5

- 1 **CHAPTER 5 COSTS, BENEFITS, ECO**  **NOMIC ,**  **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 market conditions with an d without the proposed rule

. Even in a baseline scenario without the proposed rule, the only capacity additions subject to this rule projected during the analysis period ( through 2020) are compliant with the requirements of this rule (e.g. , combined cycle natural gas and small amounts of coal with CCS supported by DOE funding ) . This conclusion also holds for several sensitivity analyses EPA performed. As a result , under a wide range of future electricity market conditions, this proposed EGU GHG NSPS is not expected to change GHG emissions for newly constructed EGUs , and is anticipated to impose negligible costs, economic impacts , or energy impacts on the EGU sector or society. An additional illustrative analysis, presented at the end of this chapter, indi cates that even in the unlikely event that electricity market conditions change enough to support additional new coal, the proposed EGU GHG NSPS would provide net benefits. This analysis concluded based on sensitivity analyses that the price of natural gas would have to increase to approximately $10/mmBtu for coal boilers without CCS to become competitive with combined cycle natural gas units , which is projected to be very unlikely. 1 **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 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 c apacity, of any type , expected to be constructed over the next decade

. A small number 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

1 This chapter presents all costs in 2007$.5

- 2

h orizon of this analysis (through the year 2020)

. For more detailed discussion of this forecast, see section 5.5. Under current and foreseeable future market conditions affecting new capacity additions, gas

- fired generating technologies can produce electric ity at a lower levelized cost than coal

-fired generating technologies, and therefore utilities are expected to rely heavily on combustion turbines and combined cycle plants using natural gas when they do need to expand capacity during the time horizon cons idered for this analysis

. C urrent and projected natural gas prices are considerably lower than the prices observed over the past decade , largely due to advances in hydraulic fracturing and horizontal drilling techniques that have opened up new shale gas re sources and substantial ly increased the supply of economically recoverable natural gas . According to EIA, Shale gas refers to natural gas that is trapped within shale formations. Shales are fine

- grained sedimentary rocks that can be rich sources of petrole um and natural gas. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. The production of natural gas from shale formations has rejuvenated the natural gas industry in the United States. The U.S. Energy Information Administration's Annual Energy Outlook 2012 (Early Release) estimates that the United States possessed 2,214 trillion cubic feet (Tcf ) of technically recoverable natural gas resources as of January 1, 2010. Natural gas from proven and unproven shale resources accounts for 542 Tcf of this resource estimate. Many shale formations, especially the Marcellus, are so large that only small portions of the entire formations have been intensively production

-tested. Consequently, the estimate of technically recoverable resources is highly uncertain, and is regularly updated as more information is gained through drilling and production. At the 2010 rate of U.S. consumption (about 24.1 Tcf per year), 2,214 Tcf of natural gas is enough to supply over 90 years of use. Although the estimate of the shale gas resource base is lower than in the prior edition of the Outlook, shale gas production estimates i ncreased between the 2011 and 2012 Outlooks, driven by lower drilling costs and continued drilling in shale plays with high concentrations of natural gas liquids and crude oil, which have a higher value in energy equival ent terms than dry natural gas. 2

2 For more information, see: http://www.eia.gov/forecasts/archive/aeo11/IF_all.cfm#prospectshale ; http://www.eia.gov/energy_in_brie f/about_shale_gas.cfm5

- 3

Ba sed on these market conditions, and detailed analysis and modeling conducted by EPA, the levelized cost of generation from a new natural gas power plant is expected to be lower on average than the levelized cost of generation from a new coal

- fired power pl ant. 3 , 4 This trend has already been observed recently, as natural gas

-fired capacity has been 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 Techno logy**  Source: National Electric Energy Data System (NEEDS) v4.10_PTox Note: Renewables include geothermal, biomass, solar, and wind energy technologies. A considerable amount of renewables were built in 2009 and 2010, and these are reflected in EPA modeli ng applications but not necessarily in NEEDS. Numerous energy sector modeling efforts, including recent projections from EIA, have provided results that are consistent with these findings. The Annual Energy Outlook (AEO) for

3 See Table 5

- 4, which reports the l evelized c ost of n ew g eneration in the Annual Energy Outlook (AEO) 2011

. 4 Note that EPA’s analysis, which is consistent with this expectation, is based on sophisticated IPM modeling, and is not b ased on simplified LCOE assumptions.

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 he r Gas (CCa nd C T)
Ren ewab le/Hydro
Nuc lear
Co al5

- 4

2011 shows a modest amount of CCS

- equipped new coal

-fired power coming online past 2012 that would be in compliance with this proposal

. 5 EIA includes some additional new coal with CCS in its baseline (2 GW), an assumption which EPA has adopted in IPM. The new CCS is in response to existing Federal incentives for the technology (the Emergency Economic Stabilization Act of 2008 and the American Reinvestment and Recovery Act of 2009). According to the AEO 2011, the majority of new generating capacity is forecast to be either natural g as 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. 6 B ased on EIA analysis, DOE concluded, 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." 7 The economics favoring new NGCC additions instead of conventional coal are robust under a range of sensitivity cases examined in the AEO. U nplanned additions of coal by 2020 are also not forecast in sensitivity cases that separately examine higher economic growth, lower coal prices, low er capital costs for fossil capaci ty, no risk premium for greenhouse gas emissions liability from conventional coal , slow er oil and gas technology deployment, low er shale gas recovery per play, and low er shale gas recovery per well. In addition, the EIA’s AEO 2012 Early Release (AEO 2012 ER) does not forecast new unplanned coal capacity without CCS through 2020 . Furthermore, it projects an increase over AEO 2011 in the price of coal relative to natural gas, strengthening the conclusion that natural gas

- fired generating technologies are likely to be the fossil fuel of choice during the analysis period

. The AEO 2012 ER also has lower electric ity demand projections than those used in IPM, reflecting an extended economic recovery and increasing energy efficiency in end

- use appliances, 8 whic h would result in the 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 forecasts show patterns of future power plant deployment that are simi lar to those presented in AEO 2011, and also forecasts no construction of new conventional coal

- fired power plants under the base case. 9

5 AEO 2011 has a small amount of planned coal capacity that is under construction 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 response to Federal incentives. 6 http://www.eia.gov/forecasts/aeo/chapter_legs_ regs.cfm 7 Department of Energy (2011). Report on the First Quadrennial Technology Review. Available at http://energy.gov/sites/prod/files/QTR_report.pdf

. 8 AEO 2012 Early Release Overview 9 http://www.epa.gov/airmarkets/progsregs/epa

- ipm/BaseCasev410.html#documentation5

- 5

A number of major utilities have made public announcements consistent with these modeling results. 10 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 refle ct 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. **5.3 External Review of EPA Applications of IPM**  EPA has used IPM extensively over the past two decades to analyze options for reducing power- sector emissions. 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 IPM scenarios conducted for this rulemaking are available at EPA’s website and in the public docket. 11 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 assumptions, and model formulation. The rulemaking process also pro vides 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 U.S. electricity sector models . The fe edback that the Agency receives provides a highly detailed check for key input assumptions, model representation, and modeling results.

10 For example: “We have no other coal

-fueled generation planned at this tim e... 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 hurry to build new ones in this environment.” John Rowe, Exelon, 9/2011, EnergyBiz; “With low gas prices, gas

- fired generation kind o f snowplows everything else” Lew Hay, NextEra, 11/1/2010, Dow Jones. 11 http://www.epa.gov/airmarkt/progsregs/epa

- ipm/index.html5

- 6

The Agency has used IPM in several recent regulatory contexts. The model has been used to support the Agency’s analytic s for the Clean Air Interstate Rule, CSAPR, MATS, and over a dozen legislative analytical efforts to forecast the costs, emission changes , and power sector impacts of various policies to reduce power sector emissions. As part of the rulemaking process, EP A 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 agenci es, 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. States have used the m odel 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 t he northeast. In the late 1990’s, the Science 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 analys e s 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 propos als. The model was also used 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 elemen t in the state implementation 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 Forum over the past 15 yea r s . **5.4 IPM is a**  **Detailed Bottom -**  **Up Model**  EPA applies IPM to consider nationwide impacts of environmental polic ies, which can also be considered at a regional level of detail appropriate to the functional organization of the power section . Although the Agency typically focuses on broad system 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 inclu des 32 power regions with detailed representation of the inter

- regional transmission system and reflects the regional aspects of natural gas and coal markets. When considering5

- 7

which new units are most cost effective to build and operate, the model conside rs the relative economics of various technologies based on their unique capital costs, operation and maintenance ( O&M ) costs, fuel costs and emission profiles. The capital costs for new units are regionalized through the application of regional adjustment factors that capture 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 loca tions 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 reflects 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 c urves 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 consul tation 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 have 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**  **5.5.1 Base Case Analysis**  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 final MATS and5

- 8

the final Transport Rule (finalized as CSAPR)

. 12 In addition to MATS and CSAPR, the baseline 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. 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 regar ding fuel supplies, the performance and cost of electric generation technologies, pollution controls, and numerous other parameters

. The IPM base case projection is based on an electricity demand growth assumption of 0.8 percent annually on average, simila r to EIA’s Annual Energy Outlook for 2010, and slightly higher than the 0.7 percent annual average growth in the AEO 2012 ER. 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. 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 (see Table 5

- 1). The change in coal represents only ret irements 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 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 mix of electricity generation sources (see Table 5

- 2)

. In addition, coal is projected to continue to provide the largest s hare of America’s electricity. 13 By 2020, EPA forecasts roughly 27 GW of new renewable capacity, 2 GW of coal with CCS, and 10 GW of new natural gas

- fired capacity. Although 2 GW of coal with CCS is included in the base case in response to incentives unde r 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). **Table 5 -**  **1 . Total Generation Capacity in 2010 and Projected by 2020 (GW)** 
**2010 2020** 

12 http://www.epa.gov/airquality/powerplanttoxics and http://www.epa.gov/airtransport

. 13 Coal

-fired generation is projected to increase above 2009 actual levels. 2020 natural gas

- fired generation is pr ojected to be lower than 2010, due in large part to the smaller relative difference in delivered natural gas and coal prices in different areas of the country projected to occur in 2020 than occurred in 2010. While the projected narrowing of this gas price an d coal price differential may increase dispatch (generation) from existing coal units, it is insufficient to shift the economic decision to favor new conventional coal

-fired capacity, which requires consideration of capital costs in addition to generation costs. The same trend is seen in AEO 2011 projections.5

- 9 Pulverized Coal 31 6 304 Natural Gas Combined Cycle 199 212 Combustion Turbine 135 143 Oil/Gas Steam 111 90 Non

- Hydro Renewables 31 73 Hydro 99 99 Nuclear 102 106 Other 5 4 **Total 998**  **1,030** Source: 2010 data from EPA's NEEDS v.4.10 PTR. 2020 p rojections from Integrated Planning Model run by EPA. Note s : The sum of the table values in each column may not match the total figure due to rounding. “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 use.
**Table 5**  **- 2**  **. 20 10**  **U.S. Electricity Net Generation and EPA Base Case Projections for 2020**

**(Billion kWh)**
**Historical Projected**  **2010 2020**  Coal 1,828 1,976 Oil 35 0.12 6 Natural Gas 901 869 Nuclear 807 840 Hydroelectric 258 286 Non

- hydro Renewables 139 289 Other 4 45 **Total 3,972**  **4,30 5**  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 p rojection from IPM run by EPA, 2011. **5.5.2 Sensitivity Analyses**  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 core parameter estimates that underlie the AEO reference case. Even under alternative scenarios where assumptions might improve the relative economic value of building new coal

-fired power plants, the AEO 2011 does not project new coal capacity being built5

- 10

through 2025, beyond the coal capacity already planned outside of the modeling. 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. 14 Although new coal capacity is built in some of these scenarios after 2025, CAA S ection 111(b) requires that this standard be reviewed every eight years, thus this regulatory requirement will likely be reviewed and potentially revised after the 2020 timeframe, which serves as the primary focus of this analysis. In addition to studying the alternative scenarios analyzed by EIA, EPA also conducted three additional sensitivity analyses using IPM : a low shale gas recovery scenario, a high electricity demand scenario, and a combination of the two. 15 The lower shale recovery scenario assumed, th at 50 percent less natural gas is recovered from each shale play relative to the base case (effectively lowering shale reserves by 50 percent , similar to the AEO 2011 low shale gas recovery scenario). The high electricity demand scenario assumed that electricity demand grows at an annual average rate of 1.1 percent , similar to EIA’s high economic growth scenario for AEO 2010 (compared to about 0.8 percent in the EPA baseline, which is similar to the reference case in AEO 2010). Figure 5

- 2 and 5

- 3 illust rate electricity demand and natural gas price in these sensitivity analyses. Note that the EPA structured the sensitivity analyses such that natural gas prices and electricity demand growth are both considerably higher than the comparable AEO 2011 scenari os. 16

14 Conversely, modeling in support 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. 15 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 demonstrate that even when considering the occurrence of two ind ependent and highly unlikely assumptions that influence new power plant additions, new unplanned coal is not expected to be built through 2020. 16 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 ele ctricity 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 conservative view of electricity demand in 2020 (mea ning 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 higher economic value to build relative to the reference case forecast conditions).5

- 11

**Figure 5 -**  **2 .**  **Projected Levels of Electricity Demand in 2020, EPA and EIA** 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**5

- 12

**Figure 5 -**  **3 .**  **Projected Natural Gas Prices in 2020, EPA and EIA (Delivered, Power Sector)**
None of these analyzed scenarios resulted in new conventional coal

-fired capacity being built in 2020 (see Figure 5

- 4) 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 authori zed 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 credits and state ren ewable portfolio standards). These scenarios show similar results as EIA, and serve to further confirm the high likelihood that no new coal capacity is likely to be built by 2020 in baseline forecasts. See Table 5

- 3 for new capacity projections in 2020. **T able 5**  **- 3.**  **Projected New Capacity in 2020**

**EPA****** **Base EPA** ****

**High EPA** **- Low** 

**Shale EPA** **- High** 

**Demand +** 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 Recover y EP

A

- Hi gh Deman d +L ow Sha le Recover y EIA

- Low Sha le

Recovery (AEO 2010) EIA Reference

Cas e - AEO 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** **)**5

- 13 **Case Demand**  **Recovery Low Shale**  **Recovery** Coal +CCS 2.0 2.0 2.0 2.0 Natural Gas Combined Cycle 7.0 22.7 7.3 24.8 Combustion Turbine 3.0 3.2 2.4 2.4 Oil/Gas Steam 0.0 1.0 2.0 3.0 Non

- Hydro Renewables 26.9 27.6 27.3 31.5 Hydro 0.0 0.0 0.0 0.0 Nuclear 0.0 0.0 0.0 0.0 Other 0.0 0.0 0.0 0.0 **Total 38.9**  **55.5 39.0**  **60.7 Note:**  **Small amounts of the “new” capacity in this table in fact refers to incremental capacity that was**  **retired in the base -**  **case, but that is not retied in some of the other cases. This includes any incremnental oil/gas steam**  **. 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 built through 2020 , and whether the requirements would require the regulated community to take actions different from those projected i n the base case . The proposed EGU GHG NSPS discusses potential requirements for new units Analysis performed by EPA, along with information from other sources, suggests that the standards as specified in this proposed rule are likely to result in negligib le emission changes , other quantifi ed benefits , energy impacts, 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 techn ologies 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. 17 **5. 6** **.1 New Units**  This proposal requires that all new fossil

-fuel fired units g reater than 25 megawatt capacity be able to meet an emission rate standard of 1,000 l bs CO 2/MWh on a gross basis . It

17 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 a re 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 conventional new coal

- fired capacity.5

- 14

also proposes an alternative compliance option that would allow new 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 coal

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

- fuel

fired boilers would be affected by the prop osed 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. 18 As discussed in section 5.5, n o new conventional coal

- fired boilers are projected to be built (ex cluding new coal built with CCS)

. This implies that the NSPS will require no changes in design or construction of new EGU s forecasted in the base case. Thus, under the baseline projections as well as the sensitivity analyses presented above, the proposed EGU GHG NSPS will not result in any reduction in emissions , nor any costs. Engineering cost analysis, even outside of a least

- cost system dispatch modeling env ironment, reaches similar conclusions. A comparison of levelized wholesale electricity costs for differing generation technologies and natural gas prices are shown in Figure 5

- 4 and Table 5

- 4
. It is important to note that both EIA and EPA include a capit al 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 surrounding futu re greenhouse gas emission reduction requirements. 19 Note that this figure only shows the costs to the generator and does not reflect the additional social costs that are associated with damages from greenhouse gas emissions or conventional air pollutants. As the figure shows, with a delivered natural gas price of $5 per million British Thermal Units (mmBtu) and a delivered coal price of $2 per mmBtu , which reflect forecasted prices from IPM in 2020, 20 electricity generated by natural gas combined cycle unit s is less expensive on average than coal generation.

18 Natural gas combu stion turbines are not covered by this proposal. 19 EIA includes "a 3

- percentage
- point increase is added to the cost of capital for investments in GHG

- intensive technologies, such as coal

-fired power plants without CCS and CTL plants." Source: EIA AEO 2009, Issues in Focus. Reflecting Concerns Over Greenhouse Gas Emissions in AEO2009, available at: http://www.eia.gov/forecasts/archive/aeo09/issues.html See also http://www.epa.gov/airmarkets/progsregs/epa

- ipm/index.html 20 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 2020.5

- 15

**($2007)**

**Figure 5 -** **4 .**  **Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation**  **Technologies , EPA** **21** 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 t his 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 (in 2007 dollars) , that new coal

- fired generation without CCS becomes competitive , in terms of dollars per megawatt hour

21 Although EPA believes that this cost data is broadly representative of the economics between new coal and new natural gas facilities, this analysis assumes representative new units and does not reflect the full array of new generating sources that could potentially be built. To the extent that other types of new units that would be affected by this rule could be built, they could exhibit different costs than presented here. For example, smaller new con ventional coal facilities which would be more expensive on a $/kw basis and have a relatively higher LCOE, and some technologies could potentially have a lower LCOE if fuel could be obtained cheaply and capital costs remained similar, or lower than, an new base load convention coal plant (petroleum coke or waste coal). These differences do not fundamentally change the analysis presented in this chapter. 0 20 40 60 80 100 120 140

Co nvent iona l

Co al ( no inve sto r clima te co ncern) Co nvent iona l

Coal ( w/ CO 2 Uncertain ty Adder ) Nat ur al G as

Co mbine d Cycle ($5 gas) Natu ral G as

Co mbine d Cycl e ($8 gas) Na tu ral G as

Co mbine d Cycl e ($9. 60 gas) Co al +C CS**$ /** **M W** **h**5

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wholesale cost of electricity generation (none of the EPA or EIA sensitivities with alternate assumptions for natural gas approach this price level)

. I t is important to note that this analysis is based on assumptions regarding the average national cost of generation at new facilities. As reported by the EIA, there is expected to be significant spatial variation in the costs of new generation due to des ign differences, labor wage and productivity differences, location adjustments, among other potential differences. 22 EPA acknowledges that there is some uncertainty around these estimates, and is unable to provide estimates for all variants. However, the r esults are expected to hold for the majority of situations. 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 econ omics. 23 **Table 5 -** **4 . 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 **Natural Gas -** **fired Conventional Combined**  **Cycle** 87 17.5 1.9 45.6 1.2 6 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

22 http://www.eia.gov/oia f/beck_plantcosts/pdf/updatedplantcosts.pdf 23 This 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 can exhibit different economics . Most other energy models, including EIA’s application of NEMS, do not consider these technologies for new electricity sources because they are marginal technologies that are rarely built, and highly dependent upon specific local factors that are difficult to model and high ly speculative (like the ability to obtain a very inexpensive local supply of suitable fuel). The models do include these technologies as part of the existing universe of sources, however. For context, there are currently 59 units nationwide that are des igned to combust either waste coal or petroleum coke, with a total capacity of roughly 5 GW (or 0.5% of the entire fleet). To the extent that these technologies would be built absent this rule due to unique local economics and fuel supply, there would be c ertain costs and benefits associated with this proposed rule, although they would be expected to be small because these sources are not often built. EPA is taking comment and solicits additional information on its consideration of these technologies in th e analysis.5

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**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 compliance option that would allow new units to meet the 1,000 lbs CO 2/MWh standard using a 30 year averaging period. 24 To the extent market participants have alternative views of both the 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 so me later date, in order to achieve the required average rate over the 30 year period. Also the above analysis reflects national averages, and given their specific situation, a market participant could determine that the economics of building a coal

- powere d facility that immediately achieves a CO 2 capture and/or removal rate consistent with the emission standard are favorable. Others have research ed the cost and efficiency of varying levels of capture relative to building other energy technologies. 25 This ongoing research indicates that lower levels of carbon capture at new coal facilities could be cost competitive , and the costs of meeting the proposed emission rate immediately could be achievable

. 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 $116/MWh compared to $147/MWh for 90 percent removal. Howev er, 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.

24 IPM does not consider the impact of elevation on performance, and utilizes a uniform elevation performance

based assumption. 25 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

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**5. 6** **.2 Reconstructed Units**  The EPA’s CAA S ection 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 which compliance with standards of performance for new sou rces 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 announced plans to do so. This provision is rarely trigg ered. 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 standard 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 any of these alternative s to change firms’ behavior because they would be expe cted to choose technologies that are compliant with the standard even in the absence of the 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 th is provision is triggered, EPA believes that the economic analysis outlined above showing 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 technologies for independent market reasons that are already compliant with the new source NSPS included in this proposal). **5. 6** **.3 Modified**  **and Transitional Units**  Modified and t ransitional units are described in the preamble and in Chapter 2 of this RIA. EPA does not anticipate any costs being associated with these units. **5. 7**  **Costs, Economic, and Energy Impacts of the Proposed Rule for New Electric Generating Units**  Under a wide range of electricity market conditions

– including EPA’s baseline scenario as well as multiple sensitivity analyses

– EPA projects that the industry will choose to construct new units that already meet these standards , regardless of this proposal

. As a r esult, EPA anticipate s that the proposed EGU GHG NSPS will result in negligible CO 2 emission changes, energy impacts, or costs for new units constructed by 2020. Likewise, the Agency does not anticipate any notable impact s on the price of electricity or e nergy supplies. Additionally, for the reasons described above , the proposed rule is not expected to raise any reliability concerns,5

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since reserve margins will not be impacted and the rule does not impose any requirements on existing facilities. **5. 8**  **Compar ison of Emissions**  **from 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 lower emission profiles for CO 2 and criteria air pollutants than new coal units

. While the proposed EGU GHG NSPS is anticipated to have negligible costs or quantifi ed benefits under a range of likely market conditions , it is instructive to consider the differences in em issions of CO 2 and conventional air pollutants between the two types of units. As Table 5

- 5 below shows, emission s from a typical new natural gas combined cycle facility are significantly lower than those from a traditional coal unit. 26 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 , sulfur dioxide ( SO 2 ) , NO x, toxic metals, acid gases, and particulate emissions than a comparable natural gas combined cycle facility. A typical natural gas combined cycle unit emit s two million metric tons less CO 2 per year than a typical new conventional coal unit, as well as 930 fewer short tons SO 2 and 1,200 fewer short tons of NO x each year. Importantly, these differences in emissions assume a new coal unit that complies with all applicable regulations, including MATS. 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.

26 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

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**Tabl e**  **5 -**  **5 . Illustrative Emissions Profiles, New Coal and Natural Gas** **- Fired Generating Units**  **27**

**Conventional Coal Natural Gas CC**  **Coal with CCS** Emissions (tons/year) Emission Rate

(lbs/MWh net) Emissions

(tons/year) Emission Rate

(lbs/MWh net) Emissions

(tons/year) Emission Rate

(lbs/MWh net) SO 2 940 0.42 10 0.0041 50 0.022 NO x 1,400 0.62 200 0.09 1,100 0.47 CO 2 3

. 6 million 1,800 1.7 million 820 0.4 million 200

Notes: SO 2 and NO x in short tons, CO 2 in metric tons. As discussed in Section 5.4, the illustrative units represent r elative emissions for new well controlled 600 MW (net) baseload units running at 85 percent capacity factor (85% capacity factor reflects operation of new baseload units and does not necessarily reflect the historic capacity factors of existing units with specifications similar to these illustrative units). Assumed coal is high sulfur bituminous with scrubber and SCR , data are based on EPA assumptions used in IPM. **5 .**  **9 Benefits of Reducing GHGs and**  **Conventional Pollutants**  Becau se emissions of CO 2 and criteria air pollutants adversely affect human health and welfare, the differences in emissions presented above translate into differences in the external social costs associated with different generation technologies. Here we provi de a general discussion about the differences in emissions of CO 2 and criteria air pollutants in the previous illustrative example

. **5.9.1 Social Cost of Carbon**  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 difference in CO 2 emissions between the two representative units discussed in S ection 5
. 8 . The SCC is an estima te 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 achieve marginal reductions in CO 2 emissions. These estimates were developed through an interagency process

27 The emissions presented here are estimated on an output basis to enable easier comparisons and to illustrate the potential impacts of moving from new coal to new natural gas. This analysis assumes representative new units and does not reflect the full array of new generating sources that could potentially be built (e.g., a small new conventional coal plant or a waste coal or petroleum coke facility). However, the emissions associated with other facilities that could be built, and which would be subject to this proposal, would not change noticeably (i.e., thes e new facilities would be subject to emissions standards for other pollutants and would emit similar levels of SO 2, NO X, and CO 2, on an output basis).5

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that included EPA and other executive branch entities, and concluded in February 2010. The SCC Technical Support Document (SCC TSD) provides a complete discussion of the methods used to develop these SCC estimates. 28 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. 29 , 30 The first three values are based on the average SCC from three integrated assessment models, at discount rates of 5, 3, and 2.5 p ercent, 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 c ontext. 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

- expected impacts from temperature change further out in the tails of the SCC distribution. The SCC incr eases 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 assumptions. Table 5

- 6 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

28 Docket ID EPA

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- 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 Economic 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 of Management and Budget, Office of Science and Technology Policy, and Department of Treasury (February 2010). Also avai lable at http://epa.gov/otaq/climate/regulations.htm 29 Note that upstream emissions changes were not considered for this rule. There may be changes in greenhouse gas emissions (in particular, meth ane) due to changes in fossil fuel extraction and transport in response to this proposal, but those were not quantified

. 30 The interagency group concluded that a global measure of the benefits from reducing U.S. GHG emissions should be the standard practic e when conducting regulatory impact analysis in support of federal rule makings. See Interagency Working Group on Social Cost of Carbon. 2010. Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866

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Academies of Science (NRC 2009) points out that any asse ssment 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 impact of changes in climate on the physical and biologica l environment, and (4) the translation of these environmental impacts into economic damages. 31 As a result, any effort to quantify and monetize the harms associated with climate change will raise serious questions of science, economics, and ethics and shou ld 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 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 models do not assign value to all of the important physical, ecological, and econ omic 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 understandably lags behind the most recent research. The limi ted 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 use d 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 estimates as the science and economic understanding of clima te 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 become available, and to continue to support research in this area. Additional details on these limitations are discussed in the SCC TSD.

31 National Research Council (2009). Hidden Costs of Energy: Unpriced Co nsequences of Energy Production and Use

. National Academies Press. See docket ID EPA

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**Table 5**  **- 6**  **. 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 vary depending on the year of CO 2 emissions and are defined in real terms. **5. 9** **.2 Health Impacts of SO** **2 and NO**  **x** 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 a s well as PM 2.5 and ozone. Reducing exposure to PM 2.5 and ozone is associated with significant human health benefits, including avoid ed mortality and 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 associated with exposure to PM 2.5 include premature mortality for adults and infants, cardiovascular morbidity such as heart attacks and hospital admissio ns, and respiratory morbidity such as 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 resp iratory 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 fro m 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). Red ucing these harmful emissions improves human welfare. For more information about the welfare benefits5

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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). Because the health and welfare benefits of SO 2 and NO x emissions in terms of incidences of health effects avoided or monetized value of health or welfare improvements depend on power plant location , the potential benefits cannot be quantified precisely for the purpose s of this illustrative example . However, reducing one thousand tons of annual SO 2 from U.S. EGUs in 2020 has been estimated 32 to yield between 3 and 9 incidences of premature mortality avoided annually and annual monetized PM 2.5 - related health benefits (i ncluding these incidences of premature mortality avoided) 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 (where the range is due to EPA’s use of two alternative p rimary estimates of PM 2.5 mortality impacts, a lower primary estimate based on Pope et al. (2002) and a higher primary estimate based on Laden et al. (2006)). Additionally, reducing one thousand tons of annual NO X from U.S. EGUs in 2020 has been estimated 33 to yield up to 1 incidence of premature mortality avoided annually and annual monetized PM 2.5 - related health benefits (including these incidences of

32 T he SO 2 and NO X benefit per- ton (BPT) 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 used to develop a previous rulemaking affecting power sector emissions of SO 2 and NO X to develop these BPT values ( Air Qu ality Modeling Technical Support Document for the final Transport Rule; http://epa.gov/airtransport/pdfs/AQModeling.pdf). EPA utilized Transport Rule (Cross

- State Air Pollution Rule) modeling ra ther than air quality modeling of EPA’s Mercury and Air Toxics Standards (MATS) because EPA did not estimate NO X BPT values for MATS and because the utilized Transport Rule modeling reduced emissions of SO 2 and NO X independently, allowing for better estima tion of PM 2.5 - related SO 2 and NO X BPT values. The air quality modeling utilized reflects emission reductions in the eastern U.S. In order to better understand the relative difference between BPT values for emission reductions in the east and west, see Tab le 5C

- 3 of the MATS Regulatory Impact Analysis (RIA) < www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf>. Using this existing air quality modeling, EPA used BenMAP ( www.epa.gov/air/be nmap ) to estimate the benefits of air quality improvements using projected 2020 population, baseline incidence rates, and economic factors. These BPT values are methodologically consistent with those reported in Fann et al. (2009). As EPA models avoided premature deaths among populations exposed to levels of PM2.5, we have lower confidence in levels below the lowest measured level (LML) for each study. However, studies using data from more recent years, during which time PM 2.5 concentrations have fallen, continue to report strong associations with mortality. For more information refer to the MATS RIA. The average BPT 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 no t 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 BPT 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. T herefore, the benefits for any specific unit can be very different than the estimates shown here. EPA notes that the BPT estimates do not reflect emission reductions after implementation of EPA’s Mercury and Air Toxics Standards. 33 Ibid.5

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premature mortality avoided) of between $ 2.5 million 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

. **5. 1**  **0 Illustrative**  **Analysis of the Social Costs of New Generating Sources**  As the analysis in sections 5.5 and 5.6 demonstrated, under a wide range of likely electricity market conditio ns – including EPA’s baseline scenario as well as multiple sensitivity analyses

– EPA projects that the industry will choose to construct new units that already meet these standards , regardless of this proposal

. In this section, we consider the unlikely scenario where future market conditions support the construction of new conventional (advanced, but without CCS) coal capacity during the analysis period in the absence of the rule. The analysis in this section indicates that in this scenario, the propose d EGU GHG NSPS is highly likely to provide net benefits to society as a whole. The starting point for this analysis is the illustrative comparison (presented in Figure 5

- 4 above) of the relative private costs of constructing and operating a representative new conventional coal EGU and a representative NGCC unit

. 34 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 between 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 for new generation capacity should account for the pollution damages associated with the competing generation technologies in addition to private generating costs. This section further explores how the potential social benefits and costs of this NSPS sta ndard may change across a wide range of natural gas prices, a key factor in the potential cost of the policy. It begins by estimating illustrative environmental damages per MWh for coal relative to gas generation and then uses

34 By fixing gen eration in this comparison, we are assuming that both technologies generate the same benefits in the form of electricity generating services. We assume in the discussion that the benefits of electricity production to consumers outweighs the private and soc ial investment cost. However, at particularly high fuel prices this might not be the case. For a discussion of when comparing the levelized costs of different generating technologies provides informative results and when it does not see, for example, Josko w 2010 and 201 1.5

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these estimate s to conduct a n illustrative sensitivity analysis for the potential social costs of the policy in this illustrative example

. 35 It should be emphasized that the analysis presented here is illustrative, although EPA believes that it leads to a robust conclusion. From an analytical perspectiv e, the challenge is to estimate expected benefits and costs given uncertainty about future market conditions. An ideal benefit

- cost analysis would first model projected generation capacity and capacity additions for every plausible se t of market conditions ( e.g., different combinations of natural gas and coal supplies and electricity demand). The effects of the proposed EGU GHG NSPS could then be estimated in each of those scenarios including the resulting estimated benefits and costs (which would depend on the amount of new generation capacity built, the technologies used, the location of new generating plants, and so on). The analysis would then estimate the conditional probability distribution of those outcomes (for example, the pro bability distribution of future natural gas prices or future electricity demand conditional on the current information on supply ). Finally, the analysis would integrate the estimated benefits and costs over the conditional probability distribution of outc omes, to arrive at the expected net benefits of the rule. The analysis just described is beyond the scope of the current RIA, and EPA believes that the sensitivity cases presented in section 5.6.1, combined with the illustrative analysis here, provide a ro bust picture of the likely costs and benefits of the standard . Nonetheless, EPA is in viting comment on whether a more detailed analysis would be practical , feasible, and an effective use of limited analytical resources, and if so , how it might be carried out and what information it would be expected to provide . If commenters believe that such an analysis would be practical and appropriate , EPA invites comment on what variables should be treated as uncertain (e.g., natural gas and coal prices, electricity demand) and on the specific conditional and potentially joint probability distributions that should be used for the future state of those variables

. In the spirit of the “ideal” analysis just described, in the remainder of this section EPA provides an illustrative analysis focusing on uncertainty in the price of natural gas, which is a key determinant of the economics of electricity generation and therefore the potential impacts of this proposed rule.

35 From an economic perspective, the analysis in sections 5.5 and 5.6 considered the net benefits of the rule under expected market conditions, and found those to be zero (because the rule would not affect what new capacity is built under those market conditions). The analysis in this section, while still purely illustrative, is an initial step toward estimating the expected net benefits of the rule as a function of market conditions.5

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**5.1 0** **.1 Illustrative**  **E**

**nvironmental D** **amages per MWh** As previously discussed in this ch a pter, 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 Merc ury and Air Toxics 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. 8

. The external costs are define d as the damages associated with pollution that are not accounted for in the private investor's decision making. 36 To illustrate the external costs associated with new generation options we combine the illustrative emission profiles for the new units, as p rovided in Table 5

- 5 , and the illustrative emissions and damage estimates discussed in the previous two section s . 37 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 38 mu ltiplied by the PM 2.5 - related SO 2 benefit per

-ton estimates , 39 subsequently dividing by MWh to estimate the external costs per unit of generation. Table 5

- 7 reports the additional pollution damages from the illustrative new coal plant relative to the illus trative new natural gas plant given different mortality risk studies and assumptions about the discount rate. These pollution damages should be relatively invariant across natural gas prices and other economic factors. D epending on the discount rate and mortality risk study used, damages associated with generation from a representative new coal unit are $ 1 1 to $ 81 per MWh, while damages associated with the illustrative new natural gas combined cycle unit are $3 to $ 31 per MWh (2007$). 40 It is important to note that although the ranges appear to overlap, for any set of assumptions (i.e., any specific mortality risk study and choice of SCC value) estimate the

36 See Baumol and Oates, 1988. 37 Only the direct emissi ons of two pollutants (CO 2 and SO 2 ) are considered in this illustrative exercise. Other pollutants and lifecycle emissions are not considered. 38 See footnote 30 in section 5.8. 39 See footnote 36 in section 5.9.2 for a description of the benefit

- per-ton val ues. In this exercise they are interpreted as damage

- per-ton values. 40 Different discount rates are applied to SCC than to the other damage estimates because CO 2 emissions are long

lived and subsequent damages occur over many years. Moreover, several rate s 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 its attention on t he 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 Regulatory Impact Ana lysis Under Executive Order 12866. Docket ID EPA

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- 114577. http://www.epa.gov/otaq/climate/regulations/scc

-tsd.pdf for details.5

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pollution damages associated with new coal generation are signifi cantly higher than those associated with new natural gas combined cycle generation in this illustrative, but representative example . For example, considering the SO 2 per ton damages based on Pope et al. 2002 using a 7% discount rate and the SCC estimate b ased on the 3% discount rate, new generation based on conventional coal in this example would result in an additional $ 17 per MWh in pollution damages compared to a new NGCC plant. Alternately, damages that reflect the SO 2 per ton damage 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 $ 33 of pollution damages per MWh from a new conventional coal unit compared to a new NGCC plant.5

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**Table 5 -**  **7 .**  **Pollution Damages ($/MWh) from Illustrative New Coal Unit**  **Relative to New** 

**Natural Gas Combined Cycle Unit 41** 

**SCC Discount Rate Damages from CO**  **2** 5% $3 3% $11 2.5% $18 3% (95 th percentile) $34

**Damages from SO 2**  **Only Discount**  **R ate**  **A pplied to**  **H ealth**  **C o**  **- B**  **enefits Mortality** **- Risk**  **Study 3% Discount Rate**  **7% Discount Rate** Pope (2002) $6 $6 Laden (2006) $16 $1 4

**Combined Damages from CO 2**  **and SO 2**  **Discount Rate Applied to Health Co**  **- Benefits**  SCC Discount Rate **3% Discount Rate 7% Discount Rate**  5% $ 9

- $ 19 $ 9

- $ 17 3% $ 17

- $ 27 $ 17

- $ 25 2.5% $ 24

- $ 33 $ 24

- $ 32 3% (95 th percentile) $ 41

- $ 50 $ 40

- $ 48 Notes: Values in first two tables may not sum due to rounding. The range of costs within each SCC value and discount rate for SO 2 pollution damages pairing reflects the use of two core estimates of PM2.5

- related premature mortality, Pope et al. (2002) representing the low er of our core estimate s and Laden et al. (2006) represent the high er of our core estimate s . Assumed coal is high sulfur bituminous with scrubber and SCR

. The combinations of health studies and discount rates represent lower and higher valuations of impacts of SO 2 emissions in the Eastern U.S. EPA has evaluated the range of potential impacts per MWh by combining all SCC values with health damages values at the 3 percent and 7 percent discount rates. To be consistent with concepts of intergenerational discounting, values for health damages, which occur within a generation, would only be combined with SCC values using a lower discount rate, e.g. the 7 percent health damages estimates would be combined with 5 percent or lower SCC values, but the 3 percent health damages would not be combined with the 5 percent SCC value. While the 5 percent SCC and 3 percent health damages estimate falls within the range of va lues we analyze, this individual estimate should not be used independently in an analysis, as it is represents a combination of discount rates that is unlikely to occur

. Combining the 3 percent SCC values with the 3 percent health damage values assumes tha t there is no difference in discount rates between intragenerational and intergenerational impacts.

41 The damages presented here are estimated on an output basis to enable easier comparisons and to illustrate the potential impacts of moving from new coal to new natural gas. This analysis assumes representative new units and does not reflect the full array of new gen erating sources that could potentially be built (e.g., a comparison of a small new conventional coal plant with a small natural gas plant, or a comparison of a waste coal or petroleum coke facility to a natural gas plant of a comparable size and capacity factor ). However, the damages associated with other facilities that could be built, and which would be subject to this proposal, would not change noticeably (i.e., these new facilities would be subject to emissions standards for other pollutants and would emit similar levels of SO 2 and CO 2, on an output basis) except for differences in local conditions, as discussed below

.5

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As with the relative investment costs of a new coal unit and a new natural gas combined cycle system, the actual environmental damages associated with thes e two technologies depends on the location under consideration and the specific fuels that would be used. A n ideal benefit

- cost analysis would account for these local circumstances (and consider alternative sources of generation). 42 However, these factors will not change the qualitative conclusion. T he damages associated with CO 2 emissions, which are 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

- co ntrolled 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. The conclusion from this analysis is that there are significant environmental damages associate d with electricity generation from a representative new conventional coal unit relative to a representative new natural gas combined cycle unit. 43 Other studies of the social costs of coal and natural gas fired generation provide similar findings (Muller et . al, 2011; NRC, 2009). 44 An important implication is that if market conditions changed sufficiently so that new coal units became marginally more profitable to operate, these new units are still likely to impose a net cost to society relative to a new natural gas plant. This idea is discussed in more detail in the next section. 45

42 EPA does not assert a specific location for the illustrative coal and natural gas combined cycle units and is therefore unable to spec ifically determine the population that would be affected by their SO 2 emissions. Therefore, the benefits for any specific unit can be very different than the estimates shown here. 43 As previously noted in this section and the previous sections on the costs and damages associated with these technologies, 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 SO 2 emissions. Therefore, the benefits for any specific unit can be very different than the estimates shown here, though the proportion associated with CO 2, which is a well dispersed global pollutant, will not be affected by location. 44 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 comparisons are based on typical existing coal and natural gas units, includ ing 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 existing coal plants (compare Tables 2

- 9 and 2

- 15). However, the NAS comparison does not 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 g eneration than natural gas combined cycle units. 45 The presence of net benefits for a given regulatory option is a necessary but not a sufficient condition for optimal regulatory design. It does however; signify that the regulatory option is welfare impr oving for society.5

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**5.1 0** **.2 Social**  **Benefits and Costs**  **a cross**  **a Range of Gas Prices**  **- Sensitivity**  **Analysis** We now discuss how a consideration of the environmental damages associated with new coal and natural gas EGUs informs the comparison of the two technologies from the standpoint of net benefits

– building on the illustrative comparison of a representative new coal unit and a representative natural gas unit developed in Sections 5. 8 and 5. 9
At current natural gas prices relative to other fuels, the difference in the estimated levelized cost of electricity for a representative NGCC unit is roughly $27 per MWh less than for a representative new conventional coal unit (see Figure 5

- 4 ). This is co nsistent with EPA’s projection, discussed at length above, that the proposed EGU GHG NSPS will not impose any social costs (or generate quantifi ed net benefits) under current and likely future market conditions

. Because the impacts of this proposed rule depend on future natural gas prices, which are uncertain, EPA conducted an illustrative analysis of the impacts of the rule over a wide range of natural gas prices. This analysis considers two distinct thresholds in the price of natural gas at present: one price at which the private cost of a representative new coal unit falls below that of a representative NGCC unit, but the generation cost advantage remains outweighed by the environmental dam ages from the perspective of society as a whole; and an even higher price at which the environmental damages no longer outweigh the private cost advantage. This analysis presents three relevant ranges within the conditional distribution of future natural gas prices that can be classified as a range of likely gas prices, unexpectedly high natural gas prices, and unprecedented natural gas prices. It is important to note that this illustrative analysis considers variation in the natural gas price holding all else constant; as discussed above, an ideal analysis would vary other conditions simultaneously

. 46 In general, this analysis shows that the policy would likely have a net benefit even under scenarios with much higher gas prices. Under some conditions, hi gher natural gas prices result in a net cost, holding all other parameters constant and disregarding benefits that we are unable to monetize

. 47 However, it is important to note that this analysis is limited in the types of social benefits and costs consider ed, given that it does address the life

- cycle pollution associated with fossil fuels along with the limitations of current SCC estimates, as previously discussed.

46 For example, high economic growth would raise both natural gas and coal prices at the same time

– extending the range of natural gas prices for which NGCC retained a cost advantage. 47 In reality this is unlikely to be the case. For ex ample, high economic growth would increase both natural gas and coal prices at the same time

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

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**Likely Natural Gas Prices.** As described earlier in this chapter, 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 natural gas

-fired combined cycle genera tion or coal

-fired generation with CCS (the latter is assumed to be built with support from federal grants). This conclusion also holds for the high

- demand and low

- shale

- gas sensitivity analyses considered above. As shown earlier in the illustrative analysis , it is only when gas prices reach approximately $9.60/mmBtu, that new conventional coal

- fired generation becomes competitive with NGCC in terms of the levelized cost of electricity (in dollars per megawatt hour )

. Projections of future market cond itions suggest that it is likely that natural gas prices will remain below this level. As noted earlier in this chapter, EIA’s projected natural gas price for 2020 in its reference scenario for AEO 2011 is $5.30 (in 2007 dollars). E ven EIA’s most pessimi stic gas sensitivity case (“low shale gas recovery per well”) only projects an electricity sector gas price of $ 7.01/mmBTU (in 2007 dollars) in 2020 (the “low shale gas recovery per play” scenario projects a price of $ 6.13 /mmBtu ( in 2007 dollars ) 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 absence of this standard. In this scenario , it appears very likely that the costs

– a nd benefits

– of the proposed standard will be zero. **Unexpectedly High Natural Gas Prices .**  In this illustrative analysis, at natural gas prices above approximately $9.60/mmBtu, the private levelized cost of electricity for a representative new conventiona l coal unit falls below that of a new NGCC unit. Therefore, above that price level some new conventional 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. 48 However, these coal units would also impose additional environmental and health damages in the form of global warming pollution and particula te matter (as a result of SO 2 and NOx emissions)

– an element of social costs that are avoided by building an NGCC unit instead

. For a range of natural gas prices above $9.60/mmBtu, the resulting external costs will outweigh the difference in the private costs in this illustrative example

– indicating that the proposed standard would yield net benefits. For example, at gas prices of $10/MMBTU, the

48 See section 5.4 for a discussion of how local conditions and other factors influenc ing the levelized cost comparison may influence the natural gas price where the levelized cost of the conventional coal unit and the NGCC unit are the same.5

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illustrative conventional coal unit would generate power for $3/ MWh less than an NGCC unit , 49 but result in g reater pollution damages of $ 9 to$ 50/MWh (see table 5

- 7 ). 50 Under the proposed standard, if in this example the NGCC unit were built instead , the resulting net social benefit would be $ 6 to $ 47/ MWh. For context, we note that these circumstances are far less likely than the zero cost scenario outlined above. To put this gas price point into historical context, $9.60/MMBTU is higher than any average annual gas price (in 2007 dollars) observed over the last 10 years, and it has only been reached temporarily in 8 of the last 120 months. 51 , 52 Looking forward, the continued development of unconventional natural gas resources in the U.S. suggests that gas prices would actually tend to be tow ards the lower end of the historical range. As discussed above, none of the EIA sensitivity cases (which represent future price trajectories for both gas and coal) show scenarios where non

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

- compliant coal would be sufficiently lower than the cost of new natural gas that the net social benefit of the standard could be negative ( i.e., a net co st ) under some assumptions for environmental damages. For example, at gas prices of $15/MMBTU, the illustrative conventional coal unit would generate power for roughly $3 7/MWh less than an NGCC unit but result in social costs of $ 9 to $ 5 0/MWh (see table 5

- 7 ). Under the proposed standard, if an NGCC unit were built instead , the resulting net social impact would range from a net cost of $ 2 8 to a net benefit of 1 3/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 . For example, assuming an SCC using a 3% discount rate , along with a 7% discount rate for estimating benefits from reduced SO 2 and the mortality

- risk estimate from Pope (2002), natural gas prices above $12/mmBtu in this illustrative example would result in net social costs from the proposed

49 Assuming an increase of $6.80/MWh in the cost of gas generation for every $1/MMBTU increase in n atural gas prices. 50 Again, assuming that coal prices do not increase along with natural gas prices as they historically have. See previous footnote. 51 See: http://www.eia.gov/dnav/ng/hist/n3045u s3A.htm . EIA reports average annual delivered natural gas prices to the electricity sector for the past 15 years (since 1996) and reports average monthly delivered natural gas prices to the electricity sector over the past 10 years (since 2001). 52 It is important to note that relatively high gases prices in a single month or year will not drive the 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 forecasts for the future, it is highly unlikely that expectations of sustained high natural gas prices, to the degree necessary to drive technology choices, will b e realized.5

- 34

standard. Alternatively, using an SCC value of 3% and using the mortality

- risk estimate from Laden (2006) along with a 3% discount rate for PM benefits, the corresponding threshold for natural gas prices would be $14/mmBtu

. Natural gas prices above these levels would be unprecedented. Average a nnual natural gas prices delivered to the electricity sector have not exceeded $ 9. 47 / mmBtu (in 2007 dollars) over the last 15 years , and projected prices do not begin to approach this level in any of EIA’s scenarios

. 53 , 54 As a result, based on historical gas prices as well as projections, EPA believes that there is an extremely small probability that natural gas prices will reach (let alone remain at) levels at which this standard would generate net social costs. We emphasize that differences in generating costs, plant design, local factors, and the relative differences between fuels costs can all have major impacts on the precise circumstances under which this standard would be projected to have no costs, net bene fits or net costs. However, based on average annual gas prices over the last 15 years, we project that this standard is most likely to have negligible costs, and, if it does impose costs, it likely also produces positive, although modest, net benefits . T here is an exceedingly low probability that it results in net costs. **5.1 0** **.3 Illustrative Costs and Benefits of CCS Compared with Conventional Coal**  The analysis above focuses on two well developed control technologies, conventional supercri ti cal coal and n atural gas combined cycle. Because these technologies are well developed, there is significantly more certainty about operating costs than for new, emerging technologies like coal with CCS. As a result, any analysis that 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 relative social costs. EPA compared the costs and damages for a model pulverized coal (PC) EGU using supercritical steam co nditions (like the one used in the comparisons above) to and IGCC plant with a CCS system (e.g. Selexol) . See technical memo

“ Control Cost and Environmental Impacts of the Proposed GHG NSPS on new Coal

- Fired Electric Utility Generating Units ” for more deta ils.

53 http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm . EIA reports average annual delivered natural gas prices to the electricity sector for the past 15 years (since 1996) and re ports average monthly delivered natural gas prices to the electricity sector over the past 10 years (since 2001). 54 Note that while EIA forecasts natural gas prices to rise, it also forecasts coal price to rise as well. An ideal comparison of levelized costs in future time periods should account for the expected change in both natural gas and coal prices.5

- 35

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 3 9 % of the CO 2 is captured and stored. EPA ha s not previously developed costs for such a unit, therefore, this analysis may not fully realize all of the cost savings possible from building a unit with significantly less than 90% capture (for instance, an IGCC could be built with a conventional gas tu rbine, 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 EG U with CCS would most 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 C lean Energy project 55 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 fo r the 90% capture case . 56 We 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) for the partial capture case . Costs for the IGCC unit with 90% capture and the supercritical pulverized coal

- fired ( SPC) unit without CCS were derived from IPM version 4.10. 57 These cost estimates are generally consistent with the range of studies estimating the cost of CCS that are a vailable, however there is uncertainty around any such projections of technology costs, particularly for early movers of this technology. Capital costs for the IGCC unit with 39% capture were assumed to be 90% of the capital costs for an IGCC unit with 90% CCS. EPA estimated the benefits associated with avoided CO 2 and SO 2 emissions in a similar fashion to the one described above

. See technical memo “ Control Cost and Environmental Impacts of the Proposed GHG NSPS on new Coal

- Fired Electric Utility Generatin g Units ” for more details. **Table 5 -**  **8 Illustrative Costs and Benefits for two CCS Scenarios Compared to Conventional** 

**Coal Plant (Millions 2007$)**
**SPC to IGCC with 3 9**  **% SP**  **C to IGCC with 90%** 

55 http://www.texascleanenergyproject.com/ 56 US DOE / NETL studies have assumed a delivered CO 2 pri ce 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/NETL

-402/1312 ( Fe bruary 2008 ). 57 http://www.epa.gov/airmarkets/progsregs/epa

- ipm/BaseCasev410.html5

- 36 **C apture**  **C apture**  Additional Gross Annual Private Costs $ 17 $ 34 Revenue from EOR $ 5 (@$15/ton) $ 37 (@$45/ton) Net Additional Annual Private Costs $ 12 ($ 3 ) Value of Monetized Benefits SCC 3% with Pope 7% $ 13 $ 24 SCC 3% with Laden 3% $ 23 $ 34 Net Monetized Benefits SCC 3% with Pope 7% ($ 1 ) $ 27 SCC 3% with Laden 3% $ 11 $ 37
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. As before, it is important to note that these co mparisons omit additional benefits that may be associated with the abatement of greenhouse gas emissions

. **5. 1**  **1 Macroeconomic and Employment Impacts**  This proposed EGU GHG NSPS is not anticipated to change GHG emissions for newly constructed electric generating units, and is anticipated to impose negligible costs or quantifi ed benefits

. 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 based on the estimated compliance costs and other energy impacts, which serve as an input to such analyses. However, sinc e 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.

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. Retrieved from http://www.washingtonpost.com/newssearch.
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-term Exposure to Fine Particulate Air Pollution. Journal of the American Medical Association 287:1132

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– 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 Qualit y Criteria for Ozone 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. Integrated 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

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