U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis (RIA) for the Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/finalria.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2013a. Technical Support Document Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. Office of Air Quality Planning and Standards, Research Triangle Park, NC. January. Available on the Internet at: http://www.epa.gov/airquality/benmap/models/Source_Apportionment_BPT_TSD_1_31_13.pdf.
U.S. Environmental Protection Agency (U.S. EPA). 2013b. Integrated Science Assessment for Ozone and Related Photochemical Oxidants. EPA/600/R-10/076F. Research Triangle Park, NC: U.S. EPA. February. Available on the Internet at http://oaspub.epa.gov/eims/eimscomm.getfile?p_download_id=511347.

 Chapter 5
Analysis of Illustrative Cost-Benefit Scenarios
5.1	Synopsis
The previous chapter of this regulatory impact analysis (RIA) presents the U.S. Environmental Protection Agency's (EPA) analysis and projections from the U.S. Energy Information Administration (EIA) that support the conclusion that the EGU New, Modified and Reconstructed Source Standards will result in negligible costs and benefits in the period of analysis. The EPA recognizes that this conclusion is based on underlying expected economic conditions (e.g., fuel prices) and assumptions about considerations investors would weigh in deciding whether to build new uncontrolled coal-fired power plants. Therefore, this chapter presents the results of several illustrative analyses that show, under a range of alternative conditions, the potential costs and benefits of these standards for individual investments that provide base load dispatchable generation. We evaluate conditions under which different generator types are constructed in lieu of a non-compliant supercritical coal unit and estimate the social benefit of adopting the investment that is compliant with the standards.  This also allows us to consider idiosyncratic circumstances under which a unit that does not comply with these standards may be constructed.
While the analysis in Chapter 4 focuses on national level conditions, the analysis in this chapter explores the potential impacts to individual investments. The analysis in this chapter finds that under unlikely conditions, in which the EPA's conclusions regarding the future economic competitiveness of new non-compliant coal-fired units with respect to other new generation technologies shifts, or that idiosyncratic situations exist that favor the construction of units that would not comply with these standards, that the benefits of the standards to society outweigh the costs.
5.2	Comparison of Emissions from Generation Technologies
As discussed in Chapter 4, natural gas combined cycle (NGCC) units are on average expected to be more economical to build and operate than new coal units (See section 4.5).  Therefore, as our point of departure for comparing the costs and benefits of an individual investment decision, we evaluate the private and social cost of a new NGCC unit that is compliant with the finalized standards with a non-compliant conventional supercritical pulverized coal (SCPC) coal-fired unit. When evaluating the costs and benefits associated with these standards, it is also important to understand the difference in emissions associated with these units. In addition to being more economical, new NGCC units also have lower emission profiles for CO2 and criteria air pollutants than new coal units. For example, a typical new SCPC facility that burns bituminous coal in compliance with current utility regulations (e.g., the Mercury and Air Toxics Standards (MATS)) would have considerably greater CO2, sulfur dioxide (SO2), nitrogen dioxide (NOx), toxic metals, acid gases, and particulate emissions than a comparable NGCC facility.
Table 5-1 shows, emissions from a typical new NGCC unit are significantly lower than those from a new coal-fired unit.  The emission characteristics are based on, and thus consistent with, the cost and performance assumptions of the illustrative units described in LCOE analysis in section 4.5. That is, these are base load units of the same net capacity operating at an 85 percent capacity factor, the coal unit is assumed to be using bituminous coal with a sulfur content of 2.8% dry, they are in compliance with current utility regulations (e.g., the MATS), etc.  The typical new NGCC unit would emit about 2.3 fewer million metric tons of CO2 per year than the typical new SCPC unit, as well as roughly 1,700 fewer short tons of SO2 and about 1,200 fewer short tons of NOx per year than the SCPC unit. Table 5-1 also provides information for a representative integrated gasification combined cycle (IGCC) unit providing the same amount of electricity and using the same coal for comparison. The new IGCC unit would emit less CO2, SO2 and NOx than a typical coal-fired SCPC unit, but has higher emissions than a new NGCC unit. Reductions in SO2 emissions are a particularly significant driver for monetized health benefits, as SO2 is a precursor to the formation of particulates in the atmosphere, and particulates are associated with premature death and other serious health effects. Further information on these pollutants' health and non-health effects is described in Chapter 3.
Table 5-1.	Illustrative Emissions Profiles, New Coal and Natural Gas-Fired
		Generating Units

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

                                   Emissions
                                 (tons/ year)
                         Emission Rate (lbs/ MWh net)
                                   Emissions
                                 (tons/ year)
                         Emission Rate (lbs/ MWh net)
                                   Emissions
                                 (tons/ year)
                         Emission Rate (lbs/ MWh net)
                                   Emissions
                                 (tons/ year)
                         Emission Rate (lbs/ MWh net)
                                   Emissions
                                  (tons/year)
                         Emission Rate (lbs/ MWh net)
                                      SO2
                                      10
                                    0.0041
                                     1,700
                                     0.74
                                     1,400
                                     0.62
                                      23
                                     0.011
                                      24
                                     0.011
                                      NOx
                                      130
                                     0.060
                                     1,400
                                     0.61
                                     1,400
                                     0.65
                                     1,200
                                     0.52
                                     1,200
                                     0.52
                                      CO2
                                  1.7 million
                                      800
                                  4.0 million
                                     1,800
                                  3.4 million
                                     1,500
                                  3.8 million
                                     1,700
                                  3.7 million
                                     1,700
Notes: SO2 and NOx in short tons, CO2 in metric tons. Values rounded to two significant digits.  Emission characteristics are based on, and thus consistent with the cost and performance assumptions of, the illustrative units described in LCOE analysis in section 4.5 (i.e., these are base load units running at 85 percent capacity factor, all coal units are assumed to be using bituminous coal with a sulfur content of 2.8% dry, etc.). The tons of emissions are estimated for a coal-fired facility that achieves the gross-output standard of 1,400 lbs/MWh and presented in this table on a net output basis. For the post-combustion CCS system assumed in the SCPC case, acidic gases (e.g., SO2, HCl) need to be scrubbed to very low levels prior to going to the CCS system to avoid degredation of the solvent. Therefore, SO2 emissions are lower in the case of the SCPC unit with partial CCS. See preamble for discussion about the format of the standard. Here we further assume all units are of the same capacity (600 MW net).
5.3	Comparison of Health and Climate Impacts from Generation Technologies
As discussed in the previous section, the emissions of GHGs and other pollutants associated with new sources of electricity generation are greater for coal-fired units than for NGCC units. Reducing the emissions associated with electricity generation results in climate, human health and non-health benefits.
To consider the health and climate benefits associated with the adoption of lower emitting new generation technologies, we apply the 2022 social benefit values discussed in Chapter 3 to the differences in illustrative emission profiles between the technologies in Table 5-1.  Specifically, we multiply the difference in CO2 emissions between two technologies by the estimates of the social cost of carbon dioxide (SC-CO2) (Table 3-1), multiply the difference in sulfur dioxide (SO2) and nitrogen dioxide (NOX) emissions by the PM2.5-related SO2 and NOX benefit per ton (BPT) estimates (Table 3-2), and add those values to get a measure of the 2022 social benefits attributable to differences in emissions of adopting the lower emitting new generation technology. We subsequently divide by the number of MWh underlying the annual emissions estimates to derive the social benefits attributable to the differences in emissions per unit of generation.
Only the direct emissions of CO2, SO2, and NOX are considered in this illustrative exercise. Other air and water pollutants emitted by these technologies and emissions from the extraction and transport of the fuels used by these technologies are not considered. For example, coal has higher mercury emissions than natural gas, but the relative benefits from the difference in mercury emissions are not considered. Furthermore, there may be differences in upstream greenhouse gas emissions (in particular, methane) from different technologies but those were not quantified for this assessment.
Table 5-2 reports the 2022 incremental climate and health benefits associated with an illustrative new NGCC unit relative to illustrative new coal-fired SCPC and IGCC units, given different mortality risk studies and assumptions about the discount rate.  The benefits presented in Table 5-2 are estimated on an output basis to enable easier comparisons to the potential costs of investing in a new non-compliant coal-fired unit relative to a new NGCC unit. These incremental benefits should be relatively invariant across natural gas prices and other economic factors. Depending on the discount rate and mortality risk study used, 2022 incremental benefits associated with generation from a representative new NGCC unit relative to a new coal-fired SCPC or IGCC unit are $7.0 to $97 per MWh (2011$).
The precise health and welfare benefits associated with reduced CO2 emissions, which are the focus of this rule, depend on the specific fuels. However, the benefits of reduced CO2 emissions do not depend on the location of generation because the location of CO2 emissions does not influence their impact on the evolution of global climate conditions. As with the relative investment costs of a new coal-fired unit and a new NGCC unit, the precise incremental health co-benefits will be location specific and depend on the specific fuels used. However, these factors will not change the qualitative conclusion. There will be incremental
Table 5-2.	2022 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Illustrative New Natural Gas Combined Cycle Generation Relative to New Non-Compliant SCPC or IGCC Coal Generation

                                     SCPC
                                     IGCC
CO2-Related Benefits using SC-CO2
5% Discount Rate
                                     $6.1
                                     $5.8
3% Discount Rate
                                      $21
                                      $20
2.5% Discount Rate
                                      $31
                                      $29
3% Discount Rate (95[th] percentile)
                                      $63
                                      $60
PM2.5-Related Co-Benefits from SO2 and NOX Reductions
3% discount rate

Krewski et al. (2009)
                                      $15
                                     $1.4
Lepeule  et al. (2012)
                                      $35
                                     $3.1
7% discount rate

Krewski et al. (2009)
                                      $14
                                     $1.2
Lepeule et al. (2012)
                                      $31
                                     $2.8
Combined CO2-Related and PM2.5-Related Benefits

               Discount Rate Applied to PM2.5-Related Benefits
                   (range based on adult mortality function)
SC-CO2 Discount Rate
                                                                             3%
                                                                             7%
                                                                             3%
                                                                             7%
5% Discount Rate
                                                                     $22 to $41
                                                                     $20 to $37
                                                                   $7.2 to $8.9
                                                                   $7.0 to $8.6
3% Discount Rate
                                                                     $36 to $55
                                                                     $35 to $52
                                                                     $21 to $23
                                                                     $21 to $22
2.5% Discount Rate
                                                                     $46 to $66
                                                                     $45 to $62
                                                                     $31 to $32
                                                                     $31 to $32
3% Discount Rate (95[th] percentile)
                                                                     $78 to $97
                                                                     $77 to $94
                                                                     $61 to $63
                                                                     $61 to $62
Notes: The emission rates and operating characteristics of the units being compared in this table are reported in Table 5.1. Benefits are estimated for a 2022 analysis year. The range of benefits within each SC-CO2 value and discount rate for PM2.5-related benefits pairing reflects the use of two core estimates of PM2.5-related premature mortality. The EPA has evaluated the range of potential impacts per MWh by combining all SC-CO2 values with health benefits values at the 3 percent and 7 percent discount rates. Combining the 3 percent SC-CO2 values with the 3 percent health benefit values assumes that there is no difference in discount rates between intragenerational and intergenerational impacts. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022.
climate and human health benefits associated with a new NGCC unit relative to a new coal-fired unit, independent of the location.
The conclusion from this analysis is that there are significant environmental and health benefits associated with electricity generation from a representative new NGCC unit relative to a new conventional coal-fired unit. Other studies of the social costs of coal and natural gas-fired generation provide similar findings (Muller et. al., 2011; NRC, 2009).
As explained previously, the power sector has moved away from the construction of coal-fired power plants in favor of natural gas-fired power plants due, in part, to the significant cost differential. Even so, it is possible that a limited number of unplanned coal-fired power plants would be constructed during the analysis period. In these circumstances, units built with CCS in place of conventional coal-fired units would result in relative climate and human health and non-health benefits. Table 5-3 reports the 2022 incremental benefits associated with an illustrative new coal-fired unit with CCS relative to illustrative new SCPC and IGCC coal-fired units, given different mortality risk studies and assumptions about the discount rate.  Depending on the coal-fired generation type, discount rate, and mortality risk study used, 2022 incremental benefits associated with generation from a representative new coal-fired unit with CCS relative to a new coal-fired unit without CCS are $0.46 to $22 per MWh (2011$). These incremental benefits will be referenced in the analyses presented in subsequent sections.

Table 5-3.	2022 Incremental Benefits ($/MWh, 2011$) of Emission Reductions from Compliant Coal-	Fired Generation with CCS meeting 1,400 lbs/MWh Relative to New Non-Compliant Coal-Fired Generation

                                     SCPC
                                     IGCC
CO2-Related Benefits using SC-CO2

5% Discount Rate
                                     $1.6
                                     $0.46
3% Discount Rate
                                     $5.4
                                     $1.6
2.5% Discount Rate
                                     $8.2
                                     $2.3
3% Discount Rate (95th percentile)
                                      $17
                                     $4.7
PM2.5-Related Benefits from SO2 and NOX Reductions
   3% discount rate

Krewski et al. (2009)
                                     $2.2
                                       *
Lepeule et al. (2012)
                                     $4.9
                                       *
   7% discount rate

Krewski et al. (2009)
                                     $2.0
                                       *
Lepeule et al. (2012)
                                     $4.5
                                       *
Combined CO2-Related and PM2.5-Related Benefits

               Discount Rate Applied to PM2.5-Related Benefits
                   (range based on adult mortality function)
SCC Discount Rate
                                      3%
                                      7%

5% Discount Rate
                                                                   $3.8 to $6.5
                                                                   $3.6 to $6.1
                                     $0.46
3% Discount Rate
                                                                    $7.6 to $10
                                                                    $7.4 to $10
                                     $1.6
2.5% Discount Rate
                                                                     $10 to $13
                                                                     $10 to $13
                                     $2.3
3% Discount Rate (95th percentile)
                                                                     $19 to $22
                                                                     $19 to $21
                                     $4.7
*IGCC with CCS results in a small SO2 emissions increase when compared to IGCC without CCS. As a result, there would be a negligible health disbenefit (one cent or less per MWh) associated with these emissions increases.
Notes: Benefits are estimated for a 2022 analysis year. The range of benefits within each SC-CO2 value and discount rate for PM2.5-related benefits pairing reflects the use of two core estimates of PM2.5-related premature mortality. The EPA has evaluated the range of potential impacts per MWh by combining all SC-CO2 values with health benefits values at the 3 percent and 7 percent discount rates. Combining the 3 percent SC-CO2 values with the 3 percent health benefit values assumes that there is no difference in discount rates between intragenerational and intergenerational impacts. PM2.5-related co-benefits are estimated using 2020 monetized health benefits-per-ton of PM2.5 precursor reductions (Table 3-2), which are representative of 2022.
5.4	Illustrative Analysis  -  Benefits and Costs of New Source Standards across a Range of Gas Prices
As the analysis in Chapter 4 demonstrated, under a wide range of likely electricity market conditions  -  including the EPA base case and EIA reference case scenarios as well as multiple alternative scenarios  -  it is expected that the industry will choose to construct new units that already meet the standards of this rulemaking, even in its absence. In this section, we consider the potential impacts of the regulation if key assumptions regarding natural gas prices were to change during the analysis period. The analysis in this section indicates that in this scenario, the standards for new sources would result in costs to the illustrative investor, but would also lead to climate and human health benefits, and is highly likely to provide net benefits to society as a whole.
Furthermore, this section demonstrates that local fuel prices must be significantly different than regional differences already captured in IPM and EIA's modeling for private investment costs to favor a new uncontrolled coal-fired unit relative to a new NGCC unit serving a particular load.  Section 4.5.4 describes how regional conditions and other factors may influence the LCOE comparison, and how these regional differences are already captured in the electricity sector modeling in support of this rule. The 64 different regions in IPM are reflect the administrative structure of regional transmission organizations (RTOs) and independent system operators (ISOs). However, within those regions there may be local conditions which differ meaningfully from the broader regional conditions. The analysis in this section examines how substantially divergent those local conditions must be from representative conditions for non-compliant coal generation to be the technology of choice to serve demand.
The starting point for this analysis is the illustrative comparison (presented in Section 4.5) of the relative levelized cost of electricity (LCOE) of representative new coal-fired SCPC and IGCC EGUs and representative NGCC units. This comparison demonstrates a significant difference in the LCOE between the coal-fired and natural gas-fired generating technologies. The estimated LCOE for a representative NGCC unit is roughly $32 and $37 per MWh less than for a representative new coal-fired SCPC or IGCC unit, respectively (see Figure 4-3).  This is consistent with the EPA's expectation that the new source standards for steam units are not projected to impose any non-negligible costs or quantified benefits under current and likely future market conditions, as discussed in Chapter 4. The emissions associated with these technologies, and the benefits in terms of reduced damages of constructing and operating the illustrative NGCC unit in lieu of the illustrative non-compliant coal unit, are reported in the previous section.
To supplement this determination, this section presents an analysis of three relevant ranges within the distribution of future natural gas prices that can be classified as likely gas prices, unexpectedly high natural gas prices, and unprecedented natural gas prices. Because the cost of natural gas is a significant share of the LCOE for NGCC units, we evaluate how changes in natural gas prices affect differences in the relative private and social costs of new technologies. We identify the natural gas price when the private costs, which are inclusive of the CUA, suggest that a new non-compliant coal may be adopted by an investor in lieu of a new NGCC unit. We then compare the social costs of these technologies, which is inclusive of both the private costs of these technologies and the damages from these technologies but exclusive of the CUA, at this natural gas price. We then identify the natural gas price when the social cost of investing in the illustrative new non-compliant coal unit is plausibly less than the social cost of the new illustrative NGCC unit.
In general, this analysis shows that there would likely be a net social benefit, even under scenarios with higher than expected gas prices, if new compliant units were built in place of new non-compliant coal-fired units as a result of this rule. Under some conditions, higher natural gas prices may result in a net social cost of constructing and operating new natural gas in lieu of non-compliant coal, holding all other parameters constant and disregarding social benefits that we are unable to monetize. However, even under these unlikely conditions the social benefits of these finalized standards may yield social net benefits as there may be other technologies that would have a lower social cost than a new non-compliant coal unit.
5.4.1	Likely Natural Gas Prices
As shown in Chapter 4, it is only when natural gas prices exceed $10/MMBtu on a levelized basis (in 2011 dollars) that the representative new coal-fired SCPC unit without CCS likely becomes competitive in terms of its cost of electricity produced. None of the sensitivities presented in Chapter 4 or the AEO2014 scenarios approach this natural gas price level on either a forward looking 20-year levelized price basis or on an average annual price basis at any point during the analysis period.
5.4.2	Unexpectedly High Natural Gas Prices
At natural gas prices above $10/mmBtu, the private levelized cost of electricity for a representative new coal-fired SCPC unit falls below that of a new NGCC unit.  Therefore, in the event of such unexpectedly high levelized fuel prices, some new coal-fired SCPC units might be constructed in the absence of this proposed rulemaking, provided that coal price do not rise at the same time, there is sufficient demand for electricity, and new non-compliant coal-fired SCPC units are competitive with other new and existing generating technologies other than NGCC units. In this scenario, there would be some compliance costs if a new NGCC unit or a compliant coal-fired unit were built as a result of the new fossil steam standard. However, generation from a new NGCC unit would also have incremental environmental and health benefits as it has less CO2 and PM2.5 (as a result of SO2 and NOx emissions) emissions than generation from a new non-compliant coal-fired SCPC unit (as would a coal-fired unit that is compliant with the new standards; see Section 5.5).
For levelized natural gas prices of $10/mmBtu and somewhat higher, the resulting emission reduction benefits of building an NGCC unit, in place of a coal-fired SCPC unit, will outweigh the costs of constructing and operating an NGCC unit in lieu of a coal-fired SCPC unit. This observation indicates that the standard for new fossil steam sources would yield net benefits in the analysis year. For example, at a levelized gas price of $11/MMBtu, the illustrative NGCC unit would generate electricity for approximately $13/MWh more than the coal-fired SCPC unit on a levelized basis, and result in incremental benefits from emissions reductions of $20 to $97/MWh (see analysis of 2022 relative benefits of NGCC: Table 5-2). The net benefit of this scenario would be $7.1 to $84/MWh.
For context, a natural gas price of $10/MMBtu (in 2011 dollars) is higher than any average annual natural gas price faced by the electric power sector since at least 1996, when the EIA historic data series begins. The continued development of unconventional natural gas resources in the U.S. suggests that gas prices may actually tend to be towards the lower end of the historical range. In addition, the highest projected average levelized natural gas price during the analysis period of any of the AEO2014 scenarios cited in Chapter 4 is $8.45MMBtu (2012 $), which occurs in the Low Oil and Gas Resource scenario (see Table 4.6). As discussed in Chapter 4, none of the EIA sensitivity cases (which account for future fuel prices for both gas and coal) show scenarios where non-compliant coal-fired units become more economic than NGCC units in the period of analysis.
5.4.3	Unprecedented Natural Gas Prices
At extremely high natural gas prices, the LCOE for a non-compliant coal-fired SCPC unit could be sufficiently lower than the cost of a new NGCC unit, such that the net benefit of the standard in a given year could be negative (i.e., a net cost), at least under some ranges of benefit estimates. For example, at a levelized gas price of $14/MMBtu, the illustrative NGCC unit would generate electricity for roughly $33/MWh more than the illustrative coal-fired SCPC, respectively, but result in social benefits from lower emissions of $20 to $97/MWh relative to the coal-fired SCPC unit (see analysis of 2022 relative benefits of NGCC: Table 5-2). If the illustrative NGCC unit were built in lieu of the illustrative SCPC as a result of the new fossil steam standard, the impact would range from a net social cost of $13/MWh to a net social benefit of $64/MWh relative to the illustrative SCPC.
As noted in the previous subsection, natural gas prices at these levels would be unprecedented. As a result, the EPA believes that the probability of levelized natural gas prices reaching levels at which this standard would generate net social costs under some ranges of benefit estimates is extremely small.
We emphasize that differences in generating costs, plant design, local factors, and the relative differences between fuels costs can all have major impacts on the precise circumstances under which this standard would be projected to have no costs, net social benefits or net social costs. However, based on historical and expected gas prices, we project that the new fossil steam standard is most likely to have negligible costs, and, if it does result in costs, it is also likely to produce positive, although modest, net social benefits. Furthermore, these results, complemented by the analysis in Chapter 4 on regional differences in levelized costs of these technologies, indicate that local differences in the cost of these technologies must be significantly different from representative conditions for non-compliant coal generation to be the technology of choice to serve demand. The probability that this proposed standard would result in net social costs is exceedingly low.
5.5	Illustrative Analysis  -  Benefits and Costs of Uncontrolled Coal and Compliant Coal
As discussed in detail in the previous section and in Chapter 4, it is unlikely that a new non-compliant coal-fired unit would be constructed in the analysis period. The power sector continues to move away from the construction of coal-fired power plants in favor of natural gas-fired power plants due, in part, to the significant LCOE differential explored in the previous section. Even so, it is possible that a limited number of conventional coal-fired power plants might be constructed in the analysis period. In these circumstances, EPA believes that any need for CCS could be accommodated and would not, based on the incremental cost of the CCS portion of the new unit, preclude the construction of the new coal-fired facility. One factor in determining that needing CCS would not preclude the construction of the new facility is the availability of Enhanced Oil Recovery (EOR) opportunities for new coal-fired facilities.
This section evaluates the impacts that might occur if an investor, who otherwise wanted to construct a new non-compliant coal unit, chose to instead construct a new compliant coal-fired unit in response to the new fossil steam standard. In this scenario, this decision would result in some costs in order to build a unit with partial CCS or co-fire with natural gas.  However, there would also be climate and other benefits resulting from reductions in CO2, SO2, and NOX emissions.
For each coal-fired generation type, SCPC and IGCC, the EPA analyzed the cost and 2022 emission impacts of meeting the new source standards. While partial CCS is considered the best system of emission reductions (BSER) for these units, it would also be possible to meet the standard without CCS through co-firing natural gas, which is also analyzed. Consistent with the LCOE estimates provided in Table 4-5 (in Chapter 4), the partial capture CCS and cofiring natural gas scenarios achieve the proposed emissions rate of 1,400 lb CO2/MWh gross output.
The cost of CCS used to support this rule assumes that the geologic sequestration of CO2 will be in deep saline formations and accounts for the cost of doing so, but the EPA also recognizes the potential for sequestering CO2 for EOR and allows a source to provide CO2 for EOR (as well as enhanced gas recovery) as a compliance option.
EOR refers to the injection of gases and/or fluids into a reservoir to increase oil production efficiency. CO2-EOR has been successfully used at many production fields throughout the United States. The oil and natural gas industry in the United States has over 40 years of experience in injection and monitoring of CO2. This experience provides a strong foundation for the technologies used in the deployment of CCS on coal-fired electric generating units.  Although deep saline formations provide the most CO2 storage opportunity (2,102 to 20,043 billion metric tons), oil and gas reservoirs are estimated to have 226 billion metric tons of CO2 storage resource.
    The use of CO2 for EOR can significantly lower the cost of implementing CCS. The opportunity to sell the captured CO2 rather than paying directly for its long-term storage, greatly improves the economics of the new generating unit. According to the International Energy Agency, of the CCS projects in operation (e.g., Boundary Dam Energy Project, Saskatchewan, Canada) or under construction or at an advanced stage of planning, 70% intend to use captured CO2 to improve recovery of oil in mature fields, including Mississippi Power's Kemper County Energy Facility, NRG Energy's W.A. Parish Petra Nova CCS Project, Summit Power's Texas Clean Energy Project, and the Hydrogen Energy California Project. The Texas Clean Energy project is planning to capture 90% of the CO2 and sell it for EOR.
Therefore, in the near term, new coal-fired EGUs with CCS may be located in areas amenable to using the captured CO2 in EOR operations because these formations have been previously well characterized for hydrocarbon recovery, likely already have suitable infrastructure (e.g., wells, pipelines, etc.), and have an associated economic benefit of increasing oil well productivity.  Furthermore, EPA believes the opportunity to engage in EOR opportunities is not significantly limited by the location of those opportunities or the current CO2 pipeline infrastructure (12 states currently have existing or under construction CO2 pipelines).  Provision of electric power does not require coal-fired facilities to be co-located with the demand it is intended to serve. Please refer to Chapter 2 for a more detailed discussion of EOR, including its geographic availability, expected future growth, and overall impact on the economics of CCS.
There are two EOR opportunities evaluated in this section  -  `High' and `Low.'  The high EOR opportunity assumes a CO2 sale price of $40 per metric ton; the low EOR opportunity assumes a CO2 sale price of $20 per metric ton   based on assumptions used by NETL in evaluating potential EOR opportunities.  For either opportunity, it is assumed that the facility is only responsible for the costs of transmitting the captured CO2 to the fence line, as is currently the practice.  Costs for the transportation, storage, and monitoring (TSM) of CO2 are included in this analysis. For non-EOR applications, TSM costs of ~$5-$15 dollars per ton of CO2 are applied based on the level of capture.
Figure 5-1 compares the LCOE for an illustrative uncontrolled coal to coal with partial CCS both with and without EOR. It also provides the LCOE of an illustrative uncontrolled coal unit to the cost of a controlled unit cofiring natural gas. With the exception of the LCOE costs accounting for EOR, these costs were provided in Table 4-5. We see in Figure 5-1 that if a limited number of non-compliant coal-fired power plants would have be constructed in the analysis period, that the adoption of CCS could be accommodated and would not, based on the incremental cost of the CCS portion of the new unit, preclude the construction of the new coal-fired facility. Furthermore, it shows that if it was not possible for a unit to provide CO2 for EOR, it may lower its costs by cofiring natural gas and still generate a substantial share of its production from coal.

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

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

                                                                    Partial CCS
                                                          Co-Firing Natural Gas
Additional LCOE [a]
                                                                            $16
                                                                            $11
Revenue from EOR (Low - High EOR)
                                                                   $3.4 to $6.7
                                                                              *
Additional LCOE, net of EOR
                                                                    $8.9 to $12
                                                                              *
Value of Monetized Benefits for 2022 Emissions

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

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

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

                                  Partial CCS
                             Co-Firing Natural Gas
Additional LCOE[a]
                                                                           $3.5
                                                                           $1.7
Revenue from EOR (Low - High EOR)
                                                                 $0.39 to $0.78
                                                                              *
Additional LCOE, net of EOR
                                                                   $2.7 to $3.1
                                                                              *
Value of Monetized Benefits for 2022 Emissions

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

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

6.1	Introduction
In addition to the standards for new sources analyzed in Chapter 4 and Chapter 5, this action also sets standards under Clean Air Act Section 111(b) for units that modify or reconstruct. For the reasons discussed in this chapter, the EPA also believes that the standards for modified and reconstructed fossil fuel-fired EGUs will result in minimal compliance costs, because we expect few modified or reconstructed EGUs in the period of analysis (through 2022).
6.2	Reconstructed Sources
The new source performance standard (NSPS) provisions (40 CFR part 60, subpart A) define a "reconstruction" as the replacement of components of an existing facility to an extent that (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and (2) it is technologically and economically feasible to meet the applicable standards. Historically, we are only aware of one EGU that has notified the EPA that it has reconstructed under the reconstruction provision of section 111(b). As a result, we anticipate that few EGUs will undertake reconstruction in the period of analysis. For this reason, the standards will not result in any significant emission reductions, costs, or quantified benefits in the period of analysis. Likewise, the Agency does not anticipate any impacts on the price of electricity or energy supply. The rule is not expected to raise any resource adequacy concerns, since reserve margins will not be impacted and the rule does not impose any additional requirements on existing facilities not triggering the reconstruction provision. There are no macroeconomic or employment impacts expected as a result of these standards.
Due to the extremely limited data available on reconstructions, it is not possible to conduct a representative illustrative analysis of what costs and benefits might result from this rule in the unlikely case that a unit were to reconstruct.
6.3	Modified Sources
Historically, few EGUs have notified the EPA that they have modified under the modification provision of section 111(b). The EPA's current regulations define an NSPS "modification" as a physical or operational change that increases the source's maximum achievable hourly rate of emissions, but specifically exempt from that definition projects that entail the installation of pollution control equipment or systems.
The EPA expects that most of the actions EGUs are likely to take in the foreseeable future that could be classified as "modifications" would qualify as pollution control projects. In many cases, those projects are likely to involve the installation of add-on control equipment needed to meet CAA requirements for criteria and air toxics air pollutants. Any associated CO2 emissions increases would likely be small and would occur as a chemical byproduct of the operation of the control equipment. In other cases, those projects would involve equipment changes to improve fuel efficiency to meet state requirements for implementation of the CAA section 111(d) rulemaking for existing sources and would have the effect of increasing a source's maximum achievable hourly emission rate (lb CO2/hr), even while decreasing its actual output based emission rate (lb CO2/MWh). Because all of these actions would be treated as pollution control projects under the EPA's current NSPS regulations, they would be specifically exempted from the definition of modification.
Given the limited information that we have about past modifications, the EPA has concluded that it lacks sufficient information to establish standards of performance for all types of modifications at steam generating units at this time.  Instead, the EPA has determined that it is appropriate to establish standards of performance at this time for large-scale modifications of steam generating units, such as major facility upgrades involving the reconstruction or replacement of steam turbines and other equipment upgrades that result in substantial increases in a unit's potential hourly CO2 emissions rate. The EPA does not have sufficient information at this time to predict the full array of actions that existing steam generating units may undertake, including those in response to applicable requirements under an approved CAA section 111(d) plan. Additionally, it is not possible to predict which, if any, of these actions may result in increases in potential CO2 hourly emissions. Nevertheless, EPA expects that, to the extent actions are undertaken by existing steam generating units, the magnitude of the increases in potential hourly CO2 emissions associated with the vast majority of such changes would generally be small and therefore would generally not be subject to the standards of performance for modified steam generating units finalized in this action.
Similar to the case of the steam generating units, the EPA also expect few existing stationary combustion turbines to modify during the period of analysis and become subject to the standards of performance the EPA is finalizing for such units in this action. Therefore, the EPA expects the standards associated with modified stationary combustion turbines to result in minimal, if any, compliance costs during the period of analysis.
Based on this information, we anticipate that few EGUs will take actions that would be considered modifications and subject to the standards of performance finalized in this action during the period of analysis. For this reason, the standards will result in minimal emission reductions, costs, or quantified benefits in the period of analysis. Likewise, the Agency does not anticipate any impacts on the price of electricity or energy supplies. This rule is not expected to raise any resource adequacy concerns, since reserve margins will not be impacted and the rule does not impose any additional requirements on existing facilities not triggering the modification provision. There are no macroeconomic or employment impacts expected as a result of these standards.
Due to the limited data available on past modifications and the diversity of existing units that could potentially modify, it is not possible to conduct a representative illustrative analysis of what costs and benefits might result from this rule in the unlikely case that a unit were to take an action that would be classified as a modification.
 Chapter 7
Statutory and Executive Order REVIEWS
7.1 	Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, Improving Regulation and Regulatory Review
This final action is a significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review. It is a significant regulatory action because it raises novel legal or policy issues arising out of legal mandates. Any changes made in response to OMB recommendations have been documented in the established dockets for this action under Docket ID No. EPA-HQ-OAR-2013-0495 (Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units) and Docket ID No. EPA-HQ-OAR-2013-0603 (Carbon Pollution Standards for Modified and Reconstructed Stationary Sources: Electric Utility Generating Units). This RIA includes an economic analysis of the potential costs and benefits associated with this action.
The EPA does not anticipate that this final action will result in any notable compliance costs. Specifically, we believe that the standards for newly constructed fossil fuel-fired EGUs (electric utility steam generating units and natural gas-fired stationary combustion turbines) will have negligible costs associated with it over a range of likely sensitivity conditions because electric power companies will choose to build new EGUs that comply with the regulatory requirements of this action even in the absence of the action, because of existing and expected market conditions. (See Chapter 5 for further discussion of sensitivities). The EPA does not project any new coal-fired steam generating units without CCS to be built in the absence of this action. However, because some companies may choose to construct coal or other fossil fuel-fired EGUs, the RIA also analyzes project-level costs of a unit with and without CCS, to quantify the potential cost for a fossil fuel-fired EGU with CCS.
The EPA also believes that the standards for modified and reconstructed fossil fuel-fired EGUs will result in minimal compliance costs, because, as previously stated, the EPA expects few modified or reconstructed EGUs in the period of analysis (through 2022). In Chapter 6, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources.
7.2 	Paperwork Reduction Act (PRA)
      The information collection activities in this final action have been submitted for approval to OMB under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number [XX]. Separate ICR documents were prepared and submitted to OMB for the proposed standards for newly constructed EGUs (EPA ICR number 2465.02) and the proposed standards for modified and reconstructed EGUs (EPA ICR number 2506.03). Because the CO2 standards for newly constructed, modified, and reconstructed EGUs will be included in the same new subpart (40 CFR part 60, subpart TTTT) and are being finalized in the same action, the ICR document for this action includes estimates of the information collection burden on owners and operators of newly constructed, modified, and reconstructed EGUs. Estimated cost burden is based on 2013 Bureau of Labor Statistics (BLS) labor cost data. Thus, all burden estimates are in 2013 dollars. Burden is defined at 5 CFR 1320.3(b). You can find a copy of the ICR in the dockets for this action (Docket ID Numbers EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them.
      The recordkeeping and reporting requirements in this final action are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B.
      An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, the Agency will announce that approval in the Federal Register and publish a technical amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final action.
7.2.1	Newly constructed EGUs
      This final action will impose minimal new information collection burden on owners and operators of affected newly constructed fossil fuel-fired EGUs (steam generating units and natural gas-fired stationary combustion turbines) beyond what those sources would already be subject to under the authorities of CAA parts 75 and 98. OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060-0626 and 2060-0629, respectively. Apart from certain reporting costs based on requirements in the NSPS General Provisions (40 CFR part 60, subpart A), which are mandatory for all owners/operators subject to CAA section 111 national emission standards, there are no new information collection costs, as the information required by the standards for newly constructed EGUs is already collected and reported by other regulatory programs.
      The EPA believes that electric power companies will choose to build new EGUs that comply with the regulatory requirements of the rule because of existing and expected market conditions. The EPA does not project any newly constructed coal-fired steam generating units that commenced construction after proposal (January 8, 2014) to commence operation over the 3-year period covered by this ICR. We estimate that 17 affected newly constructed natural gas-fired stationary combustion turbines will commence operation during that time period. As a result of this final action, owners or operators of those newly constructed units will be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months.
7.2.2	Modified and Reconstructed EGUs
      This final action is not expected to impose an information collection burden under the provisions of the PRA on owners and operators of affected modified and reconstructed fossil fuel-fired EGUs (steam generating units and natural gas-fired stationary combustion turbines). As previously stated, the EPA expects few modified or reconstructed EGUs in the period of analysis. Specifically, the EPA believes it unlikely that fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines will take actions that would constitute modifications or reconstructions as defined under the EPA's NSPS regulations. Accordingly, the standards for modified and reconstructed EGUs are not anticipated to impose any information collection burden over the 3-year period covered by this ICR. We have estimated, however, the information collection burden that would be imposed on an affected EGU if it was modified or reconstructed.
      Although not anticipated, if an EGU were to modify or reconstruct, this final action would impose minimal information collection burden on those affected sources beyond what they would already be subject to under the authorities of CAA 40 CFR parts 75 and 98. As described above, the OMB has previously approved the information collection requirements contained in the existing part 75 and 98 regulations. Apart from certain reporting costs, which are mandatory for all owners/operators subject to CAA section 111 national emission standards, there would be no new information collection costs, as the information required by the final rule is already collected and reported by other regulatory programs.
      As stated above, although the EPA expects few sources will trigger either the NSPS modification or reconstruction provisions, if an EGU were to modify or reconstruct during the 3-year period covered by this ICR, the owner or operator of the EGU will be required to prepare a summary report, which includes reporting of emissions and downtime, every 3 months. The annual reporting burden for such a unit is estimated to be $2,665 and 32 labor hours. There are no annualized capital costs or O&M costs associated with burden for modified or reconstructed EGUs.
7.2.3	Information Collection Burden
      The annual information collection burden for newly constructed, modified, and reconstructed EGUs consists only of reporting burden as explained above. The annual reporting burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $32,886 and 395 labor hours. There are no annualized capital costs or O&M costs associated with burden for newly constructed EGUs. Average burden hours per response are estimated to be 8 hours. The total number of respondents over the 3-year ICR period is estimated to be 37.
7.3 	Regulatory Flexibility Act (RFA)
      EPA certifies that this final action will not have a significant economic impact on a substantial number of small entities under the RFA. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden or otherwise has a positive economic effect on the small entities subject to the rule.
7.3.1	Newly constructed EGUs
	The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built. We expect that any newly constructed natural gas-fired stationary combustion turbines will meet the standards. We do not include an analysis of the illustrative impacts on small entities that may result from implementation of the final rule because we anticipate negligible compliance costs over a range of likely sensitivity conditions as a result of the standards for newly constructed EGUs. Thus the cost-to-sales ratios for any affected small entity would be zero costs as compared to annual sales revenue for the entity. Accordingly, there are no anticipated economic impacts as a result of the standards for newly constructed EGUs. We have therefore concluded that this final action will have no net regulatory burden for all directly regulated small entities.
7.3.2 	Modified and Reconstructed EGUs
      The EPA expects few modified fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. An NSPS modification is defined as a physical or operational change that increases the source's maximum achievable hourly rate of emissions. The EPA does not believe that there are likely to be EGUs that will take actions that would constitute modifications as defined under the EPA's NSPS regulations.
	In addition, the EPA expects few reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. Reconstruction occurs when a single project replaces components or equipment in an existing facility and exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility.
	In Chapter 6, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources. However, we do not anticipate that the rule would impose significant costs on those sources, including any that are owned by small entities.
7.4 	Unfunded Mandates Reform Act (UMRA)
    This final action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531 - 1538, and does not significantly or uniquely affect small governments.
    The EPA believes the final rule will have negligible compliance costs on owners and operators of newly constructed EGUs over a range of likely sensitivity conditions because electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly constructed natural gas-fired stationary combustion turbines will meet the standards.
    As previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. In Chapter 6, we discuss factors that limit our ability to quantify the costs and benefits of the standards for modified and reconstructed sources. However, we do not anticipate that the rule would impose significant costs on those sources.
We have therefore concluded that the standards for newly constructed, modified, and reconstructed EGUs do not impose enforceable duties on any state, local or tribal governments, or the private sector, that may result in expenditures by state, local and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. We have also concluded that this action does not have regulatory requirements that might significantly or uniquely affect small governments. The threshold amount established for determining whether regulatory requirements could significantly affect small governments is $100 million annually and, as stated above, we have concluded that the final action will not result in expenditures of $100 million or more in any one year. Specifically, the EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly constructed natural gas-fired stationary combustion turbines will meet the standards. Further, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis.
7.5 	Executive Order 13132, Federalism
      This final action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. In addition, as previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. We, therefore, anticipate that the final rule will impose minimal compliance costs.
7.6 	Executive Order 13175, Consultation and Coordination with Indian Tribal Governments
      This final action does not have tribal implications as specified in Executive Order 13175. The final rule will impose requirements on owners and operators of newly constructed, modified, and reconstructed EGUs. The EPA is aware of three facilities with coal-fired steam generating units, as well as one facility with natural gas-fired stationary combustion turbines, located in Indian Country, but is not aware of any EGUs owned or operated by tribal entities. We note that because the rule addresses CO2 emissions from newly constructed, modified, and reconstructed EGUs, it will affect existing EGUs such as those located at the four facilities in Indian Country only if those EGUs were to take actions constituting modifications or reconstructions as defined under the EPA's NSPS regulations. As previously stated, the EPA expects few modified or reconstructed EGUs in the period of analysis. Thus, the rule will neither impose substantial direct compliance costs on tribal governments nor preempt Tribal law. Accordingly, Executive Order 13175 does not apply to this action.
      Nevertheless, because the EPA is aware of Tribal interest in carbon pollution standards for the power sector and, consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA offered consultation with tribal officials during development of this rule. Prior to the April 13, 2012 proposal (77 FR 22392), the EPA sent consultation letters to the leaders of all federally recognized tribes. Although only newly constructed, modified, and reconstructed EGUs will be affected by this action, the EPA's consultation regarded planned actions for new and existing sources. The letters provided information regarding the EPA's development of NSPS and emission guidelines for EGUs and offered consultation. A consultation/outreach meeting was held on May 23, 2011, with the Forest County Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa Reservation, and the Leech Lake Band of Ojibwe. A description of that consultation is included in the preamble to the proposed standards for new EGUs (79 FR 1501, January 8, 2014).
      The EPA also offered consultation to the leaders of all federally recognized tribes after the proposed action for newly constructed EGUs was signed on September, 20, 2013. On November 1, 2013, the EPA sent letters to tribal leaders that provided information regarding the EPA's development of carbon pollution standards for new, modified, reconstructed and existing EGUs and offered consultation. No tribes requested consultation regarding the standards for newly constructed EGUs.
In addition to offering consultation, the EPA also conducted outreach to tribes during development of this rule. The EPA held a series of listening sessions prior to proposal of GHG standards for newly constructed EGUs. Tribes participated in a session on February 17, 2011, with the state agencies, as well as in a separate session with tribes on April 20, 2011. The EPA also held a series of listening sessions prior to proposal of GHG standards for modified and reconstructed EGUs and GHG emission guidelines for existing EGUs. Tribes participated in a session on September 9, 2013, together with the state agencies, as well as in a separate tribe-only session on September 26, 2013. In addition, an outreach meeting was held on September 9, 2013, with tribal representatives from some of the federally recognized tribes. The EPA also met with tribal environmental staff with the National Tribal Air Association, by teleconference, on July 25, 2013, and December 19, 2013. Additional detail regarding this stakeholder outreach is included in the preamble to the proposed emission guidelines for existing EGUs (79 FR 34830, June 18, 2014).
7.7 	Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks
       This action is not subject to Executive Order 13045 because it is not economically significant as defined in Executive Order 12866. While the action is not subject to Executive Order 13045, the EPA believes that the environmental health or safety risk addressed by this action has a disproportionate effect on children. Accordingly, the agency has evaluated the environmental health and welfare effects of climate change on children.
       CO2 is a potent greenhouse gas that contributes to climate change and is emitted in significant quantities by fossil fuel-fired power plants. The EPA believes that the CO2 emission reductions resulting from implementation of these final guidelines, as well as substantial ozone and PM2.5 emission reductions as a co-benefit, will further improve children's health.
       The assessment literature cited in the EPA's 2009 Endangerment Finding concluded that certain populations and lifestages, including children, the elderly, and the poor, are most vulnerable to climate-related health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed findings regarding these groups' vulnerabilities and the projected impacts they may experience.
       These assessments describe how children's unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households.
       More detailed information on the impacts of climate change to human health and welfare is provided in Section II.A of the preamble.
7.8 	Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
This final action is not a "significant energy action" because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. In addition, as previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. Thus, this action is not anticipated to have notable impacts on emissions, costs or energy supply decisions for the affected electric utility industry.
7.9 	National Technology Transfer and Advancement Act
      This final action involves technical standards. The following voluntary consensus standards are used in the final rule: American Society for Testing and Materials (ASTM) Methods D388-12 (Standard Classification of Coals by Rank), D396-13c (Standard Specification for Fuel Oils), D975-14 (Standard Specification for Diesel Fuel Oils), D3699-13b (Standard Specification for Kerosene), D6751-12 (Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels), D7467-13 (Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20)), and American National Standards Institute (ANSI) Standard C12.20 (American National Standard for Electricity Meters - 0.2 and 0.5 Accuracy Classes). The rule also requires use of Appendices A, B, D, F and G to 40 CFR part 75; these Appendices contain standards that have already been reviewed under the NTTAA.
7.10	Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies and activities on minority populations and low-income populations in the U.S. The EPA defines environmental justice as the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. The EPA has this goal for all communities and persons across this Nation. It will be achieved when everyone enjoys the same degree of protection from environmental and health hazards and equal access to the decision-making process to have a healthy environment in which to live, learn, and work.
Leading up to this rulemaking the EPA summarized the public health and welfare effects of GHG emissions in its 2009 Endangerment Finding. As part of the Endangerment Finding, the Administrator considered climate change risks to minority or low-income populations, finding that certain parts of the population may be especially vulnerable based on their circumstances. These include the poor, the elderly, the very young, those already in poor health, the disabled, those living alone, and/or indigenous populations dependent on one or a few resources. See Sections F and G, above, where EPA discusses Consultation and Coordination with Tribal Governments and Protection of Children. The Administrator placed weight on the fact that certain groups, including children, the elderly, and the poor, are most vulnerable to climate-related health effects.
Strong scientific evidence that the potential impacts of climate change raise environmental justice issues is found in the major assessment reports by the U.S. Global Change Research Program (USGCRP), the Intergovernmental Panel on Climate Change (IPCC), and the National Research Council (NRC) of the National Academies, summarized in the record for the Endangerment Finding. Their conclusions include that poor communities can be especially vulnerable to climate change impacts because they tend to have more limited adaptive capacities and are more dependent on climate-sensitive resources such as local water and food supplies. In addition, Native American tribal communities possess unique vulnerabilities to climate change, particularly those on established reservations that are restricted to reservation boundaries and therefore have limited relocation options. Tribal communities whose health, economic well-being, and cultural traditions depend upon the natural environment will likely be affected by the degradation of ecosystem goods and services associated with climate change.
Southwest native cultures are especially vulnerable to water quality and availability impacts. Native Alaskan communities are likely to experience disruptive impacts, including coastal erosion and shifts in the range or abundance of wild species crucial to their livelihoods and well-being. The most recent assessments continue to strengthen scientific understanding of climate change risks to minority and low-income populations in the United States. The new assessment literature provides more detailed findings regarding these populations' vulnerabilities and projected impacts they may experience. In addition, the most recent assessment literature provides new information on how some communities of color may be uniquely vulnerable to climate change health impacts in the United States. These studies find that certain climate change related impacts -- including heat waves, degraded air quality, and extreme weather events -- have disproportionate effects on low-income and some communities of color, raising environmental justice concerns. Existing health disparities and other inequities in these communities increase their vulnerability to the health effects of climate change. In addition, the studies also find that climate change poses particular threats to health, wellbeing, and ways of life of indigenous peoples in the United States.
As the scientific literature presented above and in the Endangerment Finding illustrates, low income communities and communities of color are especially vulnerable to the health and other adverse impacts of climate change.
The EPA believes the human health or environmental risk addressed by this final action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations. The final rule limits GHG emissions from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units and natural gas-fired stationary combustion turbines by establishing national emission standards for CO2.
The EPA has determined that the final rule will not result in disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because the rule is not anticipated to notably affect the level of protection provided to human health or the environment. The EPA believes that electric power companies will choose to build new fossil fuel-fired electric utility steam generating units and natural gas-fired stationary combustion turbines that comply with the regulatory requirements of the final rule because of existing and expected market conditions. The EPA does not project any new coal-fired steam generating units without CCS to be built and expects that any newly built natural gas-fired stationary combustion turbines will meet the standards. In addition, as previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines in the period of analysis. This final rule will ensure that, to whatever extent there are newly constructed, modified, and reconstructed EGUs, they will use the best performing technologies to limit emissions of CO2.
7.11	Congressional Review Act (CRA)
This final action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is not a "major rule" as defined by 5 U.S.C. 804(2).


[Federal Register Volume 80, Number 39 (Friday, February 27, 2015)]
[Proposed Rules]
[Page 10655]
[FR Doc No: 2015-04010]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R05-OAR-2011-0888; EPA-R05-OAR-2011-0969; EPA-R05-OAR-2012-0991;
EPA-R05-OAR-2013-0435; FRL-9923-47-Region 5]

Approval and Promulgation of Air Quality Implementation Plans;
Ohio; PSD Infrastructure SIP Requirements for the 2008 Lead, 2008
Ozone, 2010 NO2, and 2010 SO2 NAAQS

AGENCY: Environmental Protection Agency.

ACTION: Proposed rule.

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SUMMARY: The Environmental Protection Agency (EPA) is proposing to
approve elements of state implementation plan submissions from Ohio
regarding the Prevention of Significant Deterioration infrastructure
requirements of section 110 of the Clean Air Act (CAA) for the 2008
lead (Pb), 2008 ozone, 2010 nitrogen dioxide (NO2), and 2010
sulfur dioxide (SO2) National Ambient Air Quality Standards
(NAAQS). The infrastructure requirements are designed to ensure that
the structural components of each state's air quality management
program are adequate to meet the state's responsibilities under the
CAA.

DATES: Comments must be received on or before March 30, 2015.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R05-
OAR-2011-0888 (2008 Pb infrastructure elements), EPA-R05-OAR-2011-0969
(2008 ozone infrastructure elements), EPA-R05-OAR-2012-0991 (2010
NO2 infrastructure elements), or EPA-R05-OAR-2013-0435 (2010
SO2 infrastructure elements) by one of the following
methods:
    1. www.regulations.gov: Follow the on-line instructions for
submitting comments.
    2. Email<EMAIL_ADDRESS>    3. Fax:<PHONE_NUMBER>.
    4. Mail: Douglas Aburano, Chief, Attainment Planning and
Maintenance Section, Air Programs Branch (AR-18J), U.S. Environmental
Protection Agency, 77 West Jackson Boulevard, Chicago, Illinois 60604.
    5. Hand Delivery: Douglas Aburano, Chief, Attainment Planning and
Maintenance Section, Air Programs Branch (AR-18J), U.S. Environmental
Protection Agency, 77 West Jackson Boulevard, Chicago, Illinois 60604.
Such deliveries are only accepted during the Regional Office normal
hours of operation, and special arrangements should be made for
deliveries of boxed information. The Regional Office official hours of
business are Monday through Friday, 8:30 a.m. to 4:30 p.m., excluding
Federal holidays.
    Please see the direct final rule which is located in the Rules
section of this Federal Register for detailed instructions on how to
submit comments.

FOR FURTHER INFORMATION CONTACT: Sarah Arra, Environmental Scientist,
Attainment Planning and Maintenance Section, Air Programs Branch (AR-
18J), Environmental Protection Agency, Region 5, 77 West Jackson
Boulevard, Chicago, Illinois 60604,<PHONE_NUMBER><EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: In the Final Rules section of this Federal
Register, EPA is approving the State's SIP submittal as a direct final
rule without prior proposal because the Agency views this as a
noncontroversial submittal and anticipates no adverse comments. A
detailed rationale for the approval is set forth in the direct final
rule. If no adverse comments are received in response to this rule, no
further activity is contemplated. If EPA receives adverse comments, the
direct final rule will be withdrawn and public comments received will
be addressed in a subsequent final rule based on this proposed rule.
EPA will not institute a second comment period. Any parties interested
in commenting on this action should do so at this time. Please note
that if EPA receives adverse comment on an amendment, paragraph, or
section of this rule and if that provision may be severed from the
remainder of the rule, EPA may adopt as final those provisions of the
rule that are not the subject of an adverse comment. For additional
information, see the direct final rule which is located in the Rules
section of this Federal Register.

    Dated: February 17, 2015.
Susan Hedman,
Regional Administrator, Region 5.
[FR Doc. 2015-04010 Filed 2-26-15; 8:45 am]
BILLING CODE 6560-50-P