Regulatory Impact Analysis for the Final Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units

                                                               EPA-452/R-15-005
                                                                    August 2015

Regulatory Impact Analysis for the Final Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units

                     U.S. Environmental Protection Agency
                 Office of Air Quality Planning and Standards
                   Health and Environmental Impacts Division
                          Research Triangle Park, NC

                              CONTACT INFORMATION
      This document has been prepared by staff from the Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency. Questions related to this document should be addressed to Amanda Curry Brown, U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina 27711 (email: CurryBrown.Amanda@epa.gov).

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

             EO 12866_111(b) New-Mods 2060-AQ91 RIA Final_07312015

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

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

1. 1,800 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h.
                                      OR

2. 2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Reconstructed Fossil Fuel-Fired Steam Generating Units
           Most efficient generating technology at the affected EGU.
1. 1,800 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h.
                                      OR

2. 2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Newly Constructed and Reconstructed Natural Gas-Fired Stationary Combustion Turbines
Efficient NGCC technology for natural gas-fired base load units and clean fuels for non-base load and multi-fuel-fired units.
   1.    1,000 lb CO2/MWh-gross or 1,030 lb CO2/MWh-net for base load natural gas-fired units.

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

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

1. 1,800 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h.
                                      OR

2. 2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Reconstructed Fossil Fuel-Fired Steam Generating Units
           Most efficient generating technology at the affected EGU.
1. 1,800 lb CO2/MWh-gross for sources with heat input > 2,000 MMBtu/h.
                                      OR

2. 2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Newly Constructed and Reconstructed Natural Gas-Fired Stationary Combustion Turbines
Efficient NGCC technology for natural gas-fired base load units and clean fuels for non-base load and multi-fuel-fired units.
   1.    1,000 lb CO2/MWh-gross or 1,030 lb CO2/MWh-net for base load natural gas-fired units.
   2.    120 lb CO2/MMBtu for non-base load natural gas-fired units.
   3.    120 to 160 lb CO2/MMBtu for multi-fuel-fired units.

1.2.5	Emission Reductions
As will be discussed in more detail in Chapter 4 of this RIA, the EPA anticipates that the EGU New, Modified, and Reconstructed Source GHG Standards will result in negligible changes in GHG emissions over the analysis period. The EPA expects that owners of new units will choose generation technologies that meet these standards in the baseline due to expected economic conditions in the marketplace. Based on historical precedent, the EPA anticipates few covered units will trigger the NSPS reconstruction or modification provisions in the period of analysis. As a result, we do not anticipate any significant costs or monetized benefits associated with this rule.
1.3	Organization of the Regulatory Impact Analysis
	This report presents the EPA's analysis of the potential benefits, costs, and other economic effects of the EGU New, Modified, and Reconstructed Source GHG Standards to fulfill the requirements of an RIA. This RIA includes the following chapters:
Chapter 2, Electric Power Sector Profile, describes the industry affected by the rule.
Chapter 3, Benefits of Reducing GHGs and Other Pollutants, describes the effects of emissions on climate and health and provides background information to support the benefits analysis.
Chapter 4, Costs, Economic, and Energy Impacts of the New Source Standards, describes impacts of the rule for new sources.
Chapter 5, Analysis of Illustrative Benefit-Cost Scenarios for New Sources, describes additional analyses examining potential impacts under a range of scenarios.
Chapter 6, Modified and Reconstructed Sources, describes the potential impacts of the standards for modified and reconstructed sources.
Chapter 7, Statutory and Executive Order Impact Analyses, describes the small business, unfunded mandates, paperwork reduction act, environmental justice, and other analyses conducted for the rule to meet statutory and Executive Order requirements.

 Chapter 2
Electric Power Sector Profile
2.1 	Introduction
This chapter discusses important aspects of the power sector that relate to the EGU New, Modified and Reconstructed Source GHG Standards, including the types of electricity generating units (EGUs) affected by the regulation, and provides background on the power sector and EGUs. In addition, this chapter provides some historical background on trends in the past decade in the power sector, as well as about existing U.S. Environmental Protection Agency (EPA) regulation of the power sector.
In the past decade there have been significant structural changes in the both the mix of generating capacity and in the share of electricity generation supplied by different types of generation. These changes are the result of multiple factors in the power sector, including normal replacements of older generating units with new units, changes in the electricity intensity of the U.S. economy, growth and regional changes in the U.S. population, technological improvements in electricity generation from both existing and new units, changes in the prices and availability of different fuels, and substantial growth in electricity generation by renewable and unconventional methods. Many of these trends will continue to contribute to the evolution of the power sector. The evolving economics of the power sector, in particular the increased natural gas supply and subsequent relatively low natural gas prices, have resulted in more gas being utilized as base load energy in addition to supplying electricity during peak load. This chapter presents data on the evolution of the power sector from 2002 through 2012. Projections of new capacity and the impact of this rule on these new sources are discussed in more detail in Chapter 4 of this Regulatory Impact Assessment (RIA).
2.2 	Power Sector Overview
The production and delivery of electricity to customers consists of three distinct segments: generation, transmission, and distribution.
2.2.1 	Generation
Electricity generation is the first process in the delivery of electricity to consumers. There are two important aspects of electricity generation: capacity and net generation. Generating capacity refers to the maximum amount of production from an EGU in a typical hour, typically measured in megawatts (MW) or gigawatts (1 GW = 1,000 MW).  Electricity generation refers to the amount of electricity actually produced by EGUs, measured in kilowatt-hours (kWh) or gigawatt-hours (GWh = 1 million kWh). In addition to producing electricity for sale to the grid, generators perform other services important to reliable electricity supply, such as providing backup generating capacity in the event of unexpected changes in demand or unexpected changes in the availability of other generators. Other important services provided by generators include facilitating the regulation of the voltage of supplied generation.
Individual EGUs are not used to generate electricity 100 percent of the time.  Individual EGUs are periodically not needed to meet the regular daily and seasonal fluctuations of electricity demand. Furthermore, EGUs relying on renewable resources such as wind, sunlight, and surface water to generate electricity are routinely constrained by the availability of adequate wind, sunlight, or water at different times of the day and season. Units are also unavailable during routine and unanticipated outages for maintenance.  These factors result in the mix of generating capacity types available (i.e., the share of capacity of each type of EGU) being substantially different than the mix of the share of total electricity produced by each type of EGU in a given season or year.
Most of the existing capacity generates electricity by creating heat to generate high pressure steam that is released to rotate turbines which, in turn, create electricity. Natural gas combined cycle (NGCC) units have two generating components operating from a single source of heat.  The first cycle is a gas-fired turbine, which generates electricity directly from the heat of burning natural gas. The second cycle reuses the waste heat from the first cycle to generate steam, which is then used to generate electricity from a steam turbine.  Other EGUs generate electricity by using water or wind to rotate turbine, and a variety of other methods also make up a small, but growing, share of the overall electricity supply. The generating capacity includes fossil-fuel-fired units, nuclear units, and hydroelectric and other renewable sources (see Table 2-1). Table 2-1 also shows the comparison between the generating capacity in 2002 and 2012.
In 2012, the power sector consisted of over 19,000 generating units with a total capacity of 1,168 GW, an increase of 188 GW (or 19 percent) from the capacity in 2002 (980 GW). The 188 GW increase consisted primarily of natural gas fired EGUs (134 GW) and wind generators (55 GW), with substantially smaller net increases and decreases in other types of generating units.

Table 2-1.         Existing Electricity Generating Capacity by Energy Source, 2002 and 2012

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

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

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

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

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

                                     2002
                                     2012
                          Change Between '02 and '12

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

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

Source:	National Electric Energy Data System (NEEDS) v.5.14
Note: The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed to a generation-weighted or capacity-weighted average heat rate.) A lower heat rate indicates a higher level of fuel efficiency. Table is limited to coal-steam units in operation in 2013 or earlier, and excludes those units in NEEDS with planned retirements in 2014 or 2015.
In terms of the age of the generating units, 50 percent of the total coal generating capacity has been in service for more than 38 years, while 50 percent of the natural gas capacity has been in service less than 15 years.  Figure 2-2 presents the cumulative age distributions of the coal and gas fleets, highlighting the pronounced differences in the ages of the fleets of these two types of fossil-fuel generating capacity. Figure 2-2 also includes the distribution of generation.

Figure 2-2. Cumulative Distribution in 2010 of Coal and Natural Gas Electricity Capacity and Generation, by Age
Source:	National Electric Energy Data System (NEEDS) v.5.13
Not displayed: coal units (376 MW total, 1 percent of total) and gas units (62 MW, < .01 percent of total)) over 70 years old for clarity. Figure is limited to coal-steam units in NEEDS v.5.13 in operation in 2013 or earlier (excludes ~2,100 MW of coal-fired IGCC and fossil waste capacity), and excludes those units in NEEDS with planned retirements in 2014 or 2015.

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

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

Table 2-4.  Total U.S. Electric Power Industry Retail Sales in 2012 (billion kWh)

                                     2002
                                     2012

                        Sales/Direct Use (Billion kWh)
                            Share of Total End Use
                        Sales/Direct Use (Billion kWh)
                            Share of Total End Use
                                     Sales
Residential
                                                                          1,265
                                                                            35%
                                                                          1,375
                                                                          35.9%

Commercial
                                                                          1,104
                                                                            30%
                                                                          1,327
                                                                          34.6%

Industrial
                                                                            990
                                                                            27%
                                                                            986
                                                                          25.7%

Transportation
                                                                             NA
                                                                            -
                                                                              7
                                                                           0.2%

Other
                                                                            106
                                                                             3%
                                                                             NA
                                                                            -
Total

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

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

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

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

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

Figure 2-6.  Relative Increases in Nominal National Average Electricity Prices for Major End-Use Categories, with Inflation Indices

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

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

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

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

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

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

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

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

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

Table 2-5. 	Domestic Emissions of Greenhouse Gases, by Economic Sector (million tons of CO2 equivalent)

                                     2002
                                     2013
                          Change Between '02 and '13
                                 Sector/Source
                                 GHG Emissions
                             % Total GHG Emissions
                                 GHG Emissions
                             % Total GHG Emissions
                              Change in Emissions
                             % Change in Emissions
                        % of Total Change in Emissions
Electric Power Industry
                                                                          2,550
                                                                            33%
                                                                          2,289
                                                                            31%
                                                                           -260
                                                                           -10%
                                                                            64%
Transportation
                                                                          2,158
                                                                            28%
                                                                          1,991
                                                                            27%
                                                                           -167
                                                                            -8%
                                                                            41%
Industry
                                                                          1,564
                                                                            20%
                                                                          1,535
                                                                            21%
                                                                            -29
                                                                            -2%
                                                                             7%
Agriculture
                                                                            618
                                                                             8%
                                                                            647
                                                                             9%
                                                                             29
                                                                             5%
                                                                            -7%
Commercial
                                                                            402
                                                                             5%
                                                                            442
                                                                             6%
                                                                             40
                                                                            10%
                                                                           -10%
Residential
                                                                            412
                                                                             5%
                                                                            413
                                                                             6%
                                                                              1
                                                                             0%
                                                                             0%
U.S. Territories
                                                                             58
                                                                         <1%
                                                                             38
                                                                         <1%
                                                                            -19
                                                                           -33%
                                                                             5%
Total GHG Emissions
                                                                          7,762
                                                                           100%
                                                                          7,356
                                                                           100%
                                                                           -406
                                                                            -5%
                                                                           100%
Sinks and Reductions
                                                                           -976

                                                                           -972

                                                                              4
                                                                             0%

Net GHG Emissions
                                                                          6,786

                                                                          6,384

                                                                           -402
                                                                            -6%

Source:	EPA, 2015 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013", Table 2-12. Includes CO2, CH4, N2O and SF6 emissions.

Figure 2-17. 	Domestic Emissions of Greenhouse Gases from Major Sectors, 2002 and 2013 (million tons of CO2 equivalent)
Source:	EPA, 2015 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013", Table 2-12
Not Shown: CO2e emissions from U.S. Territories. The amount of CO2 emitted during the combustion of fossil fuels varies according to the carbon content and heating value of the fuel used. The CO2 emission factors used in IPM v5.14 (same as used in v5.13) are shown in Table 2-7. Coal has higher carbon content than oil or natural gas, and thus releases more CO2 during combustion. Coal emits about 1.7 times as much carbon per unit of energy when burned as natural gas does (EPA 2013).
Table 2-6. 	Greenhouse Gas Emissions from the Electricity Sector (Generation, Transmission and Distribution), 2002 and 2013 (million tons of CO2 equivalent)

                                     2002
                                     2013
                          Change Between '02 and '13
                            Gas/Fuel Type or Source
                                 GHG Emissions
                  % of Total GHG Emissions from Power Sector
                                 GHG Emissions
                  % of Total GHG Emissions from Power Sector
                            Change in GHG Emissions
                             % Change in Emissions
CO2

                                                                          2,521
                                                                          98.9%
                                                                          2,262
                                                                          98.8%
                                                                           -259
                                                                           -10%

Fossil Fuel Combustion
                                                                          2,505
                                                                          98.2%
                                                                          2,248
                                                                          98.2%
                                                                           -257
                                                                           -10%

Coal
                                                                          2,083
                                                                          81.7%
                                                                          1,736
                                                                          75.8%
                                                                           -347
                                                                           -17%

Natural Gas
                                                                            337
                                                                         13.22%
                                                                            487
                                                                         21.28%
                                                                            150
                                                                            45%

Petroleum
                                                                           84.7
                                                                          3.32%
                                                                           24.7
                                                                          1.08%
                                                                          -60.0
                                                                           -71%

Geothermal
                                                                            0.4
                                                                          0.02%
                                                                            0.4
                                                                          0.02%
                                                                            0.0
                                                                             0%

Incineration of Waste
                                                                           13.0
                                                                          0.51%
                                                                           11.1
                                                                          0.49%
                                                                           -1.9
                                                                           -14%

Other Process Uses of Carbonates
                                                                            2.9
                                                                          0.11%
                                                                            2.4
                                                                          0.11%
                                                                           -0.4
                                                                           -15%
CH4

                                                                            0.4
                                                                          0.02%
                                                                            0.4
                                                                          0.02%
                                                                            0.0
                                                                             0%

Stationary Combustion*
                                                                            0.4
                                                                          0.02%
                                                                            0.4
                                                                          0.02%
                                                                            0.0
                                                                             0%

Incineration of Waste
                                                                              +

                                                                             +

N2O

                                                                           13.7
                                                                          0.54%
                                                                           21.4
                                                                          0.93%
                                                                            7.7
                                                                            56%

Stationary Combustion*
                                                                           13.2
                                                                          0.52%
                                                                           21.1
                                                                          0.92%
                                                                            7.8
                                                                            59%

Incineration of Waste
                                                                            0.4
                                                                          0.02%
                                                                            0.3
                                                                          0.01%
                                                                           -0.1
                                                                           -25%
SF6

                                                                           14.7
                                                                          0.57%
                                                                            5.6
                                                                          0.25%
                                                                           -9.0
                                                                           -62%

Electrical Transmission and Distribution
                                                                           14.7
                                                                          0.57%
                                                                            5.6
                                                                          0.25%
                                                                           -9.0
                                                                           -62%
Total GHG Emissions
                                                                          2,550

                                                                          2,289

                                                                           -260

Source:	EPA, 2015 "Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013", Table 2-11
* Includes only stationary combustion emissions related to the generation of electricity.
** SF6 is not covered by this rule, which specifically regulates CO2 emissions from combustion.
+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.

Table 2-7.	Fossil Fuel Emission Factors in the EPA Base Case 5.14 IPM Power Sector Modeling Application
                                   Fuel Type
                           Carbon Dioxide (lb/MMBtu)
Coal

   Bituminous
                                202.8  -  209.6
   Subbituminous
                                209.2  -  215.8
   Lignite
                                212.6  -  219.
Natural Gas
                                     117.1
Fuel Oil

   Distillate
                                     161.4
   Residual
                                161.4  -  173.9
Biomass
                                      195
Waste Fuels

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

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

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

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

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

Table 2-8. 	Total CO2 Storage Resource (U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL))

                                 Million Tons
                                     State
                                 Low Estimate
                                 High Estimate
                                    ALABAMA
                                    135,022
                                   765,422
                                    ALASKA
                                     9,524