5
- 1 **CHAPTER 5 COSTS,**  **BENEFITS, ECONOMIC AND ENERGY**  **IMPACTS 5.1**  **Synopsis** This chapter reports the compliance cost, economic, and energy impact analysis performed for the EGU GHG NSPS. EPA used IPM , developed by ICF Consulting, in this analysis. IPM is a dynamic linear programming model that can be used to examine air pollution control policies throughout the United States for the entire power system. EPA used the IPM model to forecast likely future electricity marke t conditions with and without the proposed rule
. Because the only capacity additions projected during the analysis period (2020) are compliant with the requirements of this rule (e.g. coal boilers with CCS funded in part through federal subsidies and combined cycle natural gas ) , this proposed EGU GHG NSPS is not expected to change GHG emissions for newly constructed EGUs , nor is it anticipated to impose notable costs, economic impacts , or energy impacts on the EGU sector or society. EPA perform ed sensitivity analys e s that also did not forecast new coal in 2020. **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 polic y variables and provide the framework for how the Agency estimates the costs 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 limited new capacity, of any type , expected to be constructed over the next decade
. A small n umber of new coal

- fired power plants have been built in recent years; however, EPA does not forecast the construction of any new unplanned coal

-fired additions over the time horizon of this analysis ( through the year 2020)
. There are two main reasons why EPA expects no unplanned coal

- fired power plants will be constructed over the time horizon considered for this analysis . First, the current economic situation has dampened electricity demand, and thus there is less n eed for new generating capacity during the analysis period
. Second, generating technologies for new plants using natural gas produce electricity at lower levelized cost than other generating technologies, and therefore utilities are expected to rely heavily on combustion turbine s and combined cycle plants using natural gas when they do need to expand capacity during the time horizon considered for this analysis . This circumstanc e is different than that of a few years ago because5
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current and forecast natural gas prices are considerably lower than the levels seen over the past decade. This is a result of new drilling techniques that have substantial ly incre ased the supply of natural gas potentially available to the marketplace. Based on these market conditions, on average the levelized cost of generation from a new natural gas power plant is expected to be lower than the cost of gener ation from a new coal

- fired power plant. 1 This trend has already been observed recently, as natural gas

-fired capacity was the technology of choice for power generation over the last few years (see Figure 5

- 1).

**Figu re 5**  **- 1. Historical U.S. Power Plant Capacity Additions, by Technology** 

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 Ga s ( CC an d C T) Ren ewable/Hydro Nucl ea r Co al

**Figure 5 -**  **1. Historical U.S. Power Plant Capacity Additions, by Technology**

1 Levelized Cost of New Generation in the Annual Energy Outlook (AEO) 2011 , http://205.254.135.24/oiaf/aeo/electricity_generation.html5
- 3

Source: National Electric Energy Data System (NEEDS) v4.10_PTox Numerous energy sector modeling efforts, including recent projections from both EIA and EPA, have provided results that are consistent with these findings. The Annual Energy Outlook (AEO) for 2011 shows 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 is forecast to 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 Renewable Portfolio Standard programs and Federal tax credits for renewables. 3 The 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 policies and projected prices." 4 The economics favoring new NGCC builds instead of conven tional coal are robust under a range of sensitivity cases examined in the AEO. U nplanned additions of coal by 2020 increase in sensitivity cases that separately examine higher economic growth, lower coal prices, low fossil costs, no c oncern regarding future GHG policy, slow oil and gas technology deployment, low shale gas recovery per play, and low shale gas recovery per well. In addition, the early release of AEO 2012 currently available does not forecast new unplanned coal cap acity over the period analyzed
. Furthermore, it projects an increase over AEO 2011 in the price of coal relative to natural gas, strengthening the conclusion that natural gas is likely to be the fossil fuel of choice during the analysis period . AEO 2012 also has lower electric demand projections than those used in IPM, which would result in th e need for less new capacity in general
. EPA uses IPM to support its understanding of the economic and emissions impacts of air regulations on the power sector. IPM forecas ts show patterns of future power plant deployment that are similar to those presented in AEO 2011, and also forecasts no construction of new conventional coal

- fired power plants under the base case. 5 EPA has used IPM extensively over the past two decades in order to analyze options for reducing power

- sector emissions . The model has been used by the Agency to support

2 AEO 2011 has a small amount of planned coal capacity that is under co nstruction and expected to come online in the next year. This capacity represents certain units that likely fit the definition of transitional sour ces under this proposal. It also has 2 GW of unplanned coal capacity, which reflects new coal with CCS in r esponse to Federal incentives. 3 http://www.eia.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/a irmarkets/progsregs/epa

- ipm/BaseCasev410.html#documentation5
- 4

regulatory initiatives as well as legislative proposals design ed to address air emissions for the power sector. All of the IPM scenarios conducted for this rulemaking are available at EPA’s website and in the public docket. 6 The baseline information in this RIA includes the recently finalized Mercury and Air Toxics Standards (MATS) and Cross State Air Pollution Rule (CSAPR) In addition to MATS and CSAPR , the basel ine takes into account emissions reductions associated with the implementation of all finalized federal rules, state 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 during 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 chapter has been developed specific ally for analys i s 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, indu stry 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 t he assumptions discussed here as well as all other assumptions and inputs to the model. **5.3 External Review of EPA Applications of**  **IPM** The model undergoes periodic formal peer review, which includes separate expert panels for both 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 assumptio ns, 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 o ther developers of U.S. electricity sector models . The feedback that the Agency receives provides a highly detailed check for key input assumptions, model representation, and modeling results. The Agency has used IPM in several recent regul atory contexts. The model has been used to support the Agency’s analytics for the Clean Air Interstate Rule , CSAPR , MATS , and over a dozen legislative analytical efforts to forecast the costs, emission changes , and power sector

6 http://www.epa.gov/airmarkt/progsregs/epa

- ipm/index.html5
- 5

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 , the Western Regional Air Partnership , Ozone Transport Assessment Group ), other Federal and State agencies, environmental groups, and industry, al l 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. States 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 NO x SIP call, which has helped reduce summer NO x emissions and the formation of ozone in densely populated areas in the northeast. In the late 1990’s, the Sci ence Advisory Board reviewed IPM as part of the CAA A mendments Section 812 prospective studies that are periodically conducted . The model has also undergone considerable interagency scrutiny as part of a series of legislative analysis over th e 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 use d to support the Agency’s power sector analyses of legislative climate proposals in 2005, continuing through 2010. In addition, Regional Planning Organizations throughout the U.S. have extensively examined IPM as a key element in the state impleme ntation plan ( SIP ) process for the N ational A mbient A ir Quality Standards
. T he Agency has also used the model in a number of comparative modeling exercises sponsored by Stanford University’s Energy Modeling For um over the past 15 year s . **5.4 IPM is a Granular Model**  EPA typically presents IPM outputs in aggregate, in order to support analysis reflecting nationwide impacts of a policy. Some additional regional detail is presented, where appropriate. Although the Agency typically focuses on the broader effects when assessing the economic impacts of a particular policy, EPA’s application of IPM includes a detailed and sophisticated regional representation of key power sector variables. For example, the model includ es 32 power regions with detailed representation of the inter

- regional transmission system and reflects the regional aspects of natural gas and coal markets. When considering which new units are most cost effective to build and operate, the model consider s the relative economics of various technologies based on their unique capital costs, O&M costs, fuel costs and emission profiles. The capital costs for new units are regionalized through the application5
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of regional adjustment factors that captu re regional differences in labor, material, and construction costs. These regional cost differentiation factors are based on assumptions used in the EIA’s AEO. As part of the model’s assessment of the relative economic value of building a new power plant, the model incorporates a detailed representation of the fossil

- fuel supply system that supports fuel price projection s, a key component of new power plant economics. The model includes an endogenous representation of the North American natural gas supply system through a natural gas module that reflects a full supply/demand equilibrium of the North American gas market. This module consists of 114 supply, demand , and storage nodes and 14 liquefied natural gas regasification facility locations that are tied together by a series of link age s (i.e., pipelines) that represent the North American natural gas transmission and distribution network. IPM also endogenously models the coal supply and demand system throughout the continental U.S
. , and refle cts non
- power sector demand and imports/exports. IPM reflects 84 coal supply curves, 12 coal sulfur grades, and the coal transport network, which consists of 1,230 link age s representing rail, barge, and truck and conveyer linkages. T he coal supply curves in IPM , which are publicly available , were developed during a thorough bottom

- up, mine

- by

mine based approach that depict the coal choices and associated supply costs that power plants will face over the modeling time horizon. The IPM documentation outlines the methods and data used to quantify the economically recoverable coal reserves, characterize their cost, and build the 84 coal supply curves that are implemented in EPA modeling applications. The coal curves used by EPA were developed in consultation with Wood Mackenzie, one of the leading energy consulting firms and specialists in coal supply. These curves have been independently reviewed by industry experts and ha ve been made available for public review on several occasions over the past two years during the rulemaking process for CSAPR and MATS
. **5. 5**  **Base Case and**  **Sensitivity Analysis of Future Generating 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 MATS and the proposed Transport Rule (finalized as CSAPR)
. 9 The IPM base case projection include s a 1 percent growth in electricity demand, similar to EIA’s Annual Energy Outlook for 2010, which serves as the basis for IPM’s electric demand

9 http://www.epa.gov/airquality/powerplanttoxics , and http://www.epa.gov/airtransport

.5
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projection . This new demand will be fulfilled by existing generating capacity that is currently not being ful ly utilized , and new renewable and gas

- fired generating capacity (see 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, an d reflect the most cost
- effective dispatch and investment option , given a variety of variables 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 mi x of electricity generation sources (see Table 5

- 2)
. In addition, coal is projected to continue to provide the largest share of America’s electricity. By 2020, EPA forecasts roughly 27 GW of new renewable capacity, 2 GW of coal with CCS, and 10 GW of ne w natural gas

-fired capacity. Although 2 GW of coal with CCS is included in the base case in response to incentives under existing law, overall coal capacity is forecast to decline in response to current economics, along with some retirements due to other air regulations (CSAPR and MATS). Relative to current levels, EPA anticipates that the existing coal fleet will increase generation while gas

- fired sources will not change significantly by 2020
. This dyna mic 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)** 
**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. 2020 p rojections 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 unit that is co

-firing gas in a coal boiler is split in this table between “pulverized coal” and “Oil/Gas Steam” proportionally by fuel us e.5
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**Table 5**  **- 2**  **. 20 10**  **U.S. Electricity Net Generation and EPA Base Case Projections for 2020**

**(Billion kWh)**
**Historical Projected**  **20 10**  **2020** Coal 1,828 1,976 Oil 3 5 0.129 Natural Gas 9 01 873 Nuclear 807 841 Hydroelectric 2 58 287 Non
- hydro Renewables 1 39 288 Other 4 45 **Total 3,9**  **72 4,309**  Note s : The sum of the table values in each column may not match the total figure due to rounding. Source: 20 10 data from EIA Electric Power Annual 20 10 , Table 2.1; 2020 rojection from IP M run by EPA, 2011. Forecasts suggesting that new coal is unlikely to be built by 2020 have been shown to be robust under a range of alternative assumptions that influence the industry’s decisions to build new power plants. For example, EIA typically supplements the AEO with a series of distinct scenarios that explore specific issues and examine a future state of the world that deviates from the corec entral parameter estimates that underly underlie the reference case . Even under alternative scenarios where assumptions might improve the relative economic value of building new coal

-fired power plants, the AEO 2011 shows no new (unplanned) coal builds through 2025. Relevant scenarios include higher economic growth forecast, lower cost of coal supply, lower capital costs of fossil fuel

- fired energy technologies, and less optimistic natural gas supply. 10 Although new coal capacity is built in some of these scenarios after 2025, CAA section 111(b) requires that this standard be reviewed every eight years, thus this regulatory require ment will likely be reviewed and potentially revised after the 2020 timeframe , which serves as the primary focus of this analysis. Therefore, while the fairly robust expectation is that no new unplanned coal capacity will be built within the time horizon of this analysis , there remains a very small probability that new coal capacity might be constructed absent this regulation. Given this unlikely circumstance, t his rule c ould impose some degree of social cost and accrue some degree of social benefit. However, EPA has not quantified the costs or benefits associated with this hypothetical and difficult

-to
- quantify outcome. These scenarios lead to the fairly robust conclusion that the economics of new electricity generation are such

10 Conversely, modeling in sup port of the AEO 2011 show that new natural gas combined cycle capacity is expected to be higher in 2020 in the low fossil cost and high economic growth scenarios relative to the reference case.5
- 9

that t here is a very low probability that new unplanned coal capacity would be built in the absence of this regulation. In addition to the alternative scenarios analyzed by EIA, EPA also conducted additional sensitivit y analyses using IPM. These scenarios included alternative assumptions for natural gas supply and future electricity demand , similar in design to the alternative scenarios analyzed by EIA. For natural gas, lower shale recovery was assumed, whereby 50 percent less natural gas is rec overed from each shale play (effectively lowering shale reserves by 50 percent , similar to the AEO 2011 low shale gas recovery scenario ). For electricity growth, demand was assumed to grow at an annual average rate of 1.1 percent , similar to EIA’s high economic growth scenario for AEO 2010 (compared to 0.8 percent in the EPA baseline, which is similar to the reference case in AEO 2010). EPA ran three separate sensitivities in IPM using the aforementioned assumptions : a base case with higher electric d emand, a base case with lower shale recovery, and a base case with both assumptions
. Although EPA and EIA do not typically combine scenarios (as EPA did with the natural gas and demand sensitivity in this analysis), this scenario was performed to demonst rate that even when considering the occurrence of two independent and multiple highly unlikely assumptions events that influence new power plant additions, new unpanned coal is not expected to be built in through 2020. The se scenarios show considerabl y higher natural gas prices and higher electricity demand growth tha n any of the comp a rable AEO 2011 scenarios as well
. 11

11 EPA’s baseline electricity demand forecast used in IPM v4. 10 is based on the demand forecast in AEO 2010. AEO 2010 electricity demand forecast for the year 2020 is roughly 3.5% higher than the 2020 forecast in AEO 2011. EPA’s sensitivity with higher electricity demand growth (using the AEO 2010) uses an electricity demand for 2020 that is 6 .5 % higher than the reference case AEO 2011 demand for 2020, and 3.4% higher than the demand in the AEO 2011 high economic growth scenario. The EPA sensitivity with higher electric demand represents a very cons ervative view of electricity demand in 2020 (meaning that its electricity demand projection is considerably higher than the most recent reference case forecast, therefore representing a future in which new coal

-fired capacity would be of correspondingly hi gher economic value to build relative to the reference case forecast conditions).5
- 10 4,305 4,475
4,300 4,190 4,318

3,000 3,200 3,400 3,600 3,800 4,000 4,200 4,400 4,600

EPA
- Base Case EPA
- Hi gh De mand AEO 2 010 AEO 2 011 AEO 2 011
- Hi gh Econ. Growt h**T W** **h**

**Figure 5 -**  **2 .**  **Projected Levels of Electricity Demand in 2020, EPA and EIA**5
- 11 4.99 5.51 7.33 7.96

5.74
4.97 5.07

0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00

EP

A
- Base Case EP

A
- High Deman d EP

A
- Low Sha le Recovery EP

A
- High Deman d +L ow Sha leR ecover y EIA
- Lo w Sha le

Recovery (A EO 2010) EIA Referen ce

Cas e - AE O 2011 Aver age Price

(2011, EIA)**D e** **l i** **v e** **r e** **d P** **r i** **c e** **, P** **o w** **e r** **S e** **c t** **o r** **( $** **2 0** **0 7** **/ m** **m B** **t u** **)**

**Figure 5 -**  **3 .**  **Projected Natural Gas Prices in 2020, EPA and EIA (Delivered, Pow er Sector)** 

None of these analyzed scenarios resulted in new conventional coal

-fired capacity being built in 2020. These scenarios show similar results as EIA, and serve to further confirm the high likelihood that no new coal capacity is likely to be bui lt by 2020 in baseline forecasts. **5. 6**  **Analysis of Applicability of Proposed EGU GHG NSPS to Projected New Generating Capacity**  As the second step in the analysis, EPA analyzed the applicability of the NSPS to new generating capacity anticipated to be buil t through 2020 , and whether the requirements would require the regulated community to take actions different from those projected in the base case . The proposed EGU GHG NSPS discusses potential requirements for four types of units or actions: newly constru cted units, reconstructed units, modified units, and transitional units. Analysis performed by EPA, along with information from other sources, suggests that the5
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standards as specified in this proposed rule are not likely to result in notable emission chan ges, energy impacts, monetized benefits , costs, or economic impacts by 2020. This is because analyses performed both by EPA and 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 for new sources due to current and projected market conditions. 12 **5. 6** **.1 New Units**  This proposal requires that all new fo ssil

-fuel fired units of 25 megawatt or greater capacity be able to meet an emission rate standard of 1,000 l bs CO 2/MWh on a gross basis . It also proposes an alternative standard that would allow new units to m eet 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 coal

-fired generation using CCS
. Of the new generating capa city projected to be constructed by 2020, only the fossil

- fuel

fired boiler s would be affected by the proposed EGU GHG NSPS . The NGCC units, which are the basis of the proposed standard, are projected to meet the proposed standard through their inherent design. 13 No new conventional coal

- fired boilers , which would be subject to the proposed NSPS , are projected to be built (excluding new coal built with CCS)
. This implie s that the NSPS will require no changes in design or construction of new EGU s forecasted in the base case. Thus, there would be no expected reduction in emissions and no costs for the new EGU s whose construction is forecast
. As described a bove, the 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 natur al gas

-fired combined cycle or combustion turbine generation or coal

-fired generation with CCS (the latter is assumed to be built with support from federal grants). The EIA’s AEO 2011 modeling makes

12 EPA does not anticipate any oil or gas steam boilers to be constructed , either. Although these types of units would be subject to this rule, they have not been a technology of choice for the sector in recent years and are generally smaller ( less than the 25 MW applicability threshold included as part of this rule). In addition, the operating economics also do not favor this technology, similar to the dynamic with conventio nal new coal

- fired capacity. 13 Natural gas combustion turbines are not covered by this proposal.5
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similar conclusions. A number of major utilities have made public announcements consistent with these modeling results. 14 Engineering cost analysis, even outside of a least

- cost system dispatch modeling environment, reaches similar conclusions. If one assumes a delivered natural gas pr ice of $5 per million British Thermal Units (mmBtu) and a delivered coal price of $2 per mmBtu , which conservatively reflect forecasted prices from IPM in 2020, 15 electricity generated by natural gas combined cycle units is less e xpensive on average than coal generation. A comparison of levelized wholesale electricity costs for differing generation technologies and natural gas prices are shown in Figure 5

- 4 and Table 5

- 3
. It is important to note that both EIA and EPA include a ca pital charge rate adder (3 percent ) for new conventional coal

- fired generating capacity without CCS , which reflects the additional cost of raising capital that is currently reflected in the marketplace , related at least in part to uncertainty surro unding future greenhouse gas emission reduction requirements. 16 Note that this figure only shows the costs to the generator and does not reflect social costs associated with greenhouse gas emissions or conventional air pollutants. **Figure 5 -** **4 .**  **Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation**  **Technologies , EPA** 

14 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 ga s 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 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. 15 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 delivered (power sector) natural gas price of roughly $5/mmBtu in 2020. 16 See http://www.epa.gov/airmarkets/progsregs/epa

- ipm/ index.html , and http://www.eia.gov/forecasts/aeo/electricity_generation.cfm

.5
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**($2007)**

0 20 40 60 80 100 120 140

Co nvent iona l

Co al ( no inve sto r clima te co ncern) Co nve nt io na l

Co al ( w/ CO 2 Un certai nt y Adde r) Na tu ral G as

Co mb ined Cycl e ($5 gas) Na tu ralG as

Co mbined Cycle ($8 gas) Natu ral G as

Co mbine d Cycle ($9. 60 gas) Co al+C CS**$ /** **M W** **h**

Notes: Assumptions derived from EPA’s application of IPM. Technologies 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 (with 90 percent capture)
. I n this graph coal is a high sulfur bituminous at $2 mmBtu . Conventional Coal is at a heat rate of 8,87 5 Btu/kWh net, capacity factor of 85 percent assumed across all technologies
. It is only when gas prices reach approximately $9.60/mmBtu, that new coal

- fired generation without CCS bec omes 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 electricity sector gas price of $ 6.79 in 2 0 2 0 (the “low shale gas recovery per play” scenario projects a price of $ 5.93 /mmBtu in 20 2 0). However, it is important to note that this analysis is based on assumptions regarding the average national cost of generation at new facilities. As reported by t he EIA, there is expected to be significant spatial variation in the costs of new generation due to design differences, labor5
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wage and productivity differences, location adjustments, among other potential differences. 17 The analysis also does not explicitly consider new units designed to combust waste coal or petroleum coke (pet coke) , which may be affected by this rule, but also may exhibit different local economics. However, the results are expected to hold for the majority of situati ons. **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 65.3 3.9 24.5 1.2 94.8 **Advanced Coal** 85 74.6 7.9 25.7 1.2 109.4 **Advanced Coal with CCS** 85 92.7 9.2 33.1 1.2 136.5 **Natur al Gas**  **- fired**  **Conventional Combined Cycle**  87 17.5 1.9 45 .6 1.2 6 .1 **Advanced Combined Cycle** 87 17.9 1.9 42.1 1.2 63.1 **Advanced CC with CCS** 87 34.6 3.9 49.6 1.2 89.1 **Conventional Comb. Turbine** 30 45.8 3.7 71.5 3.5 124.5 **Advanced Combustion Turbine**  30 31.6 5.5 62.9 3.5 103.5 **Advanced Nuclear** 90 90.1 11.1 11.7 1.0 113.9 **Wind** 34 83.9 9.6 0 3.5 97.0 **Wind -**  **Offshore** 34 209.3 28.1 0 5.9 243.2 **Solar PV** 25 194.6 12.1 0 4.0 210.7 **Solar Thermal** 18 259.4 46.6 0 5.8 311.8 **Geothermal** 92 79.3 11.9 9.5 1.0 101.7 **Biomass** 83 55.3 13.7 42.3 1.3 112.5 **Hydro** 52 74.5 3. 8 6.3 1.9 86.4 Source: EIA, AEO 2011 This rule also proposes an alternative standard that would allow new units to meet the 1,000 lbs CO 2/MWh standard using a 30 year averaging period. To the extent market participants have alternative vie ws of both cost and development of CCS, new conventional coal

- fired capacity (or IGCC) could be built and operated for some time, with the intention to apply CCS with high removal efficiency at some later date, in order to achieve the required average rate over the 30 year period. Also the above analysis reflect s national averages, and in turn given their specific situation , a market participant could determine that the economics of

17 http://www.eia.gov/oiaf/ beck_plantcosts/pdf/updatedplantcosts.pdf5
- 16

building a coal

- powered facility that immediately achieves a CO 2 ca pture and/or removal rate consistent with the emission standard are favorable. Others have done research to explore the cost and efficiency of varying levels of capture relative to building alternative energy technologi es. 18 This ongoing research indicates that lower levels of carbon capture at new coal facilities could be cost competitive with these technologies , and the costs of meeting the proposed emission rate immediately could be achievable and economic. For example, The Clean Air Task Force has compiled data that indicates the levelized cost of electricity for a new supercritical pulverized coal unit with 50 percent CCS (or 1,080 lb/MWh CO 2 , which is just above the proposed standard ) could be $11 6/MWh compared to $147/MWh for 90 percent removal. However, investment decisions will be made on a case by case basis dependent upon a number of factors, all of which are difficult to estimate in advance. **5. 6** **.2 Reconstructed Units**  The EPA’s CAA sect ion 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 facility, and (ii) for wh ich compliance with standards of performance for new sources is technologically and economically 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 a nnounced 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) establishing the stand ard of performance at the same level as for new sources , (ii) establishing the standard performance at 1,800 lb CO 2/MWh , or (iii) not establishing a standard of performance for reconstructed units at this time
. EPA would not expect either alternative 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. T he costs associated with reconstructing coal

-fired unit s 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 showing that natural

- gas - fired generation is significantly more cost effecti ve than building a reconstructed coal plant results in the choice of

18 Technical Options for Lowering Carbon Emissions from Power Plants. Clean Air Task Force (June, 2011). Available at: http://www.coaltransition.org/filebin/pdf/Technical_Options_for_Lowering_Carbon_Emissions_from_ Power.p df5
- 17

natural gas combined cycle or coal with CCS technology (i.e., existing unit operators are likely to choose technologies for independent market reasons that are already compliant with the new source NSPS included in this proposal). **5. 6** **.3 Modified Units**  As explained in the preamble, T he EPA does not have a sufficient base of information to develop a proposal for the relatively few affected sources that may take actions that would constitute “modifications , ” as defined u nder the EPA’s NSPS regulations, and therefore be subject to requirements for new sources. 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 emitted
. The EPA is soliciting comment on this 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 it s 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 will not be subject to the proposed EGU GHG NSPS requirements for new sources. **5. 6** **.4 Transitional Units**  In the proposal, EPA identifies transitional sources as those sources that have received final PSD permits , but have not actually commenced c onstruction. EPA is proposing that as long as units commence construction within a set amount of time, construction can proceed without being affected by this rule. While t his proposed rule sets no standard for the transitional source subcategory of new sources, these sources may become subject to an existing source standard in a subsequent rulemaking. EPA believes that there are approximately 1 5 such units discussed previously in Chapter 2 . 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 permitted. Of those, 40 (or fewer than half) have actually commenced construction. Thirty projects have b een cancelled and approximately 1 5 sources (the transitional sources) have active permits. Based on this history and current economic conditions , EPA believes that at least some number of these units would not likely proceed to construction, regardless of the requirements of this rule. Based on this history, EPA believes that at 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. Once a unit5
- 18

ha s received a final PSD permit, it must commence construction within 18 months. The units EPA has potentially identified as “transitional” were permitted prior to this rule being proposed
. EPA is proposing that as long as units commence construction within 12 months , 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 within this transitional category that are most likely to commence construction are those that have received public incentives to install CCS. Under the proposed rule, t hese units could commence construction within the proposed time

- frame without incurring any requirement to reduce CO 2 emissions . EPA believes that the economics demonstrated above also apply to the other transitional units; such that building natural gas

- fired combined cycle generation is likely to be a less expensive option than traditional coal

- fired generation , even in the absence of this rule . The developers of the projects already permitted are likely considering these economic factors and may ultimately choose not to commit to actual construction of these previously proposed coal and petroleum coke plants. **5. 7**  **Summary of Costs, Economic, and Energy Impacts of the Proposed Rule for New, Reconstructed, Modified, and Transitional Electric Generating Units**  EPA does not anticipate that the proposed E GU GHG NSPS will result 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 these standards due to current and expected economic c onditions, 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 proje ct 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 20 09, which authorized and/or appropriated funding to DOE for CCS deployment. In the short

-term, most new capacity is projected as a mix of wind and natural gas in response to the competitive marketplace for fuels and other energy policies (such as tax cred its 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 4 for more discussion on future electricity demand). E lectricity demand is anticipated to grow by roughly 1 percent per5
- 19

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 2020 using IPM. EPA’s IPM mod eling 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, pollution controls, and num erous other parameters. **5. 8**  **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 (r egardless of whether the power sector is regulated for greenhouse gases or not), the Agency acknowledges the possibility that in unusual situations , a company could find it advantageous to build a conventional coal facility (or other potentially affected facility) if there were no greenhouse gas requirements (i.e., if the social and environmental damages of carbon emissions remain as unpriced externalities not reflected in project economics). While it is difficult to identify and evaluate hypothetical scen arios 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. However, in s uch a case the rule would also produce benefits from any reduced emissions of greenhouse gases and other air pollution. **5. 9**  **Benefits of Reduced Regulatory Uncertainty** Most major actors in the power sector anticipate eventual CO 2 emissions policy for pow er 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 decisions 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 policy 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 th em to optimize investment decisions with a greater understanding as to 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
- 20

**5. 10**  **Compa rison of Emissions Differences of Generation Technologies**  As discussed earlier in this chapter, natural gas combined cycle units are on average expected to be more economic al to build and operate than new coal units. These natural gas units also have lowe r emission profiles for CO 2 and criteria air pollutants than new coal units
. While the baseline forecast suggests that the proposed EGU GHG NSPS will have no monetized benefits 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 proposed , and as such, these comparisons are purely for illustrative purposes. A s 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. 19 For example, a typical new supercritical pulverized coal facility that burns bituminous coal in com pliance with new utility regulations (e.g., CSAPR and MATS) would have considerably greater CO 2 , sulfur dioxide ( SO 2 ) , NO x, me tals , acid gases, and particulate emissions than a comparable natural gas combined cycle facility. A typical natural gas comb ined 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 fewer short tons of NO x each year. Reductions in SO 2 emissions are a particularly significant driv er 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** 

19 E stimated emissions of CO 2, SO 2, and NO X for the illustrative new coal and natural gas combined cycle units could vary depending on a variety of assumptions including heat rate, fuel type , and emission controls , to name a few
.5
- 21 **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/y ear 3.6 million 1.6 million 0.45 million Notes: SO 2 and NO x in short tons, CO 2 in metric tons. Relative emissions for new well controlled 600 MW (net) units running at 85 percent capacity factor
. Assumed coal is high sulfur bituminous with scrubber and SCR , d ata is based on EPA assumptions used in IPM. **5 11**  **. Benefits of Reducing GHGs and**  **Conventional Pollutants**  As shown in this illustrative example, natural 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 b enefits associated with the differences in emissions of CO 2 and criteria air pollutants in the previous illustrative example
. EPA does 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 understand the value of the diffe rence 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 benefits of rulemakings that ach ieve 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 Document (SCC TSD) provides a comple te discussion of the methods used to develop these SCC estimates. 20

20 Docket ID EPA

- HQ
- OAR
- 2009
- 0472
- 114577, Technical 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 Econo mic Advisers, Council on Environmental Quality, Department of Agriculture, Department of Commerce, Department of Energy, Department of Transportation, Environmental Protection Agency, National Economic Council, Office of Energy and Climate Change, Office o f Management and Budget, Office of Science and Technology Policy, and Department of Treasury (February 2010). Also available at http://epa.gov/otaq/climate/regulations.htm5
- 22

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 dollars. 21 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 sensitive 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 included to represent higher

-than

- e xpected impacts from temperature change further out in the tails of the SCC distribution. 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 consistent with other modeling assumptio ns. Table 4

- 1 presents the SCC estimates for the years 2015 to 2050. In order to calculate the dollar value for emission reductions, the SCC estimate for each emissions year would be applied to changes in CO 2 emissions for that year, and then discounted back to the analysis year using the same discount rate used to estimate the SCC. 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 A cademies of Science (NRC 2009) points out that any assessment will suffer from uncertainty, speculation, and lack of information about (1) future emissions of greenhouse gases, (2) the effects of past and future emissions on the climate system, (3) the imp act of changes in climate on the physical and biological environment, and (4) the translation of these environmental impacts into economic damages. 22 As a result, any effort to quantify and monetize the harms associated with climate change will raise serio us 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 capture catastrophic and n on -

21 Note that upstream emi ssions 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
. 22 National Rese arch Council (2009). Hidden Costs of Energy: Unpriced Co nsequences of Energy Production and Use
. National Academies Press. See docket ID EPA

- HQ
- OAR
- 2009
- 0472
- 11486.5
- 23

catastrophic impacts, their incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk aversion. Current integrated assessment models do not assign value to all of the important physical, ecological, and economic impacts of climate change recognized in the climate change literature because of lack of precise information on the nature of damages and because the science incorporated into these models underst andably 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 researchers 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 to updating these estim ates 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 SCC values within two years , or at such time as substantially updated models b ecome 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 emission s - year specific.
As shown in the Table 5

-4, a natural gas unit emits approximately 2,000 tons 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. Reducing exposure to PM 2.5 and ozone is associated with significant human heal th benefits, including avoiding mortality and5
- 24

morbidity. Researchers have associated PM 2.5 and ozone exposure with adverse health effects in numerous toxicological, clinical, and epidemiological studies (U.S. EPA, 2009; U.S. EPA, 2006). Health effects ass ociated with exposure to PM 2.5 include premature mortality for adults and infants, cardiovascular morbidity such as heart attacks and hospital admissions, and respiratory morbidity such as asthma attacks, bronchitis, hospital and emergency room visits, wo rk loss days, restricted activity days, and respiratory symptoms
. Health effects associated with exposure to ozone include premature mortality and respiratory morbidity such as asthma attacks, 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 RIA for 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 that the public obtain s from ecosy stems 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 t hese harmful emissions improves human welfare. For more information about the 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 qu antify 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 exa mple
. However, reducing one thousand tons of annual SO 2 from U.S. EGUs in 2020 has been estimated to yield between 3 and 9 incidences of premature mortality avoided annually and annual monetized PM 2.5 - related health benefits (including these incidences of premature mortality avoided) of between $ 30 million and $ 75 million (2007$) using a 3% discount rate or between $ 28 million and $67 million (2007$) using a 7% discount rate

. Additionally, reducing one thousand tons of annual NO X from U.S. EGUs in 2020 has been estimated to yield up to 1 incidence of premature mortality avoided annually and annual monetized PM 2.5 - related health benefits (including these incidences of premature mortality avoided) of between $ 2.5 million5
- 25

and $ 6.2 million (2007$) using a 3% discount rate or between $2.3 million and $5.6 million (2007$) using a 7% discount rate.

. 23 **5. 1**  **2 Sensit**  **ivity Analysis of the Social Costs of New Generating Sources**  EPA believes that, given expected energy demand along with fuel and capital prices, new conventional coal capacity is unlikely to be constructed over the time horizon of interest in this analysis . As part of this explanation we provide an illustrative, but representative, comparison of the relative private costs of constructing and operating new conventional coal and natural gas combined cycle systems to provide the same generation services (see F igure 5.4). 24 This comparison shows that, at forecast relative fuel prices, there is a significant difference in the levelized cost of these two generating technologies. However, in the context of a social welfare analysis, the appropriate comparison betwe en multiple options is on the basis of benefits and costs to society as a whole, and not solely the private cost to an investor. From the perspective of society, the appropriate cost comparison should account for the pollution damages associated with the competing generation technologies in addition to private generating costs. This section further explores the social costs of this NSPS standard across a wide range of natural gas prices, a key factor in the cost of the policy. It begins by estimating il lustrative environmental damages per MWh for coal relative to gas generation and then uses those estimate to conduct an illustrative breakeven analysis for the social costs of the policy.

23 T he SO 2 and NO X benefit p er- ton values presented here consist of only PM 2.5 - related health benefits from reductions in SO 2 and NO X (precursors to PM 2.5 formation). EPA relied on air quality modeling ( Air Quality Modeling Technical Support Document for the final Transport Rule; http://epa.gov/airtransport/pdfs/AQModeling.pdf) used to develop a previous rulemaking affecting power sector emissions of SO 2 and NO X to develop these benefit per

-ton values, which are methodo logically consistent with those reported in Fann et al. (2009). As such, the national average benefit per

-ton values reflect a specific geographic distribution of SO 2 and NO X reductions resulting in a specific reduction in PM 2.5 exposure and may not fully reflect local or regional variability in population density, meteorology, exposure, baseline health incidence rates, or other factors that might lead to an over

- estimate or under

- estimate of the actual benefits associated with PM 2.5 precursors. T hese ben efit per

-ton values are purely illustrative as EPA does not assert a specific location for the illustrative coal and natural gas combined cycle units and is therefore unable to specifically determine the population that would be affected by their emissions
. Therefore, the benefits for any specific unit can be very different than the estimates shown here. EPA notes that the benefit per-ton estimates do not reflect emission reductions after implementation of EPA’s Mercury and Air Toxics Standards. EPA prov ides 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)
. 24 By fixing generation in this comparison, we are assuming that both technologies generate the same benefits in the form of electricity generating services. For a discussion of the usefulness of a levelized cost analysis, and when it provides informative results and when it does not, see for example Joskow 2010 and 201 1.5
- 26

**5.1 2**  **.1 Illustrative**  **E nvironmental**  **D amages per MWh**  As previously d iscussed in this chpater, the damages associated with emissions from new sources of electricity generation are greater for coal

- fired units than for natural gas combined cycle units (even when accounting for compliance with EPA’s recent Mercury and Air Tox ics Standard). To gauge the general effect of accounting for both the private and external costs of electricity generation for new generation options we continue with the illustrative example from Section 5.10. The external costs are defined as the damag es associated with pollution that are not accounted for in the private investor's decision making. 25 To illustrate the external costs associated with new generation options we combine the illustrative emission profiles for the new units, as provided in Tab le 5

-4, and the illustrative damage estimates discussed in the previous section. 26 Specifically, for each generating technology we multiply the CO 2 emissions by the estimates of the SCC and add that to the SO 2 emissions multiplied by the PM 2.5 - related SO 2 benefit per

- ton estimates 27, subsequently dividing by MWh 28 to estimate the external costs per unit of generation. Using this approach the damages associated with generation from the illustrative new coal unit are, depending on the discount rate and epidemio logy study used, $18 to $99 per MWh, while damages associated with the illustrative new natural gas combined cycle unit are $3 to $29 per MWh (2007$). 29 For any specific epidemiology study and SCC estimate the pollution damages associated with new coal ge neration in this illustrative, but representative, example are significantly higher than those associated with new natural gas combined cycle generation. For example, considering the SO 2 per ton damages based on Pope et al. 2002 using a 7% discount rate a nd the SCC estimate based on the 3% discount rate, new generation based on conventional coal in

25 See Baumol and Oates, 1988. 26 Only the direct emissions of three pollutants (CO2, SO2, and Nox) are considered in this illustrative exercise. Other pollutants and lifecycle emissions are not considered. 27 See footnote 2 3 in section 5.11 for a description of the benefit

- per-ton values. In this exerc ise they are interpreted as damage per

-ton values. 28 See footnote 19 in section 5. 10
. 29 Different discount rates are applied to SCC than to the other damage estimates because CO2 emissions are long

lived and subsequent damages occur over many years. Moreo ver, several rates are applied to SCC because the literature shows that it is sensitive to assumptions about discount rate and because no consensus exists on the appropriate rate to use in an intergenerational context. The SCC interagency group centered i ts attention on the 3 percent discount rate but emphasized the importance of considering all four SCC estimates. See the “SCC TSD,” Interagency Working Group on Social Cost of Carbon (IWGSC). 2010. Technical Support Document: Social Cost of Carbon for Regu latory Impact Analysis Under Executive Order 12866. Docket ID EPA

- HQ
- OAR
- 2009
- 0472
- 114577. http://www.epa.gov/otaq/climate/regulations/scc

-tsd.pdf, for details.5
- 27

this example would result in an additional $24 per MWh in pollution damages compared to a new NGCC plant. Alternately, damages that reflect the SO 2 per ton dama ge estimate based on Laden et al. 2006 using a 3% discount rate and the SCC estimate based on a 2.5% discount rate suggest an additional $52 of pollution damages per MWh from a new conventional coal unit compared to a new NGCC plant. Table 5

- XX reports the additional pollution damages from the illustrative new coal plant relative to the illustrative new natural gas plant given different mortality risk studies and assumptions about the discount rate. These pollution damages should be relatively invariant a cross natural gas prices and other economic factors. **Table 5 -**  **6 .**  **Pollution Damages ($/MWh) from Illustrative New Coal Unit Relative to**  **New**

**Natural Gas Combined Cycle Unit Health Co**  **- Benefits**  SCC Discount Rate **3% Discount Rate 7% Discount Rate**  5% $17

- $3 7 $16

- $33 3% $25

- $45 $24

- $42 2.5% $32

- $52 $31

- $49 3% (95 th percentile) $50

- $70 $49

- $66 Notes: The range of costs within each SCC value and discount rate for conventional pollution damages pairing reflects the use of two PM2.5

- related esti mates of premature mortality, Pope et al. (2002) representing the low estimate and Laden et al. (2006) represent the high est imate. Assumed coal is high sulfur bituminous with scrubber and SCR
. The combinations of healt h studies and discount rates represent lower and higher valuations of impacts of NOx and SO2 emissions in the Eastern U.S. As with the relative investment costs of a new coal unit and a new natural gas combined cycle system, a comparison of the environment al damages associated with these two technologies depends on the location under consideration and the specific fuels that would be used. An ideal social cost comparison of these technologies would account for these local circumstances (and consider altern ative sources of generation). 30 That said, the damages associated with CO 2 emissions, which is the focus of this rule, do not depend on the location of generation. Furthermore, the damages associated with sulfur dioxide emissions from a new very well

- contr olled coal

- fired unit firing low

- sulfur coal would still be greater than the damages from a new natural gas combined cycle unit independent of the location. Other studies of the social costs of coal and natural gas fired generation provide similar findings (Muller et. al, 2011; NRC, 2009). 31

30 EPA does not assert a s pecific location for the illustrative coal and natural gas combined cycle units and is therefore unable to specifically determine the population that would be affected by their SO 2 and NO X emissions. Therefore, the benefits for any specific unit can be ve ry different than the estimates shown here. 31 Muller et al. 2011 conclude that, “ coal

-fired power plants have air pollution damages larger than their value added”, while the same is not true for natural gas plants (see Table 5). However, these compariso ns are based on typical existing coal and natural gas units, including natural gas boilers, and are not sensitive to location. The NRC 2009 study shows that only the most polluting natural gas units may cause greater damages than even the least polluting e xisting coal plants (compare Tables 2

- 9 and 2

- 15). However, the NAS comparison does not5
- 28

Overall, these environmental damages suggest that, even if it were the case that the private cost of natural gas generation began to rise relative to the private cost of coal generation, there would still remain a subs tantial difference in the overall cost to society between these two technologies. In other words, the damages from air pollution suggest that, even in cases where new coal may be marginally more economic to operate, these new units are still likely to imp ose a net cost to society relative to a new natural gas plant. This idea is discussed in more detail in the next section. **5.1 2**  **.2 Social Costs Across A Range of Gas Prices**  **- Breakpoint Analysis**  Section 5. 11 details illustrative environmental damages ass ociated with a typical coal plant compared to a natural gas plant. The social cost of a policy should account for not only the difference in private cost between the two technologies, but also the difference in the external costs (environmental damages) a ssociated with the two technologies. At today’s gas prices the difference in the private levelized cost for these illustrative facilities is roughly $27 per MWh in favor of natural gas combined cycle at today’s gas prices (see Figure 5

-4 ). Because the un derlying economics at current gas prices favor the construction of NGCC, the proposed NSPS standard does not impose any social costs (or generate monetized net benefits). However, the net benefits from a policy interact with the relative generating costs, which in turn vary based on the prices of fuels like natural gas and coal. Because the cost of this standard is zero under EPA’s baseline scenario, and because the social costs are expected to be especially sensitive to the relatively uncertain parameter of natural gas prices, EPA conducted an illustrative analysis of the breakpoints where natural gas prices change the sign of the social costs of the policy (holding all other parameters constant). 32 This analysis describes the pattern in social costs as n atural gas prices rise across three ranges: projected gas prices, unexpectedly high natural gas prices, and unprecedented natural gas prices. **Likely Projected Natural Gas Prices.** As described earlier in this chapter, the base case modeling that EPA perform ed 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 coa l

- fired generation with CCS (the latter is assumed to be built with support from federal
compare new units located in the same place, and so some of the natural gas units with the greatest damages may be attributable to their location, and includes natural gas steam boilers, which have a higher emission rates per unit of generation than natural gas combined cycle units. 32 In reality this is unlikely to be the case. For example, high economic growth would increase both natural gas and coal prices at the sa me time

- making it harder to alter the underlying cost advantage of NGCC generation.5
- 29

grants). As shown earlier in the illustrative analysis , it is only when gas prices reach approximately $9.60/mmBtu, that coal

- fired generation without CCS becomes com petitive 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 electricity sector gas price of $ 6.79 in 2020 (the “low shale gas recovery per play” scenario projects a price of $ 5.93 /mmBtu in 2020). In other words, even under pessimistic natural gas sensitivity cases, NGCC is likely to remain the economic choice for generation over the next two decades even in the ab sence of this standard. As a result, the social costs of the standard are expected to be zero. **Unexpectedly High Natural Gas Prices .**  In this illustrative analysis, at gas prices above $9.60/mmBTU, coal generation without CCS becomes competitive with NGCC, which may mean that some new non

- CCS coal units might be constructed in the absence of the standard provided there is sufficient demand and new coal without CCS is competitive with other generating technologies. However, these coal units would also impo se social costs in the form of global warming pollution and particulate matter (as a result of SOx and NOx emissions) and this proposed standard would avoid those social costs. For example, at gas prices of $10/MMBTU, the illustrative non

- CCS coal unit wo uld generate power for $ **[3]** /MWh less than an NGCC unit 33 , but result in greater pollution damages of $16

- 70/MWh (see table 5

- XX). 34 Under the proposed standard, if the investor built the NGCC unit instead the resulting net social benefit would be $ **[13]** to **[ 67]**  /MWh. For context, we note that these circumstances are less likely than the zero cost scenario outlined above. To put this gas price breakpoint into historical context, $9.60/MMBTU is higher than any annual gas price observed over the last 10 years, and it has only been reached temporarily in 9 of the last 120 months. 35 36 Looking forward, the continued development of unconventional natural gas resources in the U.S. suggests that gas prices would actually tend to be towards the lower end of the histor ical range. As discussed above, none of the EIA sensitivity cases (which represent future price trajectories for both gas

33 Assuming an increase of $6.80/MWh in the cost of gas generation for every $1/MMBTU increase in natural gas prices. AWAITING CONFIRMATION 34 Again, assuming that coal pri ces do not increase along with natural gas prices as they historically have. See previous footnote. 35 See: http://www.eia.gov/dnav/ng/hist/n3045us3A.htm 36 It is important to note that relatively high gases prices in a single month or year will not drive th e investment decision in the technology employed for new generating units. Instead that decision will be motivated by expectations of relative fuel prices over the lifetime of the unit. Therefore given the historical path of natural gas prices and the fo recasts for the future, it is highly unlikely that expectations of sustained high natural gas prices, to the degree necessary to drive technology choices, will be realized.5
- 30

and coal) show scenarios where non

- compliant coal becomes more economic than NGCC before 2020. **Unprecedented Natural Gas Prices.** At extremely high gas prices, the private generating costs of non

- compliant coal are significantly lower than the cost of new natural gas and the net social cost of the standard could be positive (negative net benefits) under some assumptions for environmenta l damage costs. For example, at gas prices of $15/MMBTU, the illustrative non - CCS coal unit would generate power for roughly $[36]/MWh less than an NGCC unit but result in social costs of $16

- 70/MWh (see table 5

- XX). Under the proposed standard, a generat or would likely build the NGCC unit instead, resulting in a net social benefit of $[

- 19] to [34]/MWh. The point at which this standard would result in net social costs depends heavily upon the value for damages from GHGs and SO 2 ; assuming an SCC using a 3 % discount rate in this illustrative example would generate net social costs at average gas prices of $[13] to $[18]/MMBTU. Annual natural gas prices delivered to the electricity sector have not exceeded $ 9.26 /MMBTU over the last 15 years. 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 where this standard would be projected to have no costs, net benefits or net costs. However, based annual gas prices over the last 15 years, we project that this standard is most likely to have no notable costs, that there is some small probability that it produces net benefits, and an exceedingly low probability that it results in net costs. The analysis above focuses on two well developed control technologies, conventional supercricitcal coal and natural gas combined cycle. Because these technologies are well developed, there is significantly more certainty about operating costs tha n for new, emerging technologies like coal with CCS. As a result, any analysis which examines the relative social costs of coal vs. coal with CCS is considerably more uncertain and should primarily be used as a guide to the key sensitivities in the relati ve social costs. EPA compared the costs and damages for a model pulverized coal (PC) EGU using supercritical steam conditions (like the one used in the comparisons above) to and IGCC plant with a CCS system (e.g. Selexol) [SEE TECHNICAL MEMO FOR DETAILS]
. EPA analyzed the cost and emission impacts for two scenarios. In the first scenario, partial capture achieves the proposed emissions rate of 1,000 lb CO 2/MWh gross output. This requires that approximately 31% of the CO 2 is captured and stored. EPA has no t previously developed costs for such a unit, therefore, this analysis may not fully realize all of the cost5
- 31

savings possible from building a unit with significantly less than 90% capture (for instance, an IGCC could be built with a conventional gas turbin e, rather than one designed for higher temperature characteristics of a higher hydrogen content fuel). A 90% capture system was also examined to analyze the cost of several proposed new coal

-fired EGUs using CCS. In the near term, any new coal

-fired EGU wi th CCS would mostly likely be located in areas amenable to using the captured CO 2 in enhanced oil recovery (EOR) operations. This is because EOR provides a revenue stream that is not available for other forms of geologic storage. For example, the Texas Cle an Energy project 37 is planning to capture 90% of the CO 2 and sell it for enhanced oil recovery. To evaluate the potential revenues from EOR we examined two options. We considered a case where CO 2 could be sold for $45/ton based on recent DOE studies. 38 W e also considered a lower revenue sensitivity where CO 2 could be sold for $15/ton (equivalent to the cost assumed for the transport and storage of CO 2 in the analysis). Costs for the IGCC unit with 90% capture and the ultra

- supercritical coal

-fired unit wi thout CCS were derived from IPM version 4.10. 39 These cost estimates are generally consistent with the range of studies estimating the cost of CCS that are available, however there is uncertainty around any such projections of technology costs, particularly for early movers of this technology. Costs for the IGCC unit with 30% capture were derived from the costs for the IGCC unit with 90% CCS using best engineering judgment. EPA estimated the benefits associated with avoided CO2 and SO2 emissions in a simila r fashion to the one described above [REFERENCE TECHNICAL MEMO IN THE DOCKET] **Table 5 -**  **7 .**  **Illustrative Costs and Benefits for two CCS Scenarios Compared to Conventional**

**Coal Plant (Millions 2007$) –**  **NOTE –**  **WILL BE REVISED TO $/MWh FOR CONSISTENCY**  **USPC to I GCC with**  **30% C apture**  **USPS to IGCC with 90%**  **C apture**  Additional Gross Annual Private Costs $80.0 $130.3 Revenue from EOR $17.4 (@$15/ton) $143.7 (@$45/ton) Net Additional Annual Private Costs $62.6 ($13.4) Value of Quantified Benefits

37 http://www.texascleanenergyproject.com/ 38 US DOE / NETL studies have assumed a de livered CO 2 price ranging from $40

- $45/tonne. “Improving Domestic Energy Security and Lowering CO 2 Emissions with “Next Generation” CO 2 - Enhanced Oil Recovery (CO 2 - EOR)”, DOE/NETL

- 2011/1504 (June 2011); and “ Storing CO 2 with Enh anced Oil Recovery, DOE/NE TL
-402/1312 ( February 2008 ). 39 http://www.epa.gov/airmarkets/progsregs/epa

- ipm/BaseCasev410.html5
- 32 SCC 3% with Pope 7% $58 $109 SCC 3% with Laden 3% $101 $151 Net Benefits SCC 3% with Pope 7% ($4.6) $122.4 SCC 3% with Laden 3% $38.4 $164.4
This analysis suggests that the relative social cost of CCS compared to conventional coal is sensitive to the achieved generating costs for CCS units, the revenue stream from EOR, and the monetary value of avoided climate and other air pollution damages. However, it also suggests that, at relatively low prices for EOR revenue ($15/MWh), CCS generation can generate net social benefits compared to conventional coal generation. EPA recognizes that this illustrative analysis is somewhat novel, and requests comment on ways to incorporate uncertainty about future economic factors (and gas prices in particular) in to the consideration of the social cost of this rule. **5. 1**  **3 Macroeconomic and Employment Impacts**  This proposed EGU GHG 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 asso ciated with proposed rules based on the estimated compliance costs and other energy impacts, which serve as an input to such analyses. However, since the EPA does not forecast a change in behavior relative to the baseline in response to this proposed rule , there are no notable macro economic or employment impacts expected as a result of this proposed rule.

**5.1 4**  **R eferences**  U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for Particulate Matter (Final Report). EPA

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– RTP Division. December. Available on the Internet at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.5
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U.S. Environmental Protection Agency (U.S. EPA). 2006. Air Quality Criteria for Ozon e and Related Photochemical Oxidants (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. Integ rated Science Assessment for Oxides of Nitrogen and Sulfur
– Ecological Criteria National (Final Report). National Center for Environmental Assessment, Research Triangle Park, NC. EPA/600/R

- 08/139. December. Available on the Internet at <http://cfpub.epa.go v/ncea/cfm/recordisplay.cfm?deid=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 En vironmental Costs of Regulatory 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
- 127 Hoffmann, Volker H. and Trautmann, Thomas and Hamprecht, Jens. Regulatory Uncertainty: A Reason to Postpone Investments? Not Necessari ly. 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 an d 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, Cardiopulmonary Mortality, and Long

-term Exposure to Fine Particulate Air Pollution. Journal of the American Medical Association 287:1132

- 1141. W. J. Baumol and W. E. Oates, The Theory of Environmental Policy. 2nd Edition. Cambridge University Press : New York (1988).5
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P.L Joskow. 2010. Comparing the Cost of Intermittent and Dispatchable Electricity Generating Tech nologies. MIT Center for Energy and Environmental Policy Research Working Paper 10
- 013. P.L. Joskow, 2011. "Comparing the Costs of Intermittent and Dispatchable Electricity Generating Technologies," American Economic Review, vol. 101:238

- 41. N.Z. Muller, R . Mendelsohn, and W. Nordhaus. Environmental Accounting for Pollution in the United States Economy. American Economic Review. 101:1649

- 1675. National Research of Council (NRC). 2009. Hidden Costs of Energy: Unpriced Consequences of Energy Production and Us e. National Academies Press: Washington, D.C.