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1 11/2 draft EO12866EGUGHGNSPSRIA2060 - AQ9120111104Ch5.docx

**Chapter 5**  **Costs, Economic and Energy Impacts**
**5 .1**  **Synopsis** Because there are no forecasted additions of non - compliant EGU facilities ( e.g., new coal
- burning power stations without carbon controls) during the analysis period (2020 ) , t his proposed GHG EGU NSPS is not expected to change GHG emissions for newly constructed electric generating units, n or is it anticipated to impose notable costs , economic, or energy impacts on the EGU sector or society. **5 .2**  **Background** Over the last decade, EPA has conducted extensive analyses of regulatory actions impacting the power sector. These efforts support the Agency’s understanding of key policy variables and provide the framework for how the Agency estimates the cos ts and benefits associated with its actions. C urrent forecasts for the mix of new, and utilization of existing generating capacity are a key input into informing the design of EPA’s proposal
. Given excess capacity within the existing fleet and relatively low forecasts of electricity demand growth, there is a limited new capacity, of any type , expected to be constructed within the foreseeable future. A small number of new coal
-fired power plants have been built in recent years; however, EPA do es not forecast the construction of any new unplanned coal
- fired additions over the time horizon of this analysis
. There are two main reasons why EPA expects there will be no currently unplanned coal
fired power plants constructed over the time horizon considere d for this analysis
. First, the current economic and financial situation has dampened electricity demand , and thus there is less need for new generating capacity in the foreseeable future . Second, generating technologies using natural gas produce electri city at lower cost than other generating technologies, and therefore for the foreseeable future utilities are likely to rely heavily on generation from combustion turbine and combined cycle plants using natural gas when they do need to expand capacity. This circumstance is different than from a few years ago as current and forecast natural gas prices are considerably lower than levels seen over the past decade. This is because new drilling techniques have brought su bstantial additional supply to the marketplace. Based on these market conditions, on average t he cost of generation from a new natural gas power plant is expected to be lower than the cost of generation from a new coal
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2 11/2 draft fired power plant. 1 This trend is a lready apparent in recent history, where natural gas
-fired capacity was the technology of choice for power generation over the last few years (see Figure 5 - 1).
**Figure 5**  **- 1**  **. Historical U.S. Power Plant Capacity Additions, by Technology** 

Source: National Electric Energy Data System (NEEDS) v4.10_PTox Various energy sector modeling efforts, including recent projections from both EIA and EPA, show results that are consistent with these findings. The Annual Energy Outlook (AEO) for 2011 sho ws a very modest amount of CCS
- equipped new coal
-fired power coming online past 2012, however since the se plants are CCS
- equipped in response to Federal incentives , they would be in compliance with this proposal
. 2 According to the AEO 2011, the majority of new generating capacity will be either natural gas
- fired or renewable, with some lesser amounts of nuclear power. The AEO 2011 is based on existing policy and regulations, such as state RPS

1 Levelized Cost of New Generation in the Annual Energy Outlook 2011 , http://205.254.135.24/oiaf/aeo/electricity_generation.html 2 AEO 2011 has a small amount of planned coal capacity that is under construction and expected to come online in the next year. It also has 2 GW of unplanned coal capacity, which reflects new coal with CCS in response to Federal incentives. 0

10,000 20,000 30,000 40,000 50,000 60,000 70,000**C a** **p a** **c i** **t y** **( M** **W )**  Ot her Gas (CC a nd C T) Ren ewable/Hydro Nuclear Co al***E.O. 12866 Review
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3 11/2 draft programs and Federal t ax credits for renewables. 3 The Department of Energy (DOE) concluded, based on EIA analysis, that “the low capital expense, technical maturity, and dispatchability of natural gas generation are likely to dominate investment decisions under current policie s and projected prices." 4 The economics favoring new NGCC builds instead of conventional coal are robust under a range of sensitivity cases examined in the AEO. Neither planned nor unplanned additions of coal by 2020 increase in sensitivity cases that ex amine higher economic growth, lower coal prices, low fossil costs, no concern regarding future GHG policy, slow oil and gas technology deployment, low shale gas recovery per play, and low shale gas recovery per well. EPA uses the Integrated Planning Model (IPM ) to support its understanding of the economic and emissions impacts of air regulations on the power sector. IPM projections show similar patterns of future power plant deployment as AEO 2011, and IPM projections show no construction of new conventio nal coal
-fired power plants under the base case. 5 EPA has used IPM to consider control options for reducing power
- sector emissions for two decades. The model has been used by the Agency to support regulatory initiatives as well as legislative proposals designed to address air emissions for the power sector. All of the analyses are available at EPA’s website and in the public docket. 6 The baseline information in this RIA is based on the same power sector modeling platform used for the proposed Mercury an d Air Toxics Standards (MATS) from March 2011. 7 This platform includes the parameters and rule requirements from proposed MATS and the proposed Transport Rule , which was later renamed as the Cross State Air Pollution Rule (CSAPR) upon subsequent finalization. The analysis reflected in this RIA was being developed while MATS and CSAPR were still being finalized ; as a result , the baseline referenced here includes those rule s in their proposal form s . Modeling results with the rules in their final forms is unlikely to materially alter EPA’s base case forecast using IPM. In addition to the proposed Transport Rule and MATS , the baseline takes into account emissions reductions associated with the implementation of all federal rules, st ate rules and statutes, and other binding, enforceable commitments that are applicable to the power industry and which govern the installation and operation of pollution controls in the timeframe covered in the analysis. As noted above, IPM has been used for evaluating the economic and emission impacts of environmental policies for over two decades. The economic modeling presented in this

3 http://www.ei a.gov/forecasts/aeo/chapter_legs_regs.cfm 4 Department of Energy (2011). Report on the First Quadrennial Technology Review. Available at http://energy.gov/sites/prod/files/QTR_report.pdf
. 5 http://www.epa.gov/airmarkets/progsregs/epa
- ipm/BaseCasev410.html# documentation 6 http://www.epa.gov/airmarkt/progsregs/epa
- ipm/index.html 7 http://www.epa.gov/airmarkets/progsregs/epa
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4 11/2 draft chapter has been developed for the specific analyses of the power sector. Thus, the model has been designed to reflect the industry as accurately as possible. EPA uses the best available information from utilities, industry experts, gas and coal market experts, financial institutions, and government statistics as the basis for the detailed power sector modeling in IPM. More detail on IPM can be found in the model documentation, which provides additional information on the assumptions discussed here as well as all other assumptions and inputs to the model. 8 **5 .3**  **External Review of EPA Applications of the Integrated**  **Planning Model (IPM)** The model undergoes periodic formal peer review, which includes separate expert panels on the model itself, and EPA’s key modeling input assumptions. For example, over the past ten years several separate panels of independent experts have been convened to review IPM’s coal supply and transportation assumptions, natural gas assumptions, and model formulation. The rulemaking process also provides opportunity for expert review and comment by a variety of stakeholders, including owners and operators of the electricity sector that is represented by the model, public interest groups, and other developers of the U.S. electricity sector models . The feedback that the Agency receives provides a highly detailed reality check of key input assumpti ons, model representation, and modeling results. The Agency has used IPM in several recent regulatory contexts. The model has been used to support the Agency’s analytics for the Clean Air Interstate Rule (CAIR), the Cross State Air Pollution Rule (CSAPR), the proposed Mercury an Air Toxics Standards (MATS), and over a dozen legislative analytical efforts to understand the costs, benefits, and power sector impacts of various policies to reduce power sector emissions. As part of the rulemaking process, EPA is required to respond to every significant comment submitted. The model has also been used by states (e.g., for Regional Greenhouse Gas Initiative (RGGI), the Western Regional Air Partnership (WRAP), Ozone Transport Assessment Group (OTAG), other Federa l and State agencies, environmental groups, and industry, all of whom subject the model to their own review procedures. More specifically, the model has received extensive review by energy and environmental modeling experts over the past two decades. Stat es have used the model extensively to inform issues related to ozone in the northeastern portion of the U.S. This groundbreaking work set the stage for the NOx SIP call, which has helped reduce summer NOx emissions and the formation of ozone in densely po pulated areas in the northeast. In the late

8 http://www.epa.gov/airmarkets/progsregs/epa
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5 11/2 draft 1990’s, the Science Advisory Board reviewed IPM as part of the CAAA Section 812 prospective studies that are conducted periodically. The model has also undergone considerable interagency scrutiny as part of a s eries of legislative analysis over the past decade. These analyses explored a variety of approaches to controlling emissions from the power sector, and the results were presented to Congress in a comparative manner in order to evaluate the merits of policy proposals. The model was also used to support the Agency’s power sector analyses of legislative climate proposals in 200 5 , continuing through 2010. In addition, Regional Planning Organizations (RPOs) throughout the U.S. have extensively examined IPM as a key element in the SIP process for NAAQS. Lastly, the Agency has exercised the model over the past 15 years in a number of comparative modeling exercises sponsored by Stanford University’s Energy Modeling Forum. **5.4 Base Case Analysis of Future Gene**  **rating Capacity** EPA began its analysis of the economic impacts of the proposed NSPS by conducting a base case analysis of future generating capacity. This base case incorporates the proposed Mercury and Air Toxics Standards and the proposed Transport Rule. 9 The IPM base case projection includes a 1% growth in electricity demand, similar to EIA. This new demand will be fulfilled by existing generating capacity that is currently not being fully utilized , and new renewable and gas
-fired generating capacity (s ee Table 5
- 1). The change in coal represents only retirements of existing plants and no new unplanned coal builds. These projections are the result of least
- cost dispatching using IPM, and reflect the most cost
effective options, given a variety of varia bles and constraints. Although most new generating capacity will be renewable and natural gas - fired, U.S. electricity demand will continue to be met by a diverse mix of electricity generation sources (see Table 5
- 2)
. In addition, coal is projected to co ntinue to provide the largest share of America’s electricity. By 2020, EPA forecast s roughly 27 GW of new renewable capacity, 2 GW of coal with CCS, and 10 GW of natural gas
-fired capacity. Although 2 GW of coal with CCS is included in the base case, ove rall coal capacity is forecast to decline in response to current economics, along with some retirements due to upcoming air regulations (CSAPR and MATS). Relative to current levels, EPA anticipates that the existing coal fleet will increase utilization wh ile gas
-fired sources will decrease utilization slightly. Th is dynamic largely emanates from somewhat atypical supply and demand trends experienced in energy markets over the past few years , where overall electricity demand has been soft, natural gas prices have dropped considerably, and coal prices have risen. **Table 5 -**  **1 . Total Generation Capacity in 2010 and Projected by 2020 (GW)** 

9 http://www.epa.gov/airquality/powerplanttoxics , and http://www.epa.gov/airtransport
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6 11/2 draft 2010 2020 Pulverized Coal 317 299 Natural Gas Combined Cycle 201 212 Combustion Turbine 138 143 Oil/Gas Steam 115 90 Non - Hydro Renewables 31 73 Hydro 99 99 Nuclear 102 106 Other 5 7 **Total 1,009**  **1,029** Note s : The sum of the table values in each column may not match the total figure due to rounding. Source: 2010 data from EPA's NEEDS v.4.10 PTR. Projections from Integrated Planning Model run by EPA. Note: “Non
- Hydro Renewables” include biomass, geothermal, solar, and wind electric generation capacity. The capacity of a generating un it that is co
- firing gas in a coal boiler is split in this table between “pulverized coal” and “Oil/Gas Steam” proportionally by fuel use.
**Table 5**  **- 2**  **. 2009 U.S. Electricity Net Generation and EPA Base Case Projections for 2020 (Billion kWh)**  Historical Projected 2009 2020 Coal 1,756 1,976 Oil 39 0.129 Natural Gas 921 873 Nuclear 799 841 Hydroelectric 273 287 Non - hydro Renewables 144 288 Other 18 45 **Total 3,950**  **4,309** Note s : The sum of the table values in each column may not match the total figure due to rounding. Source: 2009 data from EIA Electric Power Annual 2009, Table 2.1; Projections from Integrated Planning Model run by EPA, 2011
.
**5. 5**  **Analysis of Applicability of Proposed EGU GHG NSPS to Projected New Generating Capacity**  As the sec ond step in the analysis, EPA analyzed the applicability of the NSPS to new generating capacity anticipated to be built through 2020 , and whether the requirements would require the regulated community to take actions different from those projected in the b ase case .***E.O. 12866 Review
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7 11/2 draft The proposed EGU GHG NSPS discusses potential requirements for four types of units or actions: newly constructed units, reconstructed units, modified units , and transitional units. Analysis performed by EPA, along with information from other sources , suggests that the standards as specified in this proposed rule are not likely to result in notable emission changes , energy impacts, monetized benefits , costs , or economic impacts by 2020. This is because analyses performed both by EPA and the U. S. Energy Information Admini stration (EIA) , as well as statements and actions of a number of major utilities , demonstrate that generation technologies other than coal ( mostly natural gas and renewable sources) are likely to be the technologies of choice fo r new sources due to current and projected market conditions
. **5 .**  **5 .1**  **New Units** This proposal requires that all new fossil
-fuel fired units of 25 megawatt or greater capacity be able to meet an emission rate standard of 1 , 000 pounds of CO 2 per megawatt hour (lbs CO 2/ MWh ) . It also proposes an alternative standard that would allow units to meet the 1 , 000 lbs CO 2/MWh standard using a 30 year averaging period. These standards could be met either by natural gas combined cycle generation or coa l
-fired generation using carbon capture and sequestration technology (CCS). Of the new generating capacity projected to be constructed by 2020, only the fossil
- fuel
fired units would be subject to the proposed GHG NSPS for EGU. The NGCC units, which ar e the basis of the proposed standard, will meet the proposed standard through their inherent design. No units projected to be built would be subject to the proposed NSPS. This indicates that the NSPS will require no changes in design or construction of n ew EGU s forecasted in the base case. Thus, there would be no expected reduction in emissions and no costs for the newly constructed EGU s forecasted
. As described above, t he base case modeling that EPA performed for this rule (as well as base case modeling that EPA has performed for other recent air rules) indicates that new fossil fuel
-fired generating capacity projected to be built through 2020 will be either natural gas
-fired combined cycle generation or coal
-fired generation with CCS (the l atter is assumed to be built with support from federal grants ) . The EIA’s Annual Energy Outlook (AEO) 2011 modeling makes similar conclusions. A number of major utilities have made public announcements consistent with these modeling results. 10

10 For example: “We have no other coal
-fueled generation planned at this time... When we do need new capacity, it is highly likely that we will look to natural gas plants instead of coal, especially if natural gas prices remain as low as projected.” AEP January 1, 2011, Washington Post ; “If you actually look at the economics today, you would be burning gas, not coal,” Jack Fusco, Calpine, 12/1/2010, Marketplace; “Coal’s most ardent defenders are in no***E.O. 12866 Review
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8 11/2 draft E ngineering cost analysis , even outside of a least
- cost system dispatch modeling environment, reaches similar conclusions. I f one assumes a natural gas price of $5 per million British Thermal Units ( mm Btu ) and a coal price of $2 per mmBtu , which roughly re flect forecasted prices in 202 0, 11 electricity generated by natural gas combined cycle units is less expensive on average than coal generation. A comparison of whole sale electricity costs for differing generation technologies and natural gas prices are shown in Figure 5 - 2 and Table 5 - 3 . **Figure 5**  **- 2**  **. Illustrative**  **Wholesale Levelized**  **Cost of Electricity of Alternative New**  **Generation Technologies** **, EPA ($2007)**

Notes: Assumptions derived from EPA’s application of IPM. T echnologies include Coal without CCS, Natural Gas Combined Cycle with natural gas costing $5 per mmBtu , Natural Gas Combined Cycle with $8 per mmBtu costs of natural gas, and Integrated Gasification Combined Cycle with CCS. All values in this graph assume a coal is high sulfur bituminous at $2 mmBtu, with a heat rate of 8,87 5 net . It is only when gas prices reach approximately $8/ mmBtu , that coal
- fired generation without CCS becomes competitive in terms of dollars per megawatt hour wholesale cost of electricity generation. For context, even EIA’s most pessimistic gas sensitivity case (“low shale gas recovery per well”) only projects an e lectricity sector gas price of $8.17 in 2030 (the “low shale gas recovery per play” scenario projects a price of $7.36/ mmBtu in 2030). However, it is important to note that this analysis is based on assumptions regarding the average national cost of gener ation at new facilities. As reported by the EIA, there is expected to be significant spatial variation in the costs of new generation due to design differences, labor hurry to build new ones in this environment.” John Rowe, Exelon, 9/2011, EnergyBiz; “ With low gas prices, gas
fired generation kind of snowplows everything else” Lew Hay, NextEra, 11/1/2010, Dow Jones. 11 EIA projects a U.S. average coal price of $1.65/MMBtu in 2020 ($2009). Bituminous coals are roughly $2. EPA and EIA both project delive red (power sector) natural gas price of roughly $5/mmBtu in 2020.

0 20 40 60 80 100 120 140

Conventional

Coal Natural Gas

Combined Cycle ($5 gas) Natural Gas

Combined Cycle ($8 gas) Coal + CCS**$ /** **M W** **h*****E.O. 12866 Review
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9 11/2 draft wage and productivity differences, location adjustments, among other potential differenc es. 12 The comparison also does not explicitly consider units designed to combust waste coal or pet coke, which may exhibit different local economics. However, the results are expected to hold for the majority of situations.
**Table 5**  **- 3**  **. Estimated Levelized Cost of New Generation Resources from EIA** **, U.S. Average (2016)** 

**Plant Type Capacity**  **Factor (%) U.S. Average Levelized Costs (2009 $/**  **MWh )**  **for Plants Entering Service in 2016 Levelized**  **Capital Cost**  **Fixed O&M Variable O&M**  **(Including fuel) Transmission** 

**Investment Total** 

**System Levelized**  **Cost Conventional Coal**  85 65.5 3.9 24.5 1.2 95.1 **Advanced Coal** 85 74.7 7.9 25.9 1.2 109.7 **Advanced Coal with CCS** 85 92.9 9.2 33.3 1.2 136.5 **Natural Gas -** **fired Conventional Combined Cycle**  87 17.5 1.9 44.6 1.2 65.1 **Advanced Combined Cycle** 87 17.9 1.9 41.2 1.2 62.2 **Advanced CC with CCS** 87 34.7 39 48.6 1.2 88.4 **Conventional Comb .**  **Turbine** 30 45.8 3.7 69.9 3.5 123 **Advanced Combustion Turbine** 30 31.7 5.5 61.3 3.5 102.1 **Advanced Nuclear**  90 90.2 11.1 11.7 1.0 114.0 **Wind** 34 83.3 9.5 0 3.4 96.1 **Wind -**  **Offshore** 34 209.7 28.1 0 5.9 243.7 **Solar PV** 25 194.9 12.1 0 4.0 211.0 **Solar Thermal** 18 259.8 46.6 0 5.8 312.2 **Geothermal** 91 77.4 11.9 9.5 1.0 99.8 **Biomass** 83 55.4 13.7 42.3 1.3 112.6 **Hydro** 53 78.5 4.0 6.2 1.8 90.5 **Source: EIA, AEO 2011**

**5 .**  **5 .2**  **Reconstructed Units** The EPA’s CAA section 111 regulations define reconstructed sources as, in general, existing sources (i) that replace components to such an extent that the capital costs of the new components exceed 50 percent of the capital costs of an entirely new facilit y, and (ii) for which compliance with standards of performance for new sources is technologically and economically

12 http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf***E.O. 12866 Review
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10 11/2 draft feasible (40 CFR 60.15). The Agency is aware that, in theory, operators of existing power plants may choose to reconstruct them, but we are not aware of any announced plans to do so. This provision is rarely triggered. In the proposed NSPS, EPA is taking comment on different approaches to regulation of reconstructed sources. The options for reconstructed sources, in general, include (i) not taking final action to establish a new standard of performance, which, as a practical matter, would mean that reconstructed sources would be treated as existing sources; (ii) establishing the standard of performance at either the same level as for new sour ces or at the supercritical efficiency level.

 If reconstructed sources are treated as new sources, this rule would not establish applicable requirements for them.  If reconstructed sources are regulated as the supercritical efficiency level, EPA would not expect the requirement to change firms’ behavior because they would be expected to choose technologies that are compliant with the standard even in the absence of the standard.  The same is true if reconstructed sources are required to meet the proposed new source standard. T he costs associated with reconstructing coal
-fired units are likely to be similar to the cost of building a new natural gas
-fired unit. Thus, even if this provision is triggered, EPA believes that the economic analysis outlined above s howing that natural
- gas -fired generation is significantly more cost effective than building a reconstructed coal plant results in the choice of natural gas combined cycle or coal with CCS technology (i.e., existing unit operators are likely to choose techn ologies for independent market reasons that are already compliant with the new source NSPS included in this proposal). **5 .**  **5 .3**  **Modified Units** As explained in the preamble, EPA is not aware of any EGUs that would undertake actions defined as modifications. A modification is any physical change in, or change in the method of operation of, a source that increases the amount of any air pollutant emitted by the source or results in the emission of any air pollutant not previously emitt ed. The EPA is solicit ing comment on th is issue, but in the meantime, the EPA is not proposing standards for modifications. The Agency believes that it does not , at present , have adequate information as to the type of action, its costs, or the amount of its CO 2 emissions, on which to base a proposed standard of performance. Therefore, sources that undertake physical or operational changes that increase their maximum achievable hourly CO 2 emission rate will be treated as existing sources , and thus they wi ll not be subject to the propose d EGU GHG NSPS requirements for new sources . **5 .**  **5 .4**  **Transitional Units*****E.O. 12866 Review
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11 11/2 draft In the proposal, EPA identifies transitional sources as those sources that have received permits to construct, but have not actually commenced construction. EPA believes that there are approximately 18 such units discussed previously in C hapter X . Historically, obtaining a permit does not guarantee that a unit will end up being constructed. In the last 10 years, 88 coal plants have been permitt ed. Of those, 40 (or less than half) have actually commenced construction. Thirty projects have been cancelled and approximately 18 sources (the transitional sources) have active permits. Based on this history, EPA believes that a t least some number of these units would not likely proceed to construction , regardless of the requirements of this rule. For these units, this rule adds no costs. Furthermore, in its rule, EPA is proposing that as long as units commence construction within a set amount of tim e, construction can proceed without being affected by this rule. For these units, this rule adds no additional costs and will not result in any monetized benefits
. In the absence of this rule, EPA believes the coal units that are most likely to commence construction are those that have received public incentives to install CCS. Under the proposed rule, t hese units would be able to commence construction within the proposed rule time
-frame without incurring any requir ement to reduce CO 2 emissions . EPA also believes that the economics demonstrated above also apply to the other transitional units; therefore, building natural gas
-fired combined cycle generation is likely to be a less expensive option than traditional coa l
-fired generation , even in the absence of this rule . T he developers of the projects already permitted are likely reconsidering these economic factors and may ultimately choose not to commit to actual construction of the se previously proposed coal plants
. **5 .**  **6 Summary of**  **Costs, Economic** **, and Energy Impacts of the Propos**  **ed Rule for New,**  **Reconstructed, Modified, and Transi tional Electric Generating Units**  EPA does not anticipate that the proposed GHG EGU NSPS will r esult in notable CO 2 emission changes, energy impacts, or costs for new units constructed by 2020. EPA believes that the industry will choose to construct new units that already meet the se standards due to current and expected economic conditions, regardless of this proposal
. Likewise, the Agency believe s this rule will not have notable impact s on the price of electricity or energy supplies in this country
. This finding is supported by EPA modeling of the base case , which does not project the future construction of new coal
- fired capacity beyond 2 GW of coal with CCS, which is built in response to the financial incentives for CCS included in the Emergency Economic Stabilization Act of 2008 and American Recovery and Reinvestment Act of 2009, which authorized and/or appropriated funding to DOE for CCS deployment. In the short
-term, most new capacity is***E.O. 12866 Review
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12 11/2 draft projected as a mix of wind and natural gas in response to the competitive marketplace for fuel s and other energy poli cies (such as tax credits and state renewable portfolio standards). In addition, future electricity demand expectations have trended downwards in recent forecasts, reducing the need for new capacity by 2020 (see Chapter X for more discussion on future el ectricity demand). Electricity demand is anticipated to grow by roughly 1 percent per year, and total electricity demand is projected to be 4,104 billion kWh by 2015. Table 5
- 2 shows current electricity generation alongside EPA’s projection for 20 20 using IPM. EPA’s IPM modeling for this rule relies on EIA’s Annual Energy Outlook for 2010’s electric demand forecast for the US and employs a set of EPA assumptions regarding fuel supplies , the performance and cost of electric generation technologies , p ollution controls , and numerous other parameters
. **5. 7**  **Limitations** Although there is a significant amount of information that points to a future where conventional coal (without CCS) is likely to be more costly to build relative to other, lower emitting sources of electricity (regardless of whether the power sector is reg ulated for greenhouse gases or not), the Agency acknowledge s the possibility that in unusual situations , a company could find it advantageous to build a conventional coal facility if there were no greenhouse gas requirements (i.e., if the social and enviro nmental damages of carbon emissions remain as unpriced externalities not reflected in project economics). While it is difficult to identify and evaluate hypothetical scenarios where this could come to fruition in very limited and localized circumstances, we note that today’s action for new sources would likely prevent these occurrences, since new sources would be required to meet the proposed NSPS standards. **5. 8**  **Benefits of Reduced Regulatory Uncertainty** Most major actors in the power sector anticipate eventual CO 2 emissions policy for power plants, a performance standard for new sources can reduce uncertainty by setting clear parameters for the planning of new generation. The presence of sustained regulatory uncertainty may affect the decisi ons of firms, leading them to potentially forgo more profitable investment strategies that would occur in the presence of increased regulatory certainty (Teisberg 1993, Hoffmann et al., 2009). In particular, uncertainty regarding future greenhouse gas pol icy may affect firms’ decisions with regards to the timing and types of investments made in new electricity generating capital (Blyth et al., 2007). A significant reduction in regulatory uncertainty may then increase the expected profits for firms within the electricity generating sector by allowing them to optimize investment decisions with a greater understanding as to***E.O. 12866 Review
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13 11/2 draft the future operating environment (e.g., Reinelt and Keith, 2007; Patiño
- Echeverri et al., 2009). EPA is not able to directly quantify or monetize this benefit at this time
. **5. 9**  **Comparison of Emissions Differences of**  **Generation Technologies** As discussed earlier in this chapter, natural gas units are on average expected to be more economic al to build and operate than new coal units. These natural gas units also have lower emission profiles for CO 2 and criteria air pollutants than new coal units
. While the baseline forecast suggests that the proposed GHG EGU NSPS will have no monetized benefi ts or costs, it is instructive to consider the differences in emissions of CO 2 and conventional air pollutants between the two types of units. EPA does not anticipate any incremental changes to coal or natural gas capacity as a result of this rule as prop osed , and as such, these comparisons are purely for illustrative purposes. As Table 5 - 4 below shows , emission s from a typical new natural gas combined cycle facility are significantly lower than those from a traditional coal unit
. For example, a typical new supercritical pulverized coal facility that burns bituminous coal in compliance with new utility regulations (e.g., CSAPR and MATS) would have considerably greater CO 2 , SO 2 , and NO x emissions than a comparable natural gas combined cycle facility. A typical natural gas combined cycle unit is expected to emit two million metric tons less CO 2 per year than a typical new coal unit, as well as , 2,000 fewer short tons SO 2 and 1,200 few er short tons of NO x each year . Reductions in SO 2 emissions are a particularly significant driver for monetized health benefits, as SO 2 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 effects is included in the next subsection.

**Table 5**  **- 4. Illustrative Emissions**  **Profiles ,**  **New Coal and Natural Gas**  **- Fired**  **Generating Units Conventional**  **Coal Natural Gas CC**  **Coal with CCS SO**  **2 tons/year**  2,000
--- Negligible **NO x**  **tons/year** 1,400 200 1 , 100 **CO 2**  **tons/year** 3.6 million 1. 6 million 0. 4 5 million Notes: Criteria pollutants in short tons , CO 2 in metric tons . Relative emissions for new well controlled 600 MW (net) units running at 85% capacity factor
. Assumed coal is high sulfur bituminous with scrubber and SCR . Data is based on EPA assumptions used in IPM.
**5. 8** **.1 Benefits of Reducing GHGs and**  **Criteria Pollutants** ***E.O. 12866 Review
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14 11/2 draft As shown in this illustrative example, n atural gas combined cycle units are expected to be more economic al to build and operate on average than new coal units and have lower emissions of CO 2 and conventional pollutants
. While baseline forecasts suggest that the proposed NSPS will have no notable costs or monetized benefits , it is instructive to consider the benefits associated with the differences in emissions of CO 2 and criteria air pollutants in the previous illustrative example
. EPA do es not anticipate any incremental changes to new coal or natural gas capacity as a result of this rule, and as such, these comparisons are purely for illustrative purposes
. The social cost of carbon (SCC) is a metric to estimate the monetary value of benefits associated with marginal changes in CO 2 emissions , and may therefore be utilized to un derstand the value of the difference in CO 2 emissions between the two hypothetical units discussed in section 5 .4 . The SCC is an estimate of the monetized damages associated with an incremental increase in carbon emissions in a given year. It is intended to include (but is not limited to) changes in net agricultural productivity, human health, property damages from increased flood risk, and the value of ecosystem services due to climate change. Federal agencies typically use SCC estimates to assess the b enefits of rulemakings that achieve marginal reductions in CO 2 emissions. These estimates were developed through an interagency process that included EPA and other executive branch entities, and concluded in February 2010. The SCC Technical Support Docum ent (SCC TSD) provides a complete discussion of the methods used to develop these SCC estimates. 13 The interagency group selected four SCC values for use in regulatory analyses: $7, $26, $42, and $81 per metric ton of CO 2 emissions in 2020, in 2007 doll ars. 14 The first three values are based on the average SCC from three integrated assessment models, at discount rates of 5, 3, and 2.5 percent, respectively. SCCs at several discount rates are included because the literature shows that the SCC is quite sen sitive to assumptions about the discount rate, and because no consensus exists on the appropriate rate to use in an intergenerational context. The fourth value is the 95th percentile of the SCC from all three models at a 3 percent discount rate. It is inc luded to represent higher
-than
- expected impacts from temperature change further out in the tails of the SCC distribution. Low probability, high impact (“catastrophic”) events we re

13 Docket ID EPA
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- 114577, T echnical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon , with participation by Council of Economic Advisers, Council on Environmental Quality, Departmen t of Agriculture, Department of Commerce, Department of Energy, Department of Transportation, Environmental Protection Agency, National Economic Council, Office of Energy and Climate Change, Office of Management and Budget, Office of Science and Technology Policy, and Department of Treasury (February 2010). Also available at http://epa.gov/otaq/climate/regulations.htm 14 Note that upstream emissions changes were not considered for this rule. There may be changes in greenhouse gas emissions (in particular, methane) due to changes in fossil fuel extraction and transport in response to this proposal, but those were not quantified
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15 11/2 draft reflected in two of the three models , but the interagency group nonetheless concluded that a limitation of the analysis was inadequate treatment of these potential catastrophic events. A probability density function was used for equilibrium climate sensitivity. Treating climate sensitivity probabilistically results in more high temperature outcomes, which in turn lead to higher projections of damages. The SCC increases over time because future emissions are expected to produce larger incremental damages as physical and economic systems become more stressed in response to greater climatic change. Note that the interagency group estimated the growth rate of the SCC directly using the three integrated assessment models rather than assuming a constant annual growth rate. This helps to ensure that the estimates are internally consiste nt with other modeling assumptions. Table 4
- 1 presents the SCC estimates for the years 2015 to 2050. When attempting to assess the incremental economic impacts of carbon dioxide emissions, the analyst faces a number of serious challenges. A recent report from the National Academies of Science (NRC 2009) points out that any assessment will suffer from uncertainty, speculation, and lack of information about (1) future emissions of greenhouse gases, (2) the effects of past and future emissions on the climat e system, (3) the impact of changes in climate on the physical and biological environment, and (4) the translation of these environmental impacts into economic damages. 15 As a result, any effort to quantify and monetize the harms associated with climate ch ange will raise serious questions of science, economics, and ethics and should be viewed as provisional. The interagency group noted a number of limitations to the SCC analysis, including the incomplete way in which the integrated assessment models capt ure catastrophic and non
catastrophic impacts, their incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk aversion. Current integrated assessment mode ls do not assign value to all of the important physical, ecological, and economic impacts of climate change recognized in the climate change literature because of lack of precise information on the nature of damages and because the science incorporated int o these models understandably lags behind the most recent research. The limited amount of research linking climate impacts to economic damages makes the interagency modeling exercise even more difficult. The interagency group hopes that over time researc hers and modelers will work to fill these gaps and that the SCC estimates used for regulatory analysis by the Federal government will continue to evolve with improvements in modeling. It is important to emphasize that the interagency process is committed t o updating these estimates as the science and economic understanding of climate change and its impacts on society improves over time. Specifically, they have set a preliminary goal of revisiting the

15 National Research Council (2009). Hidden Costs of Energy: Unpriced Co n sequences of Energy Production and Use
. National Academies Press. See docket ID EPA
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16 11/2 draft SCC values within two years , or at such time as substant ially updated models become available, and to continue to support research in this area. Additional details on these limitations are discussed in the SCC TSD.

**Table 5.5**  **: Social Cost of CO 2** **, 2015 -**  **2050 a**  **(in 2007 dollars)**
**Year Discount Rate and Statistic** 

**5% Average 3% Average**  **2.5% Average 3%**  **95 th**  **percentile 2015**  $6 $24 $38 $73 **2020** $7 $26 $42 $81 **2025** $8 $30 $46 $90 **2030** $10 $33 $50 $100 **2035** $11 $36 $54 $110 **2040** $13 $39 $58 $119 **2045** $14 $42 $62 $128 **2050** $16 $45 $65 $136 a The SCC values are dollar
-year and emissions
-year specific.

As shown in the Table 5
-4, a natural gas unit emits approximately 2,000 ton s less SO 2 and 1,200 tons less NO x annually when compared to a conventional coal unit. SO 2 is a precursor for fine particulate matter (PM 2.5 ) formation. NO X is a precursor for PM 2.5 and ozone formation. As such, reductions of SO 2 and NO X would in turn lower overall ambient concentrations of these pollutants as well as PM 2.5 and ozone. Reduci ng exposure to PM 2.5 and ozone is associated with significant human health benefits, including avoiding mortality and morbidity. Researchers have associated PM 2.5 and ozone exposure with adverse health effects in numerous toxicological, clinical, and epid emiological studies (U.S. EPA, 2009; U.S. EPA, 2006). Health effects associated with exposure to PM 2.5 include premature mortality for adults and infants, cardiovascular morbidity such as heart attacks, hospital admissions, and respiratory morbidity such a s asthma attacks, bronchitis, hospital and emergency room visits, work loss days, restricted activity days, and respiratory symptoms
. Health effects associated with exposure to ozone include premature mortality and respiratory morbidity such as asthma att acks, hospital and emergency room visits, and school loss days. For a full discussion of the human health benefits of reducing SO 2 and NO X emissions from power sector sources, including reducing methyl mercury, SO 2 , and NO 2 exposure, please refer to the Re gulatory Impact Analysis for the Cross
- State Air Pollution Rule (CSAPR) (U.S. EPA, 2011). In addition to human health benefits, reducing SO 2 and NO X emissions would also result in human welfare improvements by improving ecosystem services — the benefits tha t***E.O. 12866 Review
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17 11/2 draft individuals and organizations obtain from ecosystems that directly or indirectly contribute to social welfare. SO 2 and NO X emissions can adversely impact vegetation, certain manmade materials, acidic deposition, nutrient enrichment, visibility, and climate (U.S. EPA, 2009; U.S. EPA, 2008). Reducing these harmful emissions improves human welfare. For more information about t he welfare benefits of SO 2 and NO X emission reductions from power sector sources, please refer to the Regulatory Impact Analysis for the CSAPR (U.S. EPA, 2011). EPA is unable to quantify any portion of the potential health or welfare benefits in terms of incidences of health effects avoided or monetized value of health or welfare improvements due to uncertainty in power plant location and years of operation for this illustrative example
. However, reducing one thousand tons of SO 2 from U.S. EGUs has been e stimated to yield between 5 and 12 incidences of premature mortality avoided and between $39 million and $ 94 million in PM 2.5 - related health benefits on average while reducing one thousand tons of NO X from U.S. EGUs has been estimated to yield between 1 an d 2 incidences of premature mortality avoided and between $7 million and $ 17 million in PM 2.5 - related health benefits on average (Fann et. al 2009). 16 **5. 9**  **Macroeconomic and Employment Impacts** This proposed GHG EGU NSPS is not anticipated to change GHG emissions for newly constructed electric generating units, nor is it anticipated to impose notable costs or have notable economic or employment impacts. EPA typically presents the economic impacts to secondary markets (e.g., changes in industrial markets resulting from changes in electricity prices) and impacts to employment or labor markets associated with proposed rules b ased on the estimated compliance costs and other energy impacts, which serve as an input to such analyses. However, since the EPA does not forecast a change in behavior relative to the baseline in response to this proposed rule, there are no notable macro economic or employment impacts expected as a result of this proposed rule.

16 The results presented here utilize updated health impact assessment inputs, such as updated value of statistical life, and therefore differ from the results presented in the 2009 article. The summary results of this update are available online at ( http://www.epa.gov/air/benmap/bpt.html ). Additionally, the article reports benefits per ton. For this assessment we multiply the benefit per ton by on e thousand to yield benefits per thousand tons. This 2009 article does not explicitly report the incidences of premature mortality. However, this endpoint is the primary driver of the total valued health benefits (which are reported) and thereby provides additional insight into the health effects of these emissions. Th e 2009 article reported the mortality impacts of PM 2.5 exposure based on the findings of Laden et al. 2006. For this illustrative example, EPA provides two estimates of PM 2.5 mortality impacts, a low estimate based on Pope et al. 2002 and a high estimate based on Laden et al. 2006
. The results shown correspond to a 2015 analysis year and a currency year of 2006.***E.O. 12866 Review
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18 11/2 draft **References** U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for Particulate Matter (Final Report). EPA
- 600
- R - 08
- 139F. National Center for Environmental Assessment – RTP Division. December. Available on the Internet at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>. U.S. Environmental Protection Agency (U.S. EPA). 2006. Air Quality Criteria for Ozone and Related Photochemical Ox idants (Final). EPA/600/R
- 05/004aF
- cF. Washington, DC: U.S. EPA. February. Available on the Internet at <http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923>. U.S. Environmental Protection Agency (U.S. EPA). 2008. Integrated Science Assessment for O xides of Nitrogen and Sulfur – Ecological Criteria National (Final Report). National Center for Environmental Assessment, Research Triangle Park, NC. EPA/600/R
- 08/139. December. Available on the Internet at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?de id=201485>. U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis (RIA) for the final Transport Rule. Office of Air and Radiation, Washington, DC. June. Available on the Internet at <http://www.epa.gov/airtransport/pdfs/FinalRIA .pdf>. Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. The influence of location, source, and emission type in estimates of the human health benefits of reducing a ton of air pollution. Air Qual Atmos Health 2:169– 176. Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 2006. Reduction in Fine Particulate Air Pollution and Mortality. American Journal of Respiratory and Critical Care Medicine 1 73:667
- 672. Dalia Patiño
- Echeverri, Paul Fischbeck, and Elmar Kriegler. Economic and Environmental Costs of Regulato ry Uncertainty for Coal
- Fired Power Plants. Environmental Science & Technology **2009** 43 (3), 578
- 584 Reinelt, Peter S.; Keith, David W. Carbon Capture Retrofits and the Cost of Regulatory Uncertainty. **Energy Journal** , 2007, Vol. 28 Issue 4, p101
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19 11/2 draft Hoffmann, Volker H. and Trautmann, Thomas and Hamprecht, Jens. Regulatory Uncertainty: A Reason to Postpone Investments? Not Necessarily. Journal of Management Studies 2009 46 (7), 1467
- 6486. Teisberg, E.O. An option valuation analysis of investment choices by a regulated firm. Management Science, 1994, 40 (4) 535
- 548. Blyth, W. and Yang, M. and Bradley, R. Climate policy uncertainty and investment risk . 2007. OECD/IEA. Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Calle, D. Krewski, K. Ito, and G.D. Thurston. 2002. Lung Cancer, Cardiopul monary Mortality, and Long
-term Exposure to Fine Particulate Air Pollution. Journal of the American Medical Association 287:1132
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