778
                                                                           3.6%
Misc
                                                                          3,023
                                                                           0.3%
                                                                          4,257
                                                                           0.4%
                                                                          40.8%
                                                                          1,234
                                                                           0.7%
Total
                                                                        979,585
                                                                           100%
                                                                      1,167,995
                                                                           100%
                                                                            19%
                                                                        188,410
                                                                           100%
Note: This table presents generation capacity. Actual net generation is presented in Table 2-2.


Source: U.S. EIA Electric Power Annual, 2014. Downloaded from EIA Electricity Data Browser, Electric Power Plants Generating Capacity By Source, 2000  -  2013.  Available at http://www.eia.gov/electricity/data.cfm#gencapacity. 
[1] Natural Gas information in this chapter (unless otherwise stated) reflects data for all generating units using natural gas as the primary fossil heat source.  This includes Combined Cycle Combustion Turbine (31 percent of 2012 NG-fired capacity), Gas Turbine (30 percent), Combined Cycle Steam (19 percent), Steam Turbine (17 percent), and miscellaneous (< 1 percent).

The 19 percent increase in generating capacity is the net impact of newly built generating units, retirements of generating units, and a variety of increases and decreases to the nameplate capacity of individual existing units due to changes in operating equipment, changes in emission controls, etc. During the period 2002 to 2012, a total of 315,752 MW of new generating capacity was built and brought online, and 64,763 MW existing units were retired. The net effect of the re-rating of existing units reduced the total capacity by 62,579 MW. The overall net change in capacity was 188,410 MW, as shown in Table 2-1.
The newly built generating capacity was primarily natural gas (226,605 MW), which was partially offset by gas retirements (29,859 MW). Wind capacity was the second largest type of new builds (55,583 MW), augmented by 2,807 MW of solar.  The overall mix of newly built and retired capacity, along with the net effect, is shown on Figure 2-1.

Figure 2-1.  New Build and Retired Capacity (MW) by Fuel Type, 2002-2012
Source:	EIA Form 860
Not displayed: wind and solar retirements = 87 MW, net change in coal capacity = -56 MW
In 2012, electric generating sources produced a net 4,048 trillion kWh to meet electricity demand, a 5 percent increase from 2002 (3,858 trillion kWh). As presented in Table 2-2, almost 70 percent of electricity in 2012 was produced through the combustion of fossil fuels, primarily coal and natural gas, with coal accounting for the largest single share. Although the share of the total generation from fossil fuels in 2012 (67 percent) was only modestly smaller than the total fossil share in 2002 (71 percent), the mix of fossil fuel generation changed substantially during that period.  Coal generation declined by 22 percent and petroleum generation by 75 percent, while natural gas generation increased by 77 percent.  This reflects both the increase in natural gas capacity during that period as well as an increase in the utilization of new and existing gas EGUs during that period. Wind generation also grew from a very small portion of the overall total in 2002 to 3.5 percent of the 2012 total.



Table 2-2.  Net Generation in 2002 and 2012 (Trillion kWh = TWh)

                                     2002
                                     2012
                          Change Between '02 and '12
                                       
                             Net Generation (TWh)
                               Fuel Source Share
                             Net Generation (TWh)
                               Fuel Source Share
                          Net Generation Change (TWh)
                          % Change in Net Generation
Coal
                                                                        1,933.1
                                                                            50%
                                                                        1,514.0
                                                                            37%
                                                                         -419.1
                                                                         -21.7%
Natural Gas
                                                                          702.5
                                                                            18%
                                                                        1,237.8
                                                                            31%
                                                                          535.3
                                                                          76.2%
Nuclear
                                                                          780.1
                                                                            20%
                                                                          769.3
                                                                            19%
                                                                          -10.7
                                                                          -1.4%
Hydro
                                                                          255.6
                                                                             7%
                                                                          271.3
                                                                             7%
                                                                           15.7
                                                                           6.1%
Petroleum
                                                                           94.6
                                                                           2.5%
                                                                           23.2
                                                                           0.6%
                                                                          -71.4
                                                                         -75.5%
Wind
                                                                           10.4
                                                                           0.3%
                                                                          140.8
                                                                           3.5%
                                                                          130.5
                                                                        1260.0%
Other Renewable
                                                                           68.8
                                                                           1.8%
                                                                           77.5
                                                                           1.9%
                                                                            8.8
                                                                          12.7%
Misc
                                                                           13.5
                                                                           0.4%
                                                                           12.4
                                                                           0.3%
                                                                           -1.2
                                                                          -8.7%
Total
                                                                          3,858
                                                                           100%
                                                                          4,046
                                                                           100%
                                                                            188
                                                                             5%
Source: U.S. EIA Monthly Energy Review, July 2014. Table 7.2a Electricity Net Generation: Total (All Sectors).  Available at http://www.eia.gov/totalenergy/data/monthly/. Accessed 7/29/2015

Coal-fired and nuclear generating units have historically supplied "base load" electricity, the portion of electricity loads which are continually present, and typically operate throughout all hours of the year. The coal units meet the part of demand that is relatively constant. Although much of the coal fleet operates as base load, there can be notable differences across various facilities (see Table 2-3). For example, coal-fired units less than 100 megawatts (MW) in size compose 37 percent of the total number of coal-fired units, but only 6 percent of total coal-fired capacity. Gas-fired generation is better able to vary output and is the primary option used to meet the variable portion of the electricity load and has historically supplied "peak" and "intermediate" power, when there is increased demand for electricity (for example, when businesses operate throughout the day or when people return home from work and run appliances and heating/air-conditioning), versus late at night or very early in the morning, when demand for electricity is reduced. 
Table 2-3 also shows comparable data for the capacity and age distribution of natural gas units. Compared with the fleet of coal EGUs, the natural gas fleet is generally smaller and newer.  While 55 percent of the coal EGU fleet is over 500 MW per unit, 77 percent of the gas fleet is between 50 and 500 MW per unit. Many of the largest gas units are gas-fired steam-generating EGUs. 
Table 2-3.  Coal and Natural Gas Generating Units, by Size, Age, Capacity, and Thermal Efficiency (Heat Rate)
                            Unit Size Grouping (MW)
                                   No. Units
                                % of All Units
                                   Avg. Age
                         Avg. Net Summer Capacity (MW)
                        Total Net Summer Capacity (MW)
                               % Total Capacity
                           Avg. Heat Rate (Btu/kWh)
COAL
0  -  24
                                                                            223
                                                                            18%
                                                                           40.7
                                                                           11.4
                                                                          2,538
                                                                             1%
                                                                         11,733
25  -  49
                                                                            108
                                                                             9%
                                                                           44.2
                                                                           36.7
                                                                          3,963
                                                                             1%
                                                                         11,990
50  -  99
                                                                            157
                                                                            12%
                                                                           49.0
                                                                           74.1
                                                                         11,627
                                                                             4%
                                                                         11,883
100 - 149
                                                                            128
                                                                            10%
                                                                           50.6
                                                                          122.7
                                                                         15,710
                                                                             5%
                                                                         10,971
150 - 249
                                                                            181
                                                                            14%
                                                                           48.7
                                                                          190.4
                                                                         34,454
                                                                            11%
                                                                         10,620
250 - 499
                                                                            205
                                                                            16%
                                                                           38.4
                                                                          356.2
                                                                         73,030
                                                                            23%
                                                                         10,502
500 - 749
                                                                            187
                                                                            15%
                                                                           35.4
                                                                          604.6
                                                                        113,056
                                                                            36%
                                                                         10,231
750 - 999
                                                                             57
                                                                             5%
                                                                           31.4
                                                                          823.9
                                                                         46,963
                                                                            15%
                                                                          9,942
1000 - 1500
                                                                             11
                                                                             1%
                                                                           35.7
                                                                         1259.1
                                                                         13,850
                                                                             4%
                                                                          9,732
Total Coal
                                                                           1257
                                                                           100%
                                                                           42.6
                                                                          250.7
                                                                        315,191
                                                                           100%
                                                                         11,013
NATURAL GAS
0  -  24
                                                                           1992
                                                                            37%
                                                                           37.6
                                                                            7.0
                                                                         13,863
                                                                             3%
                                                                         13,531
25  -  49
                                                                            410
                                                                             8%
                                                                           21.8
                                                                          125.0
                                                                         51,247
                                                                            12%
                                                                          9,690
50 - 99
                                                                            962
                                                                            18%
                                                                           15.6
                                                                          174.2
                                                                        167,536
                                                                            39%
                                                                          8,489
100 - 149
                                                                            802
                                                                            15%
                                                                           23.4
                                                                           39.9
                                                                         31,982
                                                                             8%
                                                                         11,765
150 - 249
                                                                            167
                                                                             3%
                                                                           28.7
                                                                          342.4
                                                                         57,179
                                                                            13%
                                                                          9,311
250 - 499
                                                                            982
                                                                            18%
                                                                           24.6
                                                                           71.1
                                                                         69,788
                                                                            16%
                                                                         12,083
500 - 749
                                                                             37
                                                                             1%
                                                                           40.0
                                                                          588.8
                                                                         21,785
                                                                             5%
                                                                         11,569
750 - 1000
                                                                             14
                                                                           0.3%
                                                                           35.9
                                                                          820.9
                                                                         11,492
                                                                             3%
                                                                         10,478
Total Gas
                                                                           5366
                                                                           100%
                                                                           27.7
                                                                           79.2
                                                                        424,872
                                                                           100%
                                                                         11,652

Source:	National Electric Energy Data System (NEEDS) v.5.14
Note: The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed to a generation-weighted or capacity-weighted average heat rate.) A lower heat rate indicates a higher level of fuel efficiency. Table is limited to coal-steam units in operation in 2013 or earlier, and excludes those units in NEEDS with planned retirements in 2014 or 2015.
In terms of the age of the generating units, 50 percent of the total coal generating capacity has been in service for more than 38 years, while 50 percent of the natural gas capacity has been in service less than 15 years.  Figure 2-2 presents the cumulative age distributions of the coal and gas fleets, highlighting the pronounced differences in the ages of the fleets of these two types of fossil-fuel generating capacity. Figure 2-2 also includes the distribution of generation.
                                       
Figure 2-2. Cumulative Distribution in 2010 of Coal and Natural Gas Electricity Capacity and Generation, by Age
Source:	National Electric Energy Data System (NEEDS) v.5.13
Not displayed: coal units (376 MW total, 1 percent of total) and gas units (62 MW, < .01 percent of total)) over 70 years old for clarity. Figure is limited to coal-steam units in NEEDS v.5.13 in operation in 2013 or earlier (excludes ~2,100 MW of coal-fired IGCC and fossil waste capacity), and excludes those units in NEEDS with planned retirements in 2014 or 2015.

The locations of existing fossil units in the EPA's National Electric Energy Data System (NEEDS) v.5.13 are shown in Figure 2-3.


Figure 2-3. Fossil Fuel-Fired Electricity Generating Facilities, by Size
Source: National Electric Energy Data System (NEEDS) v.5.13
Note: This map displays fossil capacity at facilities in the NEEDS v.5.13 IPM frame. NEEDS v.5.13 reflects generating capacity expected to be online at the end of 2015. This includes planned new builds already under construction and planned retirements. In areas with a dense concentration of facilities, some facilities may be obscured. 
2.2.2 	Transmission
Transmission is the term used to describe the bulk transfer of electricity over a network of high voltage lines, from electric generators to substations where power is stepped down for local distribution. In the U.S. and Canada, there are three separate interconnected networks of high voltage transmission lines, 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 operation of their generation, transmission, and distribution systems to balance their common generation and load needs.
2.2.3 	Distribution
Distribution of electricity involves networks of lower voltage lines and substations that take the higher voltage power from the transmission system and step it down to lower voltage levels to match the needs of customers. The transmission and distribution system is the classic example of a natural monopoly, in part because it is not practical to have more than one set of lines running from the electricity generating sources to substations or from substations to residences and businesses.
Over the last couple of decades, several jurisdictions in the United States began restructuring the power industry to separate transmission and distribution from generation, ownership, and operation. Historically, the transmission system had been developed by vertically integrated utilities, establishing much of the existing transmission infrastructure.  However, as parts of the country have restructured the industry, transmission infrastructure has also been developed by transmission utilities, electric cooperatives, and merchant transmission companies, among others. Distribution, also historically developed by vertically integrated utilities, is now often managed by a number of utilities that purchase and sell electricity, but do not generate it. As discussed below, electricity restructuring has focused primarily on efforts to reorganize the industry to encourage competition in the generation segment of the industry, including ensuring open access of generation to the transmission and distribution services needed to deliver power to consumers. In many states, such efforts have also included separating generation assets from transmission and distribution assets to form distinct economic entities. Transmission and distribution remain price-regulated throughout the country based on the cost of service.
2.3 	Sales, Expenses, and Prices
These electric generating sources provide electricity for ultimate commercial, industrial, and residential customers.  Each of the three major categories of ultimate customers consume roughly a quarter to a third of the total electricity produced (see Table 2-4). Some of these uses are highly variable, such as heating and air conditioning in residential and commercial buildings, while others are relatively constant, such as industrial processes that operate 24 hours a day. The distribution between the end use categories changed very little between 2002 and 2012.

Table 2-4.  Total U.S. Electric Power Industry Retail Sales in 2012 (billion kWh)
                                       
                                     2002
                                     2012
                                       
                                       
                        Sales/Direct Use (Billion kWh)
                            Share of Total End Use
                        Sales/Direct Use (Billion kWh)
                            Share of Total End Use
                                     Sales
Residential
                                                                          1,265
                                                                            35%
                                                                          1,375
                                                                          35.9%

Commercial
                                                                          1,104
                                                                            30%
                                                                          1,327
                                                                          34.6%

Industrial
                                                                            990
                                                                            27%
                                                                            986
                                                                          25.7%

Transportation
                                                                             NA
                                                                            - 
                                                                              7
                                                                           0.2%

Other
                                                                            106
                                                                             3%
                                                                             NA
                                                                            - 
Total
 
                                                                          3,465
                                                                            95%
                                                                          3,695
                                                                            96%
Direct Use
                                                                            166
                                                                             5%
                                                                            138
                                                                             4%
Total End Use
                                                                          3,632
                                                                           100%
                                                                          3,832
                                                                           100%

Source: Table 2.2, EIA Electric Power Annual, 2013
Notes: 
Retail sales are not equal to net generation (Table 2-2) because net generation includes net exported electricity and loss of electricity that occurs through transmission and distribution.
Direct Use represents commercial and industrial facility use of onsite net electricity generation; and electricity sales or transfers to adjacent or co-located facilities for which revenue information is not available.
2.3.1 Electricity Prices
Electricity prices vary substantially across the United States, differing both between the ultimate customer categories and also by state and region of the country. Electricity prices are typically highest for residential and commercial customers because of the relatively high costs of distributing electricity to individual homes and commercial establishments. The high prices for residential and commercial customers are the result both of the necessary extensive distribution network reaching to virtually every part of the country and every building, and also the fact that generating stations are increasingly located relatively far from population centers, which increases transmission costs.  Industrial customers generally pay the lowest average prices, reflecting both their proximity to generating stations and the fact that industrial customers receive electricity at higher voltages, which makes transmission more efficient and less expensive). Industrial customers frequently pay variable prices for electricity by the season and time of day, while residential and commercial prices historically have been less variable.  Overall industrial customer prices are usually considerably closer to the wholesale marginal cost of generating electricity than residential and commercial prices.
On a state-by-state basis, all retail electricity prices vary considerably. In 2011 the national average retail electricity price (all sectors) was 9.90 cents/KWh, with a range from 6.44 cents (Idaho) to 31.59 cents (Hawaii). The Northeast, California, and Alaska have average retail prices that can be as much as double those of other states (see Figure 2-4), and Hawaii has the most expensive retail price of electricity in the country.

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

Average national retail electricity prices increased between 2002 and 2012 by 36.7 percent in nominal (current year $) terms.  The amount of increase differed for the three major end use categories (residential, commercial and industrial). National average residential prices increased the most (40.8 percent), and commercial prices increased the least (27.9 percent). The nominal year prices for 2002 through 2012 are shown in Figure 2-5. 

Figure 2-5.  Nominal National Average Electricity Prices for Three Major End-Use Categories
Source: EIA AEO 2012, Table 2.4
Electricity prices for all three end-use categories increased more than overall inflation through this period, measured by either the Gross Domestic Product (GDP) implicit price deflator (23.5 percent) or the consumer price index (CPI-U, which increased by 27.7 percent). Most of these electricity price increases occurred between 2002 and 2008. Since 2008 nominal electricity prices have been relatively stable while overall inflation continued to increase.  The increase in nominal electricity prices for the major end use categories, as well as increases in the GDP price and CPI-U indices for comparison, are shown in Figure 2-6.
                                       
Figure 2-6.  Relative Increases in Nominal National Average Electricity Prices for Major End-Use Categories, with Inflation Indices

The real (inflation-adjusted) change in average national electricity prices can be calculated using the GDP implicit price deflator. Figure 2-7 shows real (2011$) electricity prices for the three major customer categories from 1960 to 2012, and Figure 2-8 shows the relative change in real electricity prices relative to the prices in 1960. As can be seen in the figures, the price for industrial customers has always been lower than for either residential or commercial customers, but the industrial price has been more volatile. While the industrial real price of electricity in 2012 was relatively unchanged from 1960, residential and commercial real prices are 23 percent and 28 percent lower respectively than in 1960.

 
Figure 2-7.  Real National Average Electricity Prices (2011$) for Three Major End-Use Categories
Source: EIA Monthly Energy Review, April 2015, Table 9.8


 
Figure 2-8.  Relative Change in Real National Average Electricity Prices (2011$) for Three Major End-Use Categories
Source: EIA Monthly Energy Review, April 2015, Table 9.8
2.3.2 Prices of Fossil Fuels Used for Generating Electricity
Another important factor in the changes in electricity prices are the changes in fuel prices for the three major fossil fuels used in electricity generation: coal, natural gas and oil. Relative to real prices in 2002, the national average real price (in 2011$) of coal delivered to EGUs in 2012 had increased by 54 percent, while the real price of natural gas decreased by 22 percent.  The real price of oil increased by 203 percent, but with oil declining as an EGU fuel (in 2012 oil generated only 1 percent of electricity) the doubling of oil prices had little overall impact in the electricity market. The combined real delivered price of all fossil fuels in 2012 increased by 23 percent over 2002 prices.  Figure 2-9 shows the relative changes in real price of all three fossil fuels between 2002 and 2012.

                                       
Figure 2-9.  Relative Real Prices of Fossil Fuels for Electricity Generation and Change in National Average Real Price per MBtu Delivered to EGU
Source: EIA AEO 2012, Table 9.9
2.3.3 Changes in Electricity Intensity of the U.S. Economy Between 2002 to 2012
An important aspect of the changes in electricity generation (i.e., electricity demand) between 2002 and 2012 is that while total net generation increased by 4.9 percent over that period, the demand growth for generation has been low, and in fact was lower than both the population growth (9.2 percent) and real GDP growth (19.8 percent).  Figure 2-10 shows the growth of electricity generation, population and real GDP during this period.



Figure 2-10.  Relative Growth of Electricity Generation, Population, and Real GDP Since 2002
Sources: U.S. EIA Monthly Energy Review, December 2014. Table 7.2a Electricity Net Generation: Total (All Sectors).  U.S. Census.  
Because demand for electricity generation grew more slowly than both the population and GDP, the relative electric intensity of the U.S. economy improved (i.e., less electricity used per person and per real dollar of output) during 2002 to 2012.  On a per capita basis, real GDP per capita grew by 10.9 percent, increasing from $44,900 (in 2011$) per person in 2002 to $49,800 per person in 2012. At the same time electricity generation per capita decreased by 3.9 percent, declining from 13.4 MWh per person in 2002 to 12.8 MWh per person in 2012.  The combined effect of these two changes improved the overall electricity efficiency of the U.S. economy. Electricity generation per dollar of real GDP decreased 12.5 percent, declining from 299 MWh per $1 million of GDP to 261 MWh per $1 million GDP. These relative changes are shown in Figure 2-11. Figures 2-10 and 2-11 clearly show the effects of the 2007  -  2009 recession on both GDP and electricity generation, as well as the effects of the subsequent economic recovery.

                                       
Figure 2-11.  Relative Change of Real GDP, Population, and Electricity Generation Intensity Since 2002
Sources: U.S. EIA Monthly Energy Review, December 2014. Table 7.2a Electricity Net Generation: Total (All Sectors).  U.S. Census
2.4 	Deregulation and Restructuring
The process of restructuring and deregulation of wholesale and retail electric markets has changed the structure of the electric power industry. In addition to reorganizing asset management between companies, restructuring sought a functional unbundling of the generation, transmission, distribution, and ancillary services the power sector has historically provided, with the aim of enhancing competition in the generation segment of the industry.
Beginning in the 1970s, government policy shifted against traditional regulatory approaches and in favor of deregulation for many important industries, including transportation (notably commercial airlines), communications, and energy, which were all thought to be natural monopolies (prior to 1970) that warranted governmental control of pricing. However, deregulation efforts in the power sector were most active during the 1990s. Some of the primary drivers for deregulation of electric power included the desire for more efficient investment choices, the economic incentive to provide least-cost electric rates through market competition, reduced costs of combustion turbine technology that opened the door for more companies to sell power with smaller investments, and complexity of monitoring utilities' cost of service and establishing cost-based rates for various customer classes. Deregulation and market restructuring in the power sector involved the divestiture of generation from utilities, the formation of organized wholesale spot energy markets with economic mechanisms for the rationing of scarce transmission resources during periods of peak demand, the introduction of retail choice programs, and the establishment of new forms of market oversight and coordination.
The pace of restructuring in the electric power industry slowed significantly in response to market volatility in California and financial turmoil associated with bankruptcy filings of key energy companies. By the end of 2001, restructuring had either been delayed or suspended in eight states that previously enacted legislation or issued regulatory orders for its implementation (shown as "Suspended" in Figure 2-12). Eighteen other states that had seriously explored the possibility of deregulation in 2000 reported no legislative or regulatory activity in 2001 (EIA, 2003) ("Not Active" in Figure 2-12). Currently, there are 15 states plus the District of Columbia where price deregulation of generation (restructuring) has occurred ("Active" in Figure 2-12). Power sector restructuring is more or less at a standstill; by 2010 there were no active proposals under review by the Federal Energy Regulatory Commission (FERC) for actions aimed at wider restructuring, and no additional states have begun retail deregulation activity since that time.

Figure 2-12.	Status of State Electricity Industry Restructuring Activities
Source:	EIA 2010. "Status of Electricity Restructuring by State." Available online at: http://www.eia.gov/cneaf/electricity/page/restructuring/restructure_elect.html.
One major effect of the restructuring and deregulation of the power sector was a significant change in type of ownership of electricity generating units in the states that deregulated prices.  Throughout most of the 20th century, electricity was supplied by vertically integrated regulated utilities. The traditional integrated utilities controlled generation, transmission, and distribution in their designated areas, and prices were set by cost of service regulations set by state government agencies (e.g., Public Utility Commissions).  Deregulation and restructuring resulted in unbundling of the vertical integration structure. Transmission and distribution continued to operate as monopolies with cost of service regulation, while generation shifted to a mix of ownership affiliates of traditional utility ownership and some generation owned and operated by competitive companies known as Independent Power Producers (IPP). The resulting generating sector differed by state or region, as the power sector adapted to the restructuring and deregulation requirements in each state. 
By 2002, the major impacts of adapting to changes brought about by deregulation and restructuring during the 1990s were largely in place. The resulting ownership mix of generating capacity (MW) in 2002 was 62 percent of the generating capacity owned by traditional utilities, 35 percent owned by IPPs, and 3 percent owned by commercial and industrial producers. The mix of electricity generated (MWh) was more heavily weighted towards the utilities, with a distribution in 2002 of 66 percent, 30 percent, and 4 percent for utilities, IPPs and commercial/industrial, respectively.
Since 2002 IPPs have expanded faster than traditional utilities, substantially increasing their share by 2012 of both capacity (58 percent utility, 39 percent IPPs, and 3 percent commercial/industrial) and generation (58 percent, 38 percent, and 4 percent). 
The mix of capacity and generation in 2002 and 2012 for each of the ownership types is shown in Figures 2-13 (capacity) and 2-14 (generation).  The capacity and generation data for commercial and industrial owners are not shown on these figures due to the small magnitude of those ownership types. A portion of the shift of capacity and generation is due to sales and transfers of generation assets from traditional utilities to IPPs, rather than strictly the result of newly built units.


Figures 2-13 & 2-14.	Capacity and Generation Mix by Ownership Type, 2002 & 2012
Figures 2-15 and 2-16.  Generation Capacity Built and Retired between 2002 and 2012 by Ownership Type

The mix of capacity by fuel types that have been built and retired between 2002 and 2012 also varies significantly by type of ownership.  Figure 2-15 presents the new capacity built during that period, showing that IPPs built the majority of both new wind and solar generating capacity, as well as somewhat more natural gas capacity than the traditional utilities built.  Figure 2-16 presents comparable data for the retired capacity, showing that utilities retired more coal and "other" capacity (mostly oil-fired) than IPPs retired, while the IPPs retired more natural gas capacity than the utilities retired. The retired gas capacity was primarily (60 percent) steam and combustion turbines.
2.5	Emissions of Greenhouse Gases from Electric Utilities
The burning of fossil fuels, which generates about 69 percent of our electricity nationwide, results in emissions of greenhouse gases. The power sector is a major contributor of CO2 in particular, but also contributes to emissions of sulfur hexafluoride (SF6), methane (CH4), and nitrous oxide (N2O). In 2013, the electricity generation accounted for 38 percent of national CO2 emissions. Including both generation and transmission (a source of SF6), the power sector accounted for 31 percent of total nationwide greenhouse gas emissions, measured in CO2 equivalent. Table 2-5 and Figure 2-17 show the GHG emissions  from the power sector relative to other major economic sectors. Table 2-6 shows the contributions of CO2 and other GHGs from the power sector and other major emitting economic sectors. 


Table 2-5. 	Domestic Emissions of Greenhouse Gases, by Economic Sector (million tons of CO2 equivalent)
 
                                     2002
                                     2013
                          Change Between '02 and '13
                                 Sector/Source
                                 GHG Emissions
                             % Total GHG Emissions
                                 GHG Emissions
                             % Total GHG Emissions
                              Change in Emissions
                             % Change in Emissions
                        % of Total Change in Emissions
Electric Power Industry
                                                                          2,550
                                                                            33%
                                                                          2,289
                                                                            31%
                                                                           -260
                                                                           -10%
                                                                            64%
Transportation
                                                                          2,158
                                                                            28%
                                                                          1,991
                                                                            27%
                                                                           -167
                                                                            -8%
                                                                            41%
Industry
                                                                          1,564
                                                                            20%
                                                                          1,535
                                                                            21%
                                                                            -29
                                                                            -2%
                                                                             7%
Agriculture
                                                                            618
                                                                             8%
                                                                            647
                                                                             9%
                                                                             29
                                                                             5%
                                                                            -7%
Commercial
                                                                            402
                                                                             5%
                                                                            442
                                                                             6%
                                                                             40
                                                                            10%
                                                                           -10%
Residential
                                                                            412
                                                                             5%
                                                                            413
                                                                             6%
                                                                              1
                                                                             0%
                                                                             0%
U.S. Territories
                                                                             58
                                                                         <1%
                                                                             38
                                                                         <1%
                                                                            -19
                                                                           -33%
                                                                             5%
Total GHG Emissions
                                                                          7,762
                                                                           100%
                                                                          7,356
                                                                           100%
                                                                           -406
                                                                            -5%
                                                                           100%
Sinks and Reductions
                                                                           -976
                                                                               
                                                                           -972
                                                                               
                                                                              4
                                                                             0%
                                                                               
Net GHG Emissions
                                                                          6,786
                                                                               
                                                                          6,384
                                                                               
                                                                           -402
                                                                            -6%
                                                                               
Source:	EPA, 2015 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013", Table 2-12. Includes CO2, CH4, N2O and SF6 emissions. 

                                       
Figure 2-17. 	Domestic Emissions of Greenhouse Gases from Major Sectors, 2002 and 2013 (million tons of CO2 equivalent)
Source:	EPA, 2015 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013", Table 2-12
Not Shown: CO2e emissions from U.S. Territories. The amount of CO2 emitted during the combustion of fossil fuels varies according to the carbon content and heating value of the fuel used. The CO2 emission factors used in IPM v5.14 (same as used in v5.13) are shown in Table 2-7. Coal has higher carbon content than oil or natural gas, and thus releases more CO2 during combustion. Coal emits about 1.7 times as much carbon per unit of energy when burned as natural gas does (EPA 2013).
Table 2-6. 	Greenhouse Gas Emissions from the Electricity Sector (Generation, Transmission and Distribution), 2002 and 2013 (million tons of CO2 equivalent)
                                       
                                       
                                     2002
                                     2013
                          Change Between '02 and '13
                            Gas/Fuel Type or Source
                                 GHG Emissions
                  % of Total GHG Emissions from Power Sector
                                 GHG Emissions
                  % of Total GHG Emissions from Power Sector
                            Change in GHG Emissions
                             % Change in Emissions
CO2
                                                                               
                                                                          2,521
                                                                          98.9%
                                                                          2,262
                                                                          98.8%
                                                                           -259
                                                                           -10%
                                                                               
Fossil Fuel Combustion
                                                                          2,505
                                                                          98.2%
                                                                          2,248
                                                                          98.2%
                                                                           -257
                                                                           -10%
                                                                               
Coal
                                                                          2,083
                                                                          81.7%
                                                                          1,736
                                                                          75.8%
                                                                           -347
                                                                           -17%
                                                                               
Natural Gas
                                                                            337
                                                                         13.22%
                                                                            487
                                                                         21.28%
                                                                            150
                                                                            45%
                                                                               
Petroleum
                                                                           84.7
                                                                          3.32%
                                                                           24.7
                                                                          1.08%
                                                                          -60.0
                                                                           -71%
                                                                               
Geothermal
                                                                            0.4
                                                                          0.02%
                                                                            0.4
                                                                          0.02%
                                                                            0.0
                                                                             0%
                                                                               
Incineration of Waste
                                                                           13.0
                                                                          0.51%
                                                                           11.1
                                                                          0.49%
                                                                           -1.9
                                                                           -14%
                                                                               
Other Process Uses of Carbonates
                                                                            2.9
                                                                          0.11%
                                                                            2.4
                                                                          0.11%
                                                                           -0.4
                                                                           -15%
CH4
                                                                               
                                                                            0.4
                                                                          0.02%
                                                                            0.4
                                                                          0.02%
                                                                            0.0
                                                                             0%
                                                                               
Stationary Combustion*
                                                                            0.4
                                                                          0.02%
                                                                            0.4
                                                                          0.02%
                                                                            0.0
                                                                             0%
                                                                               
Incineration of Waste
                                                                              +
                                                                               
                                                                             + 
                                                                               
                                                                               
                                                                               
N2O
                                                                               
                                                                           13.7
                                                                          0.54%
                                                                           21.4
                                                                          0.93%
                                                                            7.7
                                                                            56%
                                                                               
Stationary Combustion*
                                                                           13.2
                                                                          0.52%
                                                                           21.1
                                                                          0.92%
                                                                            7.8
                                                                            59%
                                                                               
Incineration of Waste
                                                                            0.4
                                                                          0.02%
                                                                            0.3
                                                                          0.01%
                                                                           -0.1
                                                                           -25%
SF6
                                                                               
                                                                           14.7
                                                                          0.57%
                                                                            5.6
                                                                          0.25%
                                                                           -9.0
                                                                           -62%
                                                                               
Electrical Transmission and Distribution
                                                                           14.7
                                                                          0.57%
                                                                            5.6
                                                                          0.25%
                                                                           -9.0
                                                                           -62%
Total GHG Emissions
                                                                          2,550
                                                                               
                                                                          2,289
                                                                               
                                                                           -260
                                                                               
Source:	EPA, 2015 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013", Table 2-11
* Includes only stationary combustion emissions related to the generation of electricity.
** SF6 is not covered by this rule, which specifically regulates CO2 emissions from combustion.
+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.

Table 2-7.	Fossil Fuel Emission Factors in the EPA Base Case 5.14 IPM Power Sector Modeling Application
                                   Fuel Type
                           Carbon Dioxide (lb/MMBtu)
Coal 
                                       
   Bituminous 
                                202.8  -  209.6
   Subbituminous 
                                209.2  -  215.8
   Lignite 
                                212.6  -  219.
Natural Gas 
                                     117.1
Fuel Oil 
                                       
   Distillate 
                                     161.4
   Residual 
                                161.4  -  173.9
Biomass
                                      195
Waste Fuels 
                                       
   Waste Coal 
                                     204.7
   Petroleum Coke 
                                     225.1
   Fossil Waste 
                                     321.1
   Non-Fossil Waste 
                                       0
   Tires 
                                     189.5
   Municipal Solid Waste 
                                     91.9
Source:	Documentation for IPM Base Case v.5.13, Table 11-5. The emission factors used in Base Case 5.14 are identical to the emission factors in IPM Base Case 5.13.
Note:	CO2 emissions presented here for biomass account for combustion only and do not reflect emissions from initial photosynthesis (carbon sink) or harvesting activities and transportation (carbon source).
2.6 	Carbon Dioxide Control Technologies 
In the power sector, current approaches available for significantly reducing the CO2 emissions of new fossil fuel combustion sources to meet a 1,400 lb CO2/MWh emission rate include the use of: (1) highly efficient coal-fired generation (e.g., modern supercritical or ultra-supercritical steam units) with partial carbon capture and storage (CCS), (2) highly efficient coal-fired designs (e.g., modern supercritical or ultra-supercritical steam units) with up to 40 percent natural gas co-firing, (3), integrated coal gasification combined cycle (IGCC) co-firing with up to 10 percent natural gas, and/or (4) natural gas combined cycle (NGCC)  combustion turbine/steam-turbine units.
Investment decisions for the optimal choice of the type of new generating capacity capable of meeting the 1,400 lb CO2/MWh standard of performance depend in part on the intended primary use of new generating capacity.  Daily peak electricity demands, involving operation for relatively few hours per year, are often most economically met by simple-cycle combustion turbines (CT). Stationary CTs used for power generation can be installed quickly, at relatively low capital cost. They can be remotely started and loaded quickly, and can follow rapid demand changes. Full-load efficiencies of large current technology CTs are typically 30-33 percent but can be has high as 40 percent or more (high heating value basis), as compared to efficiencies of 50 percent or more for new combined-cycle units that recover and use the exhaust heat otherwise wasted from a CT.  A simple-cycle CT's lower efficiency causes it to burn much more fuel to produce a MWh of electricity than a combined-cycle unit. Thus, when burning natural gas its CO2 emission rate per MWh could be 40-60 percent higher than a more efficient NGCC unit. 
Base load electricity demand can be met with NGCC generation, coal and other fossil-fired steam generation, and IGCC technology, as well as generation from sources that do not emit CO2, such as nuclear and hydro.  IGCC employs the use of a gasifier to transform fossil fuels into synthesis gas ("syngas") and heat.  The syngas is used to fuel a combined cycle generator, and the heat from the syngas conversion can produce steam for the steam turbine portion of the combined cycle generator.  Electricity can be generated through this IGCC process somewhat more efficiently than through conventional boiler-steam generators.  Additionally, with gasification, some of the syngas can be converted into other marketable products such as fertilizers and chemical feedstocks for processes to manufacture liquid hydrocarbons (e.g., fuels and lubricants), and CO2 can be captured for use in EOR.  Figure 2-18 shows the array of products (including electricity) and by-products that can be produced in a syngas process.


Figure 2-18. 	Marketable products from Syngas Generation
Source: National Energy Technology Lab. Gasifipedia.  Available at http://www.netl.doe.gov/research/coal/energy-systems/gasification/gasifipedia/co-generation
2.6.1 	Carbon Capture and Storage
CCS can be achieved through either pre-combustion or post-combustion capture of CO2 from a gas stream associated with the fuel combusted. Furthermore, CCS can be designed and operated for full capture of the CO2 in the gas stream (i.e., above 90 percent) or for partial capture (below 90 percent). Post-combustion capture processes remove CO2 from the exhaust gas of a combustion system  -  such as a utility boiler. It is referred to as "post-combustion capture" because the CO2 is the product of the combustion of the primary fuel and the capture takes place after the combustion of that fuel. This process is illustrated for a pulverized coal power plant in Figure 2-19 and described in more detail in the preamble. (See preamble section V.D.) For post-combustion, a station's net generating output will be lower due to the energy needs of the capture process.

Figure 2-19. 	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 syngas under heat and pressure and some percentage of the carbon contained in the syngas is captured before combustion. For pre-combustion technology, a significant amount of energy is needed to gasify the fuel(s). This process is illustrated in Figure 2-20. Application of post-combustion CCS with IGCC can be designed to use no water-gas shift, or single- or two-stage shift processes, to obtain varying percentages of CO2 removal  -  from a "partial capture" percentage to 90 percent "full capture." Pre-combustion CCS typically has a lesser impact on net energy output than does post-combustion CCS. For more detail on CCS technology, see the "Report of the Interagency Task Force on Carbon Capture and Storage" (2010).


Figure 2-20.	Pre-Combustion CO2 Capture for an IGCC Power Plant
Source: Interagency Task Force on Carbon Capture and Storage 2010
Carbon capture technology has been successfully applied since 1930 on several smaller scale industrial facilities and more recently in a number of demonstration phase projects worldwide for power sector applications. In October 2014, the first commercial-scale coal-fired capture and storage project for electricity generation began operation at the Boundary Dam Power Station in Saskatchewan, Canada. The Boundary Dam Station is owned by the Province of Saskatchewan, and operated by SaskPower, a provincially owned corporation that is the primary electric utility in the Province. The commercial-scale demonstration project retrofit Unit 3 (a 130 MW, coal fired built in 1970, and rebuilt in 2013) at a total cost of approximately $1.5 billion (Canadian, or about $1.2 billion U.S.), including a partial subsidy of $240 million (Canadian) by the Canadian federal government. The carbon capture system is a post-combustion process designed to capture 90 percent of the CO2 emitted by Unit #3. Retrofitting the carbon capture system reduced the capacity of the unit to 110 MW.  The majority of the captured CO2 is used for an enhanced oil recovery (EOR) project in southern Saskatchewan. The portion of the CO2 is being stored in a nearby research and monitoring geological storage facility, where the captured CO2 will be injected 3.4 kilometers underground into a sandstone formation located below the major coal field supplying lignite to Unit # 3. The remaining captured CO2 will be injected into deep saline formations.
In the United States there are two commercial-scale CCS facilities nearing completion:
      1)  the Kemper County Carbon Dioxide Capture and Storage Project in Mississippi, and 
      2) The W.A. Parish Petra Nova CCA Project near Houston, Texas.
Construction began on the Kemper project in 2010, and the startup is currently scheduled for May 2016. The Kemper project is constructing a new 524 MW lignite unit as well as a 58 MW natural gas unit. Mississippi Power (a division of Southern Power) is building and will operate the Kemper project. The control system is designed to capture 65 percent of the CO2 generated by the plant, and is projected to capture 3.5 million tons of CO2 per year.  The resulting CO2 emission rate is expected to be approximately 800 pounds per MWh produced. The current total cost estimate is $5.6 billion, a substantial increase from the original $2.4 billion estimate. The construction has received a $270 million grant from the U.S. Department of Energy, and $133 million in investment tax credits from the Internal Revenue Service. The captured CO2 will be transported via a 60 mile pipeline and used for EOR projects in mature Mississippi oil fields.
The only other commercial-scale electricity power sector CCS project currently under construction in the United States is the W.A. Parish Petra Nova CCS Project near Houston, Texas. The Parish Petra project is a 50/50 partnership between NRG Energy (an integrated electricity company generating and supplying electricity to 1.6 million customers in Texas) and the Nippon Oil and Gas Exploration Company.  The Parish project will retrofit a post-combustion CCS system on a portion of the flue gas from the existing 610 MW coal fired Unit # 8. The CCS system will treat a 240 MW slipstream of the flue gas, and is designed to capture 90 percent of the CO2 in the treated flue gas. The capacity rating of Unit # 8 will not be reduced due to the CCS project because an 85 MW custom-built natural gas fired combustion turbine co-generation unit is being built on-site to provide both electricity and steam to the CCS unit. The total cost of the CCS project is estimated to be $1 billion (including a $167 million grant from the U.S. Department of Energy), and the project is expected to extract 1.4  -  1.6 million tons of CO2 per year. The construction contract was awarded in July, 2014, and operation is expected to begin in early 2016. The CO2 will be piped 85 miles to a reservoir for EOR in the West Ranch Oil Field.
2.7 	Geologic and Geographic Considerations for Geologic Sequestration
Geologic sequestration (GS) (i.e., long-term containment of a CO2 stream in subsurface geologic formations) is technically feasible and available throughout most of the United States. (See generally preamble to final rule at sections V.M and N.)  GS is feasible in different types of geologic formations including deep saline formations (formations with high salinity formation fluids) or in oil and gas formations, such as where injected CO2 increases oil production efficiency through EOR. CO2 may also be used for other types of enhanced recovery, such as for natural gas production. Reservoirs, such as unmineable coal seams, also offer the potential for GS. The geographic availability of deep saline formations, EOR, and unmineable coal seams is shown in Figure 2-21. Estimates of CO2 storage resources by state compiled by the Department of Energy's (DOE) National Carbon Sequestration Database and Geographic Information System (NATCARB) and published in DOE's 2012 United States Carbon Utilization and Storage Atlas (discussed below) are provided in Table 2-8.

                                       
Figure 2-21	Geologic Sequestration in the Continental United States 
Sources: EPA Greenhouse Gas Reporting Program; Department of Energy, NATCARB; Department of Transportation, National Pipeline Management System.

Table 2-8. 	Total CO2 Storage Resource (U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL))
                                       
                                 Million Tons
                                     State
                                 Low Estimate
                                 High Estimate
                                    ALABAMA
                                    135,022
                                   765,422 
                                    ALASKA
                                     9,524
                                    21,771 
                                    ARIZONA
                                      143
                                    1,290 
                                   ARKANSAS
                                     6,812
                                    70,184 
                                  CALIFORNIA
                                    37,357
                                   463,665 
                                   COLORADO
                                    41,458
                                   393,734 
                                  CONNECTICUT
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL 
                                   DELAWARE
                                      44
                                      44 
                             DISTRICT OF COLUMBIA
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL 
                                    FLORIDA
                                    113,251
                                   611,793 
                                    GEORGIA
                                    160,210
                                   175,322 
                                    HAWAII
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL 
                                     IDAHO
                                      44
                                     430 
                                   ILLINOIS
                                    11,045
                                   128,772 
                                    INDIANA
                                    35,296
                                    75,189 
                                     IOWA
                                      11
                                      55 
                                    KANSAS
                                    11,993
                                    95,173 
                                   KENTUCKY
                                     3,219
                                    8,433 
                                   LOUISIANA
                                    186,842
                                  2,319,238 
                                     MAINE
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL 
                                   MARYLAND
                                     2,050
                                    2,127 
                                 MASSACHUSETTS
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL 
(Continued on next page)

Table 2-8. 	Total CO2 Storage Resource (DOE-NETL), cont.

                                       
                                 Million Tons*
                                     State
                                 Low Estimate
                                 High Estimate
                                   MICHIGAN
                                    20,999
                                    52,040 
                                   MINNESOTA
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL 
                                  MISSISSIPPI
                                    159,846
                                  1,306,270 
                                   MISSOURI
                                      11
                                     187 
                                    MONTANA
                                    93,233
                                  1,006,100 
                                   NEBRASKA
                                    26,202
                                   124,826 
                                    NEVADA
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL 
                                 NEW HAMPSHIRE
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL 
                                  NEW JERSEY
                                       0
                                     0   
                                  NEW MEXICO
                                    47,135
                                   395,828 
                                   NEW YORK
                                     5,115
                                    5,115 
                                NORTH CAROLINA
                                     1,477
                                    20,271 
                                 NORTH DAKOTA
                                    73,954
                                   162,569 
                             Offshore Federal Only
                                    539,956
                                  7,098,976 
                                     OHIO
                                    14,837
                                    14,837 
                                   OKLAHOMA
                                    62,777
                                   269,570 
                                    OREGON
                                     7,507
                                   103,286 
                                 PENNSYLVANIA
                                    24,361
                                    24,361 
                                 RHODE ISLAND
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL 
                                SOUTH CAROLINA
                                    33,180
                                    37,677 
                                 SOUTH DAKOTA
                                     9,656
                                    26,489 
                                   TENNESSEE
                                      474
                                    4,255 
                                     TEXAS
                                    489,205
                                  4,772,925 
                                     UTAH
                                    28,076
                                   265,558 
                                    VERMONT
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL 
                                   VIRGINIA
                                      485
                                    3,208 
                                  WASHINGTON
                                    40,367
                                   547,550 
                                 WEST VIRGINIA
                                    18,353
                                    18,353 
                                   WISCONSIN
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL
                                    WYOMING
                                    80,127
                                   754,917 
                                  U.S. Total
                                   2,531,653
                                  22,147,811 

* States with a "zero" value represent estimates of minimal CO2 storage resource. States that have not yet been assessed by DOE-NETL have been identified.

2.7.2 	Availability of Geologic Sequestration in Deep Saline Formations
DOE and the United States Geological Survey (USGS) have independently conducted preliminary analyses of the availability and potential CO2 sequestration capacity of deep saline formations in the United States. DOE estimates are compiled by the DOE's NATCARB system using volumetric models and published in a Carbon Utilization and Storage Atlas. DOE estimates that areas of the United States with appropriate geology have a sequestration potential of at least 2,200 billion tons of CO2 in deep saline formations. According to DOE, at least 39 states have geologic characteristics that are amenable to deep saline GS in either onshore or offshore locations. In 2013, the USGS completed its evaluation of the technically accessible GS resources for CO2 in U.S. onshore areas and state waters using probabilistic assessment. The USGS estimates a mean of 3,300 billion tons of subsurface CO2 sequestration potential, including saline and oil and gas reservoirs, across the basins studied in the United States. As shown in Figure 2-21, there are 39 states for which onshore and offshore deep saline formation storage capacity has been identified.  
2.7.3	Availability of CO2 Storage via Enhanced Oil Recovery 
Although the regulatory impact analysis for this rule relies on GS in deep saline formations, the EPA also recognizes the potential for securely sequestering CO2 via EOR. EOR has been successfully used at numerous production fields throughout the United States to increase oil recovery. The oil industry in the United States has over 40 years of experience with EOR. An oil industry study in 2014 identified more than 125 EOR projects in 98 fields in the United States. More than half of the projects evaluated in the study have been in operation for more than 10 years, and many have been in operation for more than 30 years. This experience provides a strong foundation for demonstrating successful CO2 injection and monitoring technologies, which are needed for safe and secure GS that can be used for deployment of CCS across geographically diverse areas.
Currently, 12 states have active EOR operations and most have developed an extensive CO2 infrastructure, including pipelines, to support the continued operation and growth of EOR. An additional 18 states are within 100 kilometers (62 miles) of current EOR operations (see Figure 2-21).  The vast majority of EOR is conducted in oil reservoirs in the Permian Basin, which extends through southwest Texas and southeast New Mexico. States where EOR is currently used include Alabama, Colorado, Louisiana, Michigan, Mississippi, New Mexico, Oklahoma, Texas, Utah, and Wyoming. 
At the project level, the volume of CO2 already injected for EOR and the duration of operations are of similar magnitude to the duration and volume of CO2 expected to be captured from fossil fuel-fired EGUs. The volume of CO2 used in EOR operations can be large  (e.g., 55 million tons of CO2 were stored in the SACROC unit in the Permian Basin over 35 years), and operations at a single oil field may last for decades, injecting into multiple parts of the field.  According to data reported to the EPA's Greenhouse Gas Reporting Program (GHGRP), approximately 66 million tons of CO2 were supplied to EOR in the United States in 2013. Approximately 70 percent of this total CO2 supplied was produced from natural (geologic) CO2 sources, and approximately 30 percent was captured from anthropogenic sources. 
A DOE-sponsored study has analyzed the geographic availability of applying EOR in 11 major oil producing regions of the United States and found that there is an opportunity to significantly increase the application of EOR to areas outside of current operations.  DOE-sponsored geologic and engineering analyses show that expanding EOR operations into areas additional to the capacity already identified and applying new methods and techniques over the next 20 years could utilize 20 billion tons of anthropogenic CO2 and increase total oil production by 67 billion barrels. The availability of anthropogenic CO2 in areas outside of current sources could drive new EOR projects by making more CO2 locally available.
2.8	State Policies on GHG and Clean Energy Regulation in the Power Sector
Several states have also established emission performance standards or other measures to limit emissions of GHGs from new EGUs that are comparable to or more stringent than this rulemaking. 
In 2003, then-Governor George Pataki sent a letter to his counterparts in the Northeast and Mid-Atlantic inviting them to participate in the development of a regional cap-and-trade program addressing power plant CO2 emissions.  This program, known as the Regional Greenhouse Gas Initiative (RGGI), began in 2009 and sets a regional CO2 cap for participating states.  The currently participating states include: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont.  The cap covers CO2 emissions from all fossil-fired EGUs greater than 25 MW in participating states, and limits total emissions to 91 million tons in 2014. The 2014 emissions cap is a 51 percent reduction below the initial cap in 2009 to 2011 of 188 million tons.  This emissions budget is reduced 2.5 percent annually from 2015 to 2020. RGGI CO2 allowances are sold in a quarterly auction. RGGI conducted their 27[th] quarterly allowance auction in March, 2015 the market clearing price was $5.41 per ton of CO2 for current allowances, which was a record high price (the February '15 price of $5.21 was the previous record).  A total of allowances for 15.3 million tons were sold in the March 2015 auction, well below the record of 38.7 million tons sold in June 2013 for $3.21 per ton.
In September 2006, California Governor Schwarzenegger signed into law Senate Bill 1368. The law limits long-term investments in base load generation by the state's utilities to power plants that meet an emissions performance standard jointly established by the California Energy Commission and the California Public Utilities Commission. The Energy Commission has designed regulations that establish a standard for new and existing base load generation owned by, or under long-term contract to publicly owned utilities, of 1,100 lb CO2/MWh -net.
In 2006, Governor Schwarzenegger also signed into law Assembly Bill 32, the Global Warming Solutions Act of 2006.  This act includes a multi-sector GHG cap-and-trade program which covers approximately 85 percent of the state GHG emissions.  EGUs are included in phase I of the program, which began in 2013.  Phase II begins in 2020 and includes upstream sources.  The cap is based on a 2 percent reduction from total 2012 expected emissions, and declines 2 percent annually through 2014, then 3 percent each year until 2020.  The AB32 cap and trade program began functioning in 2011, and functioning market is now operating on the NYMEX futures commodity market. The final 2014 market price for carbon allowances was $11.23/ton of carbon. On April 17, 2015 the 2015 allowance futures price was $11.48/ton, and the spot price was $11.30/ton.
In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, "Base load Electric Generation Performance" which established statewide GHG emissions reduction goals, and imposed an emission standard that applies to any base load electric generation that commenced operation after June 1, 2008 and is located in Washington, whether or not that generation serves load located within the state. Base load generation facilities must initially comply with an emission limit of 1,100 lb CO2/MWh-net. In 2013 the State of Washington revised the emission limit to 970 lb CO2/MWh-net based on a survey of available NGCC generation units commercially available in the United States.
In 1997, Oregon required a new base load gas fired power plants to meet a CO2 emission standard that was 17 percent below the most efficient NGCC unit operating in the United States.  In 2000 Oregon established that the effective 17 percent below most efficient was 675 lb CO2/MWh-net  In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, which mandated that facilities generating base load electricity, whether gas- or coal-fired, must have emissions equal to or less than 1,100 lb CO2/MWh-net regardless of fuel type, and prohibited utilities from entering into long-term purchase agreements for base load electricity with out-of-state facilities that do not meet that standard. Natural gas- and petroleum distillate-fired facilities that are primarily used to serve peak demand or to integrate energy from renewable resources are specifically exempted from the performance standard.
In August 2011, New York Governor Cuomo signed the Power NY Act of 2011. Implementing regulations established CO2 emission standards for new and modified electric generators greater than 25 MW.  The standards vary based on the type of facility: base load facilities must meet a CO2 standard of 925 lb/MWh-net or 120 lb/MMBtu, and peaking facilities must meet a CO2 standard of 1,450 lb/MWh-net or 160 lb/MMBtu.
Several other states have enacted CO2 regulations affecting EGUs that do not set emission limits, but set other regulatory requirements limiting CO2 emissions from EGUs.  For example, Montana enacted a law in 2007 requiring the Public Service Commission to limit approvals of new equity interests in or leases of a facility used to generate coal-based electricity to facilities that capture and sequester at least half of their CO2 emissions.  Minnesota enacted the Next Generation Energy Act in 2007 requiring increases in power sector greenhouse gas emissions from any new large coal energy facilities built in Minnesota or the import of electricity from such a facility located out of state to be offset by equivalent emission reductions.  New Mexico enacted legislation in 2007 authorizing tax credits and cost recovery incentives for qualifying coal-fired facilities. To qualify, plants must capture and store emissions so that they emit less than 1,100 lb CO2/MWh, among other requirements.
Additionally, most states have implemented Renewable Portfolio Standards (RPS), or Renewable Electricity Standards (RES).  These programs are designed to increase the renewable share of a state's total electricity generation.  Currently 29 states, the District of Columbia and Guam have enforceable RPS or other mandatory renewable capacity policies, and 8 states, Puerto Rico and Guam have voluntary goals.  These programs vary widely in structure, enforcement, and scope.  
2.9 	Revenues and Expenses
Due to lower retail electricity sales, total utility operating revenues declined in 2012 to $271 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008 levels in 2012, operating expenses were appreciably lower and as a result, net income also rose in comparison to 2008 (see Table 2-9). Recent economic events have put downward pressure on electricity demand, thus dampening electricity prices and consumption (utility revenues), but have also reduced the price and cost of fossil fuels and other expenses. In 2012 electricity generation was 1.28 percent below the generation in 2011, and has declined in four of the past five years.
Table 2-9 shows that investor-owned utilities (IOUs) earned income of about 13.0 percent compared to total revenues in 2012. The 2012 return on revenue was the third highest year for the period 2002 to 2012 (average: 11.9 percent, range: 10.6 percent to 13.32 percent).

Table 2-9. 	Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities for 2002, 2008 and 2012 (nominal $millions) 
                                       
                                     
2002
                                     
2008
                                     
2012
Utility Operating Revenues
                                    219,609
                                    298,962
                                    270,912
Electric Utility
                                    200,360
                                    266,124
                                    249,166
Other Utility
                                    19,250
                                    32,838
                                    21,745
Utility Operating Expenses
                                    189,062
                                    267,263
                                    235,694
Electric Utility
                                    171,604
                                    236,572
                                    220,722
      Operation
                                    116,660
                                    175,887
                                    152,379
         Production
                                    90,715
                                    140,974
                                    111,714
            Cost of Fuel
                                    24,149
                                    47,337
                                    38,998
            Purchased Power
                                    58,810
                                    84,724
                                    54,570
            Other
                                     7,776
                                     8,937
                                    18,146
      Transmission
                                     3,560
                                     6,950
                                     7,183
      Distribution
                                     3,117
                                     3,997
                                     4,181
      Customer Accounts
                                     4,168
                                     5,286
                                     5,086
      Customer Service
                                     1,820
                                     3,567
                                     5,640
      Sales
                                      264
                                      225
                                      221
      Admin. and 
      General
                                    13,018
                                    14,718
                                    18,353
      Maintenance
                                    10,861
                                    14,192
                                    15,489
      Depreciation
                                    16,199
                                    19,049
                                    23,677
      Taxes and Other
                                    26,716
                                    26,202
                                    29,177
       Other Utility
                                    17,457
                                    30,692
                                    14,972
Net Utility Operating Income
                                    30,548
                                    31,699
                                    35,218
Source: Table 8.3, EIA Electric Power Annual, 2012
Note: These data do not include information for public utilities, nor for IPPs.
2.10 	Natural Gas Market
The natural gas market in the United States has historically experienced significant price volatility from year to year and between seasons, can undergo major price swings during short-lived weather events (such as cold snaps leading to short-run spikes in heating demand), and has seen a dramatic shift since 2008 due to increased production from shale formations. Over the last decade, the annual average nominal price of gas delivered to the power sector peaked in 2008 at $9.02/MMBtu and has since fallen dramatically to a low of $3.42/MMBtu in 2012. During that time, the daily price of natural gas reached as high as $18.48/MMBtu and as low as $2.03/MMBtu.  Adjusting for inflation using the GDP implicit price deflator, in 2011 dollars the annual average price of natural gas delivered to the power sector peaked at $9.38/MMBtu in 2008 and has fallen to a low of $3.36/MMBtu in 2012.  The annual natural gas prices in both nominal and real (2011$) terms are shown in Figure 2-22. A comparison of the trends in the real price of natural gas with the real prices of delivered coal and oil is shown in Figure 2-23. Figure 2-23 shows that while the real price of coal and oil increased from 2002 to 2012 (+54 percent and +203 percent respectively), the real price of natural gas declined by 22 percent in the same period. Most of the decline in real natural gas prices occurred between 2008 (the peak price year) and 2012, during which real gas prices declined by 64 percent while coal and oil prices both increased by 9 percent in the same period.  The sharp decline in natural gas prices from 2008 to 2012 was primarily caused by the rapid increase in natural gas production from shale formations.


Figure 2-22.	Nominal and Real (2011$) Prices of Natural Gas Delivered to the Power Sector ($/MMBtu)
Source: http://www.eia.gov/totalenergy/data/monthly/#prices. Downloaded 2/15/2015.




Figure 2-23.	 Relative Change in Real (2011$) Prices of Fossil Fuels Delivered to the Power Sector ($/MMBtu)
Source: http://www.eia.gov/totalenergy/data/monthly/#prices. Downloaded 2/15/2015.

Current and projected natural gas prices are considerably lower than the prices observed over the past decade, largely due to advances in hydraulic fracturing and horizontal drilling techniques that have opened up new shale gas resources and substantially increased the supply of economically recoverable natural gas. According to the U.S. Energy Information Administration's Annual Energy Outlook 2012 (AEO 2012) (EIA 2012):
      Shale gas refers to natural gas that is trapped within shale formations. Shales are fine-grained sedimentary rocks that can be rich sources of petroleum and natural gas. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. The production of natural gas from shale formations has rejuvenated the natural gas industry in the United States.
The EIA's AEO 2014 estimates that the United States possessed 2,266 trillion cubic feet (Tcf) of technically recoverable dry natural gas resources as of January 1, 2012. Proven reserves make up 15 percent of the technically recoverable total estimate, with the remaining 85 percent from unproven reserves. Natural gas from proven and unproven shale resources accounts for 611 Tcf of this resource estimate. 
Many shale formations, especially the Marcellus, are so large that only small portions of the entire formations have been intensively production-tested. Furthermore, estimates from the Marcellus and other emerging fields with few wells already drilled are likely to shift significantly over time as new geological and production information becomes available. Consequently, there is some uncertainty in estimate of technically recoverable resources, and it is regularly updated as more information is gained through drilling and production. 
At the 2012 rate of U.S. consumption (about 25.6 Tcf per year), 2,266 Tcf of natural gas is enough to supply nearly 90 years of use. The AEO 2014 estimate of the shale gas resource base is modestly higher than the AEO 2012 estimate (2,214 Tcf) of shale gas production, driven by lower drilling costs and continued drilling in shale plays with high concentrations of natural gas liquids and crude oil, which have a higher value in energy equivalent terms than dry natural gas.
EIA's projections of natural gas conditions did not change substantially in AEO 2014 from either the AEO 2012 or 2013, and EIA is continues to forecast  abundant reserves consistent with the above findings.  Recent historical data reported to EIA is also consistent with these trends, with 2014 being the highest year on record for domestic natural gas production. 
2.11 	References
Advanced Resources International. Improving Domestic Energy Security and Lowering CO2 Emissions with "Next Generation" CO2-Enhanced Oil Recovery (CO2-EOR). 2011. Available online at: http://www.netl.doe.gov/research/energy-analysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-04a505a19185. Clean Energy States Alliance (CESA). The State of State Renewable Portfolio Standards. June 2013. Available online at http://www.cesa.org/assets/2013-Files/RPS/State-of-State-RPSs-Report-Final-June-2013.pdfHan, Weon S., McPherson, B J., Lichtner, P C., and Wang, F P. Evaluation of CO2 trapping mechanisms at the SACROC northern platform, Permian basin, Texas, site of 35 years of CO2 injection. American Journal of Science 310. (2010): 282-324.Independent Monitor's Prudency Evaluation Report for the Kemper County IGCC Project. April 15, 2014. Available online at: http://www.psc.state.ms.us/InsiteConnect/InSiteView.aspx?model=INSITE_CONNECT&queue=CTS_ARCHIVEQ&docid=328417.
Interagency Task Force on Carbon Capture and Storage. Report of the Interagency Task Force on Carbon Capture and Storage. August 2010. Available online at: http://www.epa.gov/climatechange/downloads/CCS-Task-Force-Report-2010.pdf. 
Intergovernmental Panel on Climate Change. Climate Change 2001: The Scientific Basis. 2001. Available online at: http://www.grida.no/publications/other/ipcc_tar/?src=/climate/ipcc_tar/wg1/218.htm. 
International Energy Agency (IEA). Tracking Clean Energy Progress 2013. Input to the Clean Energy Ministerial. 2013. Available online at: http://www.iea.org/etp/tracking/.
Koottungal, Leena. 2014 Worldwide EOR Survey, Oil & Gas Journal, Volume 112, Issue 4, April 7, 2014 (corrected tables appear in Volume 112, Issue 5, May 5, 2014).
National Energy Technology Laboratory (NETL). Reducing CO2 Emissions by Improving the Efficiency of Existing Coal-fired Power Plant Fleet. July 2008. Available online at: http://www.netl.doe.gov/energy-analyses/pubs/CFPP%20Efficiency-FINAL.pdf.
National Energy Technology Laboratory (NETL). The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition. 2012. Available online at: http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlasIV/.
National Energy Technology Laboratory (NETL). Energy Analyses: Cost and Performance Baselines for Fossil Energy Plants. 2013. Available online at: http://www.netl.doe.gov/energy-analyses/baseline_studies.html.
Pacific Northwest National Laboratory (PNNL). An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009. June 2009. Available online at: http://www.pnl.gov/science/pdf/PNNL-18520_Status_of_CCS_062009.pdf.
U.S. Energy Information Administration (U.S. EIA). Carbon Dioxide Emissions from the Generation of Electric Power in the United States. July 2000. Available online at: ftp://ftp.eia.doe.gov/environment/co2emiss00.pdf.
U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2003. 2003. Available online at: http://www.eia.gov/electricity/annual/archive/03482003.pdf.  
U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2009. 2009. Available online at: http://www.eia.gov/electricity/annual/archive/03482009.pdf. 
U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2011. 2013. Available online at: http://www.eia.gov/electricity/annual/.   
U.S. Energy Information Administration (U.S. EIA). "Status of Electricity Restructuring by State." 2010a. Available online at: http://www.eia.gov/cneaf/electricity/page/restructuring/restructure_elect.html.
U.S. Energy Information Administration (U.S. EIA). AEO 2010 Retrospective Review. 2010b. Available online at: http://www.eia.gov/forecasts/aeo/retrospective/.  
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010c. Available online at: http://www.eia.gov/oiaf/archive/aeo10/index.html. 
U.S. Energy Information Administration (U.S. EIA). Annual Energy Review 2010. 2010d. Available online at: http://www.eia.gov/totalenergy/data/annual/pdf/aer.pdf.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2011. 2011. Available online at: http://www.eia.gov/forecasts/archive/aeo11/. 
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2012 (Early Release). 2012. Available online at: http://www.eia.gov/forecasts/aeo/.
U.S. Energy Information Administration (U.S. EIA). Today in Energy: Most states have Renewable Portfolio Standards.  2012a. Available online at: http://www.eia.gov/todayinenergy/detail.cfm?id=4850.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available online at: http://www.eia.gov/forecasts/aeo/.
U.S. Energy Information Administration (U.S. EIA). Monthly Energy Review, April 2015. 2015. Available online at: http://www.eia.gov/totalenergy/data/monthly/.
U.S. Environmental Protection Agency (U.S. EPA). Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 - 2011. April 2013. Available online at: http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-Main-Text.pdf.
U.S. Geological Survey (USGS) Carbon Dioxide Storage Resources Assessment Team. National assessment of geologic carbon dioxide storage resources  -  Results: U.S. Geological Survey Circular 1386. Available online at: http://pubs.usgs.gov/circ/1386/.    
 Chapter 3
Benefits of Reducing Greenhouse Gas Emissions and Other Pollutants
 This rule is designed to set emission limits for carbon dioxide (CO2), thereby limiting potential increases in future emissions and atmospheric CO2 concentrations. This will reduce the risk of adverse effects of climate change. As discussed in Chapter 4, the U.S. Environmental Protection Agency (EPA) anticipates negligible CO2 emission changes resulting from the rule relative to baseline conditions, due to market baseline market conditions. The final standards provide the benefit of regulatory certainty that any new coal-fired power plant must limit its CO2 emissions to a level reflecting the performance of a highly efficient super critical pulverized coal (SCPC) unit utilizing post-combustion partial carbon capture and storage (CCS).  As explained in preamble section V.P.1.b, there are documented instances of project developers abandoning projects using CCS due to this lack of regulatory certainty.  In addition, the history of regulatory actions has shown that emission standards that are based on the performance  of advanced control equipment lead to increased use of that control equipment, and that the absence of a requirement stifles technology development. (See preamble section V.P.1.b.) 
This chapter summarizes the adverse effects on public health and public welfare from the emissions of CO2, which is a well-mixed greenhouse gas. This form of air pollution was determined by the EPA in the 2009 Endangerment Finding to endanger public health and welfare. The major assessments by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) served as the primary scientific bases for the Endangerment Finding. A discussion of climate science findings from newer assessments can be found in the Preamble. This chapter also provides a general discussion about how the climate-related and human health benefits of emissions reductions are estimated.  These valuation approaches are used in Chapter 5 to quantify and monetize the relative differences in emissions between electric generating technologies that may be constructed in the future.
3.1	Overview of Climate Change Impacts from GHG Emissions
Through the implementation of CAA regulations, the EPA addresses the negative externalities caused by air pollution.  The preamble to the final rule summarizes the public health and public welfare impacts that were detailed in the 2009 Endangerment Finding. For health, these include the increased likelihood of heat waves, negative impacts on air quality, more intense hurricanes, more frequent and intense storms and heavy precipitation, and impacts on infectious and waterborne diseases. For welfare, these include reduced water supplies in some regions, increased water pollution, increased occurrences of floods and droughts, rising sea levels and damage to coastal infrastructure, increased peak electricity demand, changes in ecosystems, and impacts on indigenous communities. 
The preamble also summarizes new scientific assessments and recent climatic observations. Major scientific assessments released since the 2009 Endangerment Finding have further improved scientific understanding of climate change, and provide even more evidence that GHG emissions endanger public health and welfare for current and future generations. The Third National Climate Assessment (NCA3), in particular, assessed the impacts of climate change on human health in the United States, finding that, Americans will be impacted by "increased extreme weather events, wildfire, decreased air quality, threats to mental health, and illnesses transmitted by food, water, and disease-carriers such as mosquitoes and ticks." The IPCC reported similar conclusions in its Fifth Assessment Report, finding that it is likely that adverse health impacts related to heat exposure are already being exacerbated by climate change and that, if unabated, climate change will lead to a greater risk of morbidity and mortality due to more intense heat waves, undernutrition, and increased prevalence of food- and water-borne illnesses. These assessments also detail the risks to vulnerable groups such as children, the elderly and low income households. Furthermore, the assessments present an improved understanding of the impacts of climate change on public welfare, improved projections of future warming over the next century, higher projections of future sea level rise than had been previously estimated due in part to improved understanding of the Antarctic and Greenland ice sheets, more detailed description of U.S. impacts based on the National Climate Assessment, improved understanding of changes in rainfall and droughts, and new assessments of the impacts of climate change on permafrost and ocean acidification. The impacts of GHG emissions will be realized worldwide, independent upon their location of origin, and impacts outside of the United States will produce consequences relevant to the United States.      
3.2	Social Cost of Carbon
The social cost of carbon (SC-CO2) is a metric that estimates the monetary value of impacts associated with marginal changes in CO2 emissions in a given year. It includes a wide range of anticipated climate impacts, such as net changes in agricultural productivity and human health, property damage from increased flood risk, and changes in energy system costs, such as reduced costs for heating and increased costs for air conditioning. It is typically used to assess the avoided damages as a result of regulatory actions (i.e., benefits of rulemakings that lead to an incremental reduction in cumulative global CO2 emissions). This section discusses the development of the SC-CO2 estimates and the analyses in Chapter 5 apply the SC-CO2 estimates to illustrate the value to society of the difference in CO2 emissions among different generation technologies.   
The SC-CO2 estimates used in these analyses were developed over many years, using the best science available, and with multiple opportunities for input from the public, which is discussed further below.  Specifically, an interagency working group (IWG) that included the EPA and other executive branch agencies and offices used three integrated assessment models (IAMs) to develop the SC-CO2 estimates and recommended four global values for use in regulatory analyses. As noted in the Government Accountability Office's 2014 review, this interagency working group (1) used consensus-based decision-making, (2) relied on existing academic literature and modeling, and (3) took steps to disclose limitations and incorporate new information by considering public comments and revising the estimates as updated research became available. 
The SC-CO2 estimates were first released in February 2010 and updated in 2013 using new versions of each IAM.  As discussed further below, the IWG published two minor corrections to the SC-CO2 estimates in July 2015. These estimates are published in the Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866 ("current SC-CO2 TSD") and henceforth we refer to them as the "SC-CO2 estimates."   
The SC-CO2 estimates were developed using an ensemble of the three most widely cited integrated assessment models in the economics literature with the ability to estimate the SC-CO2. A key objective of the IWG was to draw from the insights of the three models while respecting the different approaches to linking GHG emissions and monetized damages taken by modelers in the published literature. After conducting an extensive literature review, the interagency group selected three sets of input parameters (climate sensitivity, socioeconomic and emissions trajectories, and discount rates) to use consistently in each model. All other model features were left unchanged, relying on the model developers' best estimates and judgments, as informed by the literature. Specifically, a common probability distribution for the equilibrium climate sensitivity parameter, which informs the strength of climate's response to atmospheric GHG concentrations, was used across all three models. In addition, a common range of scenarios for the socioeconomic parameters and emissions forecasts were used in all three models. Finally, the marginal damage estimates from the three models were estimated using a consistent range of discount rates, 2.5, 3.0, and 5.0 percent. See the 2010 SC-CO2 TSD for a complete discussion of the methods used to develop the estimates and the key uncertainties, and the current SC-CO2 TSD for the latest estimates.  
The SC-CO2 estimates represent global measures because of the distinctive nature of the climate change, which is highly unusual in at least three respects. First, emissions of most GHGs contribute to damages around the world independent of the country in which they are emitted. The SC-CO2 must therefore incorporate the full (global) damages caused by GHG emissions to address the global nature of the problem. Second, the U.S. operates in a global and highly interconnected economy, such that impacts on the other side of the world can affect our economy.  This means that the true costs of climate change to the U.S. are larger than the direct impacts that simply occur within the U.S. Third, climate change represents a classic public goods problem because each country's reductions benefit everyone else and no country can be excluded from enjoying the benefits of other countries' reductions, even if it provides no reductions itself. In this situation, the only way to achieve an economically efficient level of emissions reductions is for countries to cooperate in providing mutually beneficial reductions beyond the level that would be justified only by their own domestic benefits. In reference to the public good nature of mitigation and its role in foreign relations, thirteen prominent academics noted that these "are compelling reasons to focus on a global [SC-CO2]" in a recent article on the SC-CO2 (Pizer et al., 2014). In addition, as noted in OMB's Response to Comments on the SC-CO2, there is no bright line between domestic and global damages. Adverse impacts on other countries can have spillover effects on the United States, particularly in the areas of national security, international trade, public health and humanitarian concerns.
 
The 2010 SC-CO2 TSD noted a number of limitations to the SC-CO2 analysis, including the incomplete way in which the integrated assessment models capture catastrophic and 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 due to a lack of precise information on the nature of damages and because the science incorporated into these models understandably lags behind the most recent research. The limited amount of research linking climate impacts to economic damages makes the modeling exercise even more difficult. These individual limitations do not all work in the same direction in terms of their influence on the SC-CO2 estimates, though taken together they suggest that the SC-CO2 estimates are likely conservative. In particular, the IPCC Fourth Assessment Report (2007), which was the most current IPCC assessment available at the time of the IWG's 2009-2010 review, concluded that "It is very likely that [SC-CO2 estimates] underestimate the damage costs because they cannot include many non-quantifiable impacts." Since then, the peer-reviewed literature has continued to support this conclusion. For example, the IPCC Fifth Assessment report observed that SC-CO2 estimates continue to omit various impacts that would likely increase damages. The 95th percentile estimate was included in the recommended range for regulatory impact analysis to address these concerns.
The EPA and other agencies have continued to consider feedback on the SC-CO2 estimates from stakeholders through a range of channels, including public comments on this rulemaking and others that use the SC-CO2 in supporting analyses and through regular interactions with stakeholders and research analysts implementing the SC-CO2 methodology used by the interagency working group. The SC-CO2 comments received on this rulemaking covered a wide range of topics including the technical details of the modeling conducted to develop the SC-CO2 estimates, the aggregation and presentation of the SC-CO2 estimates, and the process by which the SC-CO2 estimates were derived. The EPA Response to Comments document provides a summary and response to the SC-CO2 comments submitted to this rulemaking.
Many of the comments the EPA received in this proceeding mirrored those that OMB received in response to a separate request for public comment on the approach used to develop the estimates and the EPA has carefully considered those comments and responses here.   After careful evaluation of the full range of comments submitted to OMB, the IWG continued to recommend the use of these SC-CO2 estimates in regulatory impact analysis. The IWG remains committed to ensuring that the SC-CO2 estimates continue to reflect the best available scientific and economic information on climate change.  In light of this commitment, the IWG announced plans to obtain expert independent advice from the National Academies of Sciences, Engineering, and Medicine. The Academies process will be informed by the public comments received and focus on the technical merits and challenges of potential approaches to improving the SC-CO2 estimates in future updates.
 OMB also has published a revised TSD that informed our analysis here.  The revision to the TSD is limited to two minor technical corrections to the current estimates. One technical correction addressed an inadvertent omission of climate change damages in the last year of analysis (2300) in one model and the second addressed a minor indexing error in another model. On average the revised recommended SC-CO2 estimates are one dollar less than the mean SC-CO2 estimates reported in the November 2013 revision to the May 2013 TSD. The change in the estimates associated with the 95th percentile estimates when using a 3 percent discount rate is slightly larger, as those estimates are heavily influenced by the results from the model that was affected by the indexing error.
The EPA has examined the minor technical corrections in the revised TSD and the public comments -- including those submitted to OMB's separate SC-CO2 comment process -- here as part of its consideration of whether and how to use SC-CO2 estimates in this proceeding.  Based on this examination, the EPA concurs with the consensus-based interagency working group, of which it is an active member, and finds that it is reasonable, and scientifically appropriate, to use the current SC-CO2 estimates for purposes of analysis here. 
The four SC-CO2 estimates the EPA is selecting to use in its analysis here are as follows: $13, $41, $62, and $120 per short ton of CO2 emissions in the year 2022 (2011$).  The first three values are based on the average SC-CO2 from the three IAMs, at discount rates of 5, 3, and 2.5 percent, respectively. SC-CO2 estimates for several discount rates are included because the literature shows that the SC-CO2 is quite sensitive to assumptions about the discount rate, and because no consensus exists on the appropriate rate to use in an intergenerational context (where costs and benefits are incurred by different generations). The fourth value is the 95th percentile of the SC-CO2 from all three models at a 3 percent discount rate. It is included to represent higher-than-expected impacts from temperature change further out in the tails of the SC-CO2 distribution (representing less likely, but potentially catastrophic, outcomes).
Table 3-1 presents the global SC-CO2 estimates for the years 2015 to 2050. In order to calculate the dollar value for emission reductions, the SC-CO2 estimate for each emissions year would be applied to changes in CO2 emissions for that year, and then discounted back to the analysis year using the same discount rate used to estimate the SC-CO2.  The SC-CO2 increases over time because future emissions are expected to produce larger incremental damages as physical and economic systems become more stressed in response to greater climate change. Note that the interagency group estimated the growth rate of the SC-CO2 directly using the three integrated assessment models rather than assuming a constant annual growth rate. This helps to ensure that the estimates are internally consistent with other modeling assumptions.   
Table 3-1.	Social Cost of CO2, 2015-2050[a] (in 2011$)
                                       
                                     Year
                          Discount Rate and Statistic
                                       
                                  5% Average
                                  3% Average
                                 2.5% Average
                                      3%
                               95[th] percentile
                                     2015
                                      $11
                                      $35
                                      $54
                                     $100
                                     2020
                                      $12
                                      $41
                                      $60
                                     $120
                                     2022
                                      $13
                                      $41
                                      $62
                                     $120
                                     2025
                                      $13
                                      $44
                                      $65
                                     $130
                                     2030
                                      $15
                                      $48
                                      $70
                                     $150
                                     2035
                                      $17
                                      $53
                                      $75
                                     $160
                                     2040
                                      $20
                                      $58
                                      $81
                                     $180
                                     2045
                                      $22
                                      $62
                                      $86
                                     $190
                                     2050
                                      $25
                                      $66
                                      $90
                                     $200
[a] These SC-CO2 values are stated in $/short ton and rounded to two significant figures. Unrounded estimates from the current TSD have been converted from $/metric ton to $/short ton using conversion factor 0.90718474 for consistency with this rulemaking and adjusted to 2011$ using the GDP Implicit Price Deflator (1.0613744). This calculation does not change the underlying methodology nor does it change the meaning of the SC-CO2 estimates. For both metric and imperial denominated SC-CO2 estimates, the values vary depending on the year of CO2 emissions and are defined in real terms. The unrounded 2011$ estimates are used in the Chapter 5 illustrative analysis.  The SC-CO2 estimates shown in this table have been rounded to two significant digits.

3.3	Health Co-Benefits of SO2 and NOx Reductions 
The EPA anticipates that this rule will result in negligible emission changes over the baseline by 2022. However, if CO2 emissions are reduced from new EGUs under this rule, then emissions of other pollutants from the power sector would also likely be reduced. For example, reducing CO2 emissions through the adoption of CCS by coal-fired boilers may also yield sulfur dioxide (SO2) and emission reductions, which in turn would yield health benefits. We refer to these additional benefits as "co-benefits". 
SO2 is a precursor for fine particulate matter formation, which is particulate matter 2.5 micrometers in diameter and smaller (PM2.5), while NOX is a precursor for PM2.5 and ground-level ozone formation. As such, reductions of SO2 and NOX would in turn lower overall ambient concentrations of PM2.5 and ozone. Reducing exposure to PM2.5 and ozone is associated with human health benefits including avoided mortality and morbidity. Researchers have associated PM2.5 and ozone exposure with adverse health effects in numerous toxicological, clinical, and epidemiological studies (U.S. EPA, 2009; U.S. EPA, 2013a). Health effects associated with exposure to PM2.5 include premature mortality for adults and infants, cardiovascular morbidity such as heart attacks and hospital admissions, and respiratory morbidity such as asthma attacks, bronchitis, hospital and emergency room visits, work loss days, restricted activity days, and respiratory symptoms. Health effects associated with exposure to ozone include premature mortality and respiratory morbidity such as hospital admissions, emergency room visits, and school loss days. In addition to human health co-benefits associated with PM2.5 and ozone exposure, reducing SO2 and NOX emissions under this rule would result in reduced health impacts from direct exposure to these pollutants. For example, ambient concentrations of SO2 are associated with respiratory symptoms in children, emergency department visits, and hospitalizations for respiratory conditions.   
Reducing SO2 and NOX emissions would also result in other human welfare (non-health) improvements including improvements in ecosystem services. SO2 and NOX emissions can adversely impact vegetation and ecosystems through acidic deposition and nutrient enrichment, and can affect certain manmade materials, visibility, and climate (U.S. EPA, 2009; U.S. EPA, 2008). 
The avoided incidences of health effects and monetized value of health or non-health improvements that result from SO2 and NOx emissions reductions depend on the location of those reductions. For a full discussion of the human health, ecosystem and other benefits of reducing SO2 and NOX emissions from power sector sources, please refer to the Regulatory Impact Analysis for the Final Carbon Pollution Guidelines for Existing Power Plants (U.S. EPA, 2015).
As described in Chapter 4, the EPA anticipates that this rule will result in no emission changes by 2022. As a result we did not need to perform a full health co-benefit impact assessment for a specific modeled compliance scenario. In Chapter 5, the EPA presents results for several illustrative plant-level analyses that show the potential impacts of the rule if certain key assumptions were to change substantially.  When assessing the co-benefits of differences in emissions from different generation technologies in Chapter 5, the EPA does not assume a specific location for the illustrative new unit. Instead, the EPA relied on a national-average benefit per-ton (BPT) method to estimate PM2.5-related health impacts of SO2 and NOX emissions. The BPT approach provides an estimate of the total monetized human health benefits (the sum of premature mortality and morbidity) of reducing one ton of PM2.5 precursor (i.e., NOX and SO2) from the sector. To develop the BPT estimates used in this analysis the EPA utilized detailed air quality modeling of the entire power sector SO2 and NOX emissions along with the BenMAP model to estimate the benefits of air quality improvements using projected 2020 population, baseline incidence rates, and economic factors.
The SO2- and NOX-related BPT estimates utilized in this analysis are derived from the TSD on estimating the BPT of reducing PM2.5 and its precursors (U.S. EPA, 2013b). These BPT values are estimated in a methodologically consistent manner with those reported in Fann et al. (2012). They differ from those reported in Fann et al. (2012) as they reflect the health impact studies and population data updated in the benefits analysis of the final PM NAAQS RIA (U.S. EPA, 2012). The recalculation of the Fann et al. (2012) BPT values based on the updated data from the PM NAAQS RIA (U.S. EPA, 2012) is described in the TSD (U.S. EPA, 2013b). The BPT values are for the entire electricity sector and are not differentiated by fuel or generator type. 
The methods used for this analysis are consistent with those used to estimate the health co-benefits from secondary PM2.5 formation for the Regulatory Impact Analysis for the Final Carbon Pollution Guidelines for Existing Power Plants (U.S. EPA, 2015).  One notable difference between the BPT values used in the two analyses is that this analysis utilizes national-average BPT estimates because the EPA does not assert a specific location for the illustrative new unit, whereas the BPT estimates used in the RIA for the final existing source guidelines differ by region. 
Despite our attempts to quantify and monetize as many of the co-benefits of reducing emissions from electricity generating sources as possible, not all known health and non-health co-benefits from reducing SO2 and NOx are accounted for in this assessment. For more information about unquantified health and non-health co-benefits of SO2 and NOx please refer to tables 5-2 and 6-2 of the PM NAAQS RIA (U.S. EPA, 2012), respectively. Furthermore, the analysis that follows does not account for known differences in other air and water pollutants between the different generating technologies, including, for example, ozone or directly-emitted PM.  The implications for limiting our consideration of co-benefits to pollutants that cause secondary PM2.5 is discussed in Chapter 5. 
As we do not assume a specific location for the new units being compared, this RIA is unable to include the type of detailed uncertainty assessment found in the RIA for the National Ambient Air Quality Standards for Particulate Matter (PM NAAQS RIA) (U.S. EPA, 2012). However, the results of the uncertainty analyses presented in the PM NAAQS RIA can provide some information regarding the uncertainty inherent in the benefits results presented in this analysis. In addition to the uncertainties described in the PM NAAQS RIA, the use of BPT estimates come with additional uncertainty. Specifically, these national-average BPT estimates reflect a specific geographic distribution of SO2 and NOX reductions resulting in a specific reduction in PM2.5 exposure and may not fully reflect local or regional variability in population density, meteorology, exposure, baseline health incidence rates, timing of emissions, or other factors that might lead to an over-estimate or under-estimate of the actual benefits associated with PM2.5 precursors in a specific location. These estimates are illustrative as the EPA does not assume a specific location for the illustrative electricity generation technologies and is therefore unable to specifically determine the population that would be affected by their emissions. Therefore, the benefits for any specific unit can be different than the estimates shown here. 
Notwithstanding these limitations, reducing one thousand tons of annual SO2 from U.S. power sector sources has been estimated to yield between four and nine 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 percent discount rate or between $34 million and $76 million (2011$) using a 7 percent discount rate. Additionally, reducing one thousand tons of annual NOX from U.S. EGUs has been estimated to yield up to one incidence of premature mortality avoided and monetized PM2.5-related health benefits (including these incidences of premature mortality avoided) of between $5.5 million and $12 million in 2020 (2011$) using a 3 percent discount rate or between $5.0 million and $11 million (2011$) using a 7 percent discount rate. For each pollutant, the range of estimated benefits for each discount rate is due to the EPA's use of two alternative primary estimates of PM2.5-related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a higher primary estimate based on Lepeule et al. (2012). The benefit per ton values are reported in Table 3-2. 
Table 3-2.	Monetized Health Benefits Per Ton of PM2.5 Precursor Reductions in 2020[a] (in 2011$)
                                       
                                PM2.5 Precursor
                                       
                                      SO2
                                      NOX
3% Discount Rate
                                       
                                       
   Krewski et al. (2009)
                                   $38,000 
                                    $5,500
   Lepeule et al. (2012)
                                    $85,000
                                    $12,000
7% Discount Rate
                                       
                                       
   Krewski et al. (2009)
                                    $34,000
                                    $5,000
   Lepeule et al. (2012)
                                    $76,000
                                    $11,000
[a] These estimates are from U.S. EPA, 2013a (electricity generating units) and are adjusted to 2011$ using the Gross Domestic Product implicit price deflator reported by the Department of Commerce.
3.4	References
40 CFR Chapter I [EPA - HQ - OAR - 2009 - 0171; FRL - 9091 - 8] RIN 2060 - ZA14, "Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act," Federal Register / Vol. 74, No. 239 / Tuesday, December 15, 2009 / Rules and Regulations.
Fann, N., K.R. Baker, C.M. Fulcher. 2012. Characterizing the PM2.5-related health benefits of emission reductions for 17 industrial, area and mobile emission sectors across the U.S. Environment International, Volume 49, 15 November 2012, Pages 141-151, ISSN 0160- 4120, http://dx.doi.org/10.1016/j.envint.2012.08.017. 
Interagency Working Group (IWG) on Social Cost of Carbon (SC-CO2). 2010. Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. Docket ID EPA-HQ-OAR-2009-0472-114577. Participation by Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture, Department of Commerce, Department of Energy, Department of Transportation, Environmental Protection Agency, National Economic Council, Office of Energy and Climate Change, Office of Management and Budget, Office of Science and Technology Policy, and Department of Treasury. http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf Accessed March 31, 2015.
Interagency Working Group (IWG) on Social Cost of Carbon (SC-CO2). 2013, Revised July 2015. Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. Docket ID EPA-HQ-OAR-2013-0495. Participation by Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture, Department of Commerce, Department of Energy, Department of Transportation, Domestic Policy Council, Environmental Protection Agency, National Economic Council, Office of Management and Budget, Office of Science and Technology Policy, and Department of Treasury. <http://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf > Accessed July 2, 2015.
Intergovernmental Panel on Climate Change (IPCC). 2007. Climate Change 2007: Synthesis Report. Contribution of Working Groups I, II and III to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change (AR4) [Core Writing Team, Pachauri, R.K and Reisinger, A. (eds.)]. IPCC, Geneva, Switzerland, 104 pp. <http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report_synthesis_report.htm>. Accessed March 30, 2015.
Intergovernmental Panel on Climate Change (IPCC). 2014. Climate Change 2014: Impacts, Adaptation, and Vulnerability. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA. 
Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz, and W.H. White. 2009. "Reanalysis of the Harvard Six Cities Study and the American Cancer Society Study of Particulate Air Pollution and Mortality." Special Report to the Health Effects Institute. Cambridge, MA. July.
Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. "Chronic Exposure to Fine Particles and Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009." Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.
Medina-Ramon, M. and J. Schwartz, 2007: Temperature, temperature extremes, and mortality: a study of acclimatization and effect modification in 50 U.S. cities.  Occupational and Environmental Medicine, 64(12), 827-833.
National Research Council (NRC). 2009. Hidden Cost of Energy: Unpriced Consequences of Energy Production and Use. National Academies Press. Washington, DC.
National Research Council (NRC). 2013. Climate and Social Stress: Implications for Security Analysis. The National Academies Press. Washington, DC.
Pizer, W., M. Adler, J. Aldy, D. Anthoff, M. Cropper, K. Gillingham, M. Greenstone, B. Murray, R. Newell, R. Richels, A. Rowell, S. Waldhoff, J. Wiener. 2014. "Using and improving the social cost of carbon." Science, Vol. 346, No. 6214, 12/05/14, pp 1189-1190.
U.S. Environmental Protection Agency (U.S. EPA). 2008. Integrated Science Assessment for Oxides of Nitrogen and Sulfur  - Ecological Criteria National (Final Report). National Center for Environmental Assessment, Research Triangle Park, NC. EPA/600/R-08/139. December. Available on the Internet at http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485. 
U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for Environmental Assessment  -  RTP Division. December. Available on the Internet at http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.
U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf. 
U.S. Environmental Protection Agency (U.S. EPA). 2013a. Integrated Science Assessment for Ozone and Related Photochemical Oxidants. EPA/600/R-10/076F. Research Triangle Park, NC: U.S. EPA. February. Available on the Internet at http://oaspub.epa.gov/eims/eimscomm.getfile?p_download_id=511347. 
U.S. Environmental Protection Agency (U.S. EPA). 2013b. Technical Support Document Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on the Internet at http://www2.epa.gov/sites/production/files/2014-10/documents/sourceapportionmentbpttsd.pdf 
U.S. Environmental Protection Agency (U.S. EPA). 2015. Regulatory Impact Analysis for the Final Carbon Pollution Guidelines for Existing Power Plants. 
U.S. Global Change Research Program (USGCRP). Global Climate Change Impacts in the United States.  Thomas R. Karl, Jerry M. Melillo, and Thomas C. Peterson, (eds.). Cambridge University Press, 2009.
 Chapter 4
Costs, Economic, and Energy Impacts of the New Source Standards
4.1	Synopsis
This chapter reports the compliance cost, economic, and energy impact analyses performed for the final EGU New Source GHG Standards. The U.S. Environmental Protection Agency (EPA) analyzed and assessed a wide range of potential scenarios and outcomes, using a detailed power sector model, other government projections for the power sector, and additional economic assessments and analyses to determine the potential impacts of this action.  
The primary finding of this assessment is that in the baseline, all projected unplanned capacity additions affected by these standards during the analysis period would already be compliant with the rule's requirements (e.g., natural gas combined cycle units, low capacity factor natural gas combustion turbines, and small amounts of coal-fired units with carbon capture and storage (CCS) supported by federal and state funding). The analysis period is defined as through 2022 to reflect that CAA Section 111(b) requires that the NSPS be reviewed every eight years.  The EPA's conclusion was based on:
      * EIA power sector modeling projections,
      * EPA power sector modeling projections,
      * Electric utility integrated resource planning (IRP) documents, and
      * Projected new EGUs reported by industry to the U.S. Energy Information Administration (EIA).
The EPA's forecast of no new non-compliant coal-fired capacity remains robust beyond the analysis period (past 2030 in both EIA and EPA baseline modeling projections) and across a wide range of alternative potential market, technical, and regulatory scenarios that influence power sector investment decisions.  As a result, the EGU New Source GHG Standards are not expected to change GHG emissions for newly constructed EGUs, and are anticipated to yield no monetized benefits and impose negligible costs, economic impacts, or energy impacts on the electricity sector or society.  While the EPA does not project any new coal-fired EGUs without CCS to be built in the absence of this rule, this chapter presents an analysis of the project-level costs of building new coal-fired capacity with and without CCS to demonstrate that a requirement of partial CCS would not preclude new coal construction due to economic conditions.  An additional illustrative analysis, presented in Chapter 5, shows that even in the unlikely event that new, non-compliant EGU capacity would be built, the final EGU New Source GHG Standards would provide net benefits under a range of assumptions.
4.2	Requirements of the Final GHG EGU NSPS
      In this action, the EPA is finalizing standards of performance for two basic categories of new units that have not commenced construction by January 8, 2014: (i) fossil fuel-fired electric utility steam generating units (boilers and IGCC units) and (ii) natural gas-fired stationary combustion turbines that generate electricity for sale and meet certain applicability criteria.
      
      The EPA is finalizing standards of performance for affected EGUs within the following two categories: (1) all fossil fuel-fired steam generating units (steam generating units, boilers and integrated gasification combined cycle (IGCC) units), and (2) all natural gas-fired stationary combustion turbines, regardless of the size of the stationary turbine unit. All affected new fossil fuel-fired EGUs would be required to meet an output-based emission rate of a specific mass of carbon dioxide (CO2) per megawatt-hour (MWh) of electricity generated energy output on a gross basis.  
      
      New fossil fuel-fired steam generating units (boilers and IGCC units) would be required to meet an emission standard of 1,400 lb CO2/MWh of gross energy output. 
      
      Newly constructed natural gas-fired stationary combustion turbines will be required to meet a standard of 1,000 lb CO2/MWh of gross energy output (or 1,030 lb CO2/MWh of net energy output). This emission limit applies to all affected natural gas-fired stationary combustion units regardless of size. The natural gas combustion turbine standard, however, will only apply to units that will exceed a sales threshold on the amount of electricity generated that is sold to the electric grid. The purpose of the sales threshold criterion is to permit gas-fired combustion turbines that only sell a small portion of the gross electricity generated to the grid ("non-base load units") to not have to meet the same emission standard as a combustion turbine unit designed primarily to generate base and intermediate electricity to be sold to the grid.
      
       Please refer to the preamble for additional detail concerning affected EGUs and standards of performance.
4.3	Power Sector Modeling Framework
4.3.1	Modeling Overview
Over the last decade, the EPA has conducted extensive analyses of regulatory actions impacting the power sector.  These efforts support the Agency's understanding of key policy variables and provide the framework for how the Agency estimates the costs and benefits associated with its actions that impact the power sector.  Current forecasts for the utilization of new and existing generating capacity are a key input into evaluating the impact of this rule.  Given excess capacity within the existing fleet and relatively low forecasts of electricity demand growth, there is limited new capacity of any type expected to be constructed over the next decade.  A small number of new coal-fired power plants have been completed and brought online in recent years. However, the EPA does not expect the construction of any new non-compliant coal-fired capacity through the analysis period. The EPA also does not expect any new non-compliant natural gas-fired stationary combustion turbines meeting the applicability criteria to be built. This conclusion is based in part on the Agency's own power sector modeling utilizing the Integrated Planning Model (IPM) as well as EIA's Annual Energy Outlook 2014 (AEO 2014) projections. 
IPM, developed by ICF International, Inc, is a state-of-the-art, peer reviewed, dynamic linear programming model that can be used to project power sector behavior under future business as usual conditions and examine prospective air pollution control policies throughout the United States for the entire electric power system. The EPA used IPM to project likely future electricity market conditions with and without this rule.  
In addition to using IPM, the EPA has closely examined modeling results from a number of alternative baseline scenarios in the AEO 2014 from the EIA. To produce the AEO, EIA employs the National Energy Modeling System (NEMS), an energy-economy modeling system of the United States.  According to EIA:
      NEMS projects the production, imports, conversion, consumption, and prices of energy, subject to assumptions on macroeconomic and financial factors, world energy markets, resource availability and costs, behavioral and technological choice criteria, cost and performance characteristics of energy technologies, and demographics.
The Electricity Market Module of NEMS produces projections of power sector behavior that minimize the cost of meeting electricity demand subject to the sector's inherent constraints, including the availability of existing generation capacity, transmission capacity and cost, cost of utility and nonutility technologies, expected load shapes, fuel markets, regulations, and other factors. EIA's AEO projections independently corroborate the EPA's conclusions in that the forecast no new generation capacity being constructed through the analysis period that would not already meet the final new source standards.  Both the IPM and AEO 2014 NEMS modeling results are presented in Section 4.4.
4.3.2	The Integrated Planning Model
IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. electric power sector. It provides forecasts of least cost capacity expansion, electricity dispatch, and emission control strategies while meeting energy demand and environmental, transmission, dispatch, and reliability constraints. The EPA has used IPM for over two decades to better understand power sector behavior under future business as usual conditions and evaluate the economic and emission impacts of prospective environmental policies. The model is designed to reflect electricity markets as accurately as possible.   The EPA uses the best available information from utilities, industry experts, gas and coal market experts, financial institutions, and government statistics as the basis for the detailed power sector modeling in IPM.  The model documentation provides additional information on the assumptions discussed here as well as all other model assumptions and inputs.[,]
Although the Agency typically focuses on broad system effects when assessing the economic impacts of a particular policy, the EPA's application of IPM includes a detailed and sophisticated regional representation of key power sector variables and its organization.  When considering which new units are most cost effective to build and operate, the model considers the relative economics of various technologies based on a wide spectrum of current and future considerations, including capital costs, operation and maintenance costs, fuel costs, utility sector regulations, and emission profiles.  The capital costs for new units account for regional differences in labor, material, and construction costs. These regional cost differentiation factors were developed based on data and assumptions used in the EIA's AEO 2013.
As part of IPM's assessment of the relative economic value of building a new power plant, the model incorporates a detailed representation of the fossil-fuel supply system that is used to forecast equilibrium fuel prices, a key component of new power plant economics.  The model includes an endogenous representation of the North American natural gas supply system through a natural gas module that reflects full supply/demand equilibrium of the North American gas market.  This module consists of 118 supply, demand, and storage nodes, 15 liquefied natural gas regasification facility locations and three LNG export facility locations that are tied together by a series of linkages (i.e., pipelines) that represent the North American natural gas transmission and distribution network.
IPM also endogenously models the coal supply and demand system throughout the continental U.S., and reflects non-power sector demand and imports/exports.  IPM reflects 36 coal supply regions, 465 coal supply curves for each of nine years, 14 coal sulfur grades, and the coal transport network, which consists of 4,947 linkages representing the costs of transporting coal via rail, barge, and truck and conveyer linkages connecting 41 regions with 575 individual coal-fired generating stations.  The coal supply curves and the transport network costs used in IPM are publicly available, and were developed during a thorough bottom-up, mine-by-mine approach that depicts the coal choices and associated supply costs that power plants will face over the modeling time horizon.  The IPM documentation outlines the methods and data used to quantify the economically recoverable coal reserves, characterize their cost, and build the 84 coal supply curves.  These curves have been independently reviewed by industry experts and have been made available for public review on several occasions over the past two years during other rulemaking processes.  
The EPA has used IPM extensively over the past two decades to analyze options for reducing power sector emissions. The model has been used to forecast the costs, emission changes, and power sector impacts for the Clean Air Interstate Rule (CAIR), Cross-State Air Pollution Rule (CSAPR), the Mercury and Air Toxics Standards (MATS), and the proposed GHG emission guidelines for existing source EGUs.  Recently IPM has also been used to estimate the air pollution reductions and power sector impacts of water and waste regulations affecting EGUs, including Cooling Water Intakes (316(b)) Rule, Disposal of Coal Combustion Residuals from Electric Utilities (CCR) and Steam Electric Effluent Limitation Guidelines (ELG).
The model undergoes periodic formal peer review, which includes separate expert panels for both the model itself and the EPA's key modeling input assumptions. The rulemaking process also provides opportunity for expert review and comment by stakeholders, including owners and operators of the electricity sector that is represented by the model, public interest groups, and other developers of U.S. electricity sector models.  The EPA is required to respond to significant comments submitted regarding the inputs used in IPM, its structure, and application.  The feedback that the Agency receives provides a detailed check for key input assumptions, model representation, and modeling results. IPM has received extensive review by energy and environmental modeling experts in a variety of contexts.  For example, from the mid-1990s through 2011 the Science Advisory Board reviewed IPM as part of the Clean Air Act (CAA) Amendments Section 812 studies of the CAA costs and benefits that are periodically conducted.  The model has also undergone considerable interagency scrutiny when it has been used to conduct over one dozen legislative analyses performed at Congress' request over the past decade.  In addition, Regional Planning Organizations throughout the U.S. have extensively examined IPM as a key element in the state implementation plan (SIP) process for achieving the National Ambient Air Quality Standards.  The Agency has also used the model in a number of comparative modeling exercises sponsored by Stanford University's Energy Modeling Forum over the past 15 years.
IPM has also been employed by state partnerships (e.g., the Regional Greenhouse Gas Initiative (RGGI), the Western Regional Air Partnership, Ozone Transport Assessment Group), other federal and state agencies, environmental groups, and industry, all of whom subject the model to their own review procedures. States have also used the model extensively to inform issues related to ozone in the northeastern U.S.  This groundbreaking work set the stage for the NOx SIP call, which has helped reduce summer nitrogen oxide (NOx) emissions and the formation of ozone in densely populated areas in the northeast.  
4.4	Analyses of Future Generating Capacity
4.4.1	Base Case Power Sector Modeling Projections
The "base case" for this analysis is a business-as-usual scenario that would be expected under market and regulatory conditions in the absence of this rule. As such, the IPM base case represents the baseline for this regulatory impact analysis. The EPA frequently updates the IPM base case to reflect the latest available electricity demand forecasts, as well as expected costs and availability of new and existing generating resources, fuels, and emissions control technologies.
The EPA conducted analysis and modeling in support of the April 2012 EGU GHG New Source Standards proposal, and concluded that new unplanned non-compliant base load power plants are not expected to be built through the analysis period (2020 for the original proposal) and beyond (77 FR 22392, April 13, 2012). The EPA conducted an analysis of the economic impacts by modeling a base case scenario of future electricity market conditions. The EPA's IPM modeling for the 2012 proposal utilized the IPM v. 4.10 base case, and relied on the AEO 2010 for the electric demand forecast for the U.S. and employed a set of the EPA's assumptions regarding fuel supplies, the performance and cost of electric generation technologies, pollution controls, and numerous other parameters. For the 2012 proposal, the EPA also conducted three additional base case sensitivity analyses using IPM. 
After considering public comments received on the 2012 proposal, the EPA issued a new proposal for carbon emissions from new power plants (79 FR 1430, January 8, 2014). The EPA's IPM modeling of the 2013 proposal relied on the AEO 2013 electric demand forecast, and was analyzed using the IPM v. 5.13 base case. The EPA also conducted three additional base case sensitivity analyses using IPM. 
For the analysis of the final rule, the EPA used the IPM v. 5.14 base case, which relied on the electric demand forecast in AEO 2014. The v. 5.14 base case updated v. 5.13 unit level specifications (including control configurations) based on comments received and EGU compliance plans in response to environmental regulations.  The base case accounts for the effects of the finalized MATS and CSAPR rules, New Source Review settlements and state rules through 2014 impacting sulfur dioxide (SO2), NOx, directly emitted particulate matter and CO2, and final actions the EPA has taken to implement the Regional Haze Rule. The EPA's IPM base case also includes two federal non-air rules effecting EGUs: the Cooling Water Intakes (316(b)) Rule and the Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR). 
Table 4-1 reports the unplanned capacity additions forecast by the IPM base case. Unplanned capacity additions are those that the model forecasts to be built in response to forecast economic conditions, such as fuel prices and demand growth. The EPA's IPM base case forecast finds that EGUs are projected to adopt technology for new steam and combustion turbine generation capacity that would be compliant with the standards, even in the absence of this rule. Only some new coal-fired units with carbon capture and storage (CCS) technology, which are receiving partial federal financial support, are included in the baseline modeling. Furthermore, new simple-cycle combustion turbines (CTs) constructed in the EPA's IPM base case are assumed to operate at an emissions rate above the standard. However, mirroring real world behavior, relatively low levels of CT generation are projected in the base case. In the base case new CTs are forecast to operate, on average in each domestic model region, at capacity factors well below the applicability requirements of this rule.  In the base case the maximum average capacity factor for individual new CTs is 14 percent or less across all domestic regions and all simulation years.  The emissions rate of new natural gas combined cycle (NGCC) units in the EPA's IPM base case is below the emissions rate standard of this final rule, although this is by assumption. However, assuming an emissions rate for new NGCC units that is below the emissions rate standard is consistent with the detailed emissions rate analysis described in the preamble for this rule. That analysis carefully considered emissions rate data on newly constructed NGCC units and GHG limitations in recently issued construction permits for NGCC facilities and found that these facilities operated below the standard or were permitted to operate below the standard.   
The EIA projections that are reflected in AEO 2014 reference case are summarized in the following tables alongside the EPA base case projections.  According to the EIA, the AEO 2014 reference case "projection is a business-as-usual trend estimate, given known technology and technological and demographic trends." It represents existing policies and regulations influencing the power sector.  As shown in Table 4-1, new coal-fired capacity through 2030 is projected to be entirely CCS-equipped and would be in compliance with these standards (300 MW) in the AEO 2014 reference case.  The projected CCS-equipped capacity is assumed to occur in response to existing federal, state, and local incentives for the technology. The AEO 2014 reference case forecasts that the vast majority of new, unplanned generating capacity will be either natural gas-fired or renewable.  The reference case projects a capacity factor for simple cycle combustion turbines of less than 20 percent in all regions and in all years, and therefore these units are projected to operate below the applicability limit for this final rule.  As in the IPM-based analysis, the emission rate for new NGCC units in the AEO 2014 reference case is assumed to be below the applicable standard in this final rule. 
As described in detail in 4.4.2, the economics favoring new natural gas combined cycle (NGCC) additions instead of coal-fired additions are robust under a range of sensitivity cases examined in the AEO 2014.  Sensitivity cases that EIA conducted in the AEO 2014, as well as the AEO 2013, separately examine higher economic growth, lower coal prices, no risk premium for greenhouse gas emissions liability from conventional coal, and lower oil and natural gas resources. None of these sensitivity cases forecast unplanned additions of coal-fired capacity without CCS in the analysis period.  This has been a consistent finding in the AEO, which led the Department of Energy (DOE) to conclude that "the low capital expense, technical maturity, and dispatchability of natural gas generation are likely to dominate investment decisions under current policies and projected prices."   






Table 4-1.	Unplanned Cumulative Capacity Additions (GW)
                                       
                                 EPA Base Case
                            AEO 2014 Reference Case
                                 Capacity Type
                                     2020
                                     2020
                                     2025
                                     2030
Conventional Coal
                                       0
                                       0
                                       0
                                       0
Coal with CCS
                                      0.3
                                      0.3
                                      0.3
                                      0.3
Natural Gas CC
                                      6.9
                                      9.8
                                     28.8
                                     95.7
Natural Gas CT
                                      2.6
                                     14.1
                                     34.5
                                     49.2
Nuclear
                                       0
                                       0
                                       0
                                       0
Renewables
                                     15.9
                                     17.4
                                     19.3
                                     22.5
Distributed Generation
                                       -
                                      1.6
                                      3.3
                                      4.6
Total
                                     25.8
                                     43.2
                                     86.3
                                     141.4
Notes: The sum of the table values in each column may not match the total figure due to rounding. EPA capacity data is net nameplate capacity, AEO capacity data is net summer generating capacity.
Source: EPA 2020 projection from IPM v. 5.14 base case; EIA 2020-2030 projection from EIA Annual Energy Outlook 2014, Table A9.

The capacity projections of EIA and the EPA represent a continuation of current trends, where natural gas-fired capacity has been the technology of choice for base load and intermediate load power generation over the last few years (see Figure 4-1), due in large part to its significant levelized cost of electricity (LCOE) advantage over coal-fired generating technologies.  A greater discussion of the relative LCOE of different generating technologies is provided beginning in Section 4.4.
Figure 4-1.	Historical U.S. Power Plant Capacity Additions, by Technology, 1891-2013
Source: Form EIA-860 (2013)  
Notes: Figure reflects all capacity brought online from 1891  -  2013, including 77 GW subsequently retired. Total capacity shown: 1,126 GW, including 12 GW built pre-1940.   Other Renewables include: hydro, biomass, solar, landfill gases, solid waste combustion and geothermal. Other includes: petroleum & distillates, petroleum coke, propane, other gases and waste heat not otherwise included. 
 In addition to new builds, increased electricity demand is expected to be partially fulfilled by increased utilization of existing generating capacity.  Generation projections are the result of least-cost economic modeling both in IPM and AEO 2014, and reflect the most cost-effective dispatch and investment decisions modeled, given a variety of variables and constraints.  Even without the deployment of new conventional coal-fired capacity, U.S. electricity demand will continue to be met by a diverse mix of electricity generation sources with coal projected to continue to provide the largest share of electricity (36 percent of total 2020 generation in AEO 2014 and 37 percent in the EPA's projections), as displayed in Table 4-2.  



Table 4-2.	2012 U.S. Electricity Net Generation and Projections for 2020, 2025, and 2030 (Billion kWh)
 
 
                                  Historical
                                 EPA Base Case
                            AEO 2014 Reference Case
                                                                              
                                     2012
                                     2020
                                     2020
                                     2025
                                     2030
Coal
                                     1,512
                                     1,534
                                     1,646
                                     1,689
                                     1,692
Oil
                                      23
                                      47
                                      18
                                      19
                                      19
Natural Gas
                                     1,228
                                     1,156
                                     1,286
                                     1,410
                                     1,552
Nuclear
                                      769
                                      815
                                      779
                                      711
                                      782
Hydroelectric
                                      274
                                      282
                                      288
                                      291
                                      294
Wind
                                      142
                                      251
                                      218
                                      218
                                      219
Other Renewables
                                      48
                                      121
                                      102
                                      133
                                      154
Other
                                      71
                                      -7
                                      65
                                      151
                                      103
Total
                                     4,067
                                     4,199
                                     4,402
                                     4,622
                                     4,815
Source: Historical data from Form EIA-860, 2012.  EPA 2020 projection from IPM 5.14 base case; EIA 2020-2030 projection from EIA Annual Energy Outlook 2014, Tables A8 and A16
Notes: The sum of the table values in each column may not match the total figure due to rounding.  "Other Renewables" include biomass, geothermal, waste and solar electric generation capacity.  "Other" includes pumped storage (net loss, non-biogenic waste, batteries, hydrogen, and other miscellaneous generation and storage technologies. Negative value reflects net energy loss from pumped storage.
It has been previously noted that the current projections for key market variables, such as natural gas prices, and state and regional regulations are now even less favorable to the development of non-compliant coal-fired capacity than at the time of the 2012 proposal.  State and regional regulations have changed since the 2012 proposal, as noted in Section 2.8, most notably regulations of GHG emissions from the power sector and state renewable portfolio standards (RPS):
         * State regulations addressing CO2 emissions  -  Several states have adopted measures to address emissions of CO2 from the power sector.  These approaches include flexible market-based programs like California's Assembly Bill 32 and  RGGI in the Northeast, and specific GHG performance standards for new power plants in California, Oregon, New York, and Washington.
         * State Renewable Portfolio Standards (RPS)  -  There are now 29 states, the District of Columbia and Puerto Rico that have an enforceable RPS, or similar laws.  Eight other States, the Virgin Islands and Guam have voluntary goals.  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. Only 12 states do not currently have an enforceable RPS.
         * 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. In general, these plans confirm the expectation that utilities anticipate any new sources of generation will be from sources that meet the standards set in this regulation.  Furthermore, these plans reflect an expectation of relatively low demand growth due, in part, to policies and regulations to reduce the electricity consumption such as energy efficiency regulations and policies, evolution of the Smart Grid, and demand response measures. 
4.4.2	Alternative Scenarios from AEO 2014 
As described in the previous section, in addition to the EPA's own analysis, the EPA reviewed EIA's recent forecasts of new capacity in the electricity sector for the AEO 2014. The AEO 2014 reference case forecasts no new non-compliant capacity would be built. Power sector modeling by EIA also projects that their conclusion of there being no new coal-fired capacity built in the analysis period is robust under a range of alternative assumptions that influence the industry's decisions to build new power plants.  For example, EIA typically supplements the AEO with scenarios that explore key market, technical, and regulatory issues.  Of the 31 scenarios contained in the AEO 2014, none project new coal-fired capacity in the analysis period used by the EPA for this RIA, including the four scenarios that may be considered most favorable to the development of coal-fired capacity displayed in Table 4-3. 


Table 4-3.	AEO 2014 Reference Case and Alternative Scenario Forecasts of Unplanned Cumulative Capacity Additions by 2020, GW 
                                 Capacity Type
                                   Reference
                                  High Growth
                                 Low Coal Cost
                          Low Gas & Oil Resource
                                No GHG Concern
Conventional Coal
                                       0
                                       0
                                       0
                                       0
                                       0
Coal with CCS
                                      0.3
                                      0.3
                                      0.3
                                      0.3
                                      0.3
Natural Gas
                                     23.9
                                     34.4
                                     19.8
                                     16.3
                                     22.7
Nuclear
                                       0
                                       0
                                      0.0
                                      2.5
                                      0.0
Non-Hydro Renewables
                                     17.4
                                     19.7
                                     17.6
                                     23.7
                                     17.5
Other
                                      1.6
                                      2.0
                                      1.5
                                      0.8
                                      1.6
Total
                                     43.2
                                     56.5
                                     39.3
                                     43.6
                                     42.1
 Note: The AEO 2014 scenario definitions are: High Economic Growth increases annual real GDP growth by 2.8 percent per year through 2040 (reference case GDP growth is 2.4 percent per year); Low Coal Cost assumes 2.4 percent greater regional coal mining productivity growth than in the reference case, and lower wages, equipment, and declining transportation costs for the coal industry than in the reference case, falling to 25 percent below the reference case by 2040; Low Oil and Gas Resource reduces the ultimate estimated recovery of shale gas, tight gas, and tight oil by 50 percent; No GHG Concern removes the perceived risk of incurring costs under a future GHG policy from market investment decisions.
4.4.3	Power Sector Fuel Price Dynamics and Trends
Expectations about what new fossil-fired generation would serve future demand have changed over the past decade from generating sources that use coal to those, primarily combined cycle systems, which use natural gas. As mature technologies, the cost and performance characteristics of conventional coal-fired capacity and NGCC are projected by the EPA to be relatively stable over time.  Therefore, expectations of future fuel prices play a key role in determining the overall cost competitiveness of conventional coal-fired units versus NGCC units.
Current and projected natural gas prices are considerably lower than observed prices over the past decade.  This is largely due to advances in hydraulic fracturing and horizontal drilling techniques that have opened up new shale gas resources and substantially increased the supply of economically recoverable natural gas. According to EIA:
      Shale gas refers to natural gas that is trapped within shale formations. Shales are fine-grained sedimentary rocks that can be rich sources of petroleum and natural gas. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. The production of natural gas from shale formations has rejuvenated the natural gas industry in the United States.
      Of the natural gas consumed in the United States in 2011, about 95 percent was produced domestically; thus, the supply of natural gas is not as dependent on foreign producers as is the supply of crude oil, and the delivery system is less subject to interruption. The availability of large quantities of shale gas should enable the United States to consume a predominantly domestic supply of gas for many years and produce more natural gas than it consumes.
The AEO 2014 projects U.S. natural gas production will increase by 13.3 trillion cubic feet (Tcf), a 55 percent increase (from 24.3 Tcf in 2014 to 37.5 Tcf in 2040). Over 75 percent of this forecast increase in domestic natural gas production is due the projected doubling of shale gas production, which is forecast to increase by 10.2 TCF (from 9.6 TCF in 2014 to 19.8 TCF in 2040).
 Recent historical data reported to EIA is also consistent with these trends, with 2014 being the highest year on record for domestic natural gas production. Gas production in 2014 was 6.3 percent above production in 2013, which is the largest annual growth rate since 1984.  The average real (2011$) natural gas price delivered to the power sector was $4.39/MMBtu in 2014, an increase from $4.25/MMBtu in 2013.[,] 
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.[,]  Modeling by the EPA and EIA incorporates the impact of these additional resources on the forecasts of the price of natural gas used by electric generating units.  The increases in the natural gas resource base are reflected not only in current natural gas prices and projections (e.g., AEO 2014), but also in current capacity planning by utilities and electricity producers across the country.  The North American Electric Reliability Corporation's (NERC) Long Term Reliability Assessment, which is based on utility plans for new capacity over a 10-year period, reinforces this consensus by stating that "gas-fired generation [is] the primary choice for new capacity." 
The EPA's and EIA's modeling frameworks are designed to reflect the longer term, fundamentals-based perspective that electric utilities and developers employ in evaluating capital investments, while analyzing alternative scenarios to account for broader fuel market uncertainties.  Short-term fuel price volatility is not the most relevant factor in this context because new power plants have asset lives measured in decades, not in months or years, and new capacity investment decisions are based on long-run expected prices, not month-to-month, or even year-to year, variations in fuel prices.  Shorter-term prices will affect how units are dispatched, but these potential dispatch impacts are considered with other factors over a longer time horizon and factored into the choice of which type of plant to build.  In contrast, the uncertainty surrounding long-term fuel prices will exert significantly greater influence on the technology selected for new capacity additions. In a modeling context with perfect foresight, this longer term uncertainty may be evaluated by the comparisons of alternative scenarios presented throughout this chapter.
In addition to major changes in the gas supply outlook, there have been notable changes in the coal supply outlook.  Coal costs have generally increased over the past few years due primarily to increased production costs.  These costs have increased as the most accessible and economically viable mines are depleted, requiring movement into coal reserves that are more costly to mine.  The basic trends in coal supply are not expected to change for the foreseeable future.
      Taken together, current and expected natural gas and coal market trends are contributing to a recent fundamental shift in the economic conditions for new power plant development that utilities and developers have recognized and responded to in planning.
4.4.4	Power Sector Fuel Projections
To examine the potential impacts of uncertainty inherent in natural gas and coal markets, the EIA used scenario analysis to generate the 2020 fuel price projections in Table 4-4. The relative prices of available fuels partially drive power sector investment decisions. Even under scenarios where the spread between the unit price of gas and coal is highest, no construction of new non-compliant generating capacity is projected in 2020, as shown in Table 4-3. 









Table 4-4.	National Delivered 2020 Fuel Prices by AEO 2014 Scenario (2011$/MMBtu)
                                   Scenario
                                  Natural Gas
                                     Coal
Reference
                                     4.99
                                     2.57
High Growth
                                     5.28
                                     2.59
Low Growth
                                     4.97
                                     2.55
High Coal Cost
                                     5.13
                                     2.90
Low Coal Cost
                                     4.88
                                     2.27
High Gas/Oil Resource
                                     4.30
                                     2.45
Low Gas/Oil Resource
                                     5.63
                                     2.63
	Note: AEO 2014 scenario definitions: High Economic Growth assumes real GDP growth is 2.8 percent peryear from 2012 to 2040 (base case assumes 2.4 percent); Low Economic Growth assumes real GDP growth is 1.9 percent per year High Coal Cost assumes lower regional productivity growth rates and higher wages, equipment, and transportation costs for the coal industry; Low Coal Cost assumes greater regional productivity growth rates and lower wages, equipment, and transportation costs for the coal industry; High Oil and Gas Resource expands the ultimate estimated recovery of shale gas, tight gas, and tight oil by 100 percent; Low Oil and Gas Resource reduces the ultimate estimated recovery of shale gas, tight gas, and tight oil by 50 percent.
However, given that power plants are long-lived assets, capacity planning decisions are necessarily undertaken with a forward view of expected market and regulatory conditions.  In producing the AEO 2014, EIA capacity expansion projections are informed by a lifecycle cost analysis over a 30-year period in which the expectations of future prices are consistent with the projections realized in the model (i.e. the model executes decisions with perfect foresight of future market, technical, and regulatory conditions).  Therefore, the fuel prices that inform capacity expansion decisions in 2020 are not only the prices that year, but the entire future fuel price stream.  For example, Figure 4-2 displays EIA's natural gas price projections for the Reference Case and several key scenarios through 2050.

Figure 4-2.	National Real Price of Natural Gas Delivered to EGUs for Select AEO 2014 Scenarios (2011$/MMBtu)
      Note: The AEO gas price forecasts go through 2040. The AEO forecasted prices are interpolated to 2050 by applying the average annual rate of price increase from 2035 to 2040 in each AEO scenario to all subsequent years from 2041 through 2049.
      
	Natural gas prices are expected to increase after 2020 in all scenarios. However, rising natural gas prices through 2040  -  including in EIA's low gas/oil resource scenario - are still not sufficient to support new, non-compliant coal-fired generation through 2022 in these scenarios. This demonstrates that natural gas prices do not have to continue at currently low levels for NGCC to maintain its economic advantage over coal-fired technologies.
While the uniformity of EIA scenarios in projecting no new, non-compliant coal-fired capacity through the analysis period is compelling, the scenario projections cannot fully illustrate the extent of the economic advantage that NGCC maintains over conventional coal, only that the advantage remains intact across a broad range of market and technical scenarios.  To identify potential market conditions that could fully erode the cost advantages of NGCC over coal-fired technologies during the analysis period, the unit-level engineering cost analysis in section 5.4 compares these technologies. That analysis builds on the unit-level cost comparisons presented in the following sections of this chapter. 
4.5	Levelized Cost of Electricity Analysis 
New capacity projections from the EPA and EIA reviewed in the previous section indicate that the NSPS is not projected to require changes in the design or construction of new EGUs from what would be expected in the absence of the rule.  Thus, under both the baseline projections and alternative scenarios analyzed in AEO 2014, the final EGU New Source GHG Standards are projected to result in negligible emission reductions, quantified benefits, or costs.
To further examine the robustness of these conclusions the EPA conducted additional analysis using the levelized cost of electricity (LCOE) for different types of new generation technologies.  The LCOE is a widely used metric that represents the cost, in dollars per output, of building and operating a generating facility over the entirety of its economic life.  Evaluating competitiveness on the basis of the LCOE is particularly useful in establishing cost comparisons between generation types with similar operating characteristics but with different cost and financial characteristics.  The typical cost components associated with the LCOE include capital, fixed operating and maintenance (FOM), variable operating and maintenance (VOM), transportation, storage and monitoring (TS&M) and fuel.  (See preamble section V. H. 5.)
4.5.1	Overview of the Concept of Levelized Cost of Electricity
The levelized capital and FOM costs may be calculated by taking the annualized capital and FOM (expressed in $/kW-yr) costs and spreading the expense over the annual generation of the facility using the expected average annual capacity factor (the percent of full load at which a unit would produce its actual annual generation if it operated for 8,760 hours). The annualized capital cost (expressed in $/kW-yr) is the product of the $/kW capital cost and the capital recovery factor (CRF).  A CRF may be calculated using the project's interest rate and book life.
The VOM cost, which is already expressed in terms of cost per unit output, may be presented with or without the fuel expense.  The fuel expense is typically the largest component of VOM costs (non-fuel components to VOM include start-up fuel, consumables, inspections, etc.) and for certain capacity types  -  such as NGCC  -  fuel expense may represent the majority of the LCOE.  
Because levelized costs consider the entire lifecycle of the facility, fuel expenses are represented by the levelized fuel price which captures the forecast of annual delivered fuel prices over the economic life of the facility at a given discount rate.  Levelizing fuel prices recognizes the necessity to consider the trajectory of fuel costs over the facility's entire economic life.
It should be noted that there are other important considerations beyond the LCOE that impact power plant investment decisions.  New power plant developers must consider the particular demand characteristics in any particular region, the existing mix of generators, operational flexibility of different types of generation, prevailing and expected electricity prices, other potential revenue opportunities (e.g., the capacity value of a particular unit, where certain power markets have mechanisms to compensate units for availability to maintain reliability, sale of co-products, etc.), and the varying financial risks associated with different generation technologies.  Broader system-wide power sector modeling  -  such as the analyses conducted by the EPA and EIA  -  is able to more effectively capture some of these considerations.
4.5.2	Cost and Performance of Technologies 
This section reports the LCOE of individual technologies that are affected EGUs of this final rule. These are compared in the following sections. The NGCC and coal-fired generation technology cost and performance assumptions that form the basis for the LCOE analysis in this RIA are from the DOE's National Energy Technology Laboratory (NETL).  NETL cost and performance characteristics were selected for coal-fired technologies because the NETL estimates were unique in the detail of their cost and performance estimates for a range of CO2 capture levels for both new super critical pulverized coal (SCPC) and integrated gasification combined cycle (IGCC) facilities.[,] In particular, the NETL costs released in 2015 include vendor quotes for new technology deployed. The use of NETL cost and performance characteristics also allows for comparisons to be made across generating technologies using a single, internally consistent framework. The CO2 capture sensitivity analysis included an evaluation of the cost, performance, and environmental profile of these facilities under different configurations that were tailored to achieve a specific level of carbon capture.  For simple cycle CTs, NETL cost and performance estimates were not available or sufficiently recent so the EPA adopted EIA's AEO 2014 estimates of the LCOE.
To represent a new SCPC facility, NETL assumed a new boiler with a combination of low-NOx burners with overfire air and a selective catalytic reduction system for NOx control. The plant was assumed to have a fabric filter and a wet limestone flue gas desulfurization scrubber for particulate matter and SO2 control, respectively. For configurations including CCS, the plant was assumed to have a sodium hydroxide polishing scrubber to ensure that the flue gas entering the CO2 capture system has a SO2 concentration of 10 parts per million or less. The SCPC unit treating a slip stream with partial post-combustion CCS were assumed to be equipped with the CO2 removal system designed by Shell Cansolv, the system currently in full-scale commercial use at the Boundary Dam facility.  Estimated costs for the system reflect the latest vendor quotations.  
Specific to the partial capture configurations for SCPC, the NETL study identified two options. The first option identified was to process the entire flue gas stream through the capture system, but at reduced solvent circulation rates. The second option was to maintain the same high solvent circulation rate and stripping steam requirement as would be used for full capture, but only treat a portion of the total flue gas stream. The NETL report determined that this "slip stream" approach was the most economical because a reduction in flue gas flow rate would: (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce the size of the CO2 absorption columns; and (3) trim the cooling water requirement of the direct contact cooling system. The "slip stream" approach  -  which leads to lower capital and operating costs  -  was therefore adopted by the EPA for cost and performance estimates under partial capture. The technology cost and performance characteristics utilized by the EPA in developing the LCOE estimates discussed in this chapter and Chapter 5 are listed below in Table 4-5.









Table 4-5.	Technology Cost and Performance Specifications (2011$) 
                                 Capacity Type
                             Capital Cost ($/MWh)
                  Fixed Operations & Maintenance ($/MWh)
                 Variable Operations & Maintenance ($/MWh)
                                   TS&M
                                    ($/MWh)
                          Levelized Fuel Cost ($/MWh)
                         Net Plant HHV Efficiency (%)
NGCC
                                      13
                                       4
                                      1.8
                                       -
                                      42
                                     50.2
SCPC
                                      39
                                      10
                                       9
                                       -
                                      25
                                     40.7
SCPC w/ Partial CCS 
(1,400 lb/MWh gross)
                                      51
                                      11
                                      10
                                       1
                                      26
                                     39.2
SCPC Co-Firing Natural Gas (1,400 lb/MWh gross)
                                      39
                                      10
                                       9
                                       -
                                      34
                                     40.3
IGCC
                                      54
                                      14
                                       9
                                       -
                                      26
                                     39.0
IGCC Co-Firing Natural Gas (1,400 lb/MWh)
                                      54
                                      14
                                       9
                                       -
                                      28
                                     39.0
Notes: Cost from NETL 2015. The coal assumed is a bituminous coal with a sulfur content of 2.8 percent (dry) at a real (2011$) price of $2.94/MMBtu, consistent with NETL 2015.  The analysis uses a natural gas price of $6.19. NETL uses a high-risk financial structure resulting in a capital charge factor (CCF) of 0.124 to evaluate the costs of all cases with CO2 capture (non-capture case uses a conventional financial structure with a CCF of 0.116).
NETL (2015) explains that there are a range of future potential costs that are up to 15 percent below, or 30 percent above their central estimate, consistent with a "feasibility study" level of design engineering applied to the various cases in this study. The value of the studies lie not in the absolute accuracy of the individual case results but in the fact that all cases were evaluated under the same set of technical and economic assumptions. This consistency of approach allows meaningful comparisons among the cases evaluated.
4.5.3	Levelized Cost of Electricity of New Generation Technologies
To support and provide context for the sectoral modeling results presented above, this section presents two LCOE comparisons: 
      1. NGCC to non-compliant Coal  -  to demonstrate the cost advantages of NGCC across a range of natural gas prices and regional market conditions.
      2. NGCC to CT  -  to demonstrate the low likelihood of a new combustion turbine being built with the expectation of meeting the applicability criteria based on utilization and thus being covered by these standards.
The illustrative unit cost and performance characteristics used in this section assume representative costs associated with spatially dependent components, such as connecting to existing fuel delivery infrastructure and the transmission grid. In practice units may experience higher or lower costs for these components depending on where they are located.  It should be noted that the LCOE comparisons presented in this section only represent the cost to the generator and do not reflect the additional social costs that are associated with emissions of greenhouse gases or other air pollutants.  A broader consideration of the health and welfare (i.e., non-health benefits) impacts of emissions from these technologies is considered in Chapter 5.
 It is also important to note that both the EIA and the EPA apply a climate uncertainty adder (CUA) - represented by a three percent increase to the weighted average cost of capital  -  to new, conventional coal-fired capacity types.  EIA developed the CUA to address inconsistencies between power sector modeling absent GHG regulation and the widespread use of a cost of CO2 emissions in power sector resource planning. While baseline power sector modeling scenarios may not specify potential future GHG regulatory requirements, investors in the industry typically incorporate some expectation of a future cost to limit CO2 emissions in resource planning evaluations that influence investment decisions.  Therefore, the CUA reflects the additional planning cost typically assigned by project developers and utilities to GHG-intensive projects in a context of climate uncertainty.  The EPA believes the inclusion of the CUA in LCOE estimates is consistent with the industry's current planning and evaluation framework for future projects (demonstrable through IRPs and public utility commission orders) and is therefore pertinent when evaluating the cost competitiveness of alternative generating technologies.  
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." Therefore, the EPA recognizes the application of the CUA is context dependent. As a part of the planning process, it is appropriately applied to evaluating prospective projects, and then removed once a project transitions from planning to execution.  While omitting the CUA is inconsistent with an analysis considering how project characteristics and market conditions would lead a developer or utility to select a certain project, as is the purpose of this section, for transparency the cost estimates based on the 2015 NETL analysis for non-compliant coal-fired projects are presented in the following analysis both with and without the CUA.  All LCOE estimates of coal-fired facilities with CCS are presented without the CUA, to represent the reduced CO2 liability associated with such technologies.
4.5.4	Levelized Cost of Electricity of NGCC and Non-compliant Coal
The EPA's base LCOE estimates for NGCC, SCPC, and IGCC are shown in Figure 4-3 by cost component (capital, FOM, VOM, TS&M, and fuel) and assume a construction date of 2020 and an 85 percent capacity factor. Although the EPA believes that this cost data is broadly representative of the economics between new coal and new natural gas facilities, this analysis assumes representative new units and does not reflect the full array of new generating sources that could potentially be built.  To the extent that other types of new EGUs that would be affected by this rule are built, they may exhibit different costs than those presented here.  For example, new conventional coal facilities of a size smaller than what is assumed in the base estimate would tend to exhibit a relatively higher LCOE, while some technologies could potentially display a lower LCOE if, all else equal, fuel could be obtained at a lower price than that assumed in this analysis (such as may be the case for petroleum coke or waste coal facilities).  These potential differences do not fundamentally change the analysis presented in this RIA.
On a levelized cost basis, NGCC is significantly cheaper than all of the non-compliant coal-fired options.  For technologies that are included in the IPM Base Case and the AEO, their LCOE values are comparable to the LCOE values calculated from the NETL study. The difference in the LCOE of NGCC and non-compliant coal technologies explains the finding in the sectoral modeling described above that natural gas generation is forecast to be the source of new fossil-fired generation.  
In addition to the disparity in total LCOE, there are fundamental differences in the cost composition between natural gas- and coal-fired facilities. NGCC costs are dominated by fuel expense while the levelized cost of coal-fired technologies driven by capital expense.  Consequently, this section will explore the impact of changes in natural gas price and the capital costs of coal-fired facilities to better quantify the magnitude of the relative cost advantage NGCC exhibits over coal-fired alternatives.












Figure 4-3.	Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation Technologies by Cost Component

      Notes: 
      (1) The coal assumed is a bituminous coal with a sulfur content of 2.8 percent (dry) and a real delivered price of $2.94/MMBtu consistent with NETL 2015.   
      (2) The levelized delivered price of natural gas is $6.19/MMBtu (2011$).
      (3) SCPC and IGCC without CCS are shown first without any CUA and then with a 3 percent CUA.
      (4)  The cost of CO2 transport, storage and monitoring (TS&M) is included as part of LCOE for SCPC with 18 percent CCS, which captures and sells CO2. 
      (5)  A capacity factor of 85 percent is assumed across all technologies. 
      (6) NETL uses a high-risk financial structure resulting in a capital charge factor (CCF) of 0.124 to evaluate the costs of all cases with CO2 capture (non-capture case uses a conventional financial structure with a CCF of 0.116).
      (7) For comparison, EIA estimates of  levelized costs in 2019 under AEO 2014 Reference Case assumptions for SCPC and IGCC are $94.4/MWh and $114.7/MWh ( both in 2012$), respectively, including a 3 percent CUA and excluding transmission investment costs. The levelized costs presented above are based on NETL assumptions and will necessarily differ from AEO 2014 levelized costs for a variety of reasons, including cost and performance characteristics, financial assumptions, and fuel input prices.  
Figure 4-4 presents the LCOE of an NGCC facility at four alternative levelized natural gas price levels.  For comparison, the LCOE estimates for SCPC and IGCC (with no CO2 control) including the CUA are provided as well.

Figure 4-4.	Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation Technologies Across Alternative Natural Gas Prices

It is only when natural gas prices exceed $11/MMBtu on a levelized basis (in 2011$) that new coal-fired generation without CCS approaches parity with NGCC in terms of the LCOE.  None of the AEO 2014 scenarios described in this chapter project national average natural gas prices near that level.   To achieve an $11/MMBtu levelized price in 2020 would require a significantly more pessimistic natural gas outlook than what is contained in AEO's low natural gas resource scenario.  To illustrate, Table 4-6 report the levelized natural gas prices (initial year of 2020) for both a 20-year period (to accommodate the end of EIA's modeling projections in 2040) and 30-year period (calculated by continuing the projected level of price increases through 2050).
Table 4-6.	Levelized Natural Gas Prices by Select AEO 2014 Scenario (2011$/MMBtu)
                                   Scenario
                            20-Year AEO Projection
                                  (2020-2039)
                         30-Year AEO-Based Projection
                                  (2020-2049)
Reference
                                     6.07
                                     6.53
High Growth
                                     6.32
                                     6.96
Low Growth
                                     5.78
                                     6.20
High Coal Cost
                                     6.19
                                     6.69
Low Coal Cost
                                     6.03
                                     6.47
High Gas/Oil Resource
                                     4.80
                                     4.85
Low Gas/Oil Resource
                                     7.70
                                     8.45
            Note: Discount rate of 5 percent, consistent with IPM assumptions.  The 30-year natural gas price is calculated by applying the average annual rate of price increase from 2035 to 2040 in all subsequent years from 2041 through 2049. The scenarios are described in Table 4-4. 
As an illustration, one potential price path that would achieve a $10/MMBtu on a 20-year levelized basis in 2020 is a natural gas price path 30 percent higher than EIA's low resource scenario in all years (see Figure 4-5).  This illustrative price path to achieve a $10/MMBtu levelized price would result in an $11.02/MMBtu annual real price in 2030 and a $13.81/MMBtu real price in 2040. Even on this significantly higher price path, a representative NGCC unit would have a lower LCOE than a non-compliant coal unit. What this information indicates is that natural gas price forecasts need to be notably higher than the highest forecast in the AEO 2014 scenarios before we would expect that general market dynamics would favor new non-compliant coal generation over new compliant natural gas generation as the fossil-fuel technology of choice to satisfy demand.  Chapter 5 discusses this finding further by bringing in the consideration of the emissions damages associated with these technologies. 
 
Figure 4-5.	Projected Real National Delivered Natural Gas Price for Select AEO 2014 Scenarios and Illustrative Path for > $10/MMBtu Levelized Price 

It is important to note that the LCOE calculations are based on assumptions regarding the representative national cost of generation at new facilities.  It is known that there is significant spatial variation in the costs of new generation due to design differences, labor productivity and wage differences, and delivered fuel prices, among other potential factors.  For example, EIA utilizes capital cost scalars to capture regional differences in labor, material and construction costs.   The minimum and maximum capital cost scalars across all regions in AEO 2014 for SCPC, IGCC, and NGCC build options are presented in Table 4-7. 
Table 4-7.	AEO 2014 Regional Capital Cost Scalars by Capacity Type
                                 Capacity Type
                          Minimum Capital Cost Scalar
                          Maximum Capital Cost Scalar
SCPC
                                     0.885
                                     1.152
IGCC
                                     0.908
                                     1.136
NGCC
                                     0.893
                                     1.205
	Applying the regional capital cost scalars displayed above to the base LCOE estimates from NETL developed earlier in this section produces only a small change in the relative competitiveness of the technologies as seen in Table 4-8.
Table 4-8.	LCOE Estimates with Minimum and Maximum AEO 2014 Regional Capital Cost Scalars (2011$/MWh)
                                 Capacity Type
                                  Reference 
                                     LCOE
                                    ($/MWh)
                    LCOE Using Minimum Capital Cost Scalar
                                    ($/MWh)
                                  LCOE Using
                          Maximum Capital Cost Scalar
                                    ($/MWh)
SCPC (no CCS, without CUA)
                                      82
                                      73
                                      95
SCPC (no CCS, with CUA)
                                      94
                                      83
                                      108
IGCC (no CCS, without CUA)
                                      103
                                      93
                                      117
IGCC (no CCS, with CUA)
                                      118
                                      108
                                      135
NGCC
                                      60
                                      54
                                      72
	The LCOE of SCPC in the lowest capital cost region still results in an LCOE that is 1 percent higher than an NGCC located in the most expensive capital cost region, even without the CUA. (The difference is 15 percent when the CUA is included.) The IGCC LCOE is 29 percent above NGCC in the most expensive region, even without considering the CUA. 
The other primary driver in determining the regional impact on competitiveness of new build options is delivered fuel prices.  As part of the AEO, EIA releases electric power projections  -  including fuel prices  -  for each of the 22 Electricity Market Module (EMM) regions.  The two regions with the highest projected 2020 natural gas prices in the AEO 2014 are the Western Electricity Coordinating Council/Southwest (Southwest) and the Florida Reliability Coordinating Council (FRCC).  The 20-year levelized natural gas and coal price forecasts (2020-2039) in the AEO 2014 reference case are displayed in Figure 4-6 for both regions.

Figure 4-6.	Levelized Regional Fuel Price from AEO 2014 Reference Case, 2020-2039 			(2011$/MMBtu)  
The FRCC region experiences the highest overall natural gas prices as well as a greater unit price differential between coal and natural gas prices under the AEO projections. The impact on the LCOE of the SCPC, IGCC, and NGCC technologies without CCS is reported in Table 4-9 for both sets of fuel prices, as well as the national average for comparison. 
Table 4-9.	LCOE Estimates For Minimum and Maximum AEO 2014 Regional Fuel Prices (2011$/MWh)
                                 Capacity Type
                    LCOE Using National Average Fuel Prices
                                    ($/MWh)
                          LCOE Using FRCC Fuel Prices
                                    ($/MWh)
                       LCOE Using Southwest Fuel Prices
                                    ($/MWh)
SCPC (no CCS, without CUA)
                                      82
                                      94
                                      82
SCPC (no CCS, with 3% CUA)
                                      94
                                      105
                                      93
IGCC (no CCS, without CUA)
                                      103
                                      114
                                      102
IGCC (no CCS, with 3% CUA)
                                      118
                                      130
                                      118
NGCC
                                      60
                                      87
                                      70
Due to the greater fuel price differential, the more favorable region for the development of coal-fired facilities from an LCOE perspective is the FRCC, where the regional fuel prices reduce the LCOE advantage of NGCC to $7/MWh over SCPC (compared with a $22/MWh advantage with national fuel prices) and $27/MWh over IGCC (compared with a $43/MWh advantage with national fuel prices.
In conclusion, even the most favorable combination of regional variability in capital costs and delivered fuel prices represented by EIA are insufficient to support new, unplanned, conventional coal-fired capacity in the analysis period.
4.5.5	Levelized Cost of Simple Cycle Combustion Turbine and Natural Gas Combined Cycle
Simple cycle combustion turbines (CTs) fulfill a fundamentally different function in power sector operations than that of NGCC and fossil-fired steam facilities.  CTs are designed to start quickly in order to meet demand for electricity during peak operating periods and are generally less expensive to build on a capital cost basis, but are also less fuel efficient than combined cycle technology, which employs heat recovery systems.  Due to lower fuel efficiencies, CTs produce a significantly higher cost of electricity (cost per kWh) at higher capacity factors and consequently are typically utilized at levels below the applicability requirements for EGUs affected by the EGU New Source GHG Standards.  New CTs are expected to most often be built to ensure reserve margins are met during peak periods (typically in the summer), and in some instances be able to generate additional revenues by selling capacity into power markets.  The EPA expects that any CT unit built in the period of analysis would be classified as a non-base load unit and would not incur any costs to meet the relevant standard. 
To illustrate the economic incentives of utilizing combustion turbines in an intermediate and base load mode of operation, Figure 4-7 presents the LCOE estimates for a new conventional CT, Advanced CT and NGCC at increasing capacity factors.  The estimates utilize the AEO 2014 Reference Case levelized natural gas price for 2020. 

Figure 4-7.	Levelized Cost of Electricity Across a Range of Capacity Factors, CT and NGCC 			(2011$/MWh at $6.07/MMBtu Levelized Natural Gas Price) 
	In the LCOE figure above, utilizing a CT for generation is less expensive than an NGCC unit only at capacity factors of less than 20 percent.  If expected utilization is greater than 20 percent, it can reasonably be expected that a utility or developer would seek to deploy NGCC over CT for a host of economic, environmental, and technical reasons.  Furthermore, the design net efficiencies for currently available potentially impacted aeroderivative simple cycle combustion turbines range from approximately 32 percent for smaller designs to 39 percent for the largest intercooled designs. The efficiencies of industrial frame units range from 30 percent for smaller designs to 36 percent for the largest units. The EPA therefore expects any CT unit built in the period of analysis to be classified as a non-base load unit.
4.6	Macroeconomic and Employment Impacts
These final EGU New Source GHG Standards are anticipated to result in negligible emission changes in the electricity sector in the analysis period, and therefore are anticipated to impose negligible costs or quantified benefits. The EPA typically analyzes impacts on employment or labor markets associated with rules based on the estimated compliance costs and other energy impacts (e.g., changes in electricity prices), which serve as an input to such analyses.  However, since the EPA does not forecast a change in behavior relative to the baseline in response to this rule, there are no notable macroeconomic or employment impacts expected as a result of this rule.  
4.7	References
Fann, N., K.R. Baker, C.M. Fulcher. 2012. Characterizing the PM2.5-related health benefits of emission reductions for 17 industrial, area and mobile emission sectors across the U.S. Environment International, Volume 49, 15 November 2012, Pages 141-151, ISSN 0160-4120, http://dx.doi.org/10.1016/j.envint.2012.08.017.
Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz, and W.H. White. 2009. "Reanalysis of the Harvard Six Cities Study and the American Cancer Society Study of Particulate Air Pollution and Mortality." Special Report to the Health Effects Institute. Cambridge, MA. July.
Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. "Chronic Exposure to Fine Particles and Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009." Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.
Malik, N.S. 2010, November 1. NextEra CEO sees clean energy standards replacing recent climate proposals [Radio transcript]. Dow Jones News [Online]. Available: Dow Jones Interactive Directory: Publications Library.
Mufson, S. January 2, 2011. "Coal's Burnout.' The Washington Post. Retrieved from: http://www.washingtonpost.com/newssearch.National Energy Technology Laboratory (NETL). Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture. Revised Sept. 16, 2013. Available online at: http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf.
National Energy Technology Laboratory (NETL). Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants. June 22, 2015. Available online at: http://www.netl.doe.gov/research/energy-analysis/energy-baseline-studies.   
Rosenberg, M. 2011, September/October. "The Reign of Cheap Gas." EnergyBiz Magazine. Retrieved from http://www.energybiz.com/magazine/article/234577/reign-cheap-gas.
Tong, S. 2010, November 1. Placing Bets on Clean Energy. [Radio transcript]. American Public Media: Marketplace [Online]. Available: Marketplace Programs on Demand.
National Petroleum Council. 2011. Prudent Development: Realizing the Potential of North America's Abundant Natural Gas and Oil Resources. Available online at: http://www.npc.org/reports/rd.html.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010. Available online at: http://www.eia.gov/oiaf/archive/aeo10/index.html. 
U.S. Energy Information Administration (U.S. EIAa). Annual Energy Outlook 2014. 2014. Available online at: http://www.eia.gov/forecasts/aeo/.
U.S. Energy Information Administration (U.S. EIA). U.S. Crude Oil and Natural Gas Proved Reserves, 2013Available online at: http://www.eia.gov/naturalgas/crudeoilreserves/pdf/usreserves.pdf 
U.S. Energy Information Administration (U.S. EIAb). Assumptions to the Annual Energy Outlook 2014. 2014. Available online at: http://www.eia.gov/forecasts/aeo/assumptions/pdf/0554(2014).pdfU.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2013a. Technical Support Document Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on the Internet at: http://www.epa.gov/airquality/benmap/models/Source_Apportionment_BPT_TSD_1_31_13.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2013b. Integrated Science Assessment for Ozone and Related Photochemical Oxidants. EPA/600/R-10/076F. Research Triangle Park, NC: U.S. EPA. February. Available on the Internet at http://oaspub.epa.gov/eims/eimscomm.getfile?p_download_id=511347.


                                       
                                       
 Chapter 5
Analysis of Illustrative Benefit-Cost Scenarios For New Sources
5.1	Synopsis
The previous chapter of this regulatory impact analysis (RIA) presents the U.S. Environmental Protection Agency's (EPA) analysis and projections from the U.S. Energy Information Administration (EIA) that support the conclusion that the EGU New Source Standards will result in negligible costs and benefits in the period of analysis. The EPA recognizes that this conclusion is based on underlying expected economic conditions (e.g., fuel prices) and assumptions about considerations investors would weigh in deciding whether to build new non-compliant coal-fired power plants. Extending the analysis in the previous chapter that considers those factors in evaluating the robustness of the findings from the sectoral perspective, this chapter presents the results of several illustrative analyses that show, under a range of alternative conditions, the potential costs and benefits of these standards for individual investments that provide base load dispatchable generation. We evaluate conditions under which different generator types are constructed in lieu of a non-compliant supercritical coal unit and estimate the benefit of adopting the investment that is compliant with the standards.  This also allows us to consider the costs and benefits of a situation where an operator chooses to build a new coal-fired unit that is compliant with the standard.  
While the analysis in Chapter 4 focuses on national level conditions, the analysis in this chapter explores the potential impacts to individual investments. The analysis in this chapter finds that under unlikely conditions in which the EPA's conclusions regarding the future economic competitiveness of new non-compliant coal-fired units relative to other new generation technologies no longer apply, or in specific situations where an operator chooses to build a coal-fired unit, that the quantifiable benefits of the standards outweigh the costs under a range of assumptions.
5.2	Comparison of Emissions from Generation Technologies
As discussed in Chapter 4, natural gas combined cycle (NGCC) units are on average expected to be more economical to build and operate than new coal units (see section 4.5).  Therefore, as our point of departure for comparing the costs and benefits of an individual investment decision, we evaluate the private cost of a new NGCC unit that is compliant with the finalized standards with the private cost of a new, non-compliant conventional supercritical pulverized coal (SCPC) coal-fired unit. When evaluating the costs and benefits associated with these standards, it is also important to understand the difference in emissions associated with these units. In addition to being more economical, new NGCC units have lower emission profiles for CO2 and criteria air pollutants than new coal units. For example, a typical new SCPC facility that burns bituminous coal in compliance with current utility regulations (e.g., the Mercury and Air Toxics Standards (MATS)) would have considerably greater CO2, sulfur dioxide (SO2), nitrogen dioxide (NOx), toxic metals, acid gases, and particulate emissions than a comparable NGCC facility.  
Table 5-1 shows that emissions of these pollutants from a typical new NGCC unit are significantly lower than those from a new coal-fired unit.  The emission characteristics are based on, and thus consistent with, the cost and performance assumptions of the illustrative units described in the levelized cost of electricity (LCOE) analysis in section 4.5. That is, these are base load units of the same net capacity operating at an 85 percent capacity factor, the coal unit is assumed to be using bituminous coal with a sulfur content of 2.8 percent dry, they are in compliance with current utility regulations (e.g., the MATS), etc.  The typical new NGCC unit would emit about 1.9 fewer million tons of CO2 per year than the typical new SCPC unit, as well as roughly 1,700 fewer tons of SO2 and about 1,300 fewer tons of NOx per year than the SCPC unit. Table 5-1 also provides comparable information for a representative integrated gasification combined cycle (IGCC) unit providing the same amount of electricity and using the same coal. The new IGCC unit would emit less CO2, SO2 and NOx than a typical coal-fired SCPC unit, but has higher emissions of each of these pollutants than a new NGCC unit. Reductions in SO2 emissions are a particularly significant driver for monetized health benefits, as SO2 is a precursor to the formation of particulates in the atmosphere, and particulates are associated with premature death and other serious health effects. NOX is both an ozone precursor, and is associated with formation of secondary fine nitrate PM2.5.  Both ozone and fine nitrate PM2.5 are associated with significant adverse health effects, including premature mortality. Further information on these pollutants' health and welfare effects is described in Chapter 3.  
Table 5-1 also shows the representative coal units' emissions of these same pollutants when meeting the promulgated standard of performance of 1,400 lb CO2/MWh. Two compliant SCPC units are presented: one uses carbon capture and storage (CCS) and another that co-fires natural gas.  The compliant IGCC unit is assumed to co-fire natural gas. For the compliant SCPC unit using CCS, in addition to reductions of CO2, SO2 emissions would also decrease due to the need to scrub acid gases to very low levels prior to carbon capture in order to prevent degradation of the solvent involved in the capture process. The NOX emission rate, measured on a net-basis, is slightly lower for non-compliant units than both compliant SCPC units. This is because there is a fuel efficiency loss associated with both compliance technologies and because NOX emission rate standards for new sources are on a gross-basis. While we account for these increases in the NOX emission rate in the analysis below, in some cases, NOX emissions from fossil-fired sources are also subject to mass limits on the total NOX emissions across EGUs (e.g. in states subject to the Cross-State Air Pollution Rule annual NOX program), so these emissions may be offset by NOX reductions from other generating units. 


Table 5-1.	Illustrative Emissions Profiles, New Coal and Natural Gas-Fired 
		Generating Units
 
                                Natural Gas CC
                                     SCPC
                     SCPC+Partial CCS (1,400 lb/MWh Gross)
                             SCPC+Co-Fire Nat Gas
                                     IGCC
                             IGCC+Co-Fire Nat Gas
 
                                  Emissions 
Emission Rate 
                                  Emissions 
Emission Rate 
                                  Emissions 
Emission Rate 
                                  Emissions 
Emission Rate 
                                  Emissions 
Emission Rate 
                                  Emissions 
Emission Rate 
SO2
                                      84
                                    0.0041
                                     1,500
                                     0.71
                                     1,200
                                     0.61
                                     1,500
                                                                           0.71
                                      18
                                    0.0087
                                      18
                                                                         0.0087
NOx
                                      130
                                     0.061
                                     1,500
                                     0.74
                                     1,500
                                     0.75
                                     1,500
                                                                           0.74
                                     1,100
                                     0.52
                                     1,100
                                                                           0.52
CO2
                                  1.6 million
                                      800
                                  3.5 million
                                     1,700
                                  3.1 million
                                     1,500
                                  3.0 million
                                                                          1,500
                                  3.5 million
                                     1,700
                                  3.4 million
                                                                          1,700

Notes: Emissions from NETL 2015. Emissions are in short tons/year and Emission Rates are in net lb/MWh. Values rounded to two significant digits.  Emission characteristics are based on, and thus consistent with the cost and performance assumptions of, the illustrative units described in LCOE analysis in section 4.5 (i.e., these are base load units running at 85 percent capacity factor, all coal units are assumed to be using bituminous coal with a sulfur content of 2.8 percent dry, etc.). The tons of emissions are estimated for a coal-fired facility that achieves the gross-output standard of 1,400 lb/MWh and presented in this table on a net output basis. For the post-combustion CCS system assumed in the SCPC case, acidic gases (e.g., SO2, HCl) need to be scrubbed to very low levels prior to going to the CCS system to avoid degradation of the solvent. Therefore, SO2 emissions are lower in the case of the SCPC unit with partial CCS. See preamble for discussion about the format of the standard. Here we further assume all units are of the same capacity (600 MW net).
  
5.3	Comparison of Health and Climate Impacts from Generation Technologies
As discussed in the previous section, the emissions of GHGs and other pollutants associated with new sources of electricity generation are greater for coal-fired units than for NGCC units. Reducing the emissions associated with electricity generation results in climate, human health, and non-health benefits. 
To consider the health and climate benefits associated with the adoption of lower emitting new generation technologies, we apply the 2022 benefit values discussed in Chapter 3 to the differences in illustrative emission profiles between the technologies in Table 5-1.   Specifically, we multiply the difference in CO2 emissions between two technologies by the estimates of the social cost of carbon dioxide (SC-CO2) (Table 3-1), multiply the difference in SO2 and NOX emissions by the PM2.5-related SO2 and NOX benefit per ton (BPT) estimates (Table 3-2), and add those values to get a measure of the 2022 benefits attributable to differences in emissions of adopting the lower emitting new generation technology. We subsequently divide by the amount of generation (in MWh) underlying the annual emissions estimates to derive the benefits attributable to the differences in emissions per unit of generation. 
Only the direct emissions of CO2, SO2, and NOX are considered in this illustrative exercise. Other air and water pollutants emitted by these technologies and emissions from the extraction and transport of the fuels used by these technologies are not considered. For example, coal has higher mercury emissions than natural gas, but the relative benefits from the difference in mercury emissions are not considered. A similar example of emissions not considered are those of directly emitted PM2.5. Furthermore, there may be differences in upstream greenhouse gas emissions (in particular, methane) from different technologies which were not quantified for this assessment.
Table 5-2 reports the 2022 incremental climate and health benefits associated with a new NGCC unit relative to a new coal-fired SCPC and IGCC units, given different mortality risk studies and assumptions about the discount rate.  These benefits are based on the emissions presented in Table 5-1. The benefits presented in Table 5-2 are estimated on an output basis to enable easier comparisons to the potential costs of investing in a new non-compliant coal-fired unit relative to a new NGCC unit. These incremental benefits should be relatively invariant across natural gas prices and other economic factors. Depending on the discount rate and mortality risk study used, 2022 incremental benefits associated with generation from a representative new NGCC unit relative to a new coal-fired SCPC or IGCC unit are $7.0 to $91 per MWh (2011$). 
The health and non-health benefits associated with reduced emissions can depend on a number of factors, including the specific fuels combusted and the location of the emissions. While the benefits of reduced CO2 emissions do not depend on the location of generation because the location of CO2 emissions does not influence their impact on the evolution of global climate conditions, the precise incremental health co-benefits will be location specific and depend on the specific fuels used. However, these factors will not change the qualitative conclusion. There will be incremental climate and human health benefits associated with a new NGCC unit relative to a new coal-fired unit, independent of the location. 

Table 5-2.	Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Illustrative New Natural Gas Combined Cycle Generation Relative to New Non-Compliant SCPC or IGCC Coal Generation in 2022

                                     SCPC
                                     IGCC
CO2-Related Benefits using SC-CO2
5% Discount Rate
                                     $5.7
                                     $5.8
3% Discount Rate
                                      $19
                                      $19
2.5% Discount Rate
                                      $28
                                      $28
3% Discount Rate (95[th] percentile)
                                      $56
                                      $57
Total PM2.5-Related Co-Benefits from SO2 and NOX Changes
3% discount rate
                                       
                                       
Krewski et al. (2009)
                                      $15
                                     $1.3
Lepeule  et al. (2012)
                                      $34
                                     $3.0
7% discount rate
                                       
                                       
Krewski et al. (2009)
                                      $14
                                     $1.2
Lepeule et al. (2012)
                                      $31
                                     $2.7
Combined CO2-Related and PM2.5-Related Benefits 

               Discount Rate Applied to PM2.5-Related Benefits 
                   (range based on adult mortality function)
SC-CO2 Discount Rate
                                      3%
                                      7%
                                      3%
                                      7%
5% Discount Rate
                                                                     $21 to $40
                                                                     $19 to $37
                                                                   $7.1 to $8.8
                                                                   $7.0 to $8.5
3% Discount Rate
                                                                     $34 to $53
                                                                     $33 to $50
                                                                     $20 to $22
                                                                     $20 to $22
2.5% Discount Rate
                                                                     $43 to $62
                                                                     $42 to $59
                                                                     $30 to $31
                                                                     $30 to $31
3% Discount Rate (95[th] percentile)
                                                                     $72 to $91
                                                                     $70 to $87
                                                                     $59 to $60
                                                                     $58 to $60
Notes: The emission rates and operating characteristics of the units being compared in this table are reported in Table 5.1. Benefits are estimated for a 2022 analysis year. The range of benefits within each SC-CO2 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 SC-CO2 values with health benefits values at the 3 percent and 7 percent discount rates. Combining the 3 percent SC-CO2 values with the 3 percent health benefit values assumes that there is no difference in discount rates between intragenerational and intergenerational impacts. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022.  
The conclusion from this analysis is that there are significant environmental and health benefits associated with electricity generation from a representative new NGCC unit relative to a new non-compliant coal-fired unit. Other studies of the social costs of coal and natural gas-fired generation provide similar findings (Muller et. al., 2011; NRC, 2009). 
As explained previously, the power sector has moved away from the construction of coal-fired power plants in favor of other generation (e.g., natural gas-fired power plants) due, in part, to the significant cost differential. Even so, it is possible that a limited number of currently unplanned coal-fired power plants would be constructed through 2022. In these circumstances, the construction of compliant coal-fired units in place of non-compliant coal-fired units would result in relative climate and human health and non-health benefits. Table 5-3 reports the 2022 incremental benefits associated with a new SCPC coal-fired unit with CCS relative to a new SCPC coal-fired unit, given different mortality risk studies and assumptions about the discount rate.  The values are calculated based on the emissions presented in Table 5-1. Depending on the discount rate used and mortality risk study used, 2022 incremental benefits associated with generation from a representative new SCPC coal-fired unit with CCS relative to a new SCPC unit without CCS are $3.1 to $18 per MWh (2011$), factoring in the disbenefit from a small increase in NOx emissions. These incremental benefits will be referenced in the analyses presented in subsequent sections.   
Table 5-3.	Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Compliant Coal-Fired Generation with CCS meeting 1,400 lb/MWh Standard Relative to New Non-Compliant Coal-Fired Generation in 2022
                                       
                                     SCPC 
CO2-Related Benefits using SC-CO2
                                       
5% Discount Rate
                                     $1.3
3% Discount Rate
                                     $4.4
2.5% Discount Rate
                                     $6.6
3% Discount Rate (95th percentile)
                                      $13
Total PM2.5-Related Benefits from SO2 and NOX Changes
   3% discount rate
                                       
Krewski et al. (2009)
                                     $1.9
Lepeule et al. (2012)
                                     $4.3
   7% discount rate
                                       
Krewski et al. (2009)
                                     $1.7
Lepeule et al. (2012)
                                     $3.9
Combined CO2-Related and PM2.5-Related Benefits 

               Discount Rate Applied to PM2.5-Related Benefits 
                   (range based on adult mortality function)
SC-CO2 Discount Rate
                                      3%
                                      7%
5% Discount Rate
                                                                   $3.2 to $5.6
                                                                   $3.1 to $5.2
3% Discount Rate
                                                                   $6.3 to $8.7
                                                                   $6.1 to $8.3
2.5% Discount Rate
                                                                    $8.5 to $11
                                                                    $8.3 to $10
3% Discount Rate (95th percentile)
                                                                     $15 to $18
                                                                     $15 to $17
Notes: Benefits are estimated for a 2022 analysis year. The range of benefits within each SC-CO2 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 SC-CO2 values with health benefits values at the 3 percent and 7 percent discount rates. Combining the 3 percent SC-CO2 values with the 3 percent health benefit values assumes that there is no difference in discount rates between intragenerational and intergenerational impacts. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022.

      Table 5-4 reports the 2022 incremental benefits associated with a new compliant coal-fired unit co-firing natural gas relative to a new non-compliant coal-fired unit, given different mortality risk studies and assumptions about the discount rate.  The values are calculated based on the emissions presented in Table 5-1. Depending on whether the unit is SCPC or IGCC, the discount rate used, and mortality risk study used, 2022 incremental benefits associated with generation from a representative new coal-fired unit co-firing natural gas relative to a new coal-fired unit that does not co-fire natural gas are 0.25 to $14 per MWh (2011$). These incremental benefits will be used in the analyses presented in subsequent sections.
      
      
      
      
      
      
      
      
      
      
      
      
      
      
Table 5-4.	Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Compliant Coal-Fired Generation with Co-Firing Natural Gas Relative to New Non-Compliant Coal-Fired Generation in 2022 
                                       
                          SCPC Co-Firing Natural Gas
                          IGCC Co-Firing Natural Gas
CO2-Related Benefits using SC-CO2
                                       
                                       
5% Discount Rate
                                     $1.5
                                     $0.25
3% Discount Rate
                                     $4.8
                                     $0.82
2.5% Discount Rate
                                     $7.2
                                     $1.2
3% Discount Rate (95th percentile)
                                      $14
                                     $2.5
Total PM2.5-Related Benefits from SO2 and NOX Changes
   3% discount rate
                                       
                                       
Krewski et al. (2009)
                                       -
                                       -
Lepeule et al. (2012)
                                       -
                                       -
   7% discount rate
                                       
                                       
Krewski et al. (2009)
                                       -
                                       -
Lepeule et al. (2012)
                                       -
                                       -
Combined CO2-Related and PM2.5-Related Benefits 

               Discount Rate Applied to PM2.5-Related Benefits 
                   (range based on adult mortality function)
SC-CO2 Discount Rate
                                      3%
                                      7%
                                      3%
                                      7%
5% Discount Rate
                                                                           $1.5
                                                                           $1.5
                                     $0.25
                                     $0.25
3% Discount Rate
                                                                           $4.8
                                                                           $4.8
                                     $0.82
                                     $0.82
2.5% Discount Rate
                                                                           $7.2
                                                                           $7.2
                                     $1.2
                                     $1.2
3% Discount Rate (95th percentile)
                                                                            $14
                                                                            $14
                                     $2.5
                                     $2.5
Notes: Benefits are estimated for a 2022 analysis year. The range of benefits within each SC-CO2 value and discount rate for PM2.5-related benefits pairing reflects the use of two core estimates of PM2.5-related premature mortality. The EPA has evaluated the range of potential impacts per MWh by combining all SC-CO2 values with health benefits values at the 3 percent and 7 percent discount rates. Combining the 3 percent SC-CO2 values with the 3 percent health benefit values assumes that there is no difference in discount rates between intragenerational and intergenerational impacts. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022.

5.4	Illustrative Analysis  -  Benefits and Costs of New Source Standards across a Range of Gas Prices
As the analysis in Chapter 4 demonstrated, under a wide range of likely electricity market conditions  -  including the EPA base case and EIA reference case scenarios as well as multiple alternative scenarios  -  it is expected that the industry will choose to construct new units that already meet the standards of this rulemaking in the baseline. Section 4.5.4 further explored how much higher natural gas prices would need to be to favor new non-compliant coal generation over new NGCC generation. In this section, we continue that analysis by considering the potential impacts of the regulation on benefits if key assumptions regarding natural gas prices were to change during the analysis period. The analysis in this section indicates that in this scenario, the standards for new sources would result in increased private costs, but would also lead to climate and human health benefits, and is highly likely to result in net benefits to society as a whole.  
Furthermore, this section, as in section 4.5.4, demonstrates that local fuel prices must be significantly different than regional differences already captured in IPM and EIA's modeling of private investment costs to favor the construction of a new non-compliant coal-fired unit over a new NGCC unit to serve a particular load.  Section 4.5.4 describes how regional conditions and other factors may influence the LCOE comparison, and how these regional differences are already captured in the electricity sector modeling in support of this rule. The 64 different regions in IPM reflect the administrative structure of regional transmission organizations (RTOs) and independent system operators (ISOs). However, there may be local conditions within those regions which differ meaningfully from the broader regional conditions. The analysis in this section evaluates how substantially divergent those local conditions must be from representative conditions for non-compliant coal generation to be the fossil fuel-fired technology of choice to serve demand.  
The starting point for this analysis is the illustrative comparison (presented in Section 4.5) of the relative LCOE of representative new coal-fired SCPC and IGCC EGUs and representative NGCC units. That comparison demonstrated 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 $34 and $43 per MWh less than for a representative new coal-fired SCPC or IGCC unit, respectively (see Figure 4-3).  This is consistent with the EPA's expectation that the new source standards for steam units are not projected to impose any appreciable costs or quantified benefits under current and likely future market conditions, as discussed in Chapter 4. The emissions associated with these technologies, and the benefits in terms of reduced damages of operating the new NGCC unit in lieu of the new non-compliant coal unit, are reported in the previous section.
To supplement this conclusion, this section identifies three relevant ranges within the distribution of future natural gas prices that can be classified as likely gas prices, unexpectedly high natural gas prices, and unprecedented natural gas prices. Because the cost of natural gas is a significant share of the LCOE for NGCC units, we evaluate how changes in natural gas prices affect differences in the relative private costs of new technologies. We identify the natural gas price when the private costs, which are inclusive of the CUA for the SCPC, suggest that a new non-compliant coal unit may be adopted by an investor in lieu of a new NGCC unit. We then compare the social costs of these technologies, which is inclusive of both the private costs of these technologies and the damages from these technologies but exclusive of the CUA, at this natural gas price. We then identify the natural gas price when the social cost of investing in the new non-compliant coal unit is plausibly less than the social cost of the new NGCC unit.  
In general, this analysis shows that there would likely be a net social benefit, even under scenarios with higher than expected gas prices, if new compliant NGCC units were built in place of new non-compliant coal-fired units as a result of this rule. Under some conditions, higher natural gas prices may result in a net social cost of constructing and operating new natural gas in lieu of non-compliant coal, holding all other parameters constant and disregarding social benefits that we are unable to monetize. However, even under these unlikely conditions these finalized standards may yield social net benefits as there may be other technologies to serve demand that would have a lower social cost than a new non-compliant coal unit. 
5.4.1	Likely Natural Gas Prices 
As shown in Chapter 4, it is only when natural gas prices exceed $11/MMBtu on a levelized basis (in 2011 dollars) that the representative new non-compliant SCPC unit likely becomes competitive with new NGCC in terms of its cost of electricity produced. As discussed in Chapter 4, none of the AEO2014 scenarios approach this natural gas price level on either a forward looking 20-year levelized price basis or on an average annual price basis at any point during the analysis period. 
5.4.2	Unexpectedly High Natural Gas Prices 
At natural gas prices above $11/MMBtu, the private LCOE for a new SCPC unit may fall below that of a new NGCC unit. Therefore, in the event of such unexpectedly high levelized fuel prices, some new SCPC units might be constructed in the absence of this final rulemaking, provided that coal price do not rise at the same time, there is sufficient demand for electricity, and new non-compliant SCPC units are competitive with other new and existing generating technologies other than NGCC units. In this scenario, we expect some compliance costs if a new NGCC unit (or a compliant coal-fired unit) were to be built in lieu of the non-compliant coal unit. However, generation from a new NGCC unit would also have incremental environmental and health benefits as it emits less CO2 SO2, and NOx than generation from a new non-compliant SCPC unit (as may a compliant coal-fired unit; see Section 5.5).
For levelized natural gas prices of $11/MMBtu and somewhat higher, the resulting emission reduction benefits of building an NGCC unit, rather than a non-compliant SCPC unit, will outweigh the increase in costs of an NGCC unit over a non-compliant SCPC unit. This observation indicates that the standard for new fossil steam sources would yield net benefits in the analysis year. For example, at a levelized gas price of $12/MMBtu, the NGCC unit would generate electricity for approximately $17/MWh more than the non-complaint SCPC unit on a levelized basis, and result in incremental benefits from emissions reductions of $19 to $91/MWh (see analysis of 2022 relative benefits of NGCC: Table 5-2). The net benefit of this scenario would be $2.2 to $73/MWh. 
For context, even a natural gas price of $10/MMBtu (in 2011 dollars) is higher than any national average annual natural gas price faced by the electric power sector since at least 1996, when the EIA historic data series begins. The continued development of unconventional natural gas resources in the U.S. suggests that annual gas prices may actually tend to be towards the lower end of the historical range. In addition, the highest projected average levelized natural gas price for 2020 of any of the AEO 2014 scenarios cited in Chapter 4 is $8.45/MMBtu (2011$), which occurs in the Low Oil and Gas Resource scenario (see Table 4-6). As discussed in Chapter 4, none of the EIA sensitivity cases (which account for future fuel prices for both gas and coal) show scenarios where non-compliant coal-fired units become more economic than NGCC units in the period of analysis.
5.4.3	Unprecedented Natural Gas Prices 
At extremely high natural gas prices, the LCOE for a non-compliant SCPC unit could be sufficiently lower than the cost of a new NGCC unit, such that the net benefit of the new fossil steam standard in a given year could be negative (i.e., a net cost), at least under some ranges of benefit estimates. For example, at a very high  levelized gas price of $14/MMBtu, the NGCC unit would generate electricity for roughly $31/MWh more than the illustrative non-compliant SCPC, but result in social benefits from lower emissions of $19 to $91/MWh relative to the non-compliant SCPC unit (see analysis of 2022 relative benefits of NGCC: Table 5-2). If the NGCC unit were built in lieu of the SCPC unit as a result of the new fossil steam standard, the impact would range from a net social cost of $11/MWh to a net social benefit of $60/MWh relative to the SCPC unit.
Depending on which discount rates are used to estimate benefits, it is possible that the standard would result in a net cost (i.e., costs exceed benefits). However, as noted in the previous subsection, natural gas prices at these levels would be unprecedented. As a result, the EPA believes that the probability of levelized natural gas prices reaching levels at which this standard would generate net social costs is extremely small.  
We emphasize that differences in generating costs, plant design, local factors, and the relative differences between fuels costs can all affect the precise circumstances under which the new steam fossil standard would be projected to have no costs, net social benefits or net social costs. However, based on historical and expected gas prices, we project that the new fossil steam standard is most likely to have negligible costs because firms will invest in technology that will comply with the standard in the baseline, and, if it does result in costs, it is also likely to produce positive, although modest, net social benefits. Furthermore, these results, complemented by the analysis in Chapter 4 on regional differences in levelized costs of these technologies, indicate that local differences in the cost of these technologies must be significantly different from representative conditions for non-compliant coal generation to be the technology of choice to serve demand. Therefore the probability that this finalized standard would result in net social costs is exceedingly low.
5.5	Illustrative Analysis  -  Benefits and Costs of Non-Compliant Coal and Compliant Coal 
As discussed in detail in the previous section and in Chapter 4, it is unlikely that a new non-compliant coal-fired unit would be constructed in the analysis period. The power sector continues to move away from the construction of coal-fired power plants in favor of natural gas-fired power plants due, in part, to the significant LCOE differential explored in the previous section. Even so, an operator may have reasons to choose to construct a conventional coal-fired power plant. (For example, some comments received on the 2012 and 2014 proposed regulations suggested that an operator may find it desirable to construct a new coal-fired EGU for the purpose of diversifying its generation fleet across fuels to hedge against uncertainty in fuel markets.) In these circumstances, the EPA believes that any need for CCS could be accommodated and would not, based on the incremental cost of the CCS portion of the new unit, preclude the construction of the new coal-fired facility. One factor in determining that needing CCS would not preclude the construction of the new facility is the availability of Enhanced Oil Recovery (EOR) opportunities for new coal-fired facilities.
This section evaluates the impacts that might occur if an investor, which otherwise wanted to construct a new non-compliant coal unit, chose to instead construct a new compliant coal-fired unit in response to the new fossil steam standard. In this scenario, this decision would result in some costs in order to build a unit with partial CCS or co-fire with natural gas.  However, there would also be climate and other benefits resulting from changes in CO2 and SO2. 
For each coal-fired generation type, SCPC and IGCC, the EPA analyzed the cost of constructing these units and emission impacts of meeting the new source standards in 2022. While partial CCS is considered the best system of emission reductions (BSER) for these SCPC units, it would also be possible to meet the standard without CCS through co-firing natural gas, which is also analyzed. 
The cost of CCS used to support this rule assumes that the geologic sequestration of CO2 will be in deep saline formations and accounts for the cost of doing so, but the EPA also recognizes the potential for sequestering CO2 for EOR. For non-EOR applications, transportation, storage, and monitoring (TS&M) costs of $5-$15 dollars per ton of CO2 are applied based on the level of capture. This range is consistent with estimates provided by NETL and the Global CCS Institute. 
EOR refers to the injection of gases and/or fluids into a reservoir to increase oil production efficiency. CO2-EOR has been successfully used at many production fields throughout the United States. The oil and natural gas industry in the United States has over 40 years of experience in injection and monitoring of CO2. This experience provides a strong foundation for the technologies used in the deployment of CCS on coal-fired electric generating units.  Although deep saline formations provide the most CO2 storage opportunity (at least 2,243 billion tons), oil and gas reservoirs are estimated to have 228 billion tons of CO2 storage resource.
    The use of CO2 for EOR can significantly lower the cost of implementing CCS. The opportunity to sell the captured CO2 rather than paying directly for its long-term storage, greatly improves the economics of the new generating unit. According to the International Energy Agency, of the CCS projects in operation (e.g., Boundary Dam Energy Project, Saskatchewan, Canada) or under construction or at an advanced stage of planning, 70 percent intend to use captured CO2 to improve recovery of oil in mature fields, including Mississippi Power's Kemper County Energy Facility, NRG Energy's W.A. Parish Petra Nova CCS Project, Summit Power's Texas Clean Energy Project, and the Hydrogen Energy California Project. The Texas Clean Energy project is planning to capture 90 percent of the CO2 and sell it for EOR.
Therefore, in the near term, new coal-fired EGUs with CCS may be located in areas amenable to using the captured CO2 in EOR operations because these formations have been previously well characterized for hydrocarbon recovery, likely already have suitable infrastructure (e.g., wells, pipelines, etc.), and have an associated economic benefit of increasing oil well productivity.  Furthermore, the EPA believes the opportunity to engage in EOR opportunities is not significantly limited by the location of those opportunities or the current CO2 pipeline infrastructure (12 states currently have active EOR operations).  Provision of electric power does not require coal-fired facilities to be co-located with the demand it is intended to serve. Please refer to Chapter 2 for a more detailed discussion of EOR, including its geographic availability, expected future growth, and overall impact on the economics of CCS.
There are two EOR opportunities evaluated in this section  -  `High' and `Low.'  The high EOR opportunity assumes a CO2 sale price of $36 per ton; the low EOR opportunity assumes a CO2 sale price of $18 per ton based on assumptions used by NETL in evaluating potential EOR opportunities.  For either opportunity, it is assumed that the facility is only responsible for the costs of transmitting the captured CO2 to the fence line, as is currently the practice.  Costs for TS&M of CO2, however, are real costs that must be borne by someone. Whether the facility, the pipeline owner or the eventual user (i.e., oil field producer) of the CO2 bear the TS&M cost could be negotiated, with the outcome varying in different situations. We expect that when CO2 is sold for EOR applications, the buyer rather than the EGU operator will likely bear those costs. However, for the purposes of this analysis, the TS&M costs are included for both EOR and non-EOR applications, recognizing that this likely slightly overstates the cost to the operator in circumstances where CO2 is sold for EOR. 
Figure 5-1 compares the LCOE for a non-compliant coal to a compliant coal unit with partial CCS both with and without EOR. With the exception of the LCOE costs accounting for EOR, these costs were provided in Table 4-5. We see in Figure 5-1 that if a limited number of non-compliant coal-fired power plants would have been constructed in the analysis period the adoption of CCS could be accommodated and would not, based on the incremental cost of the CCS portion of the new unit, preclude the construction of the new coal-fired facility. Furthermore, Figure 5-1 shows the LCOE analysis estimate that a non-compliant coal unit could achieve a 1,400 lb/MWh emission rate by co-firing with 34 percent natural gas (at a levelized cost of $34.40/MWh) at an SCPC unit, or with 6 percent natural gas at an IGCC unit. 

Figure 5-1.	Levelized Cost of Electricity, Uncontrolled Coal and Coal with Partial 			CCS (1,400 lb/MWh gross).  2011$  
      Notes: 
      (1) Cost data from NETL 2015, adjusted for EOR revenue and co-firing where applicable. 
      (2) NETL uses a high-risk financial structure resulting in a capital charge factor (CCF) of 0.124 to evaluate the costs of all cases with CO2 capture (non-capture case uses a conventional financial structure with a CCF of 0.116).
      (3) A non-compliant 550 MW (net capacity) unit SCPC requires NG co-firing at 34% to achieve a 1,400 lb/MWh CO2 emission rate.  A non-compliant 620 MW (net) IGCC unit requires 6 percent NG co-firing. LCOE costs for co-firing were estimated assuming a levelized $6.19/MMBtu price of delivered gas.
      (4) The partial control alternatives that achieve 1,400 lb/MWh using CCS without EOR include the cost of TS&M.
Tables 5-5 and 5-6 show the costs and 2022 net benefits (benefits minus private compliance costs) per MWh of adopting compliant coal in lieu of non-compliant coal. The EPA estimates of the benefits or disbenefits associated with changes in CO2, SO2, and NOX emissions using the methods described in Table 5-3. The cost estimates used are reported in Figure 5-1. As before, it is important to note that these comparisons omit additional benefits that may be associated with the abatement of greenhouse gas emissions and other benefits associated with reducing criteria pollutant emissions.


Table 5-5.	Illustrative 2022 Costs and Benefits for Compliant SCPC with Partial Capture or with Co-Firing Natural Gas Relative to Non-Compliant SCPC (per MWh 2011$)
 
                                                          SCPC with Partial CCS
                                                                          SCPC 
                                                          Co-Firing Natural Gas
Additional LCOE [a]
                                                                            $17
                                                                           $9.8
Revenue from EOR (Low - High EOR)
                                                                   $4.2 to $7.1
                                                                              *
Additional LCOE, net of EOR
                                                                    $9.6 to $13
                                                                              *
Value of Monetized Benefits for 2022 Emissions


SC-CO2 5% with Krewski 3% to SC-CO2 3% (95th) with Lepeule 3%[b]
                                                                    $3.2 to $18
                                                                    $1.5 to $14
Net Monetized Benefits


Without EOR Revenue
                                                                  -$13 to $0.84
                                                                  -$8.3 to $4.7
With EOR Revenue
                                                                  -$9.3 to $7.9
                                                                              *
[a] For this comparison the LCOE of the representative SCPC without CCS or co-firing natural gas does not include 3 percent CUA. 
b Benefits are estimated for a 2022 analysis year. Values shown are calculated using different discount rates.  Four estimates (average SC-CO2 at discount rates of 5, 3, and 2.5 percent, respectively, and 95th percentile SC-CO2 at 3 percent) of the SC-CO2 in the year 2022 were used.  See Table 3-1 for the SC-CO2 estimates. =The average SC-CO2 at 5 percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate. See section 3.2 for complete discussion of these estimates. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022. 





















Table 5-6.	Illustrative 2022 Costs and Benefits for Compliant IGCC with Co-Firing Natural Gas Relative to Non-Compliant IGCC (per MWh 2011$)
 
                                       
                          IGCC Co-Firing Natural Gas
Additional LCOE[a]
                                                                               
                                                                           $2.0
Revenue from EOR (Low - High EOR)
                                                                               
                                                                              *
Additional LCOE, net of EOR
                                                                               
                                                                              *
Value of Monetized Benefits for 2022 Emissions


SC-CO2 5% with Krewski 3% to SC-CO2 3% (95th) with Lepeule 3%[b]
                                                                               
                                                                  $0.25 to $2.5
Net Monetized Benefits 


Without EOR Revenue
                                                                               
                                                                 $-1.8 to $0.45
With EOR Revenue
                                                                               
                                                                              *
[a] For this comparison the LCOE of the representative IGCC co-firing natural gas does not include 3 percent CUA.
[b] Benefits are estimated for a 2022 analysis year. Values shown are calculated using different discount rates.  Four estimates (average SC-CO2 at discount rates of 5, 3, and 2.5 percent, respectively, and 95th percentile SC-CO2 at 3 percent) of the SC-CO2 in the year 2022 were used.  See Table 3-1 for the SC-CO2 estimates. =The average SC-CO2 at 5 percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate. See Section 3.2 for complete discussion of these estimates. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022.


      As shown in Chapter 4, current market conditions indicate that a unit compliant with the standards is currently the most economical investment, even in the baseline. The costs reported in Tables 5-5 and 5-6 represent the compliance costs to a hypothetical investor who, in the baseline, would choose to build a non-compliant fossil-fired steam power plant and, in compliance with the standard, still constructs the plant but now in such a way that reduces the plant's emissions.  In short, the compliance costs are the expenditures that the investor would make in order to comply with the standard. The underlying premise of this example is that the profit from the plant exceeds the additional cost of compliance to the investor; otherwise the investor would not be expected to make the investment. If the profit were less than the compliance costs then the investor's lost profits would be the private costs. For this reason, if the investor makes a different compliance decision other than those assumed in Table 5-5 and 5-6 the private costs will be lower, and therefore, the compliance costs presented in Table 5-5 and 5-6 would be an upper bound to the private costs borne by the hypothetical investor.   
As explained in OMB's Circular A4 and the EPA's Guidelines for Economic Analysis, social costs, and not private costs, are the appropriate metric for the benefit-cost analysis in this RIA. Social costs represents the total burden that a regulation or action will impose on the economy. It is defined as the sum of all opportunity costs incurred as a result of a regulation or action where an opportunity cost is the value lost to society of any goods and services that will not be produced and consumed as a result of a regulation. The opportunity cost of a regulation or activity is measured by the prices of the goods and services used in response to the regulation or required for that activity. Therefore, when a resource is used in response to a regulation or for an activity, it has a social cost associated with it.
The costs in Tables 5-5 and 5-6 could be taken to approximate the social cost of an individual investor complying with the standard, assuming that investor would chose to construct a compliant fossil-fired steam power plant rather than making an alternative investment. However, detailed behavioral models of the electricity sector (such as IPM) that take into many of the important criteria for investment decisions over time show that this investment decision does not hold across the economy. Therefore, these estimates are unlikely to be representative of the social costs of this rule. The conclusions presented in Chapter 4  -  that costs of the rule are likely to be negligible  -  represent the best approximation of the overall cost to society. 
5.6	Impact of the New Source Standards Considering the Cost of Lost Option Value
Consistent with the EPA's practice in evaluating the benefits and costs of significant rules, Chapter 4 uses detailed electricity sector modeling of expected market conditions to demonstrate that new EGUs expected to be built in the period of analysis would be in compliance with this final rule, even in the absence of this rule. As a result in the analysis period, as measured in those deterministic settings, the cost are expected to be negligible and there are no quantified benefits. That analysis is extended in this chapter to consider unexpected conditions in which the construction of a new non-compliant coal-fired unit would be desirable from the perspective of an individual investor and evaluates the costs and benefits of constructing a generating technology that complies with the final rule instead. This section further extends, and draws on, those analyses to discuss, qualitatively, the potential benefits and costs of the standards from the perspective of an uncertain future. 
Firms operating in the power sector have a set of options available to address increases in electricity demand, such as increasing the utilization of existing generating capacity, implementing energy efficiency programs to mitigate demand growth, or investing in new generating capacity. Within the category of investing in new generating capacity they are able to select amongst a set of generating technologies and energy sources. Uncertainty about future conditions that could impact the profitability of these different investment options means that retaining flexibility to react to future conditions and choose the most profitable investments has value to firms. The value associated with retaining flexibility and being able to select the most profitable investments in the future is referred to as "option value." This rule does not impose a direct cost on firms by requiring them to take a specific action, instead the cost of this rule for firms is the lost option value associated with losing the ability to build a new fossil steam or combustion turbine EGU with an emissions rate above their respective standards. 
This option value is determined, in part, by the likelihood that the restricted choices would have been exercised in the future absent the policy and the cost of available substitutes. Since the analysis in Chapter 4 estimates that new combustion turbines forecast in the baseline that meet the applicability criteria will already meet the standards this discussion focuses on new fossil steam EGUs. As discussed in Chapter 4, it is highly unlikely that over the analysis period there will be enough expansion in relative fuel prices (e.g., natural gas prices relative to coal) to make a typical new fossil steam EGU cost competitive with available substitutes (e.g., NGCC, investing in energy efficiency program). Even in the unlikely event that this occurs, the incremental cost of constructing a compliant fossil steam EGU with partial CCS or an alternative compliance pathway will represent an upper bound on the costs to the firm due to the availability of substitute generation sources which might be able to provide a similar service at a lower cost. Given both of these reasons, the low likelihood of the restricted options being exercised in the baseline and availability of cost effective substitutes, on average the lost option value for firms is likely to be small. 
Furthermore, as shown in the preceding sections, even in situations where an investor would find it desirable to invest in a new, non-compliant EGU over available alternatives in the baseline, the health and environmental benefits of restricting the choice set may be higher than the costs to the firm. Therefore it will also be the case that expected benefits from preventing new EGUs with an emissions rate above the respective standards, will likely be higher than the lost option value. 
A similar perspective may be applied to assessing the costs of this rule. There are at least two notable differences when assessing the lost option value from society's perspective relative to the firm's perspective. First, from society's perspective the cost is lower because the available substitution possibilities may be greater for society than for a single firm as they are not bound by the conditions of a single firm but activities that may be pursued by all electricity producers and consumers at large. Second, the value of adding a single new EGU for the purpose of diversifying the generation fleet across fuels to hedge against uncertainty in fuel markets, will likely be lower for society at large than for a single firm with a generating fleet that is relatively less coal-intensive than the entirety of the generating fleet. Both of these differences suggest that the cost of lost option value from society's perspective is lower than what is already likely to a minimal cost of lost option value for a particular firm. 
It is difficult to precisely estimate the lost option value associated with this final rule given the numerous sources of uncertainty that influence investment decisions in the electricity sector and the existing modeling tools. However, the analysis reported in this chapter and the previous chapter has considered important variables that influence investment decisions in the electricity sector and found that across a wide range of potential outcomes this rule would have negligible costs. Furthermore, considering the additional analysis in this chapter and the discussion above, the cost of the lost option value of the rule is concluded to be small. Additionally, if conditions arise that would have led to the construction of non-compliant EGUs absent the final rule, the quantifiable benefits of limiting the construction of those units likely exceeds the cost (even though not all benefits are captured). However, as discussed throughout this RIA, when considering the most likely outcomes, the new source standards are anticipated to yield no quantified benefits and impose negligible costs over the analysis period.  
5.7	References
Dixit, Avinash and Pindyck, Robert. Investment Under Uncertainty. 1994. Princeton University Press.
Joskow, P.L. 2010. Comparing the Cost of Intermittent and Dispatchable Electricity Generating Technologies. MIT Center for Energy and Environmental Policy Research Working Paper 10-013.
Joskow, P.L. 2011. Comparing the Costs of Intermittent and Dispatchable Electricity Generating Technologies. American Economic Review. vol. 101:238-41.
Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz, and W.H. White. 2009. "Reanalysis of the Harvard Six Cities Study and the American Cancer Society Study of Particulate Air Pollution and Mortality." Special Report to the Health Effects Institute. Cambridge, MA. July.
Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. "Chronic Exposure to Fine Particles and Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009." Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.
Muller, N.Z., R. Mendelsohn, and W. Nordhaus. 2011. Environmental Accounting for Pollution in the United States Economy. American Economic Review. 101:1649-1675.
National Energy Technology Laboratory (NETL). Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture. Revised Sept. 16, 2013. Available online at: http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf. 
National Energy Technology Laboratory (NETL). Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants. June 22, 2015. Available online at: http://www.netl.doe.gov/research/energy-analysis/energy-baseline-studies.  
National Research of Council (NRC). 2009. Hidden Costs of Energy: Unpriced Consequences of Energy Production and Use. National Academies Press: Washington, D.C.
Trigeorgis, Lenos. Real Options: Managerial Flexibility and Strategy in Resource Allocation. 1996. The MIT Press.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010. Available online at: http://www.eia.gov/oiaf/archive/aeo10/index.html. 
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available online at: http://www.eia.gov/forecasts/aeo/.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.
 Chapter 6
Modified and Reconstructed Source Impacts
6.1	Introduction
In addition to the standards for new sources analyzed in Chapter 4 and Chapter 5, this action also sets standards under Clean Air Act Section 111(b) for units that modify or reconstruct. For the reasons discussed in this chapter, the EPA also believes that the standards for modified and reconstructed fossil fuel-fired EGUs will result in minimal compliance costs, because we expect few 111(b) modified or reconstructed EGUs in the period of analysis (through 2022).
6.2	Reconstructed Sources
The new source performance standard (NSPS) provisions (40 CFR part 60, subpart A) define a "reconstruction" as the replacement of components of an existing facility to an extent that (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and (2) it is technologically and economically feasible to meet the applicable standards. Historically, we are only aware of one EGU that has notified the EPA that it has reconstructed under the reconstruction provision of section 111(b). As a result, we anticipate that few EGUs will undertake reconstruction in the period of analysis. For this reason, the standards will not result in any significant emission reductions, costs, or quantified benefits in the period of analysis. Likewise, the EPA does not anticipate any impacts on the price of electricity or energy supply. The rule is not expected to raise any resource adequacy concerns, since reserve margins will not be impacted and the rule does not impose any additional requirements on existing facilities not triggering the reconstruction provision. There are no notable macroeconomic or employment impacts expected as a result of these standards.
Due to the extremely limited data available on reconstructions, it is not possible to conduct a representative illustrative analysis of what costs and benefits might result from this rule in the unlikely case that a unit were to reconstruct.
6.3	Modified Sources
Historically, few EGUs have notified the EPA that they have modified under the modification provision of section 111(b). The EPA's current regulations define an NSPS "modification" as a physical or operational change that increases the source's maximum achievable hourly rate of emissions, but specifically exempt from that definition projects that entail the installation of pollution control equipment or systems. 
The EPA expects that most of the actions EGUs are likely to take in the foreseeable future that could be classified as NSPS "modifications" would qualify as pollution control projects. In many cases, those projects are likely to involve the installation of add-on control equipment needed to meet Clean Air Act (CAA) requirements for criteria and air toxics air pollutants. Any associated carbon dioxide (CO2) emissions increases would likely be small and would occur as a chemical byproduct of the operation of the control equipment. In other cases, those projects would involve equipment changes to improve fuel efficiency to meet state requirements for implementation of the CAA section 111(d) rulemaking for existing sources and would have the effect of increasing a source's maximum achievable hourly emission rate (lb CO2/hr), even while decreasing its actual output based emission rate (lb CO2/MWh). Because all of these actions would be treated as pollution control projects under the EPA's current NSPS regulations, they would be specifically exempted from the definition of modification. 
Given the limited information that we have about past modifications, the EPA has concluded that it lacks sufficient information to establish standards of performance for all types of modifications at steam generating units at this time.  Instead, the EPA has determined that it is appropriate to establish standards of performance at this time for large-scale modifications of steam generating units, such as major facility upgrades involving the reconstruction or replacement of steam turbines and other equipment upgrades that result in substantial increases in a unit's potential hourly CO2 emissions rate. The EPA does not have sufficient information at this time to predict the full array of actions that existing steam generating units may undertake, including those in response to applicable requirements under an approved CAA section 111(d) plan. Additionally, it is not possible to predict which, if any, of these actions may result in increases in potential CO2 hourly emissions. Nevertheless, the EPA expects that, to the extent actions are undertaken by existing steam generating units, the magnitude of the increases in potential hourly CO2 emissions associated with the vast majority of such changes would generally be small and therefore would generally not be subject to the standards of performance for modified steam generating units finalized in this action.

Based on this information, we anticipate that few EGUs will take actions that would be considered NSPS modifications and subject to the standards of performance finalized in this action during the period of analysis. For this reason, the standards will result in minimal emission reductions, costs, or quantified benefits in the period of analysis. Likewise, the Agency does not anticipate any impacts on the price of electricity or energy supplies. This rule is not expected to raise any resource adequacy concerns, since reserve margins will not be impacted and the rule does not impose any additional requirements on existing facilities not triggering the NSPS modification provision. There are no notable macroeconomic or employment impacts expected as a result of these standards.
Due to the limited data available on past modifications and the diversity of existing units that could potentially modify, it is not possible to conduct a representative illustrative analysis of what costs and benefits might result from this rule in the unlikely case that a unit were to take an action that would be classified as a modification.
 Chapter 7
Statutory and Executive Order Reviews
7.1 	Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, Improving Regulation and Regulatory Review
This final action is a significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review. It is a significant regulatory action because it raises novel legal or policy issues arising out of legal mandates. Any changes made in response to OMB recommendations have been documented in the established dockets for this action under Docket ID No. EPA-HQ-OAR-2013-0495 (Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units) and Docket ID No. EPA-HQ-OAR-2013-0603 (Carbon Pollution Standards for Modified and Reconstructed Stationary Sources: Electric Utility Generating Units). This RIA includes an economic analysis of the potential costs and benefits associated with this action. 
The EPA does not anticipate that this final action will result in any notable compliance costs. Specifically, we believe that the standards for newly constructed fossil fuel-fired EGUs (electric utility steam generating units and natural gas-fired stationary combustion turbines) will have negligible costs associated with it over a range of likely sensitivity conditions because electric power companies will choose to build new EGUs that comply with the regulatory requirements of this action even in the absence of the action, because of existing and expected market conditions. (See Chapter 5 for further discussion of sensitivities). The EPA does not project any new coal-fired steam generating units without CCS to be built in the absence of this action. However, because some companies may choose to construct coal or other fossil fuel-fired EGUs, the RIA also analyzes project-level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel-fired EGU with CCS. As noted previously, the monetized benefits exceed the compliance costs under a range of assumptions.
The EPA also believes that the standards for modified and reconstructed fossil fuel-fired EGUs will result in minimal compliance costs, because, as previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis (through 2022). In Chapter 6, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources.
7.2 	Paperwork Reduction Act (PRA)
      The information collection activities in this final action have been submitted for approval to OMB under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number 2465.03. Separate ICR documents were prepared and submitted to OMB for the proposed standards for newly constructed EGUs (EPA ICR number 2465.02) and the proposed standards for modified and reconstructed EGUs (EPA ICR number 2506.03). Because the CO2 standards for newly constructed, modified, and reconstructed EGUs will be included in the same new subpart (40 CFR part 60, subpart TTTT) and are being finalized in the same action, the ICR document for this action includes estimates of the information collection burden on owners and operators of newly constructed, modified, and reconstructed EGUs. Estimated cost burden is based on 2013 Bureau of Labor Statistics (BLS) labor cost data. Thus, all burden estimates are in 2013 dollars. Burden is defined at 5 CFR 1320.3(b). You can find a copy of the ICR in the dockets for this action (Docket ID Numbers EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them.
      The recordkeeping and reporting requirements in this final action are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B.
      An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, the Agency will announce that approval in the Federal Register and publish a technical amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final action.
7.2.1	Newly constructed EGUs
      This final action will impose minimal new information collection burden on owners and operators of affected newly constructed fossil fuel-fired EGUs (steam generating units and stationary combustion turbines) beyond what those sources would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060-0626 and 2060-0629, respectively. Apart from certain reporting costs to comply with the emission standards under the rule, there are no new information collection costs, as the information required by the standards for newly constructed EGUs is already collected and reported by other regulatory programs. 
      The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of the rule because of existing and expected market conditions. The EPA does not project any newly constructed coal-fired steam generating units that commenced construction after proposal (January 8, 2014) to commence operation over the 3-year period covered by this ICR. We estimate that 12 affected newly constructed natural gas combined cycle units and 25 affected newly constructed natural gas-fired simple-cycle combustion turbines will commence operation during that time period. As a result of this final action, owners or operators of those newly constructed units will be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months.
7.2.2	Modified and Reconstructed EGUs
      This final action is not expected to impose an information collection burden under the provisions of the PRA on owners and operators of affected modified and reconstructed fossil fuel-fired EGUs (steam generating units and stationary combustion turbines). As previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. Specifically, the EPA believes it unlikely that fossil fuel-fired electric utility steam generating units or stationary combustion turbines will take actions that would constitute NSPS modifications or reconstructions as defined under the EPA's NSPS regulations. Accordingly, the standards for modified and reconstructed EGUs are not anticipated to impose any information collection burden over the 3-year period covered by this ICR. We have estimated, however, the information collection burden that would be imposed on an affected EGU if it was modified or reconstructed.
      Although not anticipated, if an EGU were to modify or reconstruct, this final action would impose minimal information collection burden on those affected EGUs beyond what they would already be subject to under the authorities of CAA 40 CFR parts 75 and 98. As described above, the OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations. Apart from certain reporting costs to comply with the emission standards under the rule, there would be no new information collection costs, as the information required by the final rule is already collected and reported by other regulatory programs.
      As stated above, although the EPA expects few sources will trigger either the NSPS modification or reconstruction provisions, if an EGU were to modify or reconstruct during the 3-year period covered by this ICR, the owner or operator of the EGU will be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months. The annual reporting burden for such a unit is estimated to be $1,333 and 16 labor hours. There are no annualized capital costs or O&M costs associated with burden for modified or reconstructed EGUs. 
7.2.3	Information Collection Burden
      The annual information collection burden for newly constructed, modified, and reconstructed EGUs consists only of reporting burden as explained above. The annual reporting burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $60,997 and 651 labor hours. There are no annualized capital costs or O&M costs associated with burden for newly constructed, modified, or reconstructed EGUs. Average burden hours per response are estimated to be 7 hours. The total number of respondents over the 3-year ICR period is estimated to be 62.
7.3 	Regulatory Flexibility Act (RFA)
      EPA certifies that this final action will not have a significant economic impact on a substantial number of small entities under the RFA. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden or otherwise has a positive economic effect on the small entities subject to the rule.
7.3.1	Newly constructed EGUs
	The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built. We expect that any newly constructed natural gas-fired stationary combustion turbines will meet the standards. We do not include an analysis of the illustrative impacts on small entities that may result from implementation of the final rule because we anticipate negligible compliance costs over a range of likely sensitivity conditions as a result of the standards for newly constructed EGUs. Thus the cost-to-sales ratios for any affected small entity would be zero costs as compared to annual sales revenue for the entity. Accordingly, there are no anticipated economic impacts as a result of the standards for newly constructed EGUs. We have therefore concluded that this final action will have no net regulatory burden for all directly regulated small entities.
7.3.2 	Modified and Reconstructed EGUs
      The EPA expects few fossil fuel-fired electric utility steam generating units to trigger the NSPS modification provisions in the period of analysis. An NSPS modification is defined as a physical or operational change that increases the source's maximum achievable hourly rate of emissions. The EPA does not believe that there are likely to be EGUs that will take actions that would constitute modifications as defined under the EPA's NSPS regulations.
	In addition, the EPA expects few reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. Reconstruction occurs when a single project replaces components or equipment in an existing facility and exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility.
	In Chapter 6, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources. However, we do not anticipate that the rule would impose significant costs on those sources, including any that are owned by small entities.
7.4 	Unfunded Mandates Reform Act (UMRA)
    This final action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531 - 1538, and does not significantly or uniquely affect small governments.
    The EPA believes the final rule will have negligible compliance costs on owners and operators of newly constructed EGUs over a range of likely sensitivity conditions because electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly constructed natural gas-fired stationary combustion turbines will meet the standards.
    As previously stated, the EPA expects few fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines to trigger the modification or reconstruction provisions in the period of analysis. In Chapter 6, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources. However, we do not anticipate that the rule would impose significant costs on those sources.
We have therefore concluded that the standards for newly constructed, modified, and reconstructed EGUs do not impose enforceable duties on any state, local or tribal governments, or the private sector, that may result in expenditures by state, local and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. We have also concluded that this action does not have regulatory requirements that might significantly or uniquely affect small governments. The threshold amount established for determining whether regulatory requirements could significantly affect small governments is $100 million annually and, as stated above, we have concluded that the final action will not result in expenditures of $100 million or more in any one year. Specifically, the EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly constructed natural gas-fired stationary combustion turbines will meet the standards. Further, the EPA expects few fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis.
7.5 	Executive Order 13132, Federalism
      This final action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. In addition, as previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. We, therefore, anticipate that the final rule will impose minimal compliance costs.
7.6 	Executive Order 13175, Consultation and Coordination with Indian Tribal Governments
      This final action does not have tribal implications as specified in Executive Order 13175. The final rule will impose requirements on owners and operators of newly constructed, modified, and reconstructed EGUs. The EPA is aware of three facilities with coal-fired steam generating units, as well as one facility with natural gas-fired stationary combustion turbines, located in Indian Country, but is not aware of any EGUs owned or operated by tribal entities. We note that because the rule addresses CO2 emissions from newly constructed, modified, and reconstructed EGUs, it will affect existing EGUs such as those located at the four facilities in Indian Country only if those EGUs were to take actions constituting modifications or reconstructions as defined under the EPA's NSPS regulations. As previously stated, the EPA expects few EGUs to trigger the NSPS modification or reconstruction provisions in the period of analysis. Thus, the rule will neither impose substantial direct compliance costs on tribal governments nor preempt Tribal law. Accordingly, Executive Order 13175 does not apply to this action.
      Nevertheless, because the EPA is aware of Tribal interest in carbon pollution standards for the power sector and, consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA offered consultation with tribal officials during development of this rule. Prior to the April 13, 2012 proposal (77 FR 22392), the EPA sent consultation letters to the leaders of all federally recognized tribes. Although only newly constructed, modified, and reconstructed EGUs will be affected by this action, the EPA's consultation regarded planned actions for new and existing sources. The letters provided information regarding the EPA's development of NSPS and emission guidelines for EGUs and offered consultation. A consultation/outreach meeting was held on May 23, 2011, with the Forest County Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa Reservation, and the Leech Lake Band of Ojibwe. A description of that consultation is included in the preamble to the proposed standards for new EGUs (79 FR 1501, January 8, 2014).
      The EPA also offered consultation to the leaders of all federally recognized tribes after the proposed action for newly constructed EGUs was signed on September, 20, 2013. On November 1, 2013, the EPA sent letters to tribal leaders that provided information regarding the EPA's development of carbon pollution standards for new, modified, reconstructed and existing EGUs and offered consultation. No tribes requested consultation regarding the standards for newly constructed EGUs.
In addition to offering consultation, the EPA also conducted outreach to tribes during development of this rule. The EPA held a series of listening sessions prior to proposal of GHG standards for newly constructed EGUs. Tribes participated in a session on February 17, 2011, with the state agencies, as well as in a separate session with tribes on April 20, 2011. The EPA also held a series of listening sessions prior to proposal of GHG standards for modified and reconstructed EGUs and GHG emission guidelines for existing EGUs. Tribes participated in a session on September 9, 2013, together with the state agencies, as well as in a separate tribe-only session on September 26, 2013. In addition, an outreach meeting was held on September 9, 2013, with tribal representatives from some of the federally recognized tribes. The EPA also met with tribal environmental staff with the National Tribal Air Association, by teleconference, on July 25, 2013, and December 19, 2013. Additional detail regarding this stakeholder outreach is included in the preamble to the proposed emission guidelines for existing EGUs (79 FR 34830, June 18, 2014).
7.7 	Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks
       This action is not subject to Executive Order 13045 because it is not economically significant as defined in Executive Order 12866. While the action is not subject to Executive Order 13045, the EPA believes that the environmental health or safety risk addressed by this action has a disproportionate effect on children. Accordingly, the agency has evaluated the environmental health and welfare effects of climate change on children. 
       CO2 is a potent greenhouse gas that contributes to climate change and is emitted in significant quantities by fossil fuel-fired power plants. As stated above, the EPA believes the final rule will have negligible effects on owners and operators of newly constructed EGUs over a range of likely sensitivity conditions because electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the rule because of existing and expected market conditions. However, Chapter 5 of this RIA also analyzes project-level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel-fired unit with CCS. Under these scenarios, the rule would result in substantial reductions of both CO2, and also fine particulate matter such that net quantifiable benefits exceed regulatory costs under a range of scenarios. Under these same scenarios, this rule would have a positive effect for children's health.
       The assessment literature cited in the EPA's 2009 Endangerment Finding concluded that certain populations and lifestages, including children, the elderly, and the poor, are most vulnerable to climate-related health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed findings regarding these groups' vulnerabilities and the projected impacts they may experience.
       These assessments describe how children's unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households.
       More detailed information on the impacts of climate change to human health and welfare is provided in Section II.A of the preamble. 
7.8 	Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
This final action is not a "significant energy action" because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. In addition, as previously stated, the EPA expects few fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. Thus, this action is not anticipated to have notable impacts on emissions, costs or energy supply decisions for the affected electric utility industry.
7.9 	National Technology Transfer and Advancement Act 
      This final action involves technical standards. The following voluntary consensus standards are used in the final rule: American Society for Testing and Materials (ASTM) Methods D388-12 (Standard Classification of Coals by Rank), D396-13c (Standard Specification for Fuel Oils), D975-14 (Standard Specification for Diesel Fuel Oils), D3699-13b (Standard Specification for Kerosene), D6751-12 (Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels), D7467-13 (Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20)), and American National Standards Institute (ANSI) Standard C12.20 (American National Standard for Electricity Meters - 0.2 and 0.5 Accuracy Classes). The rule also requires use of Appendices A, B, D, F and G to 40 CFR part 75; these Appendices contain standards that have already been reviewed under the NTTAA. 
7.10	Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the U.S. The EPA defines environmental justice as the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. The EPA has this goal for all communities and persons across this Nation. It will be achieved when everyone enjoys the same degree of protection from environmental and health hazards and equal access to the decision-making process to have a healthy environment in which to live, learn, and work.
Leading up to this rulemaking the EPA summarized the public health and welfare effects of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment Finding, the Administrator considered climate change risks to minority or low-income populations, finding that certain parts of the population may be especially vulnerable based on their circumstances. Populations that were found to be particularly vulnerable to climate change risks include the poor, the elderly, the very young, those already in poor health, the disabled, those living alone, and/or indigenous populations dependent on one or a few resources. See Sections F and G, above, where the EPA discusses Consultation and Coordination with Tribal Governments and Protection of Children. The Administrator placed weight on the fact that certain groups, including children, the elderly, and the poor, are most vulnerable to climate-related health effects.
The record for the 2009 Endangerment Finding summarizes the strong scientific evidence that the potential impacts of climate change raise environmental justice issues is found in the major assessment reports by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies that the potential impacts of climate change raise environmental justice issues. These reports concluded that poor communities can be especially vulnerable to climate change impacts because they tend to have more limited adaptive capacities and are more dependent on climate-sensitive resources such as local water and food supplies. In addition, Native American tribal communities possess unique vulnerabilities to climate change, particularly those impacted by degradation of natural and cultural resource within established reservation boundaries and threats to traditional subsistence lifestyles. Tribal communities whose health, economic well-being, and cultural traditions depend upon the natural environment will likely be affected by the degradation of ecosystem goods and services associated with climate change. 
The 2009 Endangerment Finding record also specifically noted that Southwest native cultures are especially vulnerable to water quality and availability impacts. Native Alaskan communities already experiencing disruptive impacts, including coastal erosion and shifts in the range or abundance of wild species crucial to their livelihoods and well-being. The most recent assessments continue to strengthen scientific understanding of climate change risks to minority and low-income populations in the United States. The new assessment reports provides more detailed findings regarding these populations' vulnerabilities and projected impacts they may experience. In addition, the most recent assessment reports provide new information on how some communities of color may be uniquely vulnerable to climate change health impacts in the United States. These reports find that certain climate change related impacts -- including heat waves, degraded air quality, and extreme weather events -- have disproportionate effects on low-income and some communities of color, raising environmental justice concerns. Existing health disparities and other inequities in these communities increase their vulnerability to the health effects of climate change. In addition, the assessment reports also find that climate change poses particular threats to health, wellbeing, and ways of life of indigenous peoples in the United States.
As the scientific literature presented above and in the Endangerment Finding illustrates, low income communities and some communities of color are especially vulnerable to the health and other adverse impacts of climate change.
The EPA believes the human health or environmental risk addressed by this final action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations. The final rule limits GHG emissions from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units and natural gas-fired stationary combustion turbines by establishing national emission standards for CO2.
The EPA has determined that the final rule will not result in disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because the rule is not anticipated to notably affect the level of protection provided to human health or the environment. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units and natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly built natural gas-fired stationary combustion turbines will meet the standards. In addition, as previously stated, the EPA expects few fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines to trigger the NSPS modification or reconstruction provisions in the period of analysis. This final rule will ensure that, to whatever extent there are newly constructed, modified, and reconstructed EGUs, they will use the best performing technologies to limit emissions of CO2.
7.11	Congressional Review Act (CRA)
This final action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is not a "major rule" as defined by 5 U.S.C. 804(2).



United States
Environmental Protection
Agency
                 Office of Air Quality Planning and Standards
                   Health and Environmental Impacts Division
                          Research Triangle Park, NC
                                               Publication No. EPA-452/R-15-005
                                                                    August 2015

