Document ID: EPA-HQ-OAR-2013-0495-11709
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2015-10-23T04:00Z

EO 12866_111(b) New-Mods 2060-AQ91 RIA Final_20150520
 
 Executive Summary
This Regulatory Impact Analysis (RIA) discusses potential benefits, costs, and economic impacts of the Final Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units (herein referred to as the EGU New, Modified, and Reconstructed Source GHG Standards).
ES.1	Background and Context of Final Rule
The final EGU New, Modified and Reconstructed Source GHG Standards will set emission limits for greenhouse gas emissions (GHG) from newly constructed, modified, and reconstructed fossil fuel-fired electricity generating units (EGUs). This rulemaking will apply to carbon dioxide (CO2) emissions from any affected fossil fuel-fired EGU. The United States Environmental Protection Agency (EPA) is finalizing requirements for these sources because CO2 is a GHG and fossil fuel-fired power plants are the country's largest stationary source emitters of GHGs. As stated in the EPA's Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act (CAA) (74 FR 66518) and  summarized in Chapter 3 of this RIA, the anthropogenic buildup of GHGs in the atmosphere is the cause of most of the observed global warming over the last 50 years.  
On June 25, 2013, in conjunction with the announcement of his Climate Action Plan, President Obama issued a Presidential Memorandum directing the EPA to issue a proposal to address carbon pollution from new power plants by September 30, 2013, and to issue "standards, regulations, or guidelines, as appropriate, which address carbon pollution from modified, reconstructed, and existing power plants." On September 20, 2013, pursuant to authority in CAA section 111(b), EPA Administrator Gina McCarthy signed proposed carbon pollution standards for newly constructed fossil fuel-fired power plants (79 FR 1430, January 8, 2014). 
The EPA subsequently issued a Notice of Data Availability (NODA), soliciting comment on its initial interpretation of provisions in the Energy Policy Act of 2005 and the Internal Revenue Code, and also soliciting comment on a Technical Support Document, which addressed these provisions' relationship to the factual record supporting the proposed rule (79 FR 10750, February 26, 2014).   
On June 2, 2014, Administrator McCarthy signed proposed standards of performance, also pursuant to CAA section 111(b), to limit emissions of CO2 from modified and reconstructed fossil fuel-fired electric utility steam generating units and stationary combustion turbines (79 FR 34959, June 18, 2014).
In this action, the EPA is finalizing standards of performance to limit emissions of CO2 from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units and stationary combustion turbines. Consistent with the requirements of CAA section 111(b), these standards reflect the degree of emission limitation achievable through the application of the best system of emission reduction (BSER) that the EPA has determined has been adequately demonstrated for each type of unit.
ES.2 	Summary of the Final Rule 
The EPA has determined that the BSER for newly constructed steam generating units is partial carbon capture and storage (CCS) technology to meet an emission limitation of 1,400 lb CO2/MWh-gross. The standard for modified steam generating units that conduct modifications resulting in a potential hourly increase in CO2 emissions (mass per hour) of more than 10 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 1,080 lb CO2/MWh of net energy output).
The BSER determination and final standards for each affected source are shown in Table ES-1. The applicability of these standards based on the capacity and operation of a source are described in the preamble for this final rule.  The final standards for all source categories will be met on a 12-operating month rolling average basis. 
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 standard without the need for additional controls. 
The base case modeling the EPA performed for this rule (as well as modeling that the EPA has performed for other recent air rules) projects that, even in the absence of this action, new fossil-fuel fired capacity constructed through 2022 and the years following will most likely be NGCC capacity that complies with the final standards. Analyses performed both by the EPA and the Energy Information Administration (EIA) project that new compliant natural gas-fired units and renewable sources are likely to be the technologies of choice for new generating capacity due to current and projected economic market conditions. 

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

1. 1,800 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h.
                                      OR
                                       
2. 2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Reconstructed Fossil Fuel-Fired Steam Generating Units
         Most efficient generating technology at the affected source.
1. 1,800 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h.
                                      OR
                                       
2. 2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Newly Constructed, Modified, and Reconstructed Natural Gas-Fired Stationary Combustion Turbines
            Efficient Natural Gas Combined Cycle (NGCC) Technology
   1.    1,000 lb CO2/MWh-gross 
                         OR
   2.    1,080 lb CO2/MWh-net
Historically, the EPA has been notified of very few EGU NSPS modifications (for criteria pollutants) or reconstructions. As such, the EPA anticipates few covered units will trigger the reconstruction or modification provisions in the period of analysis. 
 Therefore, based on the analysis presented in Chapter 4 of this RIA, the EPA anticipates that the EGU New, Modified, and Reconstructed Source GHG Standards will result in negligible CO2 emission changes, energy impacts, quantified benefits, costs, and economic impacts by 2022. Accordingly, the EPA also does not anticipate this rule will have any significant impacts on the price of electricity, employment or labor markets, or the US economy. 
While the primary conclusion of the analysis presented in this RIA is that the standards for newly constructed EGUs will result in negligible costs and benefits, the EPA has also performed several illustrative analyses, in Chapter 5, that show the potential impacts of the rule if certain key assumptions were to change, or if idiosyncratic circumstances suggest in the absence of this rule a unit that does not comply with these standards may be constructed. This analysis finds that under the unlikely conditions in which the EPA's conclusions regarding the future economic competitiveness of new noncompliant coal-fired units with respect to other new generation technologies shifts, that the benefits of the standards to society likely outweigh the costs. 
The final standards provide the benefit of regulatory certainty that any new coal-fired power plant must limit CO2 emissions through implementation of partial CCS or other technologies such as natural gas co-firing. The final standards reduce regulatory uncertainty by defining the requirements to limit emissions of CO2 from new, modified, and reconstructed fossil fuel-fired steam generating sources. 
In addition, the EPA intends this rule to send a clear signal about the current and future status of CCS technology.  Additional CCS applications are expected to lead to improvements in these technologies' performance and consequent reductions in their cost. Identifying partial CCS technology as the best system of emission reductions (BSER) for coal-fired power plants promotes further development and encourages continued research of CCS, [,]  which is important for long-term CO2 emission reductions.  
The final standards also provide regulatory certainty for stationary combustion turbines that, along with new renewable sources, are expected to be the primary technology options to provide new generating capacity in the analysis period. Any new stationary combustion turbines must be well-designed, well-maintained, and well-operated and final applicability criteria clearly exclude combustion turbines that are intended to serve peak power demand rather than intermediate and base load.  

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

1. 1,800 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h.
                                      OR
2. 2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Reconstructed Fossil Fuel-Fired Steam Generating Units
         Most efficient generating technology at the affected source.
1. 1,800 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h.
                                      OR
                                       
2. 2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Newly Constructed, Modified, and Reconstructed Natural Gas-Fired Stationary Combustion Turbines
                           Efficient NGCC Technology
   1.    1,000 lb CO2/MWh-gross 
                         OR
   2.    1,080 lb CO2/MWh-net
1.2.5	Emission Reductions
As will be discussed in more detail in Chapter 4 of this RIA, the EPA anticipates that the EGU New, Modified, and Reconstructed Source GHG Standards will result in negligible changes in GHG emissions over the analysis period. Even in the absence of this rule, the EPA expects that owners of new units will choose generation technologies that meet these standards due to expected economic conditions in the marketplace. Based on historical precedent, the EPA anticipates few covered units will trigger the reconstruction or modification provisions in the period of analysis. As a result, we do not anticipate any significant costs or monetized benefits associated with this rule.
1.3	Organization of the Regulatory Impact Analysis
	This report presents the EPA's analysis of the potential benefits, costs, and other economic effects of the EGU New, Modified, and Reconstructed Source GHG Standards to fulfill the requirements of an RIA. This RIA includes the following chapters:
Chapter 2, Electric Power Sector Profile, describes the industry affected by the rule. 
Chapter 3, Benefits of Reducing GHGs and Other Pollutants, describes the effects of emissions on climate and health and provides background information to support the benefits analysis.
Chapter 4, Costs, Economic, and Energy Impacts, describes impacts of the rule.
Chapter 5, Analysis of Illustrative Cost-Benefit Scenarios, describes additional analyses examining potential impacts under a range of scenarios.
Chapter 6, Modified and Reconstructed Sources, describes the potential impacts of the standards for modified and reconstructed sources.
Chapter 7, Statutory and Executive Order Impact Analyses, describes the small business, unfunded mandates, paperwork reduction act, environmental justice, and other analyses conducted for the rule to meet statutory and Executive Order requirements. 
          
 Chapter 2
Electric Power Sector Profile
2.1 	Introduction
This chapter discusses important aspects of the power sector that relate to the EGU New Source GHG Standards, including the types of power-sector sources affected by the regulation, and provides background on the power sector and EGUs. In addition, this chapter provides some historical background on trends in the past decade in the power sector, as well as about existing EPA regulation of the power sector.
In the past decade there have been significant structural changes in the both the mix of generating capacity and in the share of electricity generation supplied by different types of generation. These changes are the result of multiple factors in the power sector, including normal replacements of older generating units with new units, changes in the electricity intensity of the US economy, growth and regional changes in the US population, technological improvements in electricity generation from both existing and new units, changes in the prices and availability of different fuels, and substantial growth in electricity generation by renewable and unconventional methods. Many of these trends will continue to contribute to the evolution of the power sector. The evolving economics of the power sector, in particular the increased natural gas supply and subsequent relatively low natural gas prices, have resulted in more gas being utilized as base load energy in addition to supplying electricity during peak load. This chapter presents data on the evolution of the power sector from 2002 through 2012. Projections of new capacity and the impact of this rule on these new sources are discussed in more detail in Chapter 4 of this RIA.
2.2 	Power Sector Overview
The production and delivery of electricity to customers consists of three distinct segments: generation, transmission, and distribution. 
2.2.1 	Generation
Electricity generation is the first process in the delivery of electricity to consumers. There are two important aspects of electricity generation; capacity and net generation. Generating Capacity refers to the maximum amount of production from an EGU in a typical hour, typically measured in megawatts (MW) or gigawatts (1 GW = 1000 MW).  Electricity Generation refers to the amount of electricity actually produced by EGUs, measured in kilowatt-hours (kWh) or gigawatt-hours (GWh = 1 million kWh). In addition to producing electricity for sale to the grid, generators perform other services important to reliable electricity supply, such as providing backup generating capacity in the event of unexpected changes in demand or unexpected changes in the availability of other generating markets. Other important services provided by generators include facilitating the regulation of the voltage of supplied generation.
Individual EGUs are not used to generate electricity 100 percent of the time.  Individual EGUs are periodically not needed to meet the regular daily and seasonal fluctuations of electricity demand. Furthermore, EGUs relying on renewable resources such as wind, sunlight and surface water to generate electricity are routinely constrained by the availability of adequate wind, sunlight or water at different times of the day and season. Units are also unavailable during routine and unanticipated outages for maintenance.  These factors result in the mix of generating capacity types available (e.g., the share of capacity of each type of EGU) being substantially different than the mix of the share of total electricity produced by each type of EGU in a given season or year. 
Most of the existing capacity generates electricity by creating heat to create high pressure steam that is released to rotate turbines which, in turn, create electricity. Other units generate electricity by using water or wind to rotate turbines, and a variety of other methods also make up a small, but growing, share of the overall electricity supply. The generating capacity includes fossil-fuel-fired units, nuclear units, and hydroelectric and other renewable sources (see Table 2-1). Table 2-1 also shows the comparison between the generating capacity in 2002 and 2012.
In 2012 the power sector consists of over 19,000 generating units with a total capacity of 1,168 GW, an increase of 188 GW (or 19 percent) from the capacity in 2002 (989 GW). The 188 GW increase consisted primarily of natural gas fired EGUs (134 GW) and wind generators (55 GW), with substantially smaller net increases and decreases in other types of generating units. 

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, 2012. Downloaded from EIA Electricity Data Browser, Electric Power Plants Generating Capacity By Source, 2000  -  2012.  Available at http://www.eia.gov/electricity/data.cfm#gencapacity. Accessed 12/19/2014
[1] Natural Gas information in this chapter (unless otherwise stated) reflects data for all generating units using natural gas as the primary fossil heat source.  This includes Combined Cycle Combustion Turbine (31 percent of 2012 NG-fired capacity), Gas Turbine (30 percent), Combined Cycle Steam (19 percent), Steam Turbine (17 percent), and miscellaneous (< 1 percent).

The 19 percent increase in generating capacity is the net impact of newly built generating units, retirements of generating units, and a variety of increases and decreases to the nameplate capacity of individual existing units due to changes in operating equipment, changes in emission controls, etc. During the period 2002 to 2012, a total of 315,752 MW of new generating capacity was built and brought online, and 64,763 MW existing units were retired. The net effect of the re-rating of existing units reduced the total capacity by 62,579 MW. The overall net change in capacity was 188,410 MW, as shown in Table 2-1.
The newly built generating capacity was primarily natural gas (226,605 MW), which was partially offset by gas retirements (29,859 MW). Wind capacity was the second largest type of 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 4,058 billion kWh to meet electricity demand, a 5 percent increase from 2002 (3,858 billion kWh). As presented in Table 2-2, almost 70 percent of electricity in 2012 was produced through the combustion of fossil fuels, primarily coal and natural gas, with coal accounting for the largest single share. Although the share of the total generation from fossil fuels in 2012 (67 percent) was only modestly smaller than the total fossil share in 2002 (71 percent), the mix of fossil fuel generation changed substantially during that period.  Coal generation declined by 18 percent and petroleum generation by 63 percent, while natural gas generation increased by 61 percent.  This reflects both the increase in natural gas capacity during that period as well as an increase in the utilization of new and existing gas EGUs during that period. Wind generation also grew from a very small portion of the overall total in 2002 to 4.1 percent of the 2012 total.
Table 2-2.  Net Generation in 2002 and 2012 (Trillion kWh = TWh)

                                     2002
                                     2012
                          Change Between '02 and '12
                                       
                             Net Generation (TWh)
                               Fuel Source Share
                             Net Generation (TWh)
                               Fuel Source Share
                          Net Generation Change (TWh)
                          % Change in Net Generation
Coal
                                                                        1,933.1
                                                                            50%
                                                                        1,586.0
                                                                            39%
                                                                         -347.1
                                                                         -18.0%
Natural Gas
                                                                          702.5
                                                                            18%
                                                                        1,125.9
                                                                            28%
                                                                          423.5
                                                                          60.3%
Nuclear
                                                                          780.1
                                                                            20%
                                                                          789.0
                                                                            19%
                                                                            9.0
                                                                           1.1%
Hydro
                                                                          255.6
                                                                             7%
                                                                          264.7
                                                                             7%
                                                                            9.1
                                                                           3.6%
Petroleum
                                                                           94.6
                                                                           2.5%
                                                                           26.9
                                                                           0.7%
                                                                          -67.7
                                                                         -71.6%
Wind
                                                                           10.4
                                                                           0.3%
                                                                          167.7
                                                                           4.1%
                                                                          157.3
                                                                        1519.3%
Other Renewable
                                                                           68.8
                                                                           1.8%
                                                                           85.7
                                                                           2.1%
                                                                           16.9
                                                                          24.6%
Misc
                                                                           13.5
                                                                           0.4%
                                                                           12.4
                                                                           0.3%
                                                                           -1.2
                                                                          -8.7%
Total
                                                                          3,858
                                                                           100%
                                                                          4,058
                                                                           100%
                                                                            200
                                                                             5%
Source: U.S. EIA Monthly Energy Review, December 2014. Table 7.2a Electricity Net Generation: Total (All Sectors).  Available at http://www.eia.gov/totalenergy/data/monthly/. Accessed 12/19/2014

Coal-fired and nuclear generating units have historically supplied "base load" electricity, the portion of electricity loads which are continually present, and typically operate throughout all hours of the year. The coal units meet the part of demand that is relatively constant. Although much of the coal fleet operates as base load, there can be notable differences across various facilities (see Table 2-3). For example, coal-fired units less than 100 megawatts (MW) in size compose 37 percent of the total number of coal-fired units, but only 6 percent of total 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 of EGUs is generally smaller and newer.  While 55 percent of the coal EGU fleet is over 500 MW per unit, 77 percent of the gas fleet is between 50 and 500 MW per unit. Many of the largest gas units are gas-fired steam-generating EGUs. 
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.5.14 in operation in 2013 or earlier (excludes ~2,100 MW of coal-fired IGCC and fossil waste capacity), and excludes those units in NEEDS with planned retirements in 2014 or2015.

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

Figure 2-3. Fossil Fuel-Fired Electricity Generating Facilities, by Size
Source: National Electric Energy Data System (NEEDS) v.5.13
Note: This map displays fossil capacity at facilities in the NEEDS v.5.13 IPM frame. NEEDS reflects available fossil capacity on-line by the end of 2015. This includes planned new builds already under construction and planned retirements. In areas with a dense concentration of facilities, some facilities may be obscured. 
2.2.2 	Transmission
Transmission is the term used to describe the movement of electricity over a network of high voltage lines, from electric generators to substations where power is stepped down for local distribution. In the U.S. and Canada, there are three separate interconnected networks of high voltage transmission lines, each operating synchronously. Within each of these transmission networks, there are multiple areas where the operation of power plants is monitored and controlled to ensure that electricity generation and load are kept in balance. In some areas, the operation of the transmission system is under the control of a single regional operator; in others, individual utilities coordinate the operations of their generation, transmission, and distribution systems to balance their common generation and load needs.
2.2.3 	Distribution
Distribution of electricity involves networks of lower voltage lines and substations that take the higher voltage power from the transmission system and step it down to lower voltage levels to match the needs of customers. The transmission and distribution system is the classic example of a natural monopoly, in part because it is not practical to have more than one set of lines running from the electricity generating sources to substations or from substations to residences and businesses.
Transmission has generally been developed by the larger vertically integrated utilities that typically operate generation and distribution networks. Often distribution is handled by a large number of utilities that purchase and sell electricity, but do not generate it. Over the last couple of decades, several jurisdictions in the United States began restructuring the power industry to separate transmission and distribution from generation, ownership, and operation. As discussed below, electricity restructuring has focused primarily on efforts to reorganize the industry to encourage competition in the generation segment of the industry, including ensuring open access of generation to the transmission and distribution services needed to deliver power to consumers. In many states, such efforts have also included separating generation assets from transmission and distribution assets to form distinct economic entities. Transmission and distribution remain price-regulated throughout the country based on the cost of service.
2.3 	Sales, Expenses and Prices
These electric generating sources provide electricity for commercial, industrial and residential ultimate customers.  Each of the three major ultimate categories consume roughly a quarter to a third of the total electricity 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)

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

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

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

Figure 2-5.  Nominal National Average Electricity Prices for Three Major End-Use Categories
Source: EIA AEO 2012, Table 2.4
Electricity prices for all three end-use categories increased more than overall inflation through this period, measured by either the GDP implicit price deflator (23.5 percent) or the consumer price index (CPI-U, which increased by 27.7 percent). 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% and 28% 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 3 fossil fuels between 2002 and 2012.

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

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

                                       
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 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 for each of the ownership types is shown in Figures 2-13 (capacity) and 2-14 (generation).  The capacity and generation data for commercial and industrial owners are not shown on these figures due to the small magnitude of those ownership types. Figures 2-13 and 2-14 present the mixes in 2002 and 2012. A portion of the shift of capacity and generation is due to sales and transfers of generation assets from traditional utilities to IPPs, rather than strictly the result of newly built units.

Figures 2-13 & 2-14.	Capacity and Generation Mix by Ownership Type, 2002 & 2012

The mix of capacity by fuel types that have been built and retired between 2002 and 2012 also varies significantly by type of ownership.  Figure 2-15 presents the new capacity built during that period, showing that IPPs built the majority of both new wind and solar generating capacity, as well as somewhat more natural gas capacity than the traditional utilities built.  Figure 2-16 presents comparable data for the retired capacity, showing that utilities retired more coal and "other" capacity (mostly oil-fired) than IPPs retired, while the IPPs retired more natural gas capacity than the utilities retired. The retired gas capacity was primary (60%) steam and combustion turbines.

 
Figure 2-15. 	Domestic Emissions of Greenhouse Gases from Major Sectors, 2002 and 2012 (million metric tonnes of CO2 equivalent)
Source:	EPA, 2014 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012", Table 2-12

Figures 2-15 & 2-16.	Generation Capacity Built and Retired Between 2002 and 2012 by Ownership Type
 
2.5	Emissions of Greenhouse Gases from Electric Utilities
The burning of fossil fuels, which generates about 69 percent of our electricity nationwide, results in emissions of greenhouse gases. The power sector is a major contributor of CO2 in particular, but also contributes to emissions of sulfur hexafluoride (SF6), CH4, and N2O. In 2012, the electricity generation accounted for 38 percent of national CO2 emissions. Including both generation and transmission (a source of SF6) and generation, the power sector accounted for 31 percent of total nationwide greenhouse gas emissions, measured in CO2 equivalent. Table 2-5 and Figure 2-17 show the CO2 emissions from the power sector relative to other major economic sectors. Table 2-6 shows the contributions of CO2 and other GHGs from the power and other major emitting economic sectors. 

Table 2-5. 	Domestic Emissions of Greenhouse Gases, by Economic Sector (million metric tonnes of CO2 equivalent)
 
                                     2002
                                     2012
                          Change Between '02 and '12
                                 Sector/Source
                                 GHG Emissions
                             % Total GHG Emissions
                                 GHG Emissions
                             % Total GHG Emissions
                              Change in Emissions
                             % Change in Emissions
                        % of Total Change in Emissions
Electric Power Industry
                                                                          2,313
                                                                            33%
                                                                          2,064
                                                                            32%
                                                                           -249
                                                                           -11%
                                                                            48%
Transportation
                                                                          1,958
                                                                            28%
                                                                          1,837
                                                                            28%
                                                                           -121
                                                                            -6%
                                                                            23%
Industry
                                                                          1,419
                                                                            20%
                                                                          1,278
                                                                            20%
                                                                           -140
                                                                           -10%
                                                                            27%
Agriculture
                                                                            561
                                                                             8%
                                                                            614
                                                                             9%
                                                                             53
                                                                            10%
                                                                           -10%
Commercial
                                                                            365
                                                                             5%
                                                                            353
                                                                             5%
                                                                            -12
                                                                            -3%
                                                                             2%
Residential
                                                                            374
                                                                             5%
                                                                            321
                                                                             5%
                                                                            -53
                                                                           -14%
                                                                            10%
US Territories
                                                                             52
                                                                             1%
                                                                             58
                                                                             1%
                                                                              6
                                                                            11%
                                                                            -1%
Total Emissions
                                                                          7,041
                                                                           100%
                                                                          6,526
                                                                           100%
                                                                           -516
                                                                            -7%
                                                                           100%
Sinks and Reductions
                                                                           -885
                                                                              
                                                                           -979
                                                                               
                                                                            -94
                                                                            11%
                                                                               
Net Emissions
                                                                          6,156
                                                                              
                                                                          5,546
                                                                              
                                                                           -610
                                                                           -10%
                                                                              
Source:	EPA, 2014 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012", Table 2-12. Includes CO2, CH4, N2O and SF6 emissions.
The amount of CO2 emitted during the combustion of fossil fuels varies according to the carbon content and heating value of the fuel used. The CO2 emission factors used in IPM v5.14 (same as used in v5.13) are shown in Table 2-7. Coal has higher carbon content than oil or natural gas, and thus releases more CO2 during combustion. Coal emits around 1.7 times as much carbon per unit of energy when burned as natural gas (EPA 2013).

Table 2-6. 	Greenhouse Gas Emissions from the Electricity Sector (Generation, Transmission and Distribution), 2002 and 2012 (million metric tonnes of CO2 equivalent)
                                       
                                       
                                     2002
                                     2012
                          Change Between '02 and '12
                            Gas/Fuel Type or Source
                                 GHG Emissions
                  % of Total GHG Emissions from Power Sector
                                 GHG Emissions
                  % of Total GHG Emissions from Power Sector
                              Change in Emissions
                             % Change in Emissions
CO2
                                                                               
                                                                          2,287
                                                                          98.9%
                                                                          2,039
                                                                          98.8%
                                                                           -248
                                                                           -11%
                                                                               
Fossil Fuel Combustion
                                                                          2,273
                                                                          98.2%
                                                                          2,023
                                                                          98.0%
                                                                           -250
                                                                           -11%
                                                                               
Coal
                                                                          1,890
                                                                          81.7%
                                                                          1,511
                                                                          73.2%
                                                                           -379
                                                                           -20%
                                                                               
Natural Gas
                                                                            306
                                                                         13.22%
                                                                            492
                                                                         23.85%
                                                                            187
                                                                            61%
                                                                               
Petroleum
                                                                           76.8
                                                                          3.32%
                                                                           18.8
                                                                          0.91%
                                                                          -58.0
                                                                           -76%
                                                                               
Geothermal
                                                                            0.4
                                                                          0.02%
                                                                            0.4
                                                                          0.02%
                                                                            0.0
                                                                             0%
                                                                               
Incineration of Waste
                                                                           11.8
                                                                          0.51%
                                                                           12.2
                                                                          0.59%
                                                                            0.4
                                                                             3%
                                                                               
Other Process Uses of Carbonates
                                                                            2.6
                                                                          0.11%
                                                                            4.0
                                                                          0.19%
                                                                            1.4
                                                                            54%
CH4
                                                                               
                                                                            0.4
                                                                          0.02%
                                                                            0.5
                                                                          0.02%
                                                                            0.1
                                                                            25%
                                                                               
Stationary Combustion*
                                                                            0.4
                                                                          0.02%
                                                                            0.5
                                                                          0.02%
                                                                            0.1
                                                                            25%
                                                                               
Incineration of Waste
                                                                              +
                                                                               
                                                                             + 
                                                                               
                                                                               
                                                                               
N2O
                                                                               
                                                                           12.4
                                                                          0.54%
                                                                           18.6
                                                                          0.90%
                                                                            6.2
                                                                            50%
                                                                               
Stationary Combustion*
                                                                           12.0
                                                                          0.52%
                                                                           18.3
                                                                          0.89%
                                                                            6.3
                                                                            53%
                                                                               
Incineration of Waste
                                                                            0.4
                                                                          0.02%
                                                                            0.4
                                                                          0.02%
                                                                            0.0
                                                                             0%
SF6
                                                                               
                                                                           13.3
                                                                          0.57%
                                                                            6.0
                                                                          0.29%
                                                                           -7.3
                                                                           -55%
                                                                               
Electrical Transmission and Distribution
                                                                           13.3
                                                                          0.57%
                                                                            6.0
                                                                          0.29%
                                                                           -7.3
                                                                           -55%
Total GHG Emissions
                                                                          2,313
                                                                               
                                                                          2,064
                                                                               
                                                                           -249
                                                                           -11%
Source:	EPA, 2014 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012", Table 2-13
* Includes only stationary combustion emissions related to the generation of electricity.
** SF6 is not covered by this rule, which specifically regulates GHG emissions from combustion.
+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.

Table 2-7.	Fossil Fuel Emission Factors in EPA Base Case 5.14 IPM Power Sector Modeling Application
     Fuel Type
     Carbon Dioxide (lbs/MMBtu)
Coal 
                                       
   Bituminous 
                                202.8  -  209.6
   Subbituminous 
                                209.2  -  215.8
   Lignite 
                                212.6  -  219.
Natural Gas 
                                     117.1
Fuel Oil 
                                       
   Distillate 
                                     161.4
   Residual 
                                161.4  -  173.9
Biomass
                                      195
Waste Fuels 
                                       
   Waste Coal 
                                     204.7
   Petroleum Coke 
                                     225.1
   Fossil Waste 
                                     321.1
   Non-Fossil Waste 
                                       0
   Tires 
                                     189.5
   Municipal Solid Waste 
                                     91.9
Source:	Documentation for IPM Base Case v.5.13, Table 11-5. The emission factors used in Base Case 5.14 are identical to the emission factors in IPM Base Case 5.13.
Note:	CO2 emissions presented here for biomass account for combustion only and do not reflect lifecycle emissions from initial photosynthesis (carbon sink) or harvesting activities and transportation (carbon source).
2.6 	Carbon Dioxide Control Technologies
In the power sector, current approaches available for significantly reducing the CO2 emissions of new fossil fuel combustion sources intended for intermediate and base load operations include the use of: carbon capture and storage (CCS), higher-efficiency designs (e.g., supercritical or ultra-supercritical steam units, integrated gasification combined cycle (IGCC), or combined cycle combustion turbine/steam-turbine units), and/or lower-emitting fuels (e.g. natural gas rather than coal).
Daily peak electricity demands, involving operation for relatively few hours per year, are often most economically met by simple-cycle combustion turbines (CT). Stationary CTs used for power generation can be installed quickly, at relatively low capital cost. They can be remotely started and loaded quickly, and can follow rapid demand changes. Full-load efficiencies of large 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 fertilizer, and CO2 can be captured for use in EOR.  
2.6.1 	Carbon Capture and Storage
CCS can be achieved through either pre-combustion or post-combustion capture of CO2 from a gas stream associated with the fuel combusted. Furthermore, CCS can be designed and operated for full capture of the CO2 in the gas stream (i.e., above 90 percent) or for partial capture (below 90 percent). For post-combustion capture, CO2 is stripped from the flue gas by passing the flue gas through a liquid absorbent which selectively reacts with the gaseous carbon dioxide to remove it from the combustion gas stream. The absorbent, upon saturation, transfers to a downstream operation which is heated to regenerate the absorbent by desorbing the CO2 back to gaseous form. The absorbent recycles back into the process to repeat the capture cycle while the removed carbon dioxide is compressed, sent to storage and sequestered. This process is illustrated for a pulverized coal power plant in Figure 2-18. For post-combustion, a station's net generating output will be lower due to the energy needs of the capture process.

Figure 2-18. 	Post-Combustion CO2 Capture for a Pulverized Coal Power Plant
Source: Interagency Task Force on Carbon Capture and Storage 2010
Pre-combustion capture is mainly applicable to IGCC facilities, where the fuel is converted into gaseous components ("syngas") under heat and pressure and some percentage of the carbon contained in the syngas is captured before combustion. For pre-combustion technology, a significant amount of energy is needed to gasify the fuel(s). This process is illustrated in Figure 2-19. Application of post-combustion CCS with IGCC can be designed to use no water-gas shift, or single- or two-stage shift processes, to obtain varying percentages of CO2 removal  -  from a "partial capture" percentage to 90 percent "full capture." Pre-combustion CCS typically has a lesser impact on net energy output than does post-combustion CCS. For more detail on CCS technology, see the "Report of the Interagency Task Force on Carbon Capture and Storage" (2010).

Figure 2-19.	Pre-Combustion CO2 Capture for an IGCC Power Plant
Source: Interagency Task Force on Carbon Capture and Storage 2010
Carbon capture technology has been successfully applied since 1930 on several smaller scale industrial facilities and more recently in a number of demonstration phase projects worldwide for power sector applications. In October 2014 the first industrial-scale coal-fired capture and storage demonstration project for electricity generation began operation at the Boundary Dam Power Station in Saskatchewan, Canada. The Boundary Dam Station is owned by the Province of Saskatchewan, and operated by SaskPower, a provincially owned corporation that is the primary electric utility in the Province. The demonstration project retrofit Unit 3 (a 130 MW, coal fired built in 1970, and rebuilt in 2013) at a total cost of approximately $1.5 billion (Canadian, or about $1.2 billion US), including a partial subsidy of $240 million (Canadian) by the Canadian federal government. The carbon capture system is a 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 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 the Kemper County Carbon Dioxide Capture and Storage Project in Mississippi. Construction began in 2010, and the startup is currently scheduled for May, 2016. The Kemper County CCS project is constructing a new 524 MW lignite unit as well as a 58 MW natural gas unit. Mississippi Power (a division of Southern Power) is building and will operate the Kemper County project. The control system is designed to capture 65 percent of the CO2 generated by the plant, and is projected to capture 3.5 million tons of CO2 per year.  The resulting CO2 emission rate is expected to be ~800 pounds per MWh produced. The current total cost estimate is $5.6 billion, a substantial increase from the original $2.4 billion estimate. The construction has received a $270 million grant from the US Department of Energy, and $133 million in investment tax credits from the Internal Revenue Service. The captured CO2 will be transported via a 60 mile pipeline and used for EOR projects in mature Mississippi oil fields.
The only other industrial-scale electricity power sector CCS project currently under construction is the W.A. Parish Petra Nova CCS Project near Houston, Texas. The Parish Petra project is a 50/50 partnership between NRG Energy (an integrated electricity company generating and supplying electricity to 1.6 million customers in Texas) and the Nippon Oil and Gas Exploration Company.  The Parish project will retrofit a post-combustion CCS system on a portion of the flue gas from the existing 610 MW coal fired Unit # 8. The CCS system will treat a 240 MW slipstream of the flue gas, and is designed to capture 90 percent of the CO2 in the treated flue gas. The capacity rating of Unit # 8 will not be reduced due to the CCS project because an 85 MW custom-built natural gas fired combustion turbine co-generation unit is being built on-site to provide both electricity and steam to the CCS unit. The total cost of the CCS project is estimated to be $1 billion (including a $167 million grant from the US Department of Energy), and is expected to extract 1.4  -  1.6 million tons of CO2 per year. The construction contract was awarded in July, 2014, and operation is expected to begin in early 2016. The CO2 will be piped 85 miles to a reservoir for EOR in the West Ranch Oil Field.
2.7 	Geologic and Geographic Considerations for Geologic Sequestration
Geologic sequestration (GS) (i.e., long-term containment of a CO2 stream in subsurface geologic formations) is technically feasible and available throughout most of the United States. GS is feasible in different types of geologic formations including deep saline formations (formations with high salinity formation fluids) or in oil and gas formations, such as where injected CO2 increases oil production efficiency through a process referred to as enhanced oil recovery (EOR). CO2 may also be used for other types of enhanced recovery, such as for natural gas production. Reservoirs, such as unmineable coal seams, also offer the potential for geologic storage. The geographic availability of deep saline formations, EOR, and unmineable coal seams is shown in Figure 2-20. Estimates of CO2 storage resources by state compiled by the DOE's National Carbon Sequestration Database and Geographic Information System (NATCARB) and published in a Carbon Utilization and Storage Atlas (discussed below) are provided in Table 2-8.

                                       
Figure 2-20	Geologic Sequestration in the Continental United States 
Sources: EPA Greenhouse Gas Reporting Program; Department of Energy, NATCARB; Department of Transportation, National Pipeline Management System.

Table 2-8. 	Total CO2 Storage Resource (DOE-NETL)
                                       
                             Million Metric Tons*
                                     State
                                 Low Estimate
                                 High Estimate
                                    ALABAMA
                                    122,490
                                    694,380
                                    ALASKA
                                     8,640
                                    19,750
                                    ARIZONA
                                      130
                                     1,170
                                   ARKANSAS
                                     6,180
                                    63,670
                                  CALIFORNIA
                                    33,890
                                    420,630
                                   COLORADO
                                    37,610
                                    357,190
                                  CONNECTICUT
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL
                                   DELAWARE
                                      40
                                      40
                             DISTRICT OF COLUMBIA
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL
                                    FLORIDA
                                    102,740
                                    555,010
                                    GEORGIA
                                    145,340
                                    159,050
                                    HAWAII
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL
                                     IDAHO
                                      40
                                      390
                                   ILLINOIS
                                    10,020
                                    116,820
                                    INDIANA
                                    32,020
                                    68,210
                                     IOWA
                                      10
                                      50
                                    KANSAS
                                    10,880
                                    86,340
                                   KENTUCKY
                                     2,920
                                     7,650
                                   LOUISIANA
                                    169,500
                                   2,103,980
                                     MAINE
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL
                                   MARYLAND
                                     1,860
                                     1,930
                                 MASSACHUSETTS
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL

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

                                       
                             Million Metric Tons*
                                     State
                                 Low Estimate
                                 High Estimate
                                   MICHIGAN
                                    19,050
                                    47,210
                                   MINNESOTA
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL
                                  MISSISSIPPI
                                    145,010
                                   1,185,030
                                   MISSOURI
                                      10
                                      170
                                    MONTANA
                                    84,580
                                    912,720
                                   NEBRASKA
                                    23,770
                                    113,240
                                    NEVADA
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL
                                 NEW HAMPSHIRE
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL
                                  NEW JERSEY
                                       0
                                       0
                                  NEW MEXICO
                                    42,760
                                    359,090
                                   NEW YORK
                                     4,640
                                     4,640
                                NORTH CAROLINA
                                     1,340
                                    18,390
                                 NORTH DAKOTA
                                    67,090
                                    147,480
                             Offshore Federal Only
                                    489,840
                                   6,440,090
                                     OHIO
                                    13,460
                                    13,460
                                   OKLAHOMA
                                    56,950
                                    244,550
                                    OREGON
                                     6,810
                                    93,700
                                 PENNSYLVANIA
                                    22,100
                                    22,100
                                 RHODE ISLAND
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL
                                SOUTH CAROLINA
                                    30,100
                                    34,180
                                 SOUTH DAKOTA
                                     8,760
                                    24,030
                                   TENNESSEE
                                      430
                                     3,860
                                     TEXAS
                                    443,800
                                   4,329,930
                                     UTAH
                                    25,470
                                    240,910
                                    VERMONT
                           not assessed by DOE-NETL
                           not assessed by DOE-NETL
                                   VIRGINIA
                                      440
                                     2,910
                                  WASHINGTON
                                    36,620
                                    496,730
                                 WEST VIRGINIA
                                    16,650
                                    16,650
                                   WISCONSIN
                                       0
                                       0
                                    WYOMING
                                    72,690
                                    684,850
                                  U.S. Total
                                   2,296,680
                                  20,092,180

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

2.7.2 	Availability of geologic sequestration in deep saline formations
DOE and the United States Geological Survey (USGS) have independently conducted preliminary analyses of the availability and potential CO2 sequestration capacity of deep saline formations in the United States. DOE estimates are compiled by the DOE's National Carbon Sequestration Database and Geographic Information System (NATCARB) using volumetric models and published in a Carbon Utilization and Storage Atlas. DOE estimates that areas of the United States with appropriate geology have a sequestration potential of at least 2,035 billion metric tons of CO2 in deep saline formations. According to DOE and at least 39 states have geologic characteristics that are amenable to deep saline GS in either onshore or offshore locations. In 2013, the USGS completed its evaluation of the technically accessible GS resources for CO2 in U.S. onshore areas and state waters using probabilistic assessment. The USGS estimates a mean of 3,000 billion metric tons of subsurface CO2 sequestration potential, including saline and oil and gas reservoirs, across the basins studied in the United States. As shown in Figure 2-20, there are 39 states for which onshore and offshore deep saline formation storage capacity has been identified.  
2.7.3	Availability of CO2 storage via enhanced oil recovery (EOR)
Although the regulatory impact analysis for this rule relies on GS in deep saline formations, the EPA also recognizes the potential for securely sequestering CO2 via EOR. EOR has been successfully used at numerous production fields throughout the United States to increase oil recovery. The oil industry in the United States has over 40 years of experience with EOR. An oil industry study in 2014 identified more than 125 EOR projects in 98 fields in the United States. 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 23 states are within 150 miles of current EOR operations. See Figure 2-20.  The vast majority of EOR is conducted in oil reservoirs in the Permian Basin, which extends through southwest Texas and southeast New Mexico. States where EOR is utilized include Alabama, Colorado, Louisiana, Michigan, Mississippi, New Mexico, Oklahoma, Texas, Utah, and Wyoming. 
At the project level, the volume of CO2 already injected for EOR and the duration of operations are of similar magnitude to the duration and volume of CO2 expected to be captured from fossil fuel-fired EGUs. The volume of CO2 used in EOR operations can be large  (e.g., 55 million tons of CO2 were stored in the SACROC unit in the Permian Basin over 35 years), and operations at a single oil field may last for decades, injecting into multiple parts of the field.  According to data reported to the EPA's Greenhouse Gas Reporting Program (GHGRP), approximately 60 million metric tons of CO2 were supplied to EOR in the United States in 2013. 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 18 billion metric tons of anthropogenic CO2 and increase total oil production by 67 billion barrels. The availability of anthropogenic CO2 in areas outside of current sources could drive new EOR projects by making more CO2 locally available.
2.8	GHG and Clean Energy Regulation in the Power Sector
2.8.1 	State Policies
Several states have also established emission performance standards or other measures to limit emissions of GHGs from new EGUs that are comparable to this rulemaking. 
In 2003, then-Governor George Pataki sent a letter to his counterparts in the Northeast and Mid-Atlantic inviting them to participate in the development of a regional cap-and-trade program addressing power plant CO2 emissions.  This program, known as the Regional Greenhouse Gas Initiative (RGGI), began in 2009 and sets a regional CO2 cap for participating states.  The currently participating states include: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont.  The cap covers CO2 emissions from all fossil-fired EGUs greater than 25 MW in participating states, and limits total emissions to 91 million short tons in 2014. The 2014 emissions cap is a 51 percent reduction below the initial cap in 2009 to 2011 of 188 million tons.  This emissions budget is reduced 2.5 percent annually from 2015 to 2020. RGGI CO2 allowances are sold in a quarterly auction. RGGI conducted their 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 '15 auction, well below the record of 38.7 million tons sold in June '13 for $3.21
In September 2006, California Governor Schwarzenegger signed into law Senate Bill 1368. The law limits long-term investments in baseload generation by the state's utilities to power plants that meet an emissions performance standard jointly established by the California Energy Commission and the California Public Utilities Commission. The Energy Commission has designed regulations that establish a standard for new and existing baseload generation owned by, or under long-term contract to publicly owned utilities, of 1,100 lb CO2/MWh.
In 2006 Governor Schwarzenegger also signed into law Assembly Bill 32, the Global Warming Solutions Act of 2006.  This act includes a multi-sector GHG cap-and-trade program which covers approximately 85 percent of the state GHG emissions.  EGUs are includes in phase I of the program, which began in 2013.  Phase II begins in 2020 and includes upstream sources.  The cap is based on a 2 percent reduction from total 2012 expected emissions, and declines 2 percent annually through 2014, then 3 percent each year until 2020.  The AB32 cap and trade program began functioning in 2011, and functioning market is now operating on the NYMEX futures commodity market. The final 2014 market price for 2014 carbon allowances was $12.38/tonne of carbon. On April 17, 2015 the 2015 allowance futures price was $12.65/tonne, and the spot price was $12.46/tonne.
In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, which established statewide GHG emissions reduction goals, and imposed an emission standard that applies to any baseload electric generation that commenced operation after June 1, 2008 and is located in Washington, whether or not that generation serves load located within the state. Baseload generation facilities must initially comply with an emission limit of 1,100 lb CO2/MWh.
In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, which mandated that facilities generating baseload electricity, whether gas- or coal-fired, must have emissions equal to or less than 1,100 lb CO2/MWh, and prohibited utilities from entering into long-term purchase agreements for baseload electricity with out-of-state facilities that do not meet that standard. Natural gas- and petroleum distillate-fired facilities that are primarily used to serve peak demand or to integrate energy from renewable resources are specifically exempted from the performance standard.
In August 2011, New York Governor Cuomo signed the Power NY Act of 2011. This regulation establishes CO2 emission standards for new and modified electric generators greater than 25 MW.  The standards vary based on the type of facility: base load facilities must meet a CO2 standard of 925 lb/MWh or 120 lb/MMBtu, and peaking facilities must meet a CO2 standard of 1,450 lbs/MWh or 160 lbs/MMBtu.
Additionally, most states have implemented Renewable Portfolio Standards (RPS), or Renewable Electricity Standards (RES).  These programs are designed to increase the renewable share of a state's total electricity generation.  Currently 30 states and the District of Columbia have enforceable RPS or other mandatory renewable capacity policies, and 7 states have voluntary goals.  These programs vary widely in structure, enforcement, and scope.  
2.8.2 	Federal Policies
In April 2007, the Supreme Court concluded that GHGs met the CAA definition of an air pollutant, giving the EPA the authority to regulate GHGs under the CAA contingent upon an agency determination that GHG emissions from new motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. This decision to regulate GHG emissions for motor vehicles set the stage for the determination of whether other sources of GHG emissions, including stationary sources, would need to be regulated as well.
In response to the FY2008 Consolidated Appropriations Act (H.R. 2764; Public Law 110 - 161), the EPA issued the Mandatory Reporting of Greenhouse Gases Rule (74 FR 5620) which required reporting of GHG data and other relevant information from fossil fuel suppliers and industrial gas suppliers, direct greenhouse gas emitters, and manufacturers of heavy-duty and off-road vehicles and engines. The purpose of the rule was to collect accurate and timely GHG data to inform future policy decisions. As such, it did not require that sources control greenhouse gases, but sources above certain threshold levels must monitor and report emissions.
In August 2007, the EPA issued a prevention of significant deterioration (PSD) permit to Deseret Power Electric Cooperative, authorizing it to construct a new waste-coal-fired EGU near its existing Bonanza Power Plant, in Bonanza, Utah. The permit did not include emissions control requirements for CO2. The EPA acknowledged the Supreme Court decision, but found that decision alone did not require PSD permits to include limits on CO2 emissions. Sierra Club challenged the Deseret permit. In November 2008, the Environmental Appeals Board (EAB) remanded the permit to the EPA to reconsider "whether or not to impose a CO2 BACT (best available control technology) limit in light of the `subject to regulation' definition under the CAA." The remand was based in part on EAB's finding that there was not an established EPA interpretation of the regulatory phrase "subject to regulation." 
In December 2008, the Administrator issued a memo indicating that the PSD Permitting Program would apply to pollutants that are subject to either a provision in the CAA or a regulation adopted by the EPA under the CAA that requires actual control of emissions of that pollutant. The memo further explained that pollutants for which the EPA regulations only require monitoring or reporting, such as the provisions for CO2 in the Acid Rain Program, are not subject to PSD permitting. Fifteen organizations petitioned the EPA for reconsideration, prompting the agency to issue a revised finding in March 2009. After reviewing comments, the EPA affirmed the position that PSD permitting is not triggered for a pollutant such as GHGs until a final nationwide rule requires actual control of emissions of the pollutant. For GHGs, this meant January 2011 when the first national rule limiting GHG emissions for cars and light trucks was scheduled to take effect. Therefore, a permit issued after January 2, 2011, would have to address GHG emissions.
The Administrator signed two distinct findings in December 2009 regarding greenhouse gases under section 202(a) of the Clean Air Act. The endangerment finding indicated that current and projected concentrations of the six key well-mixed greenhouse gases  -- CO2, CH4, N2O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and SF6  --  in the atmosphere threaten the public health and welfare of current and future generations. These greenhouse gases have long lifetimes and, as a result, become homogeneously distributed through the lower level of the Earth's atmosphere (IPCC, 2001). This differentiates them from other greenhouse gases that are not homogeneously distributed in the atmosphere. The cause and contribute finding indicated that the combined emissions of these well-mixed greenhouse gases from new motor vehicles and new motor vehicle engines contribute to the greenhouse gas pollution which threatens public health and welfare. Both findings were published in the Federal Register on December 15, 2009 (Docket ID EPA-HQ-OAR-2009-0171). These findings did not themselves impose any requirements on any industry or other entities, but allowed the EPA to regulate greenhouse gases under the CAA (see preamble section II.E for regulatory background). This action was a prerequisite to implementing the EPA's proposed greenhouse gas emission standards for light-duty vehicles, which was finalized in January 2010. Once a pollutant is regulated under the CAA, it is subject to permitting requirements under the PSD and Title V programs.  The 2009 Endangerment Finding and a denial of reconsideration were challenged in a lawsuit; on June 26, 2012, the DC Circuit Court upheld the Endangerment Finding and the Reconsideration Denial, ruling that the Finding was neither arbitrary nor capricious, was consistent with Massachusetts v. EPA, and was adequately supported by the administrative record. The Court found that the EPA had based its decision on "substantial scientific evidence," noted that the EPA's reliance on assessments was consistent with the methods decision-makers often use to make a science-based judgment, and stated that "EPA's interpretation of the governing CAA provisions is unambiguously correct."
In May 2010, the EPA issued the final Tailoring Rule which set thresholds for GHG emissions that define when permits under the New Source Review and Title V Operating Permit programs are required for new and existing industrial facilities. Facilities responsible for nearly 70 percent of the national GHG emissions from stationary sources, including EGUs, were subject to permitting requirements under the rule.  This rule was upheld by the D.C. Circuit in 2012.
The EPA entered into a proposed settlement agreement in December 2010 to issue rules that will address greenhouse gas emissions from fossil fuel-fired power plants. On March 27, 2012, EPA proposed NSPS for CO2 emissions from new source natural gas, coal, and other solid fossil-fired EGUs.  After consideration of information provided in more than 2.7 million comments on the March 27, 2012 proposal, as well as consideration of continuing changes in the electricity sector, the EPA determined that revisions in its initially proposed approach were warranted.  EPA replaced that prior proposal with a new proposal for NSPS for CO2 emissions from EGUs on September 20, 2013; this action finalizes that rulemaking.  Existing source standards are not addressed in this action. Details of the settlement agreement can be found on the EPA website.
2.9 	Revenues and Expenses
Due to lower retail electricity sales, total utility operating revenues declined in 2012 to $271 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008 levels in 2012, operating expenses were appreciably lower and as a result, net income also rose in comparison to 2008 (see Table 2-9). Recent economic events have put downward pressure on electricity demand, thus dampening electricity prices and consumption (utility revenues), but have also reduced the price and cost of fossil fuels and other expenses. In 2012 electricity generation was 1.28 percent below the generation in 2011, and has declined in 4 of the past 5 years.
Table 2-9 shows that investor-owned utilities (IOUs) earned income of about 13.0 percent compared to total revenues in 2012. The 2012 return on revenue was the third highest year for the period 2002 to 2012 (average: 11.9 percent range: 10.6 percent to 13.32 percent).

Table 2-9. 	Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities for 2010 (nominal $millions) 
                                       
                                     
2002
                                     
2008
                                     
2012
Utility Operating Revenues
                                    219,609
                                    298,962
                                    270,912
Electric Utility
                                    200,360
                                    266,124
                                    249,166
Other Utility
                                    19,250
                                    32,838
                                    21,745
Utility Operating Expenses
                                    189,062
                                    267,263
                                    235,694
Electric Utility
                                    171,604
                                    236,572
                                    220,722
      Operation
                                    116,660
                                    175,887
                                    152,379
         Production
                                    90,715
                                    140,974
                                    111,714
            Cost of Fuel
                                    24,149
                                    47,337
                                    38,998
            Purchased Power
                                    58,810
                                    84,724
                                    54,570
            Other
                                     7,776
                                     8,937
                                    18,146
      Transmission
                                     3,560
                                     6,950
                                     7,183
      Distribution
                                     3,117
                                     3,997
                                     4,181
      Customer Accounts
                                     4,168
                                     5,286
                                     5,086
      Customer Service
                                     1,820
                                     3,567
                                     5,640
      Sales
                                      264
                                      225
                                      221
      Admin. and 
      General
                                    13,018
                                    14,718
                                    18,353
      Maintenance
                                    10,861
                                    14,192
                                    15,489
      Depreciation
                                    16,199
                                    19,049
                                    23,677
      Taxes and Other
                                    26,716
                                    26,202
                                    29,177
       Other Utility
                                    17,457
                                    30,692
                                    14,972
Net Utility Operating Income
                                    30,548
                                    31,699
                                    35,218
Source: Table 8.3, EIA Electric Power Annual, 2012
Note: This data does not include information for public utilities, nor for Independent Power Producers (IPPs).
2.10 	Natural Gas Market
The natural gas market in the United States has historically experienced significant price volatility from year to year, between seasons within a year, can undergo major price swings during short-lived weather events (such as cold snaps leading to short-run spikes in heating demand), and has seen a dramatic shift since 2008 due increased production from shale formations . Over the last decade, the annual average nominal price of gas delivered to the power sector peaked in 2008 at $9.02/mmBtu  and has since fallen dramatically to a low of $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.  Adjusting for inflation using the GDP implicit price deflator, in $2011 the annual average price of natural gas delivered to the power sector ranged peaked at $9.38/mmBtu in 2008 and have fallen dramatically to a low of $3.36 in 2012.  The annual natural gas prices in both nominal and real (2011$) terms are in Figure 2-21. A comparison of the trends in the real price of natural gas with the real price of delivered coal and oil are shown in Figure 2-22. Figure 16 shows that while the real price of coal and oil increased from 2002 to 2012 (+54 percent and +203 percent respectively), the real price of natural gas declined by 22 percent in the same period. Most of the decline in real natural gas prices occurred between 2008 (the peak price year) and 2012, during which real gas prices declined by 64 percent while coal and oil prices both increased by 9 percent.  The sharp decline in natural gas prices from 2008 to 2012 was primarily caused by the rapid increase in natural gas production from shale formations.

Figure 2-21.	Nominal and Real (2011$) Prices of Natural Gas Delivered to the Power Sector ($/mmBtu)
Source: http://www.eia.gov/totalenergy/data/monthly/#prices. Downloaded 2/15/2015.

Figure 2-22.	 Relative Change in Real (2011$) Prices of Fossil Fuels Delivered to the Power Sector ($/mmBtu)
Source: http://www.eia.gov/totalenergy/data/monthly/#prices. Downloaded 2/15/2015.

Current and projected natural gas prices are considerably lower than the prices observed over the past decade, largely due to advances in hydraulic fracturing and horizontal drilling techniques that have opened up new shale gas resources and substantially increased the supply of economically recoverable natural gas. According to AEO 2012 (EIA 2012):
      Shale gas refers to natural gas that is trapped within shale formations. Shales are fine-grained sedimentary rocks that can be rich sources of petroleum and natural gas. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. The production of natural gas from shale formations has rejuvenated the natural gas industry in the United States.
The U.S. Energy Information Administration's Annual Energy Outlook 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, the estimate of technically recoverable resources is highly uncertain, and is regularly updated as more information is gained through drilling and production. 
At the 2012 rate of U.S. consumption (about 25.6 Tcf per year), 2,266 Tcf of natural gas is enough to supply nearly 90 years of use. The AEO 2014 estimate of  the shale gas resource base is modestly higher than the AEO 2012 estimate (2,214 Tcf) shale gas production estimates, driven by lower drilling costs and continued drilling in shale plays with high concentrations of natural gas liquids and crude oil, which have a higher value in energy equivalent terms than dry natural gas.
EIA's projections of natural gas conditions did not change substantially in AEO 2014 from either the AEO 2012 or 2013, and EIA is still forecasting abundant reserves consistent with the above findings.  Recent historical data reported to EIA is also consistent with these trends, with 2014 being the highest year on 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. Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F P. Evaluation of CO2 trapping mechanisms at the SACROC northern platform, Permian basin, Texas, site of 35 years of CO2 injection. American Journal of Science 310. (2010): 282-324.Interagency Task Force on Carbon Capture and Storage. Report of the Interagency Task Force on Carbon Capture and Storage. August 2010. Available online at: http://www.epa.gov/climatechange/downloads/CCS-Task-Force-Report-2010.pdf. 
Intergovernmental Panel on Climate Change. Climate Change 2001: The Scientific Basis. 2001. Available online at: http://www.grida.no/publications/other/ipcc_tar/?src=/climate/ipcc_tar/wg1/218.htm. 
International Energy Agency (IEA). Tracking Clean Energy Progress 2013. Input to the Clean Energy Ministerial. 2013. Available online at: http://www.iea.org/etp/tracking/.
Koottungal, Leena. 2014 Worldwide EOR Survey, Oil & Gas Journal, Volume 112, Issue 4, April 7, 2014 (corrected tables appear in Volume 112, Issue 5, May 5, 2014).
National Energy Technology Laboratory (NETL). Reducing CO2 Emissions by Improving the Efficiency of Existing Coal-fired Power Plant Fleet. July 2008. Available online at: http://www.netl.doe.gov/energy-analyses/pubs/CFPP%20Efficiency-FINAL.pdf.
National Energy Technology Laboratory (NETL). The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition. 2012. Available online at: http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlasIV/.
National Energy Technology Laboratory (NETL). Energy Analyses: Cost and Performance Baselines for Fossil Energy Plants. 2013. Available online at: http://www.netl.doe.gov/energy-analyses/baseline_studies.html.
Pacific Northwest National Laboratory (PNNL). An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009. June 2009. Available online at: http://www.pnl.gov/science/pdf/PNNL-18520_Status_of_CCS_062009.pdf.
U.S. Energy Information Administration (U.S. EIA). Carbon Dioxide Emissions from the Generation of Electric Power in the United States. July 2000. Available online at: ftp://ftp.eia.doe.gov/environment/co2emiss00.pdf.
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 CO2 concentrations. This will reduce the risk of some adverse effects of climate change. As discussed in Chapter 5, the U.S. Environmental Protection Agency (EPA) does not anticipate any notable CO2 emission changes resulting from the rule. Rather, by clarifying that in the future new coal-fired power plants will be required to meet a particular performance standard, this rulemaking reduces uncertainty and may enhance the prospects for the deployment of carbon capture and storage (CCS).    
This chapter summarizes the adverse effects on public health and public welfare detailed in the 2009 Endangerment Finding. The major assessments by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) served as the primary scientific basis for these effects. A discussion of climate science findings from newer assessments can be found in the Preamble. This chapter also provides a general discussion about how the climate-related and human health benefits of emissions reductions are estimated.  These valuation approaches are used in Chapter 5 to assess the relative differences in emissions between newly built electric generating technologies.
3.1	Overview of Climate Change Impacts from GHG Emissions
Through the implementation of CAA regulations, the EPA addresses the negative externalities caused by air pollution. In 2009, the EPA Administrator found that elevated concentrations of greenhouse gases in the atmosphere may reasonably be anticipated both to endanger public health and to endanger public welfare. It is these adverse impacts that make it necessary for the EPA to regulate GHGs from EGU sources. The preamble summarizes the public health and public welfare impacts that were detailed in the 2009 Endangerment Finding. For health, these include the increased likelihood of heat waves, negative impacts on air quality, more intense hurricanes, more frequent and intense storms and heavy precipitation, and impacts on infectious and waterborne diseases. For welfare, these include reduced water supplies in some regions, increased water pollution, increased occurrences of floods and droughts, rising sea levels and damage to coastal infrastructure, increased peak electricity demand, changes in ecosystems, and impacts on indigenous communities. 
The preamble also summarizes new scientific assessments and recent climatic observations. Major scientific assessments released since the 2009 Endangerment Finding have improved scientific understanding of the climate, and provide even more evidence that GHG emissions endanger public health and welfare for current and future generations. The National Climate Assessment (NCA3), in particular, assessed the impacts of climate change on human health in the United States, finding that, Americans will be impacted by "increased extreme weather events, wildfire, decreased air quality, threats to mental health, and illnesses transmitted by food, water, and disease-carriers such as mosquitoes and ticks." These assessments also detail the risks to vulnerable groups such as children, the elderly and low income households. Furthermore, the assessments present an improved understanding of the impacts of climate change on public welfare, higher projections of future sea level rise than had been previously estimated, a better understanding of how the warmth in the next century may reach levels that would be unprecedented relative to the preceding millions of years of history, and new assessments of the impacts of climate change on permafrost and ocean acidification. The impacts of GHG emissions will be realized worldwide, independent upon their location of origin, and impacts outside of the United States will produce consequences relevant to the United States.      
3.2	Social Cost of Carbon
The social cost of carbon (SC-CO2) is a metric that estimates the monetary value of impacts associated with marginal changes in CO2 emissions in a given year. It includes a wide range of anticipated climate impacts, such as net changes in agricultural productivity and human health, property damage from increased flood risk, and changes in energy system costs, such as reduced costs for heating and increased costs for air conditioning. It is typically used to assess the avoided damages as a result of regulatory actions (i.e., benefits of rulemakings that lead to an incremental reduction in cumulative global CO2 emissions). This section discusses the development of the SC-CO2 estimates and the Chapter 5 analysis applies the SC-CO2 estimates to illustrate the value to society of the difference in CO2 emissions among different generation technologies.   
The SC-CO2 estimates used in this analysis were developed over many years, using the best science available, and with input from the public.  Specifically, an interagency working group (IWG) that included the EPA and other executive branch agencies and offices used three integrated assessment models (IAMs) to develop the SC-CO2 estimates and recommended four global values for use in regulatory analyses. The SC-CO2 estimates were first released in February 2010 and updated in 2013 using new versions of each IAM.  These estimates were published in the 2013 Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866 (2013 SC-CO2 TSD) and henceforth we refer to them as the "SC-CO2 estimates."   
The SC-CO2 estimates were developed using an ensemble of the three most widely cited integrated assessment models in the economics literature with the ability to estimate the 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 2013 SC-CO2 TSD for the updated estimates.  
The SC-CO2 estimates represent global measures because of the distinctive nature of the climate change, which is highly unusual in at least three respects. First, emissions of most GHGs contribute to damages around the world independent of the country in which they are emitted. The SC-CO2 must therefore incorporate the full (global) damages caused by GHG emissions to address the global nature of the problem. Second, the U.S. operates in a global and highly interconnected economy, such that impacts on the other side of the world can affect our economy.  Damages from climate change in other countries can affect U.S. companies and citizens, and conflict exacerbated by climate change can require military expenditures by the U.S. This means that the true costs of climate change to the U.S. are larger than the direct impacts that simply occur within the U.S. Third, climate change represents a classic public goods problem, but one that the United States cannot solve alone. A global estimate of the SC-CO2 is therefore the economically appropriate reference point for collective actions to reduce climate change.
With the release of the 2010 SC-CO2 estimates the IWG noted that there remained a number of limitations to the analysis and committed to updating the estimates as the science and economic understanding of climate change and its impacts on society improves over time.  In particular, a goal was set to revisit the SC-CO2 estimates "within two years or at such time as substantially updated models become available." Subsequent to the release of the 2010 TSD, all three of the models used in the development of the SC-CO2 estimates were updated by their (academic) developers, in part, to reflect more recent information on the potential impacts of climate change. Therefore, in 2013 the IWG released an update to the SC-CO2 estimates that maintained the same methodology underpinning the previous estimates, but applied the most current versions of the three IAMs. The 2013 process did not revisit the 2010 interagency modeling decisions (e.g., with regard to the discount rate, reference case socioeconomic and emission scenarios or equilibrium climate sensitivity). Rather, improvements in the way damages are modeled are confined to those that have been incorporated into the latest versions of the models by the developers themselves and used in peer-reviewed publications.  
The model updates reflected in the 2013 SC-CO2 estimates include: an explicit representation of sea level rise damages in the DICE and PAGE models; updated adaptation assumptions, revisions to ensure damages are constrained by GDP, updated regional scaling of damages, and a revised treatment of potentially abrupt shifts in climate damages in the PAGE model; an updated carbon cycle in the DICE model; and updated damage functions for sea level rise impacts, the agricultural sector, and reduced space heating requirements, as well as changes to the transient response of temperature to the buildup of GHG concentrations and the inclusion of indirect effects of methane emissions in the FUND model. The 2013 SC-CO2 TSD provides additional detail on the specific model improvements and the updated estimates. When attempting to assess the incremental economic impacts of CO2 emissions, the analyst faces a number of serious challenges. A report from the National Academies of Science (NRC, 2009) points out that any assessment will suffer from uncertainty, speculation, and lack of information about (1) future emissions of greenhouse gases, (2) the effects of past and future emissions on the climate system, (3) the impact of changes in climate on the physical and biological environment, and (4) the translation of these environmental impacts into economic damages.  As a result, any effort to quantify and monetize the harms associated with climate change will raise serious questions of science, economics, and ethics and should be viewed as provisional. 
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 SCC estimates continue to omit various impacts that would likely increase damages. The 95th percentile estimate was included in the recommended range for regulatory impact analysis to address these concerns.
Nonetheless, these estimates and the discussion of their limitations represent the best available information about the social benefits of CO2 reductions to inform benefit-cost analysis. The new versions of the models used to estimate the values presented below offer some improvements in these areas, although further work remains warranted. 
Accordingly, the EPA and other agencies continue to engage in research on modeling and valuation of climate impacts with the goal to improve these estimates. The EPA and other federal agencies have considered the extensive public comments on ways to improve SC-CO2 estimation received via the notice and comment periods that were part of numerous rulemakings.  In addition, OMB's Office of Information and Regulatory Affairs sought public comment on the approach used to develop the SC-CO2 estimates. The comment period ended on February 26, 2014, and OMB is reviewing the comments received.
The four SC-CO2 estimates, updated in 2013, are as follows: $14, $47, $70, and $140 per metric ton of CO2 emissions in the year 2022 (2011$).  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 updated global SC-CO2 estimates for the years 2015 to 2050. In order to calculate the dollar value for emission reductions, the SC-CO2 estimate for each emissions year would be applied to changes in CO2 emissions for that year, and then discounted back to the analysis year using the same discount rate used to estimate the SC-CO2.  The SC-CO2 increases over time because future emissions are expected to produce larger incremental damages as physical and economic systems become more stressed in response to greater climate change. Note that the interagency group estimated the growth rate of the SC-CO2 directly using the three integrated assessment models rather than assuming a constant annual growth rate. This helps to ensure that the estimates are internally consistent with other modeling assumptions.   
Table 3-1.	Global 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
                                      $12
                                      $39
                                      $61
                                     $120
                                     2020
                                      $13
                                      $46
                                      $68
                                     $140
                                     2022
                                      $14
                                      $47
                                      $70
                                     $140
                                     2025
                                      $15
                                      $50
                                      $74
                                     $150
                                     2030
                                      $17
                                      $55
                                      $80
                                     $170
                                     2035
                                      $20
                                      $60
                                      $85
                                     $190
                                     2040
                                      $22
                                      $65
                                      $92
                                     $200
                                     2045
                                      $26
                                      $70
                                      $98
                                     $220
                                     2050
                                      $28
                                      $76
                                     $100
                                     $230
[a] The SC-CO2 values vary depending on the year of CO2 emissions and are defined in real terms. These SC-CO2 values are stated in $/metric ton. Unrounded numbers from the 2013 SC-CO2 TSD were adjusted to 2011$ and used in the illustrative analysis in Chapter 5.

3.3	Health Co-Benefits of SO2 and NOx Reductions 
The EPA anticipates that this rule will result in negligible emission changes by 2022. However, if CO2 emissions are reduced from new EGUs under this rule, then emissions of other pollutants from the power sector would also likely be reduced. For example, reducing CO2 emissions through the adoption of CCS from coal-fired boilers may also yield sulfur dioxide (SO2) and nitrogen oxide (NOX) emission reductions, which in turn would yield health benefits (we refer to these additional benefits as "co-benefits"). 
SO2 is a precursor for fine particulate matter formation, which is particulate matter 2.5 micrometers in diameter and smaller (PM2.5), while NOX is a precursor for PM2.5 and 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. 
Reducing SO2 and NOX emissions would also result in other human welfare (non-health) improvements including improvements in ecosystem services. SO2 and NOX emissions can adversely impact vegetation and ecosystems through acidic deposition and nutrient enrichment, and can affect certain manmade materials, visibility, and climate (U.S. EPA, 2009; U.S. EPA, 2008). 
The avoided incidences of health effects and monetized value of health or non-health improvements that result from SO2 and NOx emissions reductions depend on the location of those reductions. For a full discussion of the human health, ecosystem and other benefits of reducing SO2 and NOX emissions from power sector sources, please refer to the Regulatory Impact Analysis for the Final Carbon Pollution Guidelines for Existing Power Plants (U.S. EPA, 2015).
The EPA anticipates that this rule will result in negligible emission changes by 2022. As a result we did not perform a full health co-benefit impact assessment for a specific modeled compliance scenario. In Chapter 5, EPA presents results for several illustrative analyses that show the potential impacts of the rule if certain key assumptions were to change.  When assessing the co-benefits of differences in emissions from different generation technologies in Chapter 5, the EPA does not assert a specific location for the illustrative new unit. 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 Technical Support Document (TSD) on estimating the BPT of reducing PM2.5 and its precursors (U.S. EPA, 2013b). These BPT values are estimated in a methodologically consistent manner with those reported in Fann et al. (2012). They differ from those reported in Fann et al. (2012) as they reflect the health impact studies and population data updated in the benefits analysis of the final PM NAAQS RIA (U.S. EPA, 2012). The recalculation of the Fann et al. (2012) BPT values based on the updated data from the PM NAAQS RIA (U.S. EPA, 2012) is described in the TSD (U.S. EPA, 2013b). The BPT values are for the entire electricity sector and are not differentiated by fuel or generator type. 
The methods used for this analysis are consistent with those used to estimate the health co-benefits from secondary PM2.5 formation for the Regulatory Impact Analysis for the Final Carbon Pollution Guidelines for Existing Power Plants (U.S. EPA, 2015).  One notable difference between the BPT values used in the two analyses is that this analysis utilizes national-average BPT estimates because EPA does not assert a specific location for the illustrative new unit, whereas the BPT estimates used in the RIA for the final existing source guidelines differ by region. Chapter 5 discusses how the analysis may be affected when considering regional differences in the damages associated with these pollutants. 
Despite our attempts to quantify and monetize as many of the co-benefits of reducing emissions from electricity generating sources as possible, not all known health and non-health co-benefits from reducing SO2 and NOx are accounted for in this assessment. For more information about unquantified health and non-health co-benefits of SO2 and NOx please refer to tables 5-2 and 6-2 of the PM NAAQS RIA (U.S. EPA, 2012), respectively. Furthermore, the analysis that follows does not account for known differences in other air and water pollutants between the different generating technologies, including, for example, ozone and directly-emitted PM and ozone.  The reason and implications for limiting our consideration of co-benefits to pollutants that cause secondary PM2.5 is discussed in Chapter 5. 
As we do not conjecture a specific location for the new units being compared, this RIA is unable to include the type of detailed uncertainty assessment found in the PM NAAQS RIA (U.S. EPA, 2012). However, the results of the uncertainty analyses presented in the PM NAAQS RIA can provide some information regarding the uncertainty inherent in the benefits results presented in this analysis. In addition to the uncertainties described in the PM NAAQS RIA, the use of BPT estimates come with additional uncertainty. Specifically, these national-average BPT estimates reflect a specific geographic distribution of SO2 and NOX reductions resulting in a specific reduction in PM2.5 exposure and may not fully reflect local or regional variability in population density, meteorology, exposure, baseline health incidence rates, timing of emissions, or other factors that might lead to an over-estimate or under-estimate of the actual benefits associated with PM2.5 precursors in a specific location. These estimates are illustrative as the EPA does not assert a specific location for the illustrative electricity generation technologies and is therefore unable to specifically determine the population that would be affected by their emissions. Therefore, the benefits for any specific unit can be different than the estimates shown here. 
Notwithstanding these limitations, reducing one thousand tons of annual SO2 from U.S. power sector sources has been estimated to yield between 4 and 9 incidences of premature mortality avoided and monetized PM2.5-related health benefits (including these incidences of premature mortality avoided) between $38 million and $85 million in 2020 (2011$) using a 3% discount rate or between $34 million and $76 million (2011$) using a 7% discount rate. Additionally, reducing one thousand tons of annual NOX from U.S. EGUs has been estimated to yield up to 1 incidence of premature mortality avoided and monetized PM2.5-related health benefits (including these incidences of premature mortality avoided) of between $5.5 million and $12 million in 2020 (2011$) using a 3% discount rate or between $5.0 million and $11 million (2011$) using a 7% discount rate. For each pollutant, the range of estimated benefits for each discount rate is due to the EPA's use of two alternative primary estimates of PM2.5-related mortality impacts: a lower primary estimate based on Krewski et al. (2009) and a higher primary estimate based on Lepeule et al. (2012). The benefit per ton values are reported in Table 3-2. 
Table 3-2.	Monetized Health Benefits Per Ton of PM2.5 Precursor Reductions in 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. Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. Docket ID EPA-HQ-OAR-2013-0495. Participation by Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture, Department of Commerce, Department of Energy, Department of Transportation, Domestic Policy Council, Environmental Protection Agency, National Economic Council, Office of Management and Budget, Office of Science and Technology Policy, and Department of Treasury. <http://www.whitehouse.gov/sites/default/files/omb/assets/inforeg/technical-update-social-cost-of-carbon-for-regulator-impact-analysis.pdf> Accessed March 31, 2015.
Intergovernmental Panel on Climate Change (IPCC). 2007. Climate Change 2007: Synthesis Report. Contribution of Working Groups I, II and III to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change (AR4) [Core Writing Team, Pachauri, R.K and Reisinger, A. (eds.)]. IPCC, Geneva, Switzerland, 104 pp. <http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report_synthesis_report.htm>. Accessed March 30, 2015.
Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz, and W.H. White. 2009. "Reanalysis of the Harvard Six Cities Study and the American Cancer Society Study of Particulate Air Pollution and Mortality." Special Report to the Health Effects Institute. Cambridge, MA. July.
Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. "Chronic Exposure to Fine Particles and Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009." Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.
Medina-Ramon, M. and J. Schwartz, 2007: Temperature, temperature extremes, and mortality: a study of acclimatization and effect modification in 50 U.S. cities.  Occupational and Environmental Medicine, 64(12), 827-833.
National Research Council (NRC). 2009. Hidden Cost of Energy: Unpriced Consequences of Energy Production and Use. National Academies Press. Washington, DC.
U.S. Environmental Protection Agency (U.S. EPA). 2008. Integrated Science Assessment for Oxides of Nitrogen and Sulfur  - Ecological Criteria National (Final Report). National Center for Environmental Assessment, Research Triangle Park, NC. EPA/600/R-08/139. December. Available on the Internet at http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485.
U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for Environmental Assessment  -  RTP Division. December. Available on the Internet at http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.
U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2013a. Integrated Science Assessment for Ozone and Related Photochemical Oxidants. EPA/600/R-10/076F. Research Triangle Park, NC: U.S. EPA. February. Available on the Internet at http://oaspub.epa.gov/eims/eimscomm.getfile?p_download_id=511347.
U.S. Environmental Protection Agency (U.S. EPA). 2013b. Technical Support Document Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on the Internet at http://www2.epa.gov/sites/production/files/2014-10/documents/sourceapportionmentbpttsd.pdf
U.S. Environmental Protection Agency (U.S. EPA). 2015. Regulatory Impact Analysis for the Final Carbon Pollution Guidelines for Existing Power Plants. [UPDATE LOCATION WHEN AVAILABLE]
U.S. Global Change Research Program (USGCRP). Global Climate Change Impacts in the United States.  Thomas R. Karl, Jerry M. Melillo, and Thomas C. Peterson, (eds.). Cambridge University Press, 2009.
 Chapter 4
Costs, Economic, and Energy Impacts
4.1	Synopsis
This chapter reports the central compliance cost, economic, and energy impact analyses performed for the proposed EGU New Source GHG Standards. The EPA analyzed and assessed a wide range of potential scenarios and outcomes, using a detailed power sector model, other government projections for the power sector, and additional economic assessments and analyses to determine the potential impacts of this action.  
The primary finding of this assessment is that in the absence of this proposed rule, all projected unplanned capacity additions affected by this proposal during the analysis period would already be compliant with the rule's requirements (e.g., natural gas combined cycle units, low capacity factor natural gas combustion turbines, and small amounts of coal-fired units with CCS supported by Federal and State funding). The analysis period is defined as through 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,
      * Projected new EGUs reported by industry to EIA.
The EPA's finding of no new conventional coal-fired capacity is robust beyond the analysis period (past 2030 in both EIA and EPA baseline modeling projections) and across a wide range of alternative potential market, technical, and regulatory scenarios that influence power sector investment decisions.  As a result, the EGU New Source GHG Standards are not expected to change GHG emissions for newly constructed EGUs, and are anticipated to yield no monetized benefits and impose negligible costs, economic impacts, or energy impacts on the electricity sector or society.  While the EPA does not project any new coal-fired EGUs without CCS to be built in the absence of this rule, this chapter presents an analysis of the project-level costs of building new coal-fired capacity with and without CCS to demonstrate that a requirement of partial CCS would not preclude new coal construction.  An additional illustrative analysis, presented at the end of this chapter, shows that even in the unlikely event that new, noncompliant EGU capacity would be built in the absence of this rule the proposed EGU New Source GHG Standards would provide net social benefits under a range of assumptions.
4.2	Requirements of the Final GHG EGU NSPS
      In this action, the EPA is finalizing standards of performance for two basic categories of new units that have not commenced construction by January 8, 2014: (i) fossil fuel-fired electric utility steam generating units (boilers and IGCC units), including new units and existing units that undergo a major modification or reconstruction; and (ii) natural gas-fired stationary combustion turbines that generate electricity for sale and meet certain size and operational criteria.
      
      The EPA is finalizing standards of performance for affected sources within the following two categories: (1) all fossil fuel-fired steam generating units (steam generating units, boilers and IGCC units), and (2) all natural gas-fired stationary combustion turbines, regardless of the size of the stationary turbine unit. All affected new fossil fuel-fired EGUs would be required to meet an output-based emission rate of a specific mass of CO2 per MWh of electricity generated energy output on a gross basis.  
      
      New fossil fuel-fired steam generating units (boilers and IGCC units) would be required to meet an emission standard of 1,400 lb CO2/MWh of gross energy output. This is a less stringent standard than the proposed limitation (1,100 lb CO2/MWh) in the 2013 proposed rule. Existing fossil fuel-fires steam generating units that 	are making modifications that will result in an increase of more than 10% of that unit's historic CO2/MWh emission rate, or are being reconstructed, will be required to meet an emission standard determined by the size of the heat input of the unit. Such modified units with a heat input greater than 2,000 MMBtu/hour will have an emission limit of 1,800 lb CO2/MWh of gross energy output. Modified units with a heat input rate less than or equal to 2,000 MMBtu/hour will have an emission limit of 2,000 lb CO2/MWh of gross energy output.
      
      Newly constructed, modified or reconstructed natural gas-fired stationary combustion turbines will be required to meet a standard of 1,000 lb CO2/MWh of gross energy output (or 1,080 lb CO2/MWh of net energy output). This emission limit applies to all affected natural 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 will operate as a combined heat and power (CHP) unit and only sell a small portion of the gross electricity generated to the grid to not have to meet the same emission standard as a combustion turbine unit designed primarily to generate electricity to be sold to the grid.
      
       Please refer to the preamble for additional detail concerning affected sources and standards of performance.
4.3	Power Sector Modeling Framework
4.3.1	Modeling Overview
Over the last decade, the EPA has conducted extensive analyses of regulatory actions impacting the power sector.  These efforts support the Agency's understanding of key policy variables and provide the framework for how the Agency estimates the costs and benefits associated with its actions that impact the power sector.  Current forecasts for the utilization of new and existing generating capacity are a key input into evaluating the impact of this rule.  Given excess capacity within the existing fleet and relatively low forecasts of electricity demand growth, there is limited new capacity - of any type - expected to be constructed over the next decade.  A small number of new coal-fired power plants have been completed and brought online in recent years; however, the EPA does not expect the construction of any new 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 IPM as well as EIA's Annual Energy Outlook 2014 (AEO 2014) projections. 
IPM, developed by ICF International, Inc, is a state-of-the-art, peer reviewed, dynamic linear programming model that can be used to project power sector behavior under future business as usual conditions and examine prospective air pollution control policies throughout the United States for the entire electric power system. The EPA used IPM to project likely future electricity market conditions with and without this rule.  In addition to using IPM, the EPA has closely examined the AEO 2014 from the EIA.
To produce the AEO, EIA employs the National Energy Modeling System (NEMS), an energy-economy modeling system of the United States.  According to EIA:
"NEMS projects the production, imports, conversion, consumption, and prices of energy, subject to assumptions on macroeconomic and financial factors, world energy markets, resource availability and costs, behavioral and technological choice criteria, cost and performance characteristics of energy technologies, and demographics."
The Electricity Market Module of NEMS produces projections of power sector behavior that minimize the cost of meeting electricity demand subject to the sector's inherent constraints, including the availability of existing generation capacity, transmission capacity and cost, cost of utility and nonutility technologies, expected load shapes, fuel markets, regulations, and other factors. EIA's AEO projections independently support the EPA's conclusions in that it projects no new generation capacity being constructed through the analysis period that would not already meet the level of the standard even in the absence of the standard.  Both sets of modeling results are presented in Section 4.4.
4.3.2	The Integrated Planning Model
IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. electric power sector. It provides forecasts of least cost capacity expansion, electricity dispatch, and emission control strategies while meeting energy demand and environmental, transmission, dispatch, and reliability constraints. The EPA has used IPM for over two decades to better understand power sector behavior under future business as usual conditions and evaluate the economic and emission impacts of prospective environmental policies. The model is designed to reflect electricity markets as accurately as possible.   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 are based on assumptions used in the EIA's AEO.
As part of IPM's assessment of the relative economic value of building a new power plant, the model incorporates a detailed representation of the fossil-fuel supply system that is used to forecast equilibrium fuel prices, a key component of new power plant economics.  The model includes an endogenous representation of the North American natural gas supply system through a natural gas module that reflects full supply/demand equilibrium of the North American gas market.  This module consists of 118 supply, demand, and storage nodes, 15 liquefied natural gas regasification facility locations and 3 LNG export facility locations that are tied together by a series of linkages (i.e., pipelines) that represent the North American natural gas transmission and distribution network.
IPM also endogenously models the coal supply and demand system throughout the continental U.S., and reflects non-power sector demand and imports/exports.  IPM reflects 36 coal supply regions, 465 coal supply curves for each of 9 years, 14 coal sulfur grades, and the coal transport network, which consists of 4,947 linkages representing the costs of transporting coal via rail, barge, and truck and conveyer linkages connecting 41 regions with 575 individual coal-fired generating stations.  The coal supply curves and the transport network costs used in IPM are publicly available, were developed during a thorough bottom-up, mine-by-mine approach that depicts the coal choices and associated supply costs that power plants will face over the modeling time horizon.  The IPM documentation outlines the methods and data used to quantify the economically recoverable coal reserves, characterize their cost, and build the 84 coal supply curves.  The coal supply curves were developed in consultation with Wood Mackenzie, one of the leading energy consulting firms and specialists in coal supply.  These curves have been independently reviewed by industry experts and have been made available for public review on several occasions over the past two years during other rulemaking processes.  
The EPA has used IPM extensively over the past two decades to analyze options for reducing power sector emissions. Recently, the model has been used to forecast the costs, emission changes, and power sector impacts for the Clean Air Interstate Rule (CAIR), Cross-State Air Pollution Rule (CSAPR), and the Mercury and Air Toxics Standards (MATS).  
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.  EPA is required to respond to significant comments submitted regarding the inputs used in IPM, its structure, and application.  The feedback that the Agency receives provides a detailed check for key input assumptions, model representation, and modeling results. IPM has received extensive review by energy and environmental modeling experts in a variety of contexts.  For example, from the mid-1990s through 2011 the Science Advisory Board reviewed IPM as part of the CAA Amendments Section 812 studies of the Clean Air Act costs and benefits that are periodically conducted.  The model has also undergone considerable interagency scrutiny when it has been used to conduct over one dozen legislative analyses (performed at Congress' request) over the past decade.  In addition, Regional Planning Organizations throughout the U.S. have extensively examined IPM as a key element in the state implementation plan (SIP) process for achieving the National Ambient Air Quality Standards.  The Agency has also used the model in a number of comparative modeling exercises sponsored by Stanford University's Energy Modeling Forum over the past 15 years.
IPM has also been employed by states (e.g., for RGGI, the Western Regional Air Partnership, Ozone Transport Assessment Group), other Federal and State agencies, environmental groups, and industry, all of whom subject the model to their own review procedures. States have also used the model extensively to inform issues related to ozone in the northeastern U.S.  This groundbreaking work set the stage for the NOx SIP call, which has helped reduce summer NOx emissions and the formation of ozone in densely populated areas in the northeast.  
4.4	Analyses of Future Generating Capacity
4.4.1	Base Case Power Sector Modeling Projections
EPA conducted analysis and modeling in support of the April 2012 EGU GHG New Source Standards proposal, and concluded that new unplanned noncompliant base load power plants are not expected to be economic both during, and well beyond, the analysis period. The EPA conducted an analysis of the economic impacts by modeling a base case scenario of future electricity market conditions. The EPA's IPM modeling for the 2012 proposal utilized the IPM v. 4.10 base case, and relied on the AEO 2010 for the electric demand forecast for the U.S. and employed a set of the EPA's assumptions regarding fuel supplies, the performance and cost of electric generation technologies, pollution controls, and numerous other parameters. 
After considering public comments received on the 2012 proposal, the EPA issued a new proposal for carbon emissions from new power plants in September, 2013. The EPA's IPM modeling of the 2013 111(b) proposal relied on the AEO 2013 electric demand forecast, and was analyzed using the IPM v. 5.13 base case. 
For the analysis of the final 111(b) rule, the EPA used the IPM v. 5.14 base case, which relied on the electric demand forecast in AEO 2014. The v. 5.14 base case updated v. 5.13 unit level specifications (including control configurations) based on comments received and environmental regulations.  The base case accounts for the effects of the finalized MATS and CSAPR rules, New Source Review settlements and state rules through 2014 impacting sulfur dioxide (SO2), NOx, directly emitted particulate matter and CO2, and final actions the EPA has taken to implement the Regional Haze Rule. The EPA's IPM base case also includes two federal non-air rules effecting EGUs: the Cooling Water Intakes (316(b)) Rule and the Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR). 
The EPA's IPM base case forecast finds that new generation capacity is expected to be compliant with the standards, even in the absence of this rule. Some new coal-fired units with federally-supported carbon capture and storage (CCS) are forecast to be constructed, though these units are expected to be compliant with their standards under this rule. New capacity is forecast to be predominately stationary combustion turbines and renewables. New simple-cycle combustion turbines (CTs) constructed in the EPA's IPM base case are assumed to operate at an emissions rate above the standard. Mirroring real world behavior, relatively low levels of CT generation are projected in the base case. In the base case new CTs are forecast to operate, on average in each domestic model region, at capacity factors well below the applicability requirements of this rule.  In the base case the maximum average capacity factor for individual new CTs is 14% or less across all domestic regions and all simulation years.  The emission rate of new natural gas combined cycle (NGCC) units in the EPA's IPM base case emit below the emissions rate standard of this final rule by assumption. However, a modeled emissions rate for new NGCC units below the standard is consistent with the detailed emissions rate analysis described in the preamble for this rule, which carefully considered emissions rate data on newly constructed NGCC units and GHG limitations in recently issued construction permits for NGCC facilities.   
The EIA projections that are reflected in AEO 2014 are summarized in the following tables alongside the EPA base case projections.  New coal-fired capacity through 2030 in the AEO 2014 reference case is entirely CCS-equipped and would be in compliance with this proposal (300 MW).  The projected CCS-equipped capacity is assumed to occur in response to existing Federal, State, and local incentives for the technology. According to the AEO 2014  -  which represents existing policies and regulations influencing the power sector - the vast majority of new, unplanned generating capacity is forecast to be either natural gas-fired or renewable.  The economics favoring new natural gas combined cycle (NGCC) additions instead of coal-fired additions are robust under a range of sensitivity cases examined in the AEO 2013 and AEO 2014.  Sensitivity cases that EIA conducted in those AEOs separately examine higher economic growth, lower coal prices, no risk premium for greenhouse gas emissions liability from conventional coal, and lower oil and natural gas resources also forecast zero unplanned additions of coal-fired capacity without CCS in the analysis period.  This has been a consistent finding in the AEO, which led EIA to conclude that "the low capital expense, technical maturity, and dispatchability of natural gas generation are likely to dominate investment decisions under current policies and projected prices."  

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

The capacity projections of EIA and the EPA represent a continuation of current trends, where natural gas-fired capacity has been the technology of choice for base load and intermediate load power generation over the last few years (see Figure 4-1), due in large part to its significant levelized cost of 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, 1940-2011

Source: Form EIA-860 (2011)  
Note: Renewables include hydro, geothermal, biomass solar, and wind energy technologies.    
In addition to new builds, increased electricity demand is expected to be partially fulfilled by increased utilization of existing generating capacity.  Generation projections are the result of least-cost economic modeling both in IPM and AEO 2014, and reflect the most 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% of total 2020 generation in AEO 2014 and 37% 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
                            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 misc. generation and storage technologies. Negative value reflects net energy loss from pumped storage.
It has been previously noted that since the time of the original 2012 proposed new source rule, projections for key market variables are now even less favorable to the development of coal-fired capacity.  State and regional regulations have necessarily evolved since the AEO 2010 and the EPA's modeling projections for the 2012 proposal, most notably regulations of GHG emissions from the power sector and state renewable portfolio standards (RPS):
         * State regulations addressing CO2 emissions  -  Several states have adopted measures to address emissions of CO2 from the power sector.  These approaches include flexible market-based programs like California's Assembly Bill 32 and the RGGI in the Northeast, and specific GHG performance standards for new power plants in California, Oregon, New York, and Washington.
         * State Renewable Portfolio Standards (RPS)  -  According to EIA, 30 states and the District of Columbia have an enforceable RPS, or similar laws.  There are eight other States that 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. 
         * 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 that any new sources of generation will be from renewables, in response to state and federal regulations and incentives, and natural gas prices.  Furthermore, these plans reflect an expectation of relatively low demand growth due, in part, to policies and regulations to reduce the electricity consumption such as energy efficiency regulations and policies, evolution of the Smart Grid, and demand response measures. 
4.4.2	Alternative Scenarios from AEO 2014 
In addition to EPA's own analysis, EPA reviewed EIA's recent forecasts of new capacity in the electricity sector for the AEO 2014, which uses the National Energy Market System (NEMS) model. The AEO 2014 reference case forecasts no new coal that would not comply with the final new source standards. Furthermore, the reference case projects a capacity factor for CTs of less than 20% in all regions and in all years.  Furthermore, power sector modeling by EIA projects no new coal-fired capacity in the analysis period have been demonstrated to be robust under a range of alternative assumptions that influence the industry's decisions to build new power plants.  For example, EIA typically supplements the AEO with scenarios that explore key market, technical, and regulatory issues.  Of the 31 scenarios contained in the AEO 2014, none project new coal-fired capacity in the analysis period, including the four scenarios that may be considered most favorable to the development of coal-fired capacity displayed in Table 4-3. 

Table 4-3.	AEO 2014 Reference and Alternative Scenario Forecasts of Unplanned Cumulative Capacity Additions by 2020, GW 
                                 Capacity Type
                                   Reference
                                  High Growth
                                 Low Coal Cost
                          Low Gas & Oil Resource
                                No GHG Concern
Conventional Coal
                                       0
                                       0
                                       0
                                       0
                                       0
Coal with CCS
                                      0.3
                                      0.3
                                      0.3
                                      0.3
                                      0.3
Natural Gas
                                     23.9
                                     34.4
                                     19.8
                                     16.3
                                     22.7
Nuclear
                                       0
                                       0
                                      0.0
                                      2.5
                                      0.0
Non-Hydro Renewables
                                     17.4
                                     19.7
                                     17.6
                                     23.7
                                     17.5
Other
                                      1.6
                                      2.0
                                      1.5
                                      0.8
                                      1.6
Total
                                     43.2
                                     56.5
                                     39.3
                                     43.6
                                     42.1
 
4.4.3	Power Sector Fuel Price Dynamics and Trends
As mature technologies, the cost and performance characteristics of conventional coal-fired capacity and NGCC are projected by EPA to be relatively stable over time in comparison to emerging generation technologies.  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% was produced domestically; thus, the supply of natural gas is not as dependent on foreign producers as is the supply of crude oil, and the delivery system is less subject to interruption. The availability of large quantities of shale gas should enable the United States to consume a predominantly domestic supply of gas for many years and produce more natural gas than it consumes.
The AEO 2014 projects U.S. natural gas production will increase by 13.3 trillion cubic feet (Tcf), a 55% increase (from 24.3 Tcf in 2014 to 37.5 Tcf in 2040). Over 75% of this forecasted increase in domestic natural gas production is due the projected doubling of shale gas production, which is forecast to increase by 10.2 TCF (from 9.6 TCF in 2014 to 19.8 TCF in 2040).
 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% above production in 2013, which is the largest annual growth rate since 1984.  The average real (2011$) delivered natural gas price delivered to the power sector was $4.39 per MMBtu in 2014, an increase from $4.25/MMBtu in 2013.  
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." 
EPA's and EIA's modeling frameworks are designed to reflect the longer term, fundamentals-based perspective that electric utilities and developers employ in evaluating capital investments, while utilizing scenario testing to account for broader fuel market uncertainties.  Short-term fuel price volatility is not the most relevant factor in this context because new power plants have asset lives measured in decades, not in months or years, and new capacity investment decisions are based on long-run expected prices, not month-to-month, or even year-to year, variations in fuel prices.  Shorter-term prices will affect how units are dispatched, but these potential dispatch impacts are considered with other factors over a longer time horizon and factored into the choice of which type of plant to build.  In contrast, the uncertainty surrounding long-term fuel prices will exert significantly greater influence on the technology selected for new capacity additions. In a modeling context with perfect foresight, this longer term uncertainty may be evaluated by the scenario testing presented throughout this analysis.
In addition to major changes in the gas supply outlook, there have been notable changes in the coal supply outlook.  Coal costs have generally increased over the past few years due primarily to increased production costs.  These costs have increased as the most accessible and economically viable mines are depleted, requiring movement into coal reserves that are more costly to mine.  The basic trends in coal supply are not expected to change for the foreseeable future.
      Taken together, current and expected natural gas and coal market trends are contributing to a fundamental shift in the economic conditions for new power plant development that utilities and developers have recognized and responded to in planning.
4.4.4	Power Sector Fuel Projections
  To examine the potential impacts of uncertainty inherent in natural gas and coal markets, the EIA used scenario analysis to generate the 2020 fuel price projections in Table 4-4.

Table 4-4.	National Delivered 2020 Fuel Prices by AEO 2014 Scenario (2011$/MMBtu)
                                   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

	However, given that power plants are long-lived assets, capacity planning decisions are necessarily undertaken with a forward view of expected market and regulatory conditions.  In producing the AEO 2014, EIA capacity expansion projections are informed by a lifecycle cost analysis over a 30-year period in which the expectations of future prices are consistent with the projections realized in the model (i.e. the model executes decisions with perfect foresight of future market, technical, and regulatory conditions).  Therefore, the fuel prices that inform capacity expansion decisions in 2020 is not only the prices that year, but the entire future fuel price stream.  For example, Figure 4-2 displays EIA's natural gas price projections for the Reference Case and several key scenarios through 2040.

Figure 4-2.	National Real Price of Natural Gas Delivered to EGUs for Select AEO 2014 Scenarios (2011$/MMBtu)
      Note: The AEO gas price forecasts go through 2040. The AEO forecasted prices are interpolated to 2040 by applying the average annual rate of price increase from 2035 to 2040 in each AEO scenario to all subsequent years from 2041 through 2049.
      
	 Natural gas prices are expected to increase after 2020 in all 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 in the analysis period (i.e., through 2022), demonstrating that natural gas prices at currently low levels are not required to persist for NGCC to maintain its economic advantage over coal-fired technologies.
While the uniformity of EIA scenarios in projecting no new non-compliant coal-fired capacity through the analysis period is compelling, the scenario projections cannot fully illustrate the extent of the economic advantage that NGCC maintains over conventional coal  -  only that the advantage remains intact across a broad range of market and technical scenarios.  To identify potential market conditions that could fully erode the private cost advantages of NGCC over coal-fired technologies during the analysis period, the following section adopts a static, engineering cost analysis.
4.5	Levelized Cost of Electricity Analysis 
New capacity projections from the EPA and EIA reviewed in the previous section indicate that the NSPS is not projected to require changes in the design or construction of new EGUs from what would be expected in the absence of the rule.  Thus, under both the baseline projections and alternative scenarios analyzed in AEO 2014, the proposed EGU New Source GHG Standards are not projected to result in any emission reductions, monetized benefits, or costs.
To further examine the robustness of these conclusions the EPA conducted additional analysis using the levelized cost of electricity (LCOE) for different types of new generation technologies.  The LCOE is a widely used metric that represents the cost, in dollars per output, of building and operating a generating facility over the entirety of its economic life.  Evaluating competitiveness on the basis of the LCOE is particularly useful in establishing cost comparisons between generation types with similar operating characteristics but with different cost and financial characteristics.  The typical cost components associated with the LCOE include capital, fixed operating and maintenance (FOM), variable operating and maintenance (VOM), and fuel.
4.5.1	Overview of the Concept of Levelized Cost of Electricity
The levelized capital and FOM costs may be calculated by taking the annualized capital and FOM (expressed in $/kW-yr) costs and spreading the expense over the annual generation of the facility using the expected average annual capacity factor (the percent of full load at which a unit would produce its actual annual generation if it operated for 8760 hours). The annualized capital cost (expressed in $/kw-yr) is the product of the $/kW capital cost and the capital recovery factor (CRF).  A CRF may be calculated using the project's interest rate (i) and book life (n).
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 
The NGCC and coal-fired generation technology cost and performance assumptions that form the basis for the LCOE analysis in this chapter are from the DOE's National Energy Technology Laboratory (NETL).  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.[,] 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.  The EPA selected NETL cost and performance characteristics for NGCC to ensure that the cost comparisons between NGCC and coal-fired technologies  -  the primary comparison made in this chapter  -  was based on a single, internally consistent framework.  For technologies where NETL cost and performance estimates were not available or sufficiently recent  -  such as for nuclear and simple cycle CT  -  EPA adopted EIA's AEO 2014 estimates of the LCOE.
To represent a new SCPC facility, NETL assumed a new boiler with a combination of 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 ppmv or less. The SCPC with CCS plant configurations were assumed to be equipped with Fluor's Econamine FG Plus[SM] process for post-combustion CO2 capture via temperature swing absorption with a monoethanolamine (MEA) solution as the chemical solvent.
Specific to the partial capture configurations for SCPC, the NETL study identified two options. The first option identified was to process the entire flue gas stream through the MEA capture system, but at reduced solvent circulation rates. The second option was to maintain the same high solvent circulation rate and stripping steam requirement as would be used for full capture, but only treat a portion of the total flue gas stream. The NETL report determined that this "slip stream" approach was the most economical because a reduction in flue gas flow rate will: (1) decrease the quantity of energy consumed by flue gas blowers; (2) reduce the size of the CO2 absorption columns; and (3) trim the cooling water requirement of the direct contact 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.
For a new IGCC EGU, the NETL study evaluated a number of IGCC plant configurations. EPA adopted the configurations presented as the most viable  -  from both an economic and technological perspective  -  for the no capture, partial capture and full capture cases. The no CO2 capture case employed an IGCC that used the two-stage acid gas (Selexol(TM)) process for acid gas control (i.e., hydrogen sulfide and CO2) but no water-gas shift reactor. The 25 percent CO2 capture case utilized the same two-stage Selexol(TM) unit to maximize CO2 capture from the unshifted syngas.  To achieve higher CO2 capture levels  -  including full capture - the IGCC was assumed to be configured with a two-stage water-gas shift reaction with bypass and the two-stage acid gas (Selexol(TM)) scrubbing system.  In summary, the technology cost and performance characteristics utilized by the EPA in developing the LCOE estimates discussed in this chapter and Chapter 5 are listed below in Table 4-5.
Table 4-5.	Technology Cost and Performance Specifications (2011$) 
                                 Capacity Type
                      Total Overnight Capital Cost ($/kw)
                 Fixed Operations & Maintenance ($/kw-yr)
                 Variable Operations & Maintenance ($/MWh)
                         Levelized Fuel Cost ($/MMBtu)
                         Net Plant HHV Efficiency (%)
NGCC
                                      891
                                     31.4
                                      1.8
                                     6.07
                                     51.1
SCPC
                                     2,452
                                     83.0
                                      7.7
                                     2.80
                                     39.3
SCPC w/ Partial CCS 
(1,400 lbs/MWh gross)
                                     2,876
                                     94.9
                                      8.9
                                     2.80
                                     36.9
IGCC
                                     2,969
                                     81.8
                                      9.3
                                     2.80
                                     39.0
IGCC w/ Partial CCS 
(1,400 lbs/MWh gross)
                                     3,419
                                     112.5
                                      9.4
                                     2.80
                                     38.8
Notes: The coal assumed is a bituminous coal with a sulfur content of 2.8% (dry) at a real (2011$) price of $2.80/MMBtu, consistent with AEO 2014 Reference Case forecast levelized delivered coal (all types) price.  The natural gas price is the EIA AEO 2014 forecast levelized real (2011$) delivered gas price from EIA's AEO 2014 Reference Case.  NETL (2013) explains that there are a range of future potential costs that are up to 15% below, or 30% above their central estimate, consistent with a "feasibility study" level of design engineering applied to the various cases in this study. The value of the studies lie not in the absolute accuracy of the individual case results but in the fact that all cases were evaluated under the same set of technical and economic assumptions. This consistency of approach allows meaningful comparisons among the cases evaluated.

4.5.3	Levelized Cost of Electricity of New Generation Technologies
To support and provide context for the sectoral modeling results presented above, this section presents two LCOE comparisons: 
      1. NGCC to Uncontrolled Coal  -  to demonstrate the cost advantages of NGCC across a range of natural gas prices and regional market conditions.
      2. NGCC to CT  -  to demonstrate the low likelihood of a new combustion turbine being built with the expectation of meeting the applicability criteria based on utilization and thus being covered by this proposal.
The illustrative unit cost and performance characteristics used in this section assume representative costs associated with spatially dependent components, such as connecting to existing fuel delivery infrastructure and the transmission grid. In practice units may experience higher or lower costs for these components depending on where they are located.  It should be noted that the LCOE comparisons presented in this section only represent the cost to the generator and do not reflect the additional social costs that are associated with emissions of greenhouse gases or other air pollutants.  A broader consideration of the health and welfare impacts of emissions from these technologies is considered in Chapter 5.
 It is also important to note that both the EIA and EPA apply a climate uncertainty adder (CUA) - represented by a three percent increase to the weighted average cost of capital  -  to new, conventional coal-fired capacity types.  EIA developed the CUA to address differences in how investments in new capacity are evaluated in power sector models as compared to resource planning exercises commonly conducted by the industry.  While baseline power sector 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 risk typically assigned by project developers and utilities to GHG-intensive projects in a context of climate uncertainty.  When comparing ex-ante private investment costs, the EPA believes the inclusion of the CUA in LCOE estimates is consistent with the industry's current planning and evaluation framework for future projects (demonstrable through IRPs and public utility commission orders) and is therefore necessary to adopt in evaluating potential investment behavior in light of the cost competitiveness of alternative generating technologies.  
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 in an evaluative sense to prospective projects, and then removed once a project transitions from planning to execution.  While omitting the CUA is inconsistent with an analysis considering how project characteristics and market conditions would lead a developer or utility to select a certain project, as is the purpose of this section, for transparency the LCOE estimates for uncontrolled coal-fired projects are presented both with and without the CUA.  All LCOE estimates of coal-fired facilities with CCS (partial or full) are presented without the CUA, to represent the reduced CO2 liability associated with such technologies.
4.5.4	Levelized Cost of Electricity of NGCC and Uncontrolled Coal
The EPA's base LCOE estimates for NGCC, SCPC, and IGCC are displayed in Figure 4-3 by cost component (capital, FOM, VOM, TS&M and fuel) and assume a construction date of 2020. Although the EPA believes that this cost data is broadly representative of the economics between new coal and new natural gas facilities, this analysis assumes representative new units and does not reflect the full array of new generating sources that could potentially be built.  To the extent that other types of new units that would be affected by this rule are built, they may exhibit different costs than those presented here.  For example, new conventional coal facilities of a size smaller than what is assumed in the base estimate would tend to exhibit a relatively higher LCOE, while some technologies could potentially display a lower LCOE if  -  all else equal - fuel could be obtained at a lower price than that assumed in this analysis (such as may be the case for petroleum coke or waste coal facilities).  These potential differences do not fundamentally change the analysis presented in this chapter.
On a levelized cost basis, NGCC is significantly cheaper than all of the uncontrolled coal-fired options.  In addition to the disparity in LCOE totals, the cost composition exhibits fundamental differences between natural gas- and coal-fired facilities, with NGCC dominated by fuel expense and the levelized cost of coal-fired technologies driven by capital expense.  Consequently, this section will explore the impact of changes in natural gas price and the capital costs of coal-fired facilities to better quantify the magnitude of the relative cost advantage NGCC exhibits over coal-fired alternatives.

Figure 4-3.	Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation Technologies by Cost Component
      Notes: 
      (1) The coal assumed is a bituminous coal with a sulfur content of 2.8% (dry) and a real delivered price of $2.80/MMBtu. $2.80/MMBtu is the levelized real (2011$) delivered average coal price from the AEO 2014 reference case for all coals during the 20 year forecast period 2020-2039. The $2.80/MMBtu coal price is assumed for all years; therefore, the price serves as both the 2020 fuel cost as well as the levelized fuel cost over any future period of time.   
      (2) The levelized delivered price of natural gas is $6.07/MMBtu (2011$).This price is the levelized real (2011$) delivered gas price from the AEO 2014 reference during the 20 year forecast period 2020-2039.
      (3) A 3% climate uncertainty adder (CUA) is added to the SCPC without any CCS control. The CUA is not added to the SCPC with partial control, nor to the two IGCC alternatives.
      (4) The cost of CO2 transport, storage and monitoring (TS&M) is included as part of LCOE for the two alternatives capturing CO2. 
      (5) The gross CO2 emission rates for these illustrative new generation technologies are: NGCC = 778 lbs/MMBtu; SCPC (no CCS) = 1,677 lbs/MMBtu; SCPC with CCS on 22% of emission stream = 1,400 lbs/MMBtu; IGCC (no CCS) = 1,434 lbs/MMBtu; IGCC with CCS on 2.8% of emission stream = 1,400 lbs/MMBtu.
      (6) A capacity factor of 85 percent is assumed across all technologies. 
      (7) For comparison, EIA estimates levelized costs under AEO 2013 assumptions for SCPC and IGCC are $99/MWh and $122/MWh, respectively, including a 3% CUA and excluding transmission investment costs. The levelized costs presented above are based on NETL assumptions and will necessarily differ from AEO 2014 levelized costs for a variety of reasons, including cost and performance characteristics, financial assumptions, and fuel input prices.  
The figure below presents the LCOE of an NGCC facility at three levelized natural gas price levels.  For reference, the base LCOE estimates for SCPC and IGCC (with no CO2 control) are included as well.

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

It is only when natural gas prices exceed $10/MMBtu on a levelized basis (in 2011$) that new coal-fired generation without CCS approaches parity with NGCC in terms of the LCOE (none of the EPA sensitivities or AEO 2014 scenarios described in this chapter project national average natural gas prices near that level).   To achieve a $10/MMBtu levelized price in 2020 would require a significantly more pessimistic natural gas outlook than what is contained in AEO's low natural gas resource scenario.  To illustrate, Table 4-6 report the levelized natural gas prices (initial year of 2020) for both a 20-year period (to accommodate the end of EIA's modeling projections in 2040) and 30-year period (calculated by continuing the projected level of price increases through 2050).

Table 4-6.	Levelized Natural Gas Prices by Select AEO 2014 Scenario (2011$/MMBtu)
                                   Scenario
                            20-Year AEO Projection
                                  (2020-2039)
                         30-Year AEO-Based Projection
                                  (2020-2049)
Reference
                                     6.07
                                     6.53
High Growth
                                     6.32
                                     6.96
Low Growth
                                     5.78
                                     6.20
High Coal Cost
                                     6.19
                                     6.69
Low Coal Cost
                                     6.03
                                     6.47
High Gas/Oil Resource
                                     4.80
                                     4.85
Low Gas/Oil Resource
                                     7.70
                                     8.45
            Note: Discount rate of 5%, consistent with IPM assumptions.  The 30-year natural gas price is calculated by applying the average annual rate of price increase from 2035 to 2040 in all subsequent years from 2041 through 2049.
One potential price path that would achieve a $10/MMBtu on a 20-year levelized basis in 2020 is a natural gas price path 30% higher than EIA's low resource scenario in all years; see Figure 4-5 below.  This illustrative price path to achieve a $10/MMBtu levelized price would result in a $11.02/MMBtu annual real price in 2030 and a $13.81/MMBtu real price in 2040. 
 
Figure 4-5.	Projected Real National Delivered Natural Gas Price for Select AEO 2014 Scenarios and Illustrative Path for > $10/MMBtu Levelized Cost 

It is important to note that the LCOE calculations are based on assumptions regarding the average national cost of generation at new facilities.  It is known that there is significant spatial variation in the costs of new generation due to design differences, labor productivity and wage differences, and delivered fuel prices, among other potential factors.  
For example, EIA utilizes capital cost scalars to capture regional differences in labor, material and construction costs.  The minimum and maximum capital cost scalars across all regions in AEO 2014 for SCPC, IGCC, and NGCC build options are presented below in Table 4-7: 
Table 4-7.	AEO 2014 Regional Capital Cost Scalars by Capacity Type
                                 Capacity Type
                          Minimum Capital Cost Scalar
                          Maximum Capital Cost Scalar
SCPC
                                     0.885
                                     1.152
IGCC
                                     0.908
                                     1.136
NGCC
                                     0.893
                                     1.205
	Applying the regional capital cost scalars displayed above to the base LCOE estimates developed earlier in this section produces only a small change in the relative competitiveness of the technologies as seen in Table 4-8.
Table 4-8.	LCOE Estimates with Minimum and Maximum AEO 2014 Regional Capital Cost Scalars (2011$/MWh)
                                 Capacity Type
                                  Reference 
                                     LCOE
                          Minimum Capital Cost Scalar
                          Maximum Capital Cost Scalar
SCPC (no CCS, with CUA)
                                      91
                                      81
                                      105
IGCC (no CCS, without CUA)
                                      96
                                      87
                                      109
NGCC
                                      59
                                      53
                                      71
	The LCOE of SCPC in the lowest capital cost region still results in an LCOE that is 13% higher than an NGCC located in the most expensive capital cost region.  The IGCC LCOE is 22% above NGCC in the most expensive region. 
The other primary driver in determining the regional impact on competitiveness of new build options is delivered fuel prices.  As part of the AEO, EIA releases electric power projections  -  including fuel prices  -  for each of the 22 Electricity Market Module (EMM) regions.  The two regions with the highest projected 2020 natural gas prices in the AEO 2014 are the Western Electricity Coordinating Council/Southwest (`Southwest') and the Florida Reliability Coordinating Council (FRCC).  The 20-year levelized natural gas and coal price forecasts (2020-2039) in the AEO 2014 reference case are displayed in Figure 4-6 for both regions.

Figure 4-6.	Levelized Regional Fuel Price from AEO 2014 Reference Case, 2020-2039 			(2011$/MMBtu)  
While the FRCC region experiences the highest overall natural gas prices, the Southwest region realizes a greater $/MMBtu differential between coal and natural gas prices under the AEO projections; the impact on the LCOE of the SCPC, IGCC, and NGCC technologies without CCS is reported in Table 4-9 for both sets of fuel prices, as well as the national average for comparison. 
Table 4-9.	LCOE Estimates For Minimum and Maximum AEO 2014 Regional Capital Cost 			Scalars (2011$/MWh)
                                 Capacity Type
                         National Average Fuel Prices
                               FRCC Fuel Prices
                             Southwest Fuel Prices
SCPC (w/ 3% CUA)
                                      91
                                      98
                                      88
IGCC (No CUA)
                                      96
                                      104
                                      93
NGCC
                                      59
                                      87
                                      70
Due to the greater fuel price differential, the more favorable region for the development of coal-fired facilities from an LCOE perspective is the Southwest, where the regional fuel prices reduce the LCOE advantage of NGCC to $28/MWh over SCPC (compared with a $32 advantage with national fuel prices) and $23/MWh over IGCC (compared with a $37 advantage with national fuel prices.
In conclusion, even the most favorable combination of regional variability in capital costs and delivered fuel prices represented by EIA are insufficient to support new, unplanned, conventional coal-fired capacity in the analysis period.

4.5.7	Levelized Cost of Simple Cycle Combustion Turbine and Natural Gas Combined Cycle
Simple Cycle Combustion Turbines (CTs) fulfill a fundamentally different function in power sector operations than that of NGCC and fossil-fired steam facilities.  CTs are designed to start quickly in order to meet demand for electricity during peak operating periods and are generally less expensive to build (on a capital cost basis) but are also less fuel efficient than combined cycle technology, (which employs heat recovery systems).  Due to lower fuel efficiencies, CTs produce a significantly higher cost of electricity (cost per kWh) at higher capacity factors and consequently are typically utilized at levels below the applicability requirements for sources affected by the EGU New Source GHG Standards.  Specifically, the final emission standards do not apply to stationary combustion turbines subject to a federally enforceable permit condition limiting annual electric sales to the specific design efficiency of the combustion turbine multiplied by the unit's potential electric output or less. New CTs are expected to most often be built to ensure reserve margins are met during peak periods (typically in the summer), and in some instances be able to generate additional revenues by selling capacity into power markets.  Thus, in practice, EPA expects that potential CT units would not meet the applicability requirements finalized in this rule and would therefore, not be subject to the standards of performance. 
To illustrate the economic incentives of utilizing combustion turbines in an intermediate and base load mode of operation, Figure 4-7 presents the LCOE estimates for a new CT, Advanced CT and NGCC at increasing capacity factors.  The estimates utilize the AEO 2014 Reference Case levelized natural gas price for 2020. 

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%.  If expected utilization is greater than 20%, it can reasonably be expected that a utility or developer would seek to deploy NGCC over CT for a host of economic, environmental, and technical reasons.  Furthermore, the design net efficiencies for currently available potentially impacted aeroderivative simple cycle combustion turbines range from approximately 32 percent for smaller designs to 39 percent for the largest intercooled designs. The efficiencies of industrial frame units range from 30 percent for smaller designs to 36 percent for the largest units. The EPA therefore does not expect new CT units to be constructed, which would meet the applicability requirements. 
4.8	Macroeconomic and Employment Impacts
These final EGU New Source GHG Standards are not anticipated to change GHG emissions for newly constructed electric generating units, and are anticipated to impose negligible costs or monetized benefits.  EPA typically impacts on employment or labor markets associated with rules based on the estimated compliance costs and other energy impacts, which serve as an input to such analyses.  However, since the EPA does not forecast a change in behavior relative to the baseline in response to this rule, there are no notable macroeconomic or employment impacts expected as a result of this rule.  
4.9	References
Dixit, Avinash and Pindyck, Robert. Investment Under Uncertainty. 1994. Princeton University Press.
Fann, N., K.R. Baker, C.M. Fulcher. 2012. Characterizing the PM2.5-related health benefits of emission reductions for 17 industrial, area and mobile emission sectors across the U.S. Environment International, Volume 49, 15 November 2012, Pages 141-151, ISSN 0160-4120, http://dx.doi.org/10.1016/j.envint.2012.08.017.
Joskow, P.L. 2010. Comparing the Cost of Intermittent and Dispatchable Electricity Generating Technologies. MIT Center for Energy and Environmental Policy Research Working Paper 10-013.
P.L. Joskow. 2011. Comparing the Costs of Intermittent and Dispatchable Electricity Generating Technologies. American Economic Review. vol. 101:238-41.
Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz, and W.H. White. 2009. "Reanalysis of the Harvard Six Cities Study and the American Cancer Society Study of Particulate Air Pollution and Mortality." Special Report to the Health Effects Institute. Cambridge, MA. July.
Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. "Chronic Exposure to Fine Particles and Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009." Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.
Malik, N.S. 2010, November 1. NextEra CEO sees clean energy standards replacing recent climate proposals [Radio transcript]. Dow Jones News [Online]. Available: Dow Jones Interactive Directory: Publications Library.
Mufson, S. 2011, January 2. Coal's burnout. The Washington Post. Retrieved from 
      http://www.washingtonpost.com/newssearch. 

Muller, N.Z., R. Mendelsohn, and W. Nordhaus. 2011. Environmental Accounting for Pollution in the United States Economy. American Economic Review. 101:1649-1675.
National Energy Technology Laboratory (NETL). Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture. Revised Sept. 16, 2013. Available online at: http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf. 
Rosenberg, M. 2011, September/October. "The Reign of Cheap Gas." EnergyBiz Magazine. Retrieved from http://www.energybiz.com/magazine/article/234577/reign-cheap-gas.
Tong, S. 2010, November 1. Placing Bets on Clean Energy. [Radio transcript]. American Public Media: Marketplace [Online]. Available: Marketplace Programs on Demand.
National Petroleum Council. 2011. Prudent Development: Realizing the Potential of North America's Abundant Natural Gas and Oil Resources. Available online at: http://www.npc.org/reports/rd.html.
National Research of Council (NRC). 2009. Hidden Costs of Energy: Unpriced Consequences of Energy Production and Use. National Academies Press: Washington, D.C.
Trigeorgis, Lenos. Real Options: Managerial Flexibility and Strategy in Resource Allocation. 1996. The MIT Press.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010. Available online at: http://www.eia.gov/oiaf/archive/aeo10/index.html. 
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available online at: http://www.eia.gov/forecasts/aeo/.
U.S. Environmental Protection Agency (U.S. EPA). 2008. Integrated Science Assessment for Oxides of Nitrogen and Sulfur  - Ecological Criteria National (Final Report). National Center for Environmental Assessment, Research Triangle Park, NC. EPA/600/R-08/139. December. Available on the Internet at http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485. 
U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for Environmental Assessment  -  RTP Division. December. Available on the Internet at http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546. 
U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2013a. Technical Support Document Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on the Internet at: http://www.epa.gov/airquality/benmap/models/Source_Apportionment_BPT_TSD_1_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 Cost-Benefit Scenarios
5.1	Synopsis
The previous chapter of this regulatory impact analysis (RIA) presents the U.S. Environmental Protection Agency's (EPA) analysis and projections from the U.S. Energy Information Administration (EIA) that support the conclusion that the EGU New, Modified and Reconstructed Source Standards will result in negligible costs and benefits in the period of analysis. The EPA recognizes that this conclusion is based on underlying expected economic conditions (e.g., fuel prices) and assumptions about considerations investors would weigh in deciding whether to build new uncontrolled coal-fired power plants. Therefore, this chapter presents the results of several illustrative analyses that show, under a range of alternative conditions, the potential costs and benefits of these standards for individual investments that provide base load dispatchable generation. We evaluate conditions under which different generator types are constructed in lieu of a non-compliant supercritical coal unit and estimate the social benefit of adopting the investment that is compliant with the standards.  This also allows us to consider idiosyncratic circumstances under which a unit that does not comply with these standards may be constructed.  
While the analysis in Chapter 4 focuses on national level conditions, the analysis in this chapter explores the potential impacts to individual investments. The analysis in this chapter finds that under unlikely conditions, in which the EPA's conclusions regarding the future economic competitiveness of new non-compliant coal-fired units with respect to other new generation technologies shifts, or that idiosyncratic situations exist that favor the construction of units that would not comply with these standards, that the benefits of the standards to society outweigh the costs.
5.2	Comparison of Emissions from Generation Technologies
As discussed in Chapter 4, natural gas combined cycle (NGCC) units are on average expected to be more economical to build and operate than new coal units (See section 4.5).  Therefore, as our point of departure for comparing the costs and benefits of an individual investment decision, we evaluate the private and social cost of a new NGCC unit that is compliant with the finalized standards with a non-compliant conventional supercritical 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 also have lower emission profiles for CO2 and criteria air pollutants than new coal units. For example, a typical new SCPC facility that burns bituminous coal in compliance with current utility regulations (e.g., the Mercury and Air Toxics Standards (MATS)) would have considerably greater CO2, sulfur dioxide (SO2), nitrogen dioxide (NOx), toxic metals, acid gases, and particulate emissions than a comparable NGCC facility.  
Table 5-1 shows, emissions from a typical new NGCC unit are significantly lower than those from a new coal-fired unit.  The emission characteristics are based on, and thus consistent with, the cost and performance assumptions of the illustrative units described in LCOE analysis in section 4.5. That is, these are base load units of the same net capacity operating at an 85 percent capacity factor, the coal unit is assumed to be using bituminous coal with a sulfur content of 2.8% dry, they are in compliance with current utility regulations (e.g., the MATS), etc.  The typical new NGCC unit would emit about 2.3 fewer million metric tons of CO2 per year than the typical new SCPC unit, as well as roughly 1,700 fewer short tons of SO2 and about 1,200 fewer short tons of NOx per year than the SCPC unit. Table 5-1 also provides information for a representative integrated gasification combined cycle (IGCC) unit providing the same amount of electricity and using the same coal for comparison. The new IGCC unit would emit less CO2, SO2 and NOx than a typical coal-fired SCPC unit, but has higher emissions than a new NGCC unit. Reductions in SO2 emissions are a particularly significant driver for monetized health benefits, as SO2 is a precursor to the formation of particulates in the atmosphere, and particulates are associated with premature death and other serious health effects. Further information on these pollutants' health and non-health effects is described in Chapter 3.  
Table 5-1.	Illustrative Emissions Profiles, New Coal and Natural Gas-Fired 
		Generating Units

                                Natural Gas CC
                                     SCPC
                    SCPC+ Partial CCS (1,400 lbs/MWh Gross)
                                     IGCC
                    IGCC+ Partial CCS (1,400 lbs/MWh Gross)

                                   Emissions
                                 (tons/ year)
                         Emission Rate (lbs/ MWh net)
                                   Emissions
                                 (tons/ year)
                         Emission Rate (lbs/ MWh net)
                                   Emissions
                                 (tons/ year)
                         Emission Rate (lbs/ MWh net)
                                   Emissions
                                 (tons/ year)
                         Emission Rate (lbs/ MWh net)
                                   Emissions
                                  (tons/year)
                         Emission Rate (lbs/ MWh net)
                                      SO2
                                      10
                                    0.0041
                                     1,700
                                     0.74
                                     1,400
                                     0.62
                                      23
                                     0.011
                                      24
                                     0.011
                                      NOx
                                      130
                                     0.060
                                     1,400
                                     0.61
                                     1,400
                                     0.65
                                     1,200
                                     0.52
                                     1,200
                                     0.52
                                      CO2
                                  1.7 million
                                      800
                                  4.0 million
                                     1,800
                                  3.4 million
                                     1,500
                                  3.8 million
                                     1,700
                                  3.7 million
                                     1,700
Notes: SO2 and NOx in short tons, CO2 in metric tons. Values rounded to two significant digits.  Emission characteristics are based on, and thus consistent with the cost and performance assumptions of, the illustrative units described in LCOE analysis in section 4.5 (i.e., these are base load units running at 85 percent capacity factor, all coal units are assumed to be using bituminous coal with a sulfur content of 2.8% dry, etc.). The tons of emissions are estimated for a coal-fired facility that achieves the gross-output standard of 1,400 lbs/MWh and presented in this table on a net output basis. For the 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 degredation of the solvent. Therefore, SO2 emissions are lower in the case of the SCPC unit with partial CCS. See preamble for discussion about the format of the standard. Here we further assume all units are of the same capacity (600 MW net).  
5.3	Comparison of Health and Climate Impacts from Generation Technologies
As discussed in the previous section, the emissions of GHGs and other pollutants associated with new sources of electricity generation are greater for coal-fired units than for NGCC units. Reducing the emissions associated with electricity generation results in climate, human health and non-health benefits. 
To consider the health and climate benefits associated with the adoption of lower emitting new generation technologies, we apply the 2022 social benefit values discussed in Chapter 3 to the differences in illustrative emission profiles between the technologies in Table 5-1.  Specifically, we multiply the difference in CO2 emissions between two technologies by the estimates of the social cost of carbon dioxide (SC-CO2) (Table 3-1), multiply the difference in sulfur dioxide (SO2) and nitrogen dioxide (NOX) emissions by the PM2.5-related SO2 and NOX benefit per ton (BPT) estimates (Table 3-2), and add those values to get a measure of the 2022 social benefits attributable to differences in emissions of adopting the lower emitting new generation technology. We subsequently divide by the number of MWh underlying the annual emissions estimates to derive the social benefits attributable to the differences in emissions per unit of generation. 
Only the direct emissions of CO2, SO2, and NOX are considered in this illustrative exercise. Other air and water pollutants emitted by these technologies and emissions from the extraction and transport of the fuels used by these technologies are not considered. For example, coal has higher mercury emissions than natural gas, but the relative benefits from the difference in mercury emissions are not considered. Furthermore, there may be differences in upstream greenhouse gas emissions (in particular, methane) from different technologies but those were not quantified for this assessment.
Table 5-2 reports the 2022 incremental climate and health benefits associated with an illustrative new NGCC unit relative to illustrative new coal-fired SCPC and IGCC units, given different mortality risk studies and assumptions about the discount rate.  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 $97 per MWh (2011$). 
The precise health and welfare benefits associated with reduced CO2 emissions, which are the focus of this rule, depend on the specific fuels. However, the benefits of reduced CO2 emissions do not depend on the location of generation because the location of CO2 emissions does not influence their impact on the evolution of global climate conditions. As with the relative investment costs of a new coal-fired unit and a new NGCC unit, the precise incremental health co-benefits will be location specific and depend on the specific fuels used. However, these factors will not change the qualitative conclusion. There will be incremental 
Table 5-2.	2022 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Illustrative New Natural Gas Combined Cycle Generation Relative to New Non-Compliant SCPC or IGCC Coal Generation

                                     SCPC
                                     IGCC
CO2-Related Benefits using SC-CO2
5% Discount Rate
                                     $6.1
                                     $5.8
3% Discount Rate
                                      $21
                                      $20
2.5% Discount Rate
                                      $31
                                      $29
3% Discount Rate (95[th] percentile)
                                      $63
                                      $60
PM2.5-Related Co-Benefits from SO2 and NOX Reductions
3% discount rate
                                       
                                       
Krewski et al. (2009)
                                      $15
                                     $1.4
Lepeule  et al. (2012)
                                      $35
                                     $3.1
7% discount rate
                                       
                                       
Krewski et al. (2009)
                                      $14
                                     $1.2
Lepeule et al. (2012)
                                      $31
                                     $2.8
Combined CO2-Related and PM2.5-Related Benefits 

               Discount Rate Applied to PM2.5-Related Benefits 
                   (range based on adult mortality function)
SC-CO2 Discount Rate
                                                                             3%
                                                                             7%
                                                                             3%
                                                                             7%
5% Discount Rate
                                                                     $22 to $41
                                                                     $20 to $37
                                                                   $7.2 to $8.9
                                                                   $7.0 to $8.6
3% Discount Rate
                                                                     $36 to $55
                                                                     $35 to $52
                                                                     $21 to $23
                                                                     $21 to $22
2.5% Discount Rate
                                                                     $46 to $66
                                                                     $45 to $62
                                                                     $31 to $32
                                                                     $31 to $32
3% Discount Rate (95[th] percentile)
                                                                     $78 to $97
                                                                     $77 to $94
                                                                     $61 to $63
                                                                     $61 to $62
Notes: The emission rates and operating characteristics of the units being compared in this table are reported in Table 5.1. Benefits are estimated for a 2022 analysis year. The range of benefits within each SC-CO2 value and discount rate for PM2.5-related benefits pairing reflects the use of two core estimates of PM2.5-related premature mortality. 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.  
climate and human health benefits associated with a new NGCC unit relative to a new coal-fired unit, independent of the location. 
The conclusion from this analysis is that there are significant environmental and health benefits associated with electricity generation from a representative new NGCC unit relative to a new conventional coal-fired unit. Other studies of the social costs of coal and natural gas-fired generation provide similar findings (Muller et. al., 2011; NRC, 2009). 
As explained previously, the power sector has moved away from the construction of coal-fired power plants in favor of natural gas-fired power plants due, in part, to the significant cost differential. Even so, it is possible that a limited number of unplanned coal-fired power plants would be constructed during the analysis period. In these circumstances, units built with CCS in place of conventional coal-fired units would result in relative climate and human health and non-health benefits. Table 5-3 reports the 2022 incremental benefits associated with an illustrative new coal-fired unit with CCS relative to illustrative new SCPC and IGCC coal-fired units, given different mortality risk studies and assumptions about the discount rate.  Depending on the coal-fired generation type, discount rate, and mortality risk study used, 2022 incremental benefits associated with generation from a representative new coal-fired unit with CCS relative to a new coal-fired unit without CCS are $0.46 to $22 per MWh (2011$). These incremental benefits will be referenced in the analyses presented in subsequent sections.   

Table 5-3.	2022 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Compliant Coal-	Fired Generation with CCS meeting 1,400 lbs/MWh Relative to New Non-Compliant Coal-Fired Generation 
                                       
                                     SCPC 
                                     IGCC 
CO2-Related Benefits using SC-CO2
                                       
                                       
5% Discount Rate
                                     $1.6
                                     $0.46
3% Discount Rate
                                     $5.4
                                     $1.6
2.5% Discount Rate
                                     $8.2
                                     $2.3
3% Discount Rate (95th percentile)
                                      $17
                                     $4.7
PM2.5-Related Benefits from SO2 and NOX Reductions
   3% discount rate
                                       
                                       
Krewski et al. (2009)
                                     $2.2
                                       *
Lepeule et al. (2012)
                                     $4.9
                                       *
   7% discount rate
                                       
                                       
Krewski et al. (2009)
                                     $2.0
                                       *
Lepeule et al. (2012)
                                     $4.5
                                       *
Combined CO2-Related and PM2.5-Related Benefits 

               Discount Rate Applied to PM2.5-Related Benefits 
                   (range based on adult mortality function)
SCC Discount Rate
                                      3%
                                      7%
                                       
                                       
5% Discount Rate
                                                                   $3.8 to $6.5
                                                                   $3.6 to $6.1
                                     $0.46
3% Discount Rate
                                                                    $7.6 to $10
                                                                    $7.4 to $10
                                     $1.6
2.5% Discount Rate
                                                                     $10 to $13
                                                                     $10 to $13
                                     $2.3
3% Discount Rate (95th percentile)
                                                                     $19 to $22
                                                                     $19 to $21
                                     $4.7
*IGCC with CCS results in a small SO2 emissions increase when compared to IGCC without CCS. As a result, there would be a negligible health disbenefit (one cent or less per MWh) associated with these emissions increases. 
Notes: Benefits are estimated for a 2022 analysis year. The range of benefits within each SC-CO2 value and discount rate for PM2.5-related benefits pairing reflects the use of two core estimates of PM2.5-related premature mortality. 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, even in its absence. In this section, we consider the potential impacts of the regulation if key assumptions regarding natural gas prices were to change during the analysis period. The analysis in this section indicates that in this scenario, the standards for new sources would result in costs to the illustrative investor, but would also lead to climate and human health benefits, and is highly likely to provide net benefits to society as a whole.  
Furthermore, this section demonstrates that local fuel prices must be significantly different than regional differences already captured in IPM and EIA's modeling for private investment costs to favor a new uncontrolled coal-fired unit relative to a new NGCC unit serving a particular load.  Section 4.5.4 describes how regional conditions and other factors may influence the LCOE comparison, and how these regional differences are already captured in the electricity sector modeling in support of this rule. The 64 different regions in IPM are reflect the administrative structure of regional transmission organizations (RTOs) and independent system operators (ISOs). However, within those regions there may be local conditions which differ meaningfully from the broader regional conditions. The analysis in this section examines how substantially divergent those local conditions must be from representative conditions for non-compliant coal generation to be the technology of choice to serve demand.  
The starting point for this analysis is the illustrative comparison (presented in Section 4.5) of the relative levelized cost of electricity (LCOE) of representative new coal-fired SCPC and IGCC EGUs and representative NGCC units. This comparison demonstrates a significant difference in the LCOE between the coal-fired and natural gas-fired generating technologies. The estimated LCOE for a representative NGCC unit is roughly $32 and $37 per MWh less than 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 non-negligible costs or quantified benefits under current and likely future market conditions, as discussed in Chapter 4. The emissions associated with these technologies, and the benefits in terms of reduced damages of constructing and operating the illustrative NGCC unit in lieu of the illustrative non-compliant coal unit, are reported in the previous section.
To supplement this determination, this section presents an analysis of three relevant ranges within the distribution of future natural gas prices that can be classified as likely gas prices, unexpectedly high natural gas prices, and unprecedented natural gas prices. Because the cost of natural gas is a significant share of the LCOE for NGCC units, we evaluate how changes in natural gas prices affect differences in the relative private and social costs of new technologies. We identify the natural gas price when the private costs, which are inclusive of the CUA, suggest that a new non-compliant coal may be adopted by an investor in lieu of a new NGCC unit. We then compare the social costs of these technologies, which is inclusive of both the private costs of these technologies and the damages from these technologies but exclusive of the CUA, at this natural gas price. We then identify the natural gas price when the social cost of investing in the illustrative new non-compliant coal unit is plausibly less than the social cost of the new illustrative NGCC unit.  
In general, this analysis shows that there would likely be a net social benefit, even under scenarios with higher than expected gas prices, if new compliant units were built in place of new non-compliant coal-fired units as a result of this rule. 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 the social benefits of these finalized standards may yield social net benefits as there may be other technologies that would have a lower social cost than a new non-compliant coal unit. 
5.4.1	Likely Natural Gas Prices 
As shown in Chapter 4, it is only when natural gas prices exceed $10/MMBtu on a levelized basis (in 2011 dollars) that the representative new coal-fired SCPC unit without CCS likely becomes competitive in terms of its cost of electricity produced. None of the sensitivities presented in Chapter 4 or the AEO2014 scenarios approach this natural gas price level on either a forward looking 20-year levelized price basis or on an average annual price basis at any point during the analysis period. 
5.4.2	Unexpectedly High Natural Gas Prices 
At natural gas prices above $10/mmBtu, the private levelized cost of electricity for a representative new coal-fired SCPC unit falls below that of a new NGCC unit.  Therefore, in the event of such unexpectedly high levelized fuel prices, some new coal-fired SCPC units might be constructed in the absence of this proposed rulemaking, provided that coal price do not rise at the same time, there is sufficient demand for electricity, and new non-compliant coal-fired SCPC units are competitive with other new and existing generating technologies other than NGCC units. In this scenario, there would be some compliance costs if a new NGCC unit or a compliant coal-fired unit were built as a result of the new fossil steam standard. However, generation from a new NGCC unit would also have incremental environmental and health benefits as it has less CO2 and PM2.5 (as a result of SO2 and NOx emissions) emissions than generation from a new non-compliant coal-fired SCPC unit (as would a coal-fired unit that is compliant with the new standards; see Section 5.5).
For levelized natural gas prices of $10/mmBtu and somewhat higher, the resulting emission reduction benefits of building an NGCC unit, in place of a coal-fired SCPC unit, will outweigh the costs of constructing and operating an NGCC unit in lieu of a coal-fired SCPC unit. This observation indicates that the standard for new fossil steam sources would yield net benefits in the analysis year. For example, at a levelized gas price of $11/MMBtu, the illustrative NGCC unit would generate electricity for approximately $13/MWh more than the coal-fired SCPC unit on a levelized basis, and result in incremental benefits from emissions reductions of $20 to $97/MWh (see analysis of 2022 relative benefits of NGCC: Table 5-2). The net benefit of this scenario would be $7.1 to $84/MWh. 
For context, a natural gas price of $10/MMBtu (in 2011 dollars) is higher than any average annual natural gas price faced by the electric power sector since at least 1996, when the EIA historic data series begins. The continued development of unconventional natural gas resources in the U.S. suggests that gas prices may actually tend to be towards the lower end of the historical range. In addition, the highest projected average levelized natural gas price during the analysis period of any of the AEO2014 scenarios cited in Chapter 4 is $8.45MMBtu (2012 $), which occurs in the Low Oil and Gas Resource scenario (see Table 4.6). As discussed in Chapter 4, none of the EIA sensitivity cases (which account for future fuel prices for both gas and coal) show scenarios where non-compliant coal-fired units become more economic than NGCC units in the period of analysis.
5.4.3	Unprecedented Natural Gas Prices 
At extremely high natural gas prices, the LCOE for a non-compliant coal-fired SCPC unit could be sufficiently lower than the cost of a new NGCC unit, such that the net benefit of the standard in a given year could be negative (i.e., a net cost), at least under some ranges of benefit estimates. For example, at a levelized gas price of $14/MMBtu, the illustrative NGCC unit would generate electricity for roughly $33/MWh more than the illustrative coal-fired SCPC, respectively, but result in social benefits from lower emissions of $20 to $97/MWh relative to the coal-fired SCPC unit (see analysis of 2022 relative benefits of NGCC: Table 5-2). If the illustrative NGCC unit were built in lieu of the illustrative SCPC as a result of the new fossil steam standard, the impact would range from a net social cost of $13/MWh to a net social benefit of $64/MWh relative to the illustrative SCPC.
As noted in the previous subsection, natural gas prices at these levels would be unprecedented. As a result, the EPA believes that the probability of levelized natural gas prices reaching levels at which this standard would generate net social costs under some ranges of benefit estimates is extremely small.  
We emphasize that differences in generating costs, plant design, local factors, and the relative differences between fuels costs can all have major impacts on the precise circumstances under which this standard would be projected to have no costs, net social benefits or net social costs. However, based on historical and expected gas prices, we project that the new fossil steam standard is most likely to have negligible costs, and, if it does result in costs, it is also likely to produce positive, although modest, net social benefits. Furthermore, these results, complemented by the analysis in Chapter 4 on regional differences in levelized costs of these technologies, indicate that local differences in the cost of these technologies must be significantly different from representative conditions for non-compliant coal generation to be the technology of choice to serve demand. The probability that this proposed standard would result in net social costs is exceedingly low.
5.5	Illustrative Analysis  -  Benefits and Costs of Uncontrolled Coal and Compliant Coal 
As discussed in detail in the previous section and in Chapter 4, it is unlikely that a new non-compliant coal-fired unit would be constructed in the analysis period. The power sector continues to move away from the construction of coal-fired power plants in favor of natural gas-fired power plants due, in part, to the significant LCOE differential explored in the previous section. Even so, it is possible that a limited number of conventional coal-fired power plants might be constructed in the analysis period. In these circumstances, EPA believes that any need for CCS could be accommodated and would not, based on the incremental cost of the CCS portion of the new unit, preclude the construction of the new coal-fired facility. 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, who otherwise wanted to construct a new non-compliant coal unit, chose to instead construct a new compliant coal-fired unit in response to the new fossil steam standard. In this scenario, this decision would result in some costs in order to build a unit with partial CCS or co-fire with natural gas.  However, there would also be climate and other benefits resulting from reductions in CO2, SO2, and NOX emissions. 
For each coal-fired generation type, SCPC and IGCC, the EPA analyzed the cost and 2022 emission impacts of meeting the new source standards. While partial CCS is considered the best system of emission reductions (BSER) for these units, it would also be possible to meet the standard without CCS through co-firing natural gas, which is also analyzed. Consistent with the LCOE estimates provided in Table 4-5 (in Chapter 4), the partial capture CCS and cofiring natural gas scenarios achieve the proposed emissions rate of 1,400 lb CO2/MWh gross output.  
The cost of CCS used to support this rule assumes that the geologic sequestration of CO2 will be in deep saline formations and accounts for the cost of doing so, but the EPA also recognizes the potential for sequestering CO2 for EOR and allows a source to provide CO2 for EOR (as well as enhanced gas recovery) as a compliance option. 
EOR refers to the injection of gases and/or fluids into a reservoir to increase oil production efficiency. CO2-EOR has been successfully used at many production fields throughout the United States. The oil and natural gas industry in the United States has over 40 years of experience in injection and monitoring of CO2. This experience provides a strong foundation for the technologies used in the deployment of CCS on coal-fired electric generating units.  Although deep saline formations provide the most CO2 storage opportunity (2,102 to 20,043 billion metric tons), oil and gas reservoirs are estimated to have 226 billion metric tons of CO2 storage resource.
    The use of CO2 for EOR can significantly lower the cost of implementing CCS. The opportunity to sell the captured CO2 rather than paying directly for its long-term storage, greatly improves the economics of the new generating unit. According to the International Energy Agency, of the CCS projects in operation (e.g., Boundary Dam Energy Project, Saskatchewan, Canada) or under construction or at an advanced stage of planning, 70% intend to use captured CO2 to improve recovery of oil in mature fields, including Mississippi Power's Kemper County Energy Facility, NRG Energy's W.A. Parish Petra Nova CCS Project, Summit Power's Texas Clean Energy Project, and the Hydrogen Energy California Project. The Texas Clean Energy project is planning to capture 90% of the CO2 and sell it for EOR.
Therefore, in the near term, new coal-fired EGUs with CCS may be located in areas amenable to using the captured CO2 in EOR operations because these formations have been previously well characterized for hydrocarbon recovery, likely already have suitable infrastructure (e.g., wells, pipelines, etc.), and have an associated economic benefit of increasing oil well productivity.  Furthermore, EPA believes the opportunity to engage in EOR opportunities is not significantly limited by the location of those opportunities or the current CO2 pipeline infrastructure (12 states currently have existing or under construction CO2 pipelines).  Provision of electric power does not require coal-fired facilities to be co-located with the demand it is intended to serve. Please refer to Chapter 2 for a more detailed discussion of EOR, including its geographic availability, expected future growth, and overall impact on the economics of CCS.
There are two EOR opportunities evaluated in this section  -  `High' and `Low.'  The high EOR opportunity assumes a CO2 sale price of $40 per metric ton; the low EOR opportunity assumes a CO2 sale price of $20 per metric ton   based on assumptions used by NETL in evaluating potential EOR opportunities.  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 the transportation, storage, and monitoring (TSM) of CO2 are included in this analysis. For non-EOR applications, TSM costs of ~$5-$15 dollars per ton of CO2 are applied based on the level of capture.   
Figure 5-1 compares the LCOE for an illustrative uncontrolled coal to coal with partial CCS both with and without EOR. It also provides the LCOE of an illustrative uncontrolled coal unit to the cost of a controlled unit cofiring natural gas. With the exception of the LCOE costs accounting for EOR, these costs were provided in Table 4-5. We see in Figure 5-1 that if a limited number of non-compliant coal-fired power plants would have be constructed in the analysis period, that the adoption of CCS could be accommodated and would not, based on the incremental cost of the CCS portion of the new unit, preclude the construction of the new coal-fired facility. Furthermore, it shows that if it was not possible for a unit to provide CO2 for EOR, it may lower its costs by cofiring natural gas and still generate a substantial share of its production from coal. 

Figure 5-1.	Levelized Cost of Electricity, Uncontrolled Coal and Coal with Partial 			CCS (1,400 lbs/MWh gross).  2011$  
      Notes: 
      (1) EIA estimated LCOE under AEO 2014 assumptions for uncontrolled SCPC is $116 (2011$).  AEO 2014 does not provide LCOE estimates for IGCC, or for full or partial CCS capture technologies.
      (2) Uncontrolled SCPC requires NG cofiring to provide 43% of total heat input to achieve a 1,400 lbs/MMBtu CO2 emission rate.  Uncontrolled IGCC requires 6% NG cofiring.
      (3) The partial control alternatives that achieve 1,400 #/MMBtu using carbon capture include the cost of transportion, storage and monitoring (TS&M).

Tables 5-4 and 5-5 show the costs and 2022 net benefits per MWh of each of adopting compliant coal in lieu of non-compliant coal. The EPA estimates of the benefits associated with avoided CO2, SO2, and NOX emissions using the methods described in Table 5-3. The cost estimates used are reported in Figure 5-1. While the levelized cost comparison in Figure 5-1 focuses on the cost to the individual investor, the comparison of the uncontrolled coal unit to a scenario where the source sells CO2 for EOR includes the cost of TSM for CCS when monetizing the net benefits of this approach. This is because TSM will require real resources regardless of who pays for it.  As before, it is important to note that these comparisons omit additional benefits that may be associated with the abatement of greenhouse gas emissions and other benefits associated with reducing SO2 and NOX emissions.
Table 5-4.	Illustrative 2022 Social Costs and Benefits for Compliant SCPC with Partial Capture or with Co-Firing Natural Gas Relative to Non-Compliant SCPC (per MWh 2011$)
 
                                                                    Partial CCS
                                                          Co-Firing Natural Gas
Additional LCOE [a]
                                                                            $16
                                                                            $11
Revenue from EOR (Low - High EOR)
                                                                   $3.4 to $6.7
                                                                              *
Additional LCOE, net of EOR
                                                                    $8.9 to $12
                                                                              *
Value of Monetized Benefits for 2022 Emissions

SCC 5% with Krewski 3% to SCC 3% (95th) with Lepeule 3%[b]
                                                                    $3.8 to $22
                                                                    $1.6 to $19
Net Monetized Benefits

Without EOR Revenue
                                                                   -$12 to $5.9
                                                                  -$9.6 to $7.6
With EOR Revenue[c]
                                                                   -$8.4 to $13
                                                                              *
[a] For this comparison the LCOE of the representative SCPC without CCS does not include 3% CUA. 
b Table 5-3 reports these values for the comparison to the compliant unit with partial CCS. Benefits are estimated for a 2022 analysis year. Values shown are calculated using different discount rates.  Four estimates of the SC-CO2 in the year 2022 were used:  $14, $47, and $70 per metric ton (average SC-CO2 at discount rates of 5, 3, and 2.5 percent, respectively) and $140 per metric ton (95th percentile SC-CO2 at 3 percent).  The average SC-CO2 at 5 percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate. See section 3.2 for complete discussion of these estimates. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022. 
C The cost of TSM is not included in this comparison even though this is an opportunity cost borne by society. 

Table 5-5.	Illustrative 2022 Social Costs and Benefits for Compliant IGCC with Partial Capture or with Co-Firing Natural Gas Relative to Non-Compliant IGCC (per MWh 2011$)
 
                                  Partial CCS
                             Co-Firing Natural Gas
Additional LCOE[a]
                                                                           $3.5
                                                                           $1.7
Revenue from EOR (Low - High EOR)
                                                                 $0.39 to $0.78
                                                                              *
Additional LCOE, net of EOR
                                                                   $2.7 to $3.1
                                                                              *
Value of Monetized Benefits for 2022 Emissions

SCC 5% with Krewski 3% to SCC 3% (95th) with Lepeule 3%[b]
                                                                  $0.45 to $4.7
                                                                  $0.27 to $2.8
Net Monetized Benefits 

Without EOR Revenue
                                                                    -$3 to $1.3
                                                                   $1.4 to $1.1
With EOR Revenue
                                                                  -$2.6 to $2.1
                                                                              *
[a] For this comparison the LCOE of the representative IGCC without CCS does not include 3% CUA.
[b] Table 5-3 reports these values for the comparison to the compliant unit with partial CCS. Benefits are estimated for a 2022 analysis year. Values shown are calculated using different discount rates.  Four estimates of the SC-CO2 in the year 2022 were used:  $14, $47, and $70 per metric ton (average SC-CO2 at discount rates of 5, 3, and 2.5 percent, respectively) and $142 per metric ton (95th percentile SC-CO2 at 3 percent).  The average SC-CO2 at 5 percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate. See Section 3.2 for complete discussion of these estimates. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022.
C The cost of TSM is not included in this comparison even though this is an opportunity cost borne by society. 
5.6	Impact of the New Source Standards Considering the Cost of Lost Option Value
Consistent with EPA's practice in evaluating the benefits and costs of significant rules, Chapter 4 uses detailed electricity sector modeling of expected market conditions to demonstrate that new EGUs expected to be built in the period of analysis would be in compliance with this proposed rule, even in the absence of this rule. As a result, the quantifiable benefits and costs of the standards, as measured in those deterministic settings, are expected to be negligible in the analysis period. That analysis is extended in this chapter to acknowledge unexpected conditions that could occur during the period of analysis in which the construction of a new non-compliant EGUs would be desirable from the perspective of an individual firm and evaluates the social costs and benefits of constructing a generating technology that complies with the proposed rule instead. This section further extends, and draws on, those analyses to discuss, qualitatively, the potential social benefits and costs of the standards from the perspective of an uncertain future. 
Firms operating in the power sector have a set of options available to address increases in electricity demand, such as increasing the utilization of existing generating capacity, 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 natural gas combustion turbines forecast in the baseline, which meet the applicability criteria, will already meet the standards this discussion focuses on new fossil steam EGUs. As discussed in Chapter 4, it is highly unlikely that over the analysis period there will be enough expansion in relative fuel prices (e.g., natural gas prices relative to coal) to make a typical new fossil steam EGU cost competitive with available substitutes (e.g., NGCC, investing in energy efficiency program). Even in the unlikely event that this occurs, the incremental cost of constructing a compliant fossil steam EGU with partial CCS or an alternative compliance pathway will represent an upper bound on the costs to the firm due to the availability of substitute generation sources which might be able to provide a similar service at a lower cost. Given both of these reasons, the low likelihood of the restricted options being exercised in the baseline and availability of cost effective substitutes, on average the lost option value for firms is likely to be minimal. 
Furthermore, as shown in the preceding sections, even when conditions arise where it is known with certainty that an outlying firm would find it most profitable to invest in a new non-compliant unit EGU over available alternatives in the baseline, the social benefits of restricting the choice set likely outweighs the costs to the firm. Therefore it will also be the case that expected social benefits from preventing new EGUs with an emissions rate above their respective standards, will likely outweigh the lost option value. 
A similar perspective may be applied to assessing the social costs of this rule. There are at least two notable differences when assessing the lost option value from society's perspective relative to the firm's perspective. First, from society's perspective the available substitution possibilities are greater as they are not bound by the conditions of a single firm but activities that may be pursued by electricity producers and consumers at large. Second, the benefits of adding a single new EGU for the purpose of diversifying the generation fleet across fuels to hedge against uncertainty in fuel markets, will likely be lower for society at large than for a single firm with a more limited generating fleet.  Both of these differences suggest that the lost option value from a social perspective is lower than what is already likely to a minimal lost option value for the average firm. 
It is difficult to precisely estimate the lost option value associated with this final rule given the numerous sources of uncertainty that influence investment decisions in the electricity sector and the existing modeling tools. However, the analysis reported in this chapter and the previous chapter has considered important variables that influence investment decisions in the electricity sector and found that across a wide range of potential outcomes this rule would have no quantifiable costs. Furthermore, considering the additional analysis in this chapter and the discussion above, the cost of the lost option value of the rule is concluded to be small. Additionally, if conditions arise that would have led to the construction of non-compliant EGUs absent the proposed rule, the quantifiable monetized social benefits of limiting the construction of those units likely exceeds the cost (even though not all social benefits are captured). However, as discussed throughout this RIA, when considering the most likely outcomes, the new source standards are anticipated to yield no monetized benefits and impose negligible costs over the analysis period.  
5.8	References
Dixit, Avinash and Pindyck, Robert. Investment Under Uncertainty. 1994. Princeton University Press.
Joskow, P.L. 2010. Comparing the Cost of Intermittent and Dispatchable Electricity Generating Technologies. MIT Center for Energy and Environmental Policy Research Working Paper 10-013.
Joskow, P.L. 2011. Comparing the Costs of Intermittent and Dispatchable Electricity Generating Technologies. American Economic Review. vol. 101:238-41.
Krewski, D., R.T. Burnett, M.S. Goldbert, K. Hoover, J. Siemiatycki, M. Jerrett, M. Abrahamowicz, and W.H. White. 2009. "Reanalysis of the Harvard Six Cities Study and the American Cancer Society Study of Particulate Air Pollution and Mortality." Special Report to the Health Effects Institute. Cambridge, MA. July.
Lepeule, J., F. Laden, D. Dockery, and J. Schwartz. 2012. "Chronic Exposure to Fine Particles and Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009." Environ Health Perspect. In press. Available at: http://dx.doi.org/10.1289/ehp.1104660.
Muller, N.Z., R. Mendelsohn, and W. Nordhaus. 2011. Environmental Accounting for Pollution in the United States Economy. American Economic Review. 101:1649-1675.
National Energy Technology Laboratory (NETL). Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture. Revised Sept. 16, 2013. Available online at: http://www.netl.doe.gov/energy-analyses/pubs/Gerdes-08022011.pdf. 
National Research of Council (NRC). 2009. Hidden Costs of Energy: Unpriced Consequences of Energy Production and Use. National Academies Press: Washington, D.C.
Trigeorgis, Lenos. Real Options: Managerial Flexibility and Strategy in Resource Allocation. 1996. The MIT Press.
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010. Available online at: http://www.eia.gov/oiaf/archive/aeo10/index.html. 
U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available online at: http://www.eia.gov/forecasts/aeo/.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.
 Chapter 6 
 Modified and Reconstructed Source Impacts

6.1	Introduction
In addition to the standards for new sources analyzed in Chapter 4 and Chapter 5, this action also sets standards under Clean Air Act Section 111(b) for units that modify or reconstruct. For the reasons discussed in this chapter, the EPA also believes that the standards for modified and reconstructed fossil fuel-fired EGUs will result in minimal compliance costs, because we expect few modified or reconstructed EGUs in the period of analysis (through 2022).
6.2	Reconstructed Sources
The new source performance standard (NSPS) provisions (40 CFR part 60, subpart A) define a "reconstruction" as the replacement of components of an existing facility to an extent that (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and (2) it is technologically and economically feasible to meet the applicable standards. Historically, we are only aware of one EGU that has notified the EPA that it has reconstructed under the reconstruction provision of section 111(b). As a result, we anticipate that few EGUs will undertake reconstruction in the period of analysis. For this reason, the standards will not result in any significant emission reductions, costs, or quantified benefits in the period of analysis. Likewise, the Agency does not anticipate any impacts on the price of electricity or energy supply. The rule is not expected to raise any resource adequacy concerns, since reserve margins will not be impacted and the rule does not impose any additional requirements on existing facilities not triggering the reconstruction provision. There are no macroeconomic or employment impacts expected as a result of these standards.
Due to the extremely limited data available on reconstructions, it is not possible to conduct a representative illustrative analysis of what costs and benefits might result from this rule in the unlikely case that a unit were to reconstruct.
6.3	Modified Sources
Historically, few EGUs have notified the EPA that they have modified under the modification provision of section 111(b). The EPA's current regulations define an NSPS "modification" as a physical or operational change that increases the source's maximum achievable hourly rate of emissions, but specifically exempt from that definition projects that entail the installation of pollution control equipment or systems. 
The EPA expects that most of the actions EGUs are likely to take in the foreseeable future that could be classified as "modifications" would qualify as pollution control projects. In many cases, those projects are likely to involve the installation of add-on control equipment needed to meet CAA requirements for criteria and air toxics air pollutants. Any associated CO2 emissions increases would likely be small and would occur as a chemical byproduct of the operation of the control equipment. In other cases, those projects would involve equipment changes to improve fuel efficiency to meet state requirements for implementation of the CAA section 111(d) rulemaking for existing sources and would have the effect of increasing a source's maximum achievable hourly emission rate (lb CO2/hr), even while decreasing its actual output based emission rate (lb CO2/MWh). Because all of these actions would be treated as pollution control projects under the EPA's current NSPS regulations, they would be specifically exempted from the definition of modification. 
Given the limited information that we have about past modifications, the EPA has concluded that it lacks sufficient information to establish standards of performance for all types of modifications at steam generating units at this time.  Instead, the EPA has determined that it is appropriate to establish standards of performance at this time for large-scale modifications of steam generating units, such as major facility upgrades involving the reconstruction or replacement of steam turbines and other equipment upgrades that result in substantial increases in a unit's potential hourly CO2 emissions rate. The EPA does not have sufficient information at this time to predict the full array of actions that existing steam generating units may undertake, including those in response to applicable requirements under an approved CAA section 111(d) plan. Additionally, it is not possible to predict which, if any, of these actions may result in increases in potential CO2 hourly emissions. Nevertheless, EPA expects that, to the extent actions are undertaken by existing steam generating units, the magnitude of the increases in potential hourly CO2 emissions associated with the vast majority of such changes would generally be small and therefore would generally not be subject to the standards of performance for modified steam generating units finalized in this action.
Similar to the case of the steam generating units, the EPA also expect few existing stationary combustion turbines to modify during the period of analysis and become subject to the standards of performance the EPA is finalizing for such units in this action. Therefore, the EPA expects the standards associated with modified stationary combustion turbines to result in minimal, if any, compliance costs during the period of analysis.
Based on this information, we anticipate that few EGUs will take actions that would be considered modifications and subject to the standards of performance finalized in this action during the period of analysis. For this reason, the standards will result in minimal emission reductions, costs, or quantified benefits in the period of analysis. Likewise, the Agency does not anticipate any impacts on the price of electricity or energy supplies. This rule is not expected to raise any resource adequacy concerns, since reserve margins will not be impacted and the rule does not impose any additional requirements on existing facilities not triggering the modification provision. There are no macroeconomic or employment impacts expected as a result of these standards.
Due to the limited data available on past modifications and the diversity of existing units that could potentially modify, it is not possible to conduct a representative illustrative analysis of what costs and benefits might result from this rule in the unlikely case that a unit were to take an action that would be classified as a modification.
 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.
The EPA also believes that the standards for modified and reconstructed fossil fuel-fired EGUs will result in minimal compliance costs, because, as previously stated, the EPA expects few modified or reconstructed EGUs in the period of analysis (through 2022). In Chapter 6, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources.
7.2 	Paperwork Reduction Act (PRA)
      The information collection activities in this final action have been submitted for approval to OMB under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number [XX]. Separate ICR documents were prepared 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 natural gas-fired stationary combustion turbines) beyond what those sources would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060-0626 and 2060-0629, respectively. Apart from certain reporting costs based on requirements in the NSPS General Provisions (40 CFR part 60, subpart A), which are mandatory for all owners/operators subject to CAA section 111 national emission standards, there are no new information collection costs, as the information required by the standards for newly constructed EGUs is already collected and reported by other regulatory programs. 
      The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of the rule because of existing and expected market conditions. The EPA does not project any newly constructed coal-fired steam generating units that commenced construction after proposal (January 8, 2014) to commence operation over the 3-year period covered by this ICR. We estimate that 17 affected newly constructed natural gas-fired stationary combustion turbines will commence operation during that time period. As a result of this final action, owners or operators of those newly constructed units will be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months.
7.2.2	Modified and Reconstructed EGUs
      This final action is not expected to impose an information collection burden under the provisions of the PRA on owners and operators of affected modified and reconstructed fossil fuel-fired EGUs (steam generating units and natural gas-fired stationary combustion turbines). As previously stated, the EPA expects few modified or reconstructed EGUs in the period of analysis. Specifically, the EPA believes it unlikely that fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines will take actions that would constitute modifications or reconstructions as defined under the EPA's NSPS regulations. Accordingly, the standards for modified and reconstructed EGUs are not anticipated to impose any information collection burden over the 3-year period covered by this ICR. We have estimated, however, the information collection burden that would be imposed on an affected EGU if it was modified or reconstructed.
      Although not anticipated, if an EGU were to modify or reconstruct, this final action would impose minimal information collection burden on those affected sources beyond what they would already be subject to under the authorities of CAA 40 CFR parts 75 and 98. As described above, the OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations. Apart from certain reporting costs, which are mandatory for all owners/operators subject to CAA section 111 national emission standards, there would be no new information collection costs, as the information required by the final rule is already collected and reported by other regulatory programs.
      As stated above, although the EPA expects few sources will trigger either the NSPS modification or reconstruction provisions, if an EGU were to modify or reconstruct during the 3-year period covered by this ICR, the owner or operator of the EGU will be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months. The annual reporting burden for such a unit is estimated to be $2,665 and 32 labor hours. There are no annualized capital costs or O&M costs associated with burden for modified or reconstructed EGUs. 
7.2.3	Information Collection Burden
      The annual information collection burden for newly constructed, modified, and reconstructed EGUs consists only of reporting burden as explained above. The annual reporting burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $32,886 and 395 labor hours. There are no annualized capital costs or O&M costs associated with burden for newly constructed EGUs. Average burden hours per response are estimated to be 8 hours. The total number of respondents over the 3-year ICR period is estimated to be 37.
7.3 	Regulatory Flexibility Act (RFA)
      EPA certifies that this final action will not have a significant economic impact on a substantial number of small entities under the RFA. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden or otherwise has a positive economic effect on the small entities subject to the rule.
7.3.1	Newly constructed EGUs
	The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built. We expect that any newly constructed natural gas-fired stationary combustion turbines will meet the standards. We do not include an analysis of the illustrative impacts on small entities that may result from implementation of the final rule because we anticipate negligible compliance costs over a range of likely sensitivity conditions as a result of the standards for newly constructed EGUs. Thus the cost-to-sales ratios for any affected small entity would be zero costs as compared to annual sales revenue for the entity. Accordingly, there are no anticipated economic impacts as a result of the standards for newly constructed EGUs. We have therefore concluded that this final action will have no net regulatory burden for all directly regulated small entities.
7.3.2 	Modified and Reconstructed EGUs
      The EPA expects few modified fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. An NSPS modification is defined as a physical or operational change that increases the source's maximum achievable hourly rate of emissions. The EPA does not believe that there are likely to be EGUs that will take actions that would constitute modifications as defined under the EPA's NSPS regulations.
	In addition, the EPA expects few reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. Reconstruction occurs when a single project replaces components or equipment in an existing facility and exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility.
	In Chapter 6, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources. However, we do not anticipate that the rule would impose significant costs on those sources, including any that are owned by small entities.
7.4 	Unfunded Mandates Reform Act (UMRA)
    This final action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531 - 1538, and does not significantly or uniquely affect small governments.
    The EPA believes the final rule will have negligible compliance costs on owners and operators of newly constructed EGUs over a range of likely sensitivity conditions because electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly constructed natural gas-fired stationary combustion turbines will meet the standards.
    As previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. In Chapter 6, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources. However, we do not anticipate that the rule would impose significant costs on those sources.
We have therefore concluded that the standards for newly constructed, modified, and reconstructed EGUs do not impose enforceable duties on any state, local or tribal governments, or the private sector, that may result in expenditures by state, local and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. We have also concluded that this action does not have regulatory requirements that might significantly or uniquely affect small governments. The threshold amount established for determining whether regulatory requirements could significantly affect small governments is $100 million annually and, as stated above, we have concluded that the final action will not result in expenditures of $100 million or more in any one year. Specifically, the EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly constructed natural gas-fired stationary combustion turbines will meet the standards. Further, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis.
7.5 	Executive Order 13132, Federalism
      This final action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. In addition, as previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. We, therefore, anticipate that the final rule will impose minimal compliance costs.
7.6 	Executive Order 13175, Consultation and Coordination with Indian Tribal Governments
      This final action does not have tribal implications as specified in Executive Order 13175. The final rule will impose requirements on owners and operators of newly constructed, modified, and reconstructed EGUs. The EPA is aware of three facilities with coal-fired steam generating units, as well as one facility with natural gas-fired stationary combustion turbines, located in Indian Country, but is not aware of any EGUs owned or operated by tribal entities. We note that because the rule addresses CO2 emissions from newly constructed, modified, and reconstructed EGUs, it will affect existing EGUs such as those located at the four facilities in Indian Country only if those EGUs were to take actions constituting modifications or reconstructions as defined under the EPA's NSPS regulations. As previously stated, the EPA expects few modified or reconstructed EGUs in the period of analysis. Thus, the rule will neither impose substantial direct compliance costs on tribal governments nor preempt Tribal law. Accordingly, Executive Order 13175 does not apply to this action.
      Nevertheless, because the EPA is aware of Tribal interest in carbon pollution standards for the power sector and, consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA offered consultation with tribal officials during development of this rule. Prior to the April 13, 2012 proposal (77 FR 22392), the EPA sent consultation letters to the leaders of all federally recognized tribes. Although only newly constructed, modified, and reconstructed EGUs will be affected by this action, the EPA's consultation regarded planned actions for new and existing sources. The letters provided information regarding the EPA's development of NSPS and emission guidelines for EGUs and offered consultation. A consultation/outreach meeting was held on May 23, 2011, with the Forest County Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa Reservation, and the Leech Lake Band of Ojibwe. A description of that consultation is included in the preamble to the proposed standards for new EGUs (79 FR 1501, January 8, 2014).
      The EPA also offered consultation to the leaders of all federally recognized tribes after the proposed action for newly constructed EGUs was signed on September, 20, 2013. On November 1, 2013, the EPA sent letters to tribal leaders that provided information regarding the EPA's development of carbon pollution standards for new, modified, reconstructed and existing EGUs and offered consultation. No tribes requested consultation regarding the standards for newly constructed EGUs.
In addition to offering consultation, the EPA also conducted outreach to tribes during development of this rule. The EPA held a series of listening sessions prior to proposal of GHG standards for newly constructed EGUs. Tribes participated in a session on February 17, 2011, with the state agencies, as well as in a separate session with tribes on April 20, 2011. The EPA also held a series of listening sessions prior to proposal of GHG standards for modified and reconstructed EGUs and GHG emission guidelines for existing EGUs. Tribes participated in a session on September 9, 2013, together with the state agencies, as well as in a separate 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. The EPA believes that the CO2 emission reductions resulting from implementation of these final guidelines, as well as substantial ozone and PM2.5 emission reductions as a co-benefit, will further improve children's health. 
       The assessment literature cited in the EPA's 2009 Endangerment Finding concluded that certain populations and lifestages, including children, the elderly, and the poor, are most vulnerable to climate-related health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed findings regarding these groups' vulnerabilities and the projected impacts they may experience.
       These assessments describe how children's unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households.
       More detailed information on the impacts of climate change to human health and welfare is provided in Section II.A of the preamble. 
7.8 	Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
This final action is not a "significant energy action" because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. In addition, as previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. Thus, this action is not anticipated to have notable impacts on emissions, costs or energy supply decisions for the affected electric utility industry.
7.9 	National Technology Transfer and Advancement Act 
      This final action involves technical standards. The following voluntary consensus standards are used in the final rule: American Society for Testing and Materials (ASTM) Methods D388-12 (Standard Classification of Coals by Rank), D396-13c (Standard Specification for Fuel Oils), D975-14 (Standard Specification for Diesel Fuel Oils), D3699-13b (Standard Specification for Kerosene), D6751-12 (Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels), D7467-13 (Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20)), and American National Standards Institute (ANSI) Standard C12.20 (American National Standard for Electricity Meters - 0.2 and 0.5 Accuracy Classes). The rule also requires use of Appendices A, B, D, F and G to 40 CFR part 75; these Appendices contain standards that have already been reviewed under the NTTAA. 
7.10	Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies and activities on minority populations and low-income populations in the U.S. The EPA defines environmental justice as the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. The EPA has this goal for all communities and persons across this Nation. It will be achieved when everyone enjoys the same degree of protection from environmental and health hazards and equal access to the decision-making process to have a healthy environment in which to live, learn, and work.
Leading up to this rulemaking the EPA summarized the public health and welfare effects of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment Finding, the Administrator considered climate change risks to minority or low-income populations, finding that certain parts of the population may be especially vulnerable based on their circumstances. These include the poor, the elderly, the very young, those already in poor health, the disabled, those living alone, and/or indigenous populations dependent on one or a few resources. See Sections F and G, above, where EPA discusses Consultation and Coordination with Tribal Governments and Protection of Children. The Administrator placed weight on the fact that certain groups, including children, the elderly, and the poor, are most vulnerable to climate-related health effects.
Strong scientific evidence that the potential impacts of climate change raise environmental justice issues is found in the major assessment reports by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies, summarized in the record for the Endangerment Finding. Their conclusions include that poor communities can be especially vulnerable to climate change impacts because they tend to have more limited adaptive capacities and are more dependent on climate-sensitive resources such as local water and food supplies. In addition, Native American tribal communities possess unique vulnerabilities to climate change, particularly those on established reservations that are restricted to reservation boundaries and therefore have limited relocation options. Tribal communities whose health, economic well-being, and cultural traditions depend upon the natural environment will likely be affected by the degradation of ecosystem goods and services associated with climate change. 
Southwest native cultures are especially vulnerable to water quality and availability impacts. Native Alaskan communities are likely to experience disruptive impacts, including coastal erosion and shifts in the range or abundance of wild species crucial to their livelihoods and well-being. The most recent assessments continue to strengthen scientific understanding of climate change risks to minority and low-income populations in the United States. The new assessment literature provides more detailed findings regarding these populations' vulnerabilities and projected impacts they may experience. In addition, the most recent assessment literature provides new information on how some communities of color may be uniquely vulnerable to climate change health impacts in the United States. These studies find that certain climate change related impacts -- including heat waves, degraded air quality, and extreme weather events -- have disproportionate effects on low-income and some communities of color, raising environmental justice concerns. Existing health disparities and other inequities in these communities increase their vulnerability to the health effects of climate change. In addition, the studies also find that climate change poses particular threats to health, wellbeing, and ways of life of indigenous peoples in the United States.
As the scientific literature presented above and in the Endangerment Finding illustrates, low income communities and communities of color are especially vulnerable to the health and other adverse impacts of climate change.
The EPA believes the human health or environmental risk addressed by this final action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations. The final rule limits GHG emissions from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units and natural gas-fired stationary combustion turbines by establishing national emission standards for CO2.
The EPA has determined that the final rule will not result in disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because the rule is not anticipated to notably affect the level of protection provided to human health or the environment. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units and natural 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 modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. This final rule will ensure that, to whatever extent there are newly constructed, modified, and reconstructed EGUs, they will use the best performing technologies to limit emissions of CO2.
7.11	Congressional Review Act (CRA)
This final action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is not a "major rule" as defined by 5 U.S.C. 804(2).