The EPA's base LCOE estimates for NGCC, SCPC, and IGCC are shown in Figure 4-3 by cost component (capital, FOM, VOM, TS&M, and fuel) and assume a construction date of 2020 and an 85 percent capacity factor. Although the EPA believes that this cost data is broadly representative of the economics between new coal and new natural gas facilities, this analysis assumes representative new units and does not reflect the full array of new generating sources that could potentially be built.  To the extent that other types of new EGUs that would be affected by this rule are built, they may exhibit different costs than those presented here.  For example, new conventional coal facilities of a size smaller than what is assumed in the base estimate would tend to exhibit a relatively higher LCOE, while some technologies could potentially display a lower LCOE if, all else equal, fuel could be obtained at a lower price than that assumed in this analysis (such as may be the case for petroleum coke or waste coal facilities).  These potential differences do not fundamentally change the analysis presented in this RIA.
On a levelized cost basis, NGCC is significantly cheaper than all of the non-compliant coal-fired options.  For technologies that are included in the IPM Base Case and the AEO, their LCOE values are comparable to the LCOE values calculated from the NETL study. The difference in the LCOE of NGCC and non-compliant coal technologies explains the finding in the sectoral modeling described above that natural gas generation is forecast to be the source of new fossil-fired generation.
In addition to the disparity in total LCOE, there are fundamental differences in the cost composition between natural gas- and coal-fired facilities. NGCC costs are dominated by fuel expense while the levelized cost of coal-fired technologies driven by capital expense.  Consequently, this section will explore the impact of changes in natural gas price and the capital costs of coal-fired facilities to better quantify the magnitude of the relative cost advantage NGCC exhibits over coal-fired alternatives.

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

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

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

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

Figure 4-5.	Projected Real National Delivered Natural Gas Price for Select AEO 2014 Scenarios and Illustrative Path for > $10/MMBtu Levelized Price

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

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

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

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

Table 5-1.	Illustrative Emissions Profiles, New Coal and Natural Gas-Fired
		Generating Units

                                Natural Gas CC
                                     SCPC
                     SCPC+Partial CCS (1,400 lb/MWh Gross)
                             SCPC+Co-Fire Nat Gas
                                     IGCC
                             IGCC+Co-Fire Nat Gas

                                  Emissions
Emission Rate
                                  Emissions
Emission Rate
                                  Emissions
Emission Rate
                                  Emissions
Emission Rate
                                  Emissions
Emission Rate
                                  Emissions
Emission Rate
SO2
                                      84
                                    0.0041
                                     1,500
                                     0.71
                                     1,200
                                     0.61
                                     1,500
                                                                           0.71
                                      18
                                    0.0087
                                      18
                                                                         0.0087
NOx
                                      130
                                     0.061
                                     1,500
                                     0.74
                                     1,500
                                     0.75
                                     1,500
                                                                           0.74
                                     1,100
                                     0.52
                                     1,100
                                                                           0.52
CO2
                                  1.6 million
                                      800
                                  3.5 million
                                     1,700
                                  3.1 million
                                     1,500
                                  3.0 million
                                                                          1,500
                                  3.5 million
                                     1,700
                                  3.4 million
                                                                          1,700

Notes: Emissions from NETL 2015. Emissions are in short tons/year and Emission Rates are in net lb/MWh. Values rounded to two significant digits.  Emission characteristics are based on, and thus consistent with the cost and performance assumptions of, the illustrative units described in LCOE analysis in section 4.5 (i.e., these are base load units running at 85 percent capacity factor, all coal units are assumed to be using bituminous coal with a sulfur content of 2.8 percent dry, etc.). The tons of emissions are estimated for a coal-fired facility that achieves the gross-output standard of 1,400 lb/MWh and presented in this table on a net output basis. For the post-combustion CCS system assumed in the SCPC case, acidic gases (e.g., SO2, HCl) need to be scrubbed to very low levels prior to going to the CCS system to avoid degradation of the solvent. Therefore, SO2 emissions are lower in the case of the SCPC unit with partial CCS. See preamble for discussion about the format of the standard. Here we further assume all units are of the same capacity (600 MW net).

5.3	Comparison of Health and Climate Impacts from Generation Technologies
As discussed in the previous section, the emissions of GHGs and other pollutants associated with new sources of electricity generation are greater for coal-fired units than for NGCC units. Reducing the emissions associated with electricity generation results in climate, human health, and non-health benefits.
To consider the health and climate benefits associated with the adoption of lower emitting new generation technologies, we apply the 2022 benefit values discussed in Chapter 3 to the differences in illustrative emission profiles between the technologies in Table 5-1.   Specifically, we multiply the difference in CO2 emissions between two technologies by the estimates of the social cost of carbon dioxide (SC-CO2) (Table 3-1), multiply the difference in SO2 and NOX emissions by the PM2.5-related SO2 and NOX benefit per ton (BPT) estimates (Table 3-2), and add those values to get a measure of the 2022 benefits attributable to differences in emissions of adopting the lower emitting new generation technology. We subsequently divide by the amount of generation (in MWh) underlying the annual emissions estimates to derive the benefits attributable to the differences in emissions per unit of generation.
Only the direct emissions of CO2, SO2, and NOX are considered in this illustrative exercise. Other air and water pollutants emitted by these technologies and emissions from the extraction and transport of the fuels used by these technologies are not considered. For example, coal has higher mercury emissions than natural gas, but the relative benefits from the difference in mercury emissions are not considered. A similar example of emissions not considered are those of directly emitted PM2.5. Furthermore, there may be differences in upstream greenhouse gas emissions (in particular, methane) from different technologies which were not quantified for this assessment.
Table 5-2 reports the 2022 incremental climate and health benefits associated with a new NGCC unit relative to a new coal-fired SCPC and IGCC units, given different mortality risk studies and assumptions about the discount rate.  These benefits are based on the emissions presented in Table 5-1. The benefits presented in Table 5-2 are estimated on an output basis to enable easier comparisons to the potential costs of investing in a new non-compliant coal-fired unit relative to a new NGCC unit. These incremental benefits should be relatively invariant across natural gas prices and other economic factors. Depending on the discount rate and mortality risk study used, 2022 incremental benefits associated with generation from a representative new NGCC unit relative to a new coal-fired SCPC or IGCC unit are $7.0 to $91 per MWh (2011$).
The health and non-health benefits associated with reduced emissions can depend on a number of factors, including the specific fuels combusted and the location of the emissions. While the benefits of reduced CO2 emissions do not depend on the location of generation because the location of CO2 emissions does not influence their impact on the evolution of global climate conditions, the precise incremental health co-benefits will be location specific and depend on the specific fuels used. However, these factors will not change the qualitative conclusion. There will be incremental climate and human health benefits associated with a new NGCC unit relative to a new coal-fired unit, independent of the location.

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

                                     SCPC
                                     IGCC
CO2-Related Benefits using SC-CO2
5% Discount Rate
                                     $5.7
                                     $5.8
3% Discount Rate
                                      $19
                                      $19
2.5% Discount Rate
                                      $28
                                      $28
3% Discount Rate (95[th] percentile)
                                      $56
                                      $57
Total PM2.5-Related Co-Benefits from SO2 and NOX Changes
3% discount rate

Krewski et al. (2009)
                                      $15
                                     $1.3
Lepeule  et al. (2012)
                                      $34
                                     $3.0
7% discount rate

Krewski et al. (2009)
                                      $14
                                     $1.2
Lepeule et al. (2012)
                                      $31
                                     $2.7
Combined CO2-Related and PM2.5-Related Benefits

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

                                     SCPC
CO2-Related Benefits using SC-CO2

5% Discount Rate
                                     $1.3
3% Discount Rate
                                     $4.4
2.5% Discount Rate
                                     $6.6
3% Discount Rate (95th percentile)
                                      $13
Total PM2.5-Related Benefits from SO2 and NOX Changes
   3% discount rate

Krewski et al. (2009)
                                     $1.9
Lepeule et al. (2012)
                                     $4.3
   7% discount rate

Krewski et al. (2009)
                                     $1.7
Lepeule et al. (2012)
                                     $3.9
Combined CO2-Related and PM2.5-Related Benefits

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

      Table 5-4 reports the 2022 incremental benefits associated with a new compliant coal-fired unit co-firing natural gas relative to a new non-compliant coal-fired unit, given different mortality risk studies and assumptions about the discount rate.  The values are calculated based on the emissions presented in Table 5-1. Depending on whether the unit is SCPC or IGCC, the discount rate used, and mortality risk study used, 2022 incremental benefits associated with generation from a representative new coal-fired unit co-firing natural gas relative to a new coal-fired unit that does not co-fire natural gas are 0.25 to $14 per MWh (2011$). These incremental benefits will be used in the analyses presented in subsequent sections.

Table 5-4.	Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Compliant Coal-Fired Generation with Co-Firing Natural Gas Relative to New Non-Compliant Coal-Fired Generation in 2022

                          SCPC Co-Firing Natural Gas
                          IGCC Co-Firing Natural Gas
CO2-Related Benefits using SC-CO2

5% Discount Rate
                                     $1.5
                                     $0.25
3% Discount Rate
                                     $4.8
                                     $0.82
2.5% Discount Rate
                                     $7.2
                                     $1.2
3% Discount Rate (95th percentile)
                                      $14
                                     $2.5
Total PM2.5-Related Benefits from SO2 and NOX Changes
   3% discount rate

Krewski et al. (2009)
                                       -
                                       -
Lepeule et al. (2012)
                                       -
                                       -
   7% discount rate

Krewski et al. (2009)
                                       -
                                       -
Lepeule et al. (2012)
                                       -
                                       -
Combined CO2-Related and PM2.5-Related Benefits

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

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

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

Table 5-5.	Illustrative 2022 Costs and Benefits for Compliant SCPC with Partial Capture or with Co-Firing Natural Gas Relative to Non-Compliant SCPC (per MWh 2011$)

                                                          SCPC with Partial CCS
                                                                          SCPC
                                                          Co-Firing Natural Gas
Additional LCOE [a]
                                                                            $17
                                                                           $9.8
Revenue from EOR (Low - High EOR)
                                                                   $4.2 to $7.1
                                                                              *
Additional LCOE, net of EOR
                                                                    $9.6 to $13
                                                                              *
Value of Monetized Benefits for 2022 Emissions

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

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

Table 5-6.	Illustrative 2022 Costs and Benefits for Compliant IGCC with Co-Firing Natural Gas Relative to Non-Compliant IGCC (per MWh 2011$)

                          IGCC Co-Firing Natural Gas
Additional LCOE[a]

                                                                           $2.0
Revenue from EOR (Low - High EOR)

                                                                              *
Additional LCOE, net of EOR

                                                                              *
Value of Monetized Benefits for 2022 Emissions

SC-CO2 5% with Krewski 3% to SC-CO2 3% (95th) with Lepeule 3%[b]

                                                                  $0.25 to $2.5
Net Monetized Benefits

Without EOR Revenue

                                                                 $-1.8 to $0.45
With EOR Revenue

                                                                              *
[a] For this comparison the LCOE of the representative IGCC co-firing natural gas does not include 3 percent CUA.
[b] Benefits are estimated for a 2022 analysis year. Values shown are calculated using different discount rates.  Four estimates (average SC-CO2 at discount rates of 5, 3, and 2.5 percent, respectively, and 95th percentile SC-CO2 at 3 percent) of the SC-CO2 in the year 2022 were used.  See Table 3-1 for the SC-CO2 estimates. =The average SC-CO2 at 5 percent produced the lowest estimate and the 95th percentile estimate at 3 percent produced the highest estimate. See Section 3.2 for complete discussion of these estimates. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022.

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

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

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