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CHAPTER 5

COSTS, BENEFITS, ECONOMIC, AND ENERGY IMPACTS

5.1 Synopsis

This chapter reports the compliance cost, economic, and energy impact analysis 

performed for the EGU GHG NSPS. EPA used IPM, developed by ICF Consulting, in this analysis. 

IPM is a dynamic linear programming model that can be used to examine air pollution control 

policies throughout the United States for the entire power system. EPA used the IPM model to 

forecast likely future electricity market conditions with and 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 20201) 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, 

indicates 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.2

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. Current forecasts for the mix of new, and utilization of existing,

generating capacity are a key input into informing the design of EPA’s proposal. Given excess 

capacity within the existing fleet and relatively low forecasts of electricity demand growth, 

there is limited new capacity, of any type, expected to be constructed over the next decade. A 

 

1

Note that while the analysis presented in this RIA is for the year 2020, IPM projections were also made for 2030 

and are available in the docket.

2

This chapter presents all costs in 2007$.
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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 

horizon 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 electricity 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 considered for this analysis. Current 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 resources and substantially 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 petroleum 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 increased 

between the 2011 and 2012 Outlooks, driven by lower drilling costs and continued 
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drilling in shale plays with high concentrations of natural gas liquids and crude oil, which 

have a higher value in energy equivalent terms than dry natural gas.3

Based 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 plant.4,5 

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).

 

3

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

http://www.eia.gov/energy_in_brief/about_shale_gas.cfm

4

See Table 5-4, which reports the levelized cost of new generation in the Annual Energy Outlook (AEO) 2011. 

5

Note that EPA’s analysis, which is consistent with this expectation, is based on sophisticated IPM modeling, and is 

not based on simplified LCOE assumptions.
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Figure 5-1. Historical U.S. Power Plant Capacity Additions, by Technology

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 modeling 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 

2011 shows a modest amount of CCS-equipped new coal-fired power coming online past 2012

that would be in compliance with this proposal.

6

 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 

 

6

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 sources under 

this proposal. It also has 2 GW of unplanned coal capacity, which reflects new coal with CCS in response to 

Federal incentives.

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Capacity (M

W)

Other

Gas (CC and CT)

Renewable/Hydro

Nuclear

Coal
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to the AEO 2011, the majority of new generating capacity is forecast to be either natural gasfired 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.7 Based 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."8 The economics favoring 

new NGCC additions instead of conventional coal are robust under a range of sensitivity cases 

examined in the AEO. Unplanned additions of coal by 2020 are also not forecast in sensitivity 

cases that separately examine higher economic growth, lower coal prices, lower capital costs 

for fossil capacity, no risk premium for greenhouse gas emissions liability from conventional 

coal, slower oil and gas technology deployment, lower shale gas recovery per play, and lower

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 electricity demand projections than 

those used in IPM, reflecting an extended economic recovery and increasing energy efficiency 

in end-use appliances,9 which 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 similar to those presented in AEO 2011, and also forecasts no construction 

of new conventional coal-fired power plants under the base case.10 

A number of major utilities have made public announcements consistent with these 

modeling results.11

 

7

http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm

8

Department of Energy (2011). Report on the First Quadrennial Technology Review. Available at 

http://energy.gov/sites/prod/files/QTR_report.pdf. 

9

AEO 2012 Early Release Overview

10 http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation

11 For example: “We have no other coal-fueled generation planned at this time... When we do need new capacity, 

it is highly likely that we will look to natural gas plants instead of coal, especially if natural gas prices remain as 

low as projected.” AEP January 1, 2011, Washington Post; “If you actually look at the economics today, you 

would be burning gas, not coal,” Jack Fusco, Calpine, 12/1/2010, Marketplace; “Coal’s most ardent defenders 

are in no hurry to build new ones in this environment.” John Rowe, Exelon, 9/2011, EnergyBiz; “With low gas 

prices, gas-fired generation kind of snowplows everything else” Lew Hay, NextEra, 11/1/2010, Dow Jones.
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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 specifically for analysis of the power sector. Thus, the model has been designed to 

reflect the industry as accurately as possible. EPA uses the best available information from 

utilities, industry experts, gas and coal market experts, financial institutions, and government 

statistics as the basis for the detailed power sector modeling in IPM. More detail on IPM can be 

found in the model documentation, which provides additional information on the assumptions 

discussed here as well as all other assumptions and inputs to the model.

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.12

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 provides opportunity for expert review and comment by a 

variety of stakeholders, including owners and operators of the electricity sector that is 

represented by the model, public interest groups, and other developers of U.S. electricity sector

models. The feedback that the Agency receives provides a highly detailed check for key input 

assumptions, model representation, and modeling results.

The Agency has used IPM in several recent regulatory contexts. The model has been 

used to support the Agency’s analytics for the Clean Air Interstate Rule, CSAPR, MATS, and over 

a dozen legislative analytical efforts to forecast the costs, emission changes, and power sector 

impacts of various policies to reduce power sector emissions. As part of the rulemaking 

process, EPA is required to respond to every significant comment submitted. 

 

12 http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html
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The model has also been used by states (e.g., for Regional Greenhouse Gas Initiative, 

the Western Regional Air Partnership, Ozone Transport Assessment Group), other Federal and 

State agencies, environmental groups, and industry, 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 model 

extensively to inform issues related to ozone in the northeastern portion of the U.S. This 

groundbreaking work set the stage for the NOx SIP call, which has helped reduce summer NOx

emissions and the formation of ozone in densely populated areas in the northeast. In the late 

1990’s, the Science Advisory Board reviewed IPM as part of the CAA Amendments Section 812 

prospective studies that are periodically conducted. The model has also undergone 

considerable interagency scrutiny as part of a series of legislative analyses over the past 

decade. These analyses explored a variety of approaches to controlling emissions from the 

power sector, and the results were presented to Congress in a comparative manner in order to 

evaluate the merits of policy proposals. The model was also used to support the Agency’s 

power sector analyses of legislative climate proposals in 2005, continuing through 2010. In 

addition, Regional Planning Organizations throughout the U.S. have extensively examined IPM 

as a key element in the state implementation plan (SIP) process for the National Ambient Air 

Quality Standards. The 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 years.

5.4 IPM is a Detailed Bottom-Up Model

EPA applies IPM to consider nationwide impacts of environmental policies, 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 

includes 32 power regions with detailed representation of the inter-regional transmission 

system and reflects the regional aspects of natural gas and coal markets. When considering 

which new units are most cost effective to build and operate, the model considers 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 
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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 projections, a key component of new power plant economics. The 

model includes an endogenous representation of the North American natural gas supply system 

through a natural gas module that reflects a full supply/demand equilibrium of the North 

American gas market. This module consists of 114 supply, demand, and storage nodes and 14 

liquefied natural gas regasification facility locations that are tied together by a series of linkages 

(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 linkages representing rail, barge, and truck and conveyer linkages. The coal supply curves

in IPM, which are publicly available, were developed during a thorough bottom-up, mine-bymine based approach that depict the coal choices and associated supply costs that power 

plants will face over the modeling time horizon. The IPM documentation outlines the methods 

and data used to quantify the economically recoverable coal reserves, characterize their cost, 

and build the 84 coal supply curves that are implemented in EPA modeling applications. The 

coal curves used by EPA were developed in consultation with Wood Mackenzie, one of the 

leading energy consulting firms and specialists in coal supply. These curves have been 

independently reviewed by industry experts and 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 and 

the final Transport Rule (finalized as CSAPR).

13 In addition to MATS and CSAPR, the baseline 

takes into account emissions reductions associated with the implementation of all finalized 

 

13 http://www.epa.gov/airquality/powerplanttoxics and http://www.epa.gov/airtransport. 
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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 regarding 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, similar 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 4,086 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 retirements of 

existing plants and no new unplanned coal builds. These projections are the result of least-cost 

dispatching using IPM, and reflect the most cost-effective 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 share of America’s electricity.14 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 under 

existing law, overall coal capacity is forecast to decline in response to current economics, along 

with some retirements due to other air regulations (CSAPR and MATS). 

 

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

projected 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 and 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.
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Table 5-1. Total Generation Capacity in 2010 and Projected by 2020 (GW)

2010 2020

Pulverized Coal 316 304

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 projections from Integrated Planning Model run by EPA.

Notes: 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. 2010 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 0.126

Natural Gas 901 869

Nuclear 807 840

Hydroelectric 258 286

Non-hydro Renewables 139 289

Other 4 45

Total 3,972 4,305

Notes: The sum of the table values in each column may not match the total figure due to rounding.

Source: 2010 data from EIA Electric Power Annual 2010, Table 2.1; 2020 projection 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 
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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 built 

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.15 Although 

new coal capacity is built in some of these scenarios after 2025, CAA Section 111(b) requires 

that this standard be reviewed every eight years, thus this regulatory 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.16 The lower shale recovery 

scenario assumed, that 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 illustrate 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 scenarios.17

 

15 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. 

16 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 independent and highly unlikely assumptions that influence new power plant additions, new 

unplanned coal is not expected to be built through 2020. 

17 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 2.5% higher than the 2020 forecast in AEO 2011. 

EPA’s sensitivity with higher electricity demand growth (using the AEO 2010) uses an electricity demand for 

2020 that is about 6% higher than the reference case AEO 2011 demand for 2020, and about 3% 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 (meaning that its electricity demand 

projection is considerably higher than the most recent reference case forecast, therefore representing a future 

in which new coal-fired capacity would be of correspondingly higher economic value to build relative to the 

reference case forecast conditions).
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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 - High Demand AEO 2010 AEO 2011 AEO 2011 - High 

Econ. Growth

TWh
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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 authorized and/or appropriated 

funding to DOE for CCS deployment.18 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 renewable 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.

 

18 A number of the sources that EPA has identified as transitional sources have received some form of DOE 

financial assistance to demonstrate CCS. Several additional projects have received funding but have not yet 

received air permits. Beyond these projects, prospects for additional federal funding are dependent on the 

overall budget process.

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

EPA - Base Case EPA - High

Demand

EPA - Low Shale 

Recovery

EPA - High

Demand + Low 

Shale Recovery

EIA - Low Shale 

Recovery (AEO 

2010)

EIA Reference 

Case - AEO 2011

Average Price 

(2011, EIA)

Delivered Price, Power Sector ($2007/m

mBtu)
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Table 5-3. Projected New Capacity in 2020

EPABase 

Case

EPAHigh 

Demand

EPA-Low 

Shale 

Recovery

EPA-High 

Demand + 

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

Non-Hydro Renewables 26.9 27.6 27.3 31.5

Total 38.9 55.5 39.0 60.7

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 in 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 negligible emission changes, other 

quantified 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 technologies other than coal (mostly natural gas 

and renewable sources) are likely to be the technologies of choice for new sources due to 

current and projected market conditions.19

5.6.1 New Units

This proposal requires that all new fossil-fuel fired units greater than 25 megawatt 

capacity be able to meet an emission rate standard of 1,000 lbs CO2/MWh on a gross basis. It 

also proposes an alternative compliance option that would allow new units to meet the 1,000 

 

19 EPA does not anticipate any oil or gas steam boilers to be constructed, either. Although these types of units 

would be subject to this rule, they have not been a technology of choice for the sector in recent years and are 

generally smaller (less than the 25 MW applicability threshold included as part of this rule). In addition, the 

operating economics also do not favor this technology, similar to the dynamic with conventional new coal-fired 

capacity.
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lbs CO2/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-fuelfired boilers would be affected by the proposed EGU GHG NSPS. The NGCC units, which are the 

basis of the proposed standard, are projected to meet the proposed standard through their 

inherent design.20 As discussed in section 5.5, no new conventional coal-fired boilers are 

projected to be built (excluding new coal built with CCS). This implies that the NSPS will require 

no changes in design or construction of new EGUs 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, or any costs.

Engineering cost analysis, even outside of a least-cost system dispatch modeling 

environment, 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 capital 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 future greenhouse gas emission reduction requirements.21 

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 2020,22 electricity generated by natural gas combined cycle units is less 

expensive on average than coal generation. 

 

20 Natural gas combustion turbines are not covered by this proposal.

21 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

22 EIA projects a U.S. average power sector delivered coal price of $2.08/MMBtu in 2020 ($2007). EPA and EIA 

both project delivered (power sector) natural gas price of roughly $5/mmBtu in 2020.
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($2007)

Figure 5-4. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation 

Technologies, EPA23

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). In this graph coal is a high sulfur bituminous at $2 

mmBtu. Conventional Coal is at a heat rate of 8,875 Btu/kWh net, capacity factor of 85 percent assumed across all 

technologies. 

 

23 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 conventional 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

Conventional 

Coal (no 

investor 

climate 

concern)

Conventional 

Coal (w/ CO2 

Uncertainty

Adder)

Natural Gas 

Combined 

Cycle ($5 gas)

Natural Gas

Combined 

Cycle ($8 gas)

Natural Gas

Combined 

Cycle ($9.60 

gas)

Coal + CCS

$/M

Wh
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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 

wholesale cost of electricity generation (none of the EPA or EIA sensitivities with alternate 

assumptions for natural gas approach this price level). 

It is important to note that this analysis is based on assumptions regarding the average 

national cost of generation at new facilities. As reported by the EIA, there is expected to be 

significant spatial variation in the costs of new generation due to design differences, labor wage 

and productivity differences, location adjustments, among other potential differences.24 EPA 

acknowledges that there is some uncertainty around these estimates, and is unable to provide 

estimates for all variants. However, the results 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 economics.25

This rule also proposes an alternative compliance option that would allow new units to 

meet the 1,000 lbs CO2/MWh standard using a 30 year averaging period.26 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 some 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-powered facility that immediately achieves a CO2 capture and/or 

removal rate consistent with the emission standard are favorable.

 

24 http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf

25 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 highly 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 designed 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 certain 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 the analysis.

26 IPM does not consider the impact of elevation on performance, and utilizes a uniform elevation performancebased assumption.
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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 66.1

 Advanced Combined Cycle 87 17.9 1.9 42.1 1.2 63.1

 Advanced CC with CCS 87 34.6 3.9 49.6 1.2 89.1

 Conventional Comb. Turbine 30 45.8 3.7 71.5 3.5 124.5

 Advanced Combustion 

Turbine 30 31.6 5.5 62.9 3.5 103.5

Advanced Nuclear 90 90.1 11.1 11.7 1.0 113.9

Wind 34 83.9 9.6 0 3.5 97.0

Wind - Offshore 34 209.3 28.1 0 5.9 243.2

Solar PV 25 194.6 12.1 0 4.0 210.7

Solar Thermal 18 259.4 46.6 0 5.8 311.8

Geothermal 92 79.3 11.9 9.5 1.0 101.7

Biomass 83 55.3 13.7 42.3 1.3 112.5

Hydro 52 74.5 3.8 6.3 1.9 86.4

Source: EIA, AEO 2011

Others have researched the cost and efficiency of varying levels of capture relative to 

building other energy technologies.27 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 CO2, which is just above the 

proposed standard) could be $116/MWh compared to $147/MWh for 90 percent removal. 

 

27 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

df
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However, investment decisions will be made on a case by case basis dependent upon a number 

of factors, all of which are difficult to estimate in advance.

5.6.2 Reconstructed Units

The EPA’s CAA Section 111 regulations define reconstructed sources as, in general, 

existing sources (i) that replace components to such an extent that the capital costs of the new 

components exceed 50 percent of the capital costs of an entirely new facility, and (ii) for which 

compliance with standards of performance for new sources is technologically and economically 

feasible (40 CFR 60.15). The Agency is aware that, in theory, operators of existing power plants 

may choose to reconstruct them, but we are not aware of any announced plans to do so. This 

provision is rarely triggered. In light of this limited experience concerning reconstructions, the 

Agency lacks adequate information that is needed to propose a standard of performance for 

reconstructions. As a result, in today’s action, the EPA is not including a proposal for 

reconstructions. Instead, we solicit comment on how we should approach reconstructions and, 

depending on the information we receive, we may propose and finalize a standard for 

reconstructions at a later time. 

5.6.3 Modified and Transitional Units

Modified and transitional 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 result, EPA 

anticipates that the proposed EGU GHG NSPS will result in negligible CO2 emission changes, 

energy impacts, or costs for new units constructed by 2020. Likewise, the Agency does not 

anticipate any notable impacts on the price of electricity or energy supplies. Additionally, for 

the reasons described above, the proposed rule is not expected to raise any reliability concerns, 

since reserve margins will not be impacted and the rule does not impose any requirements on

existing facilities.
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5.8 Comparison of Emissions from Generation Technologies

As discussed earlier in this chapter, natural gas combined cycle units are on average 

expected to be more economical to build and operate than new coal units. These natural gas 

units also have lower emission profiles for CO2 and criteria air pollutants than new coal units. 

While the proposed EGU GHG NSPS is anticipated to have negligible costs or quantified benefits

under a range of likely market conditions, it is instructive to consider the differences in 

emissions of CO2 and conventional air pollutants between the two types of units. 

As Table 5-5 below shows, emissions from a typical new natural gas combined cycle 

facility are significantly lower than those from a traditional coal unit.28 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 CO2, sulfur dioxide 

(SO2), NOx, toxic metals, acid gases, and particulate emissions than a comparable natural gas

combined cycle facility. A typical natural gas combined cycle unit emits two million metric tons 

less CO2 per year than a typical new conventional coal unit, as well as 930 fewer short tons SO2

and 1,200 fewer short tons of NOx each year. Importantly, these differences in emissions 

assume a new coal unit that complies with all applicable regulations, including MATS. 

Reductions in SO2 emissions are a particularly significant driver for monetized health benefits, 

as SO2 is a precursor to the formation of particulates in the atmosphere, and particulates are 

associated with premature death and other serious health effects. Further information on 

these pollutants’ health effects is included in the next subsection.

 

28 Estimated emissions of CO2, SO2, and NOX 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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Table 5-5. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired Generating Units29

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)

SO2 940 0.42 10 0.0041 50 0.022

NOx 1,400 0.62 200 0.09 1,100 0.47

CO2 3.6 million 1,800 1.7 million 820 0.4 million 200

Notes: SO2 and NOxin short tons, CO2in metric tons. As discussed in Section 5.4, the illustrative units represent relative 

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

Because emissions of CO2 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 provide a general 

discussion about the differences in emissions of CO2 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 CO2 emissions, and may therefore be utilized to 

understand the value of the difference in CO2 emissions between the two representative units 

discussed in Section 5.8. The SCC is an estimate of the monetized damages associated with an 

incremental increase in carbon emissions in a given year. It is intended to include (but is not 

limited to) changes in net agricultural productivity, human health, property damages from 

increased flood risk, and the value of ecosystem services due to climate change. Federal 

agencies typically use SCC estimates to assess the benefits of rulemakings that achieve marginal 

reductions in CO2 emissions. These estimates were developed through an interagency process 

 

29 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., these new facilities would be subject to emissions standards for other pollutants and would 

emit similar levels of SO2, NOX, and CO2, on an output basis).
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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.30 

The interagency group selected four SCC values for use in regulatory analyses: $7, $26, 

$42, and $81 per metric ton of CO2 emissions in 2020, in 2007 dollars.31,32 The first three values 

are based on the average SCC from three integrated assessment models, at discount rates of 5, 

3, and 2.5 percent, respectively. SCCs at several discount rates are included because the 

literature shows that the SCC is quite sensitive to assumptions about the discount rate, and 

because no consensus exists on the appropriate rate to use in an intergenerational context. The 

fourth value is the 95th percentile of the SCC from all three models at a 3 percent discount rate. 

It is included to represent higher-than-expected impacts from temperature change further out 

in the tails of the SCC distribution. 

The SCC increases over time because future emissions are expected to produce larger 

incremental damages as physical and economic systems become more stressed in response to 

greater climatic change. Note that the interagency group estimated the growth rate of the SCC 

directly using the three integrated assessment models rather than assuming a constant annual 

growth rate. This helps to ensure that the estimates are internally consistent with other 

modeling 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 CO2 emissions for that year, and then discounted back to 

the analysis year using the same discount rate used to estimate the SCC.

 

30 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support Document: Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon, with 

participation by Council of 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 available at 

http://epa.gov/otaq/climate/regulations.htm

31 Note that upstream emissions changes were not considered for this rule. There may be changes in greenhouse 

gas emissions (in particular, methane) due to changes in fossil fuel extraction and transport in response to this 

proposal, but those were not quantified.

32 The interagency group concluded that a global measure of the benefits from reducing U.S. GHG emissions should 

be the standard practice 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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When attempting to assess the incremental economic impacts of carbon dioxide 

emissions, the analyst faces a number of serious challenges. A recent report from the National 

Academies of Science (NRC 2009) points out that any assessment will suffer from uncertainty, 

speculation, and lack of information about (1) future emissions of greenhouse gases, (2) the 

effects of past and future emissions on the climate system, (3) the impact of changes in climate 

on the physical and biological environment, and (4) the translation of these environmental 

impacts into economic damages.33 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 should be viewed as provisional. 

The interagency group noted a number of limitations to the SCC analysis, including the 

incomplete way in which the integrated assessment models capture catastrophic and noncatastrophic impacts, their incomplete treatment of adaptation and technological change, 

uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding 

risk aversion. Current integrated assessment models do not assign value to all of the important 

physical, ecological, and economic impacts of climate change recognized in the climate change 

literature because of lack of precise information on the nature of damages and because the 

science incorporated into these models understandably lags behind the most recent research. 

The limited amount of research linking climate impacts to economic damages makes the 

interagency modeling exercise even more difficult. The interagency group hopes that over time 

researchers and modelers will work to fill these gaps and that the SCC estimates used for 

regulatory analysis by the Federal government will continue to evolve with improvements in 

modeling. It is important to emphasize that the interagency process is committed to updating 

these estimates as the science and economic understanding of climate change and its impacts 

on society improves over time. Specifically, they have set a preliminary goal of revisiting the 

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.

 

33 National Research Council (2009). Hidden Costs of Energy: Unpriced Consequences of Energy Production and Use. 

National Academies Press. See docket ID EPA-HQ-OAR-2009-0472-11486.
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Table 5-6. Social Cost of CO2, 2015-2050a(in 2007 dollars)

Year

Discount Rate and Statistic

5% Average 3% Average 2.5% Average 3%

95th 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 CO2 emissions and are defined in real terms.

5.9.2 Health Impacts of SO2 and NOx

SO2 is a precursor for fine particulate matter (PM2.5) formation. NOX is a precursor for 

PM2.5 and ozone formation. As such, reductions of SO2 and NOX would in turn lower overall 

ambient concentrations of these pollutants as well as PM2.5 and ozone. Reducing exposure to 

PM2.5 and ozone is associated with significant human health benefits, including avoided

mortality and morbidity. Researchers have associated PM2.5 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 PM2.5 include premature mortality 

for adults and infants, cardiovascular morbidity such as heart attacks and hospital admissions, 

and respiratory morbidity such as asthma attacks, bronchitis, hospital and emergency room 

visits, work loss days, restricted activity days, and respiratory symptoms. Health effects 

associated with exposure to ozone include premature mortality and respiratory morbidity such 

as asthma attacks, hospital and emergency room visits, and school loss days. For a full 

discussion of the human health benefits of reducing SO2 and NOX emissions from power sector 

sources, including reducing methyl mercury, SO2, and NO2 exposure, please refer to the RIA for 

CSAPR (U.S. EPA, 2011). 

In addition to human health benefits, reducing SO2 and NOX emissions would also result 

in human welfare improvements by improving ecosystem services—the benefits that the public

obtains from ecosystems that directly or indirectly contribute to social welfare. SO2 and NOX

emissions can adversely impact vegetation, certain manmade materials, acidic deposition, 

nutrient enrichment, visibility, and climate (U.S. EPA, 2009; U.S. EPA, 2008). Reducing these 
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harmful emissions improves human welfare. For more information about the welfare benefits 

of SO2 and NOX 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 SO2 and NOx 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 

purposes of this illustrative example. However, reducing one thousand tons of annual SO2 from 

U.S. EGUs in 2020 has been estimated34 to yield between 3 and 9 incidences of premature 

mortality avoided annually and annual monetized PM2.5-related health benefits (including 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 primary estimates of PM2.5 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 NOX from U.S. 

 

34 The SO2 and NOX benefit per-ton (BPT) values presented here consist of only PM2.5-related health benefits from 

reductions in SO2 and NOX (precursors to PM2.5 formation). EPA relied on air quality modeling used to develop 

a previous rulemaking affecting power sector emissions of SO2 and NOX to develop these BPT values (Air Quality 

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 rather than air quality modeling of EPA’s Mercury and Air Toxics Standards (MATS) because EPA did 

not estimate NOX BPT values for MATS and because the utilized Transport Rule modeling reduced emissions of 

SO2 and NOX independently, allowing for better estimation of PM2.5-related SO2 and NOX 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 Table 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/benmap) 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 PM2.5 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 SO2 and 

NOX reductions resulting in a specific reduction in PM2.5 exposure and may not fully reflect local or regional 

variability in population density, meteorology, exposure, baseline health incidence rates, or other factors that 

might lead to an over-estimate or under-estimate of the actual benefits associated with PM2.5 precursors. 

These 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. Therefore, 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. 
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EGUs in 2020 has been estimated35 to yield up to 1 incidence of premature mortality avoided 

annually and annual monetized PM2.5-related health benefits (including these incidences of 

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.

5.10 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 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. 

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 proposed 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.

36

 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 standard 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 

 

35 Ibid.

36 By fixing generation 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 benefit of electricity 

production to consumers outweighs the private and social 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, Joskow 2010 and 2011. 
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these estimates to conduct an illustrative sensitivity analysis for the potential social costs of the 

policy in this illustrative example.

37

It should be emphasized that the analysis presented here is illustrative, although EPA 

believes that it leads to a robust conclusion. From an analytical perspective, 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 set 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 

probability 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 outcomes, 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 robust picture of the likely costs and benefits of the standard. Nonetheless, EPA is 

inviting 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 

 

37 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.
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key determinant of the economics of electricity generation and therefore the potential impacts 

of this proposed rule.

5.10.1 Illustrative Environmental Damages per MWh 

As previously discussed in this chapter, the damages associated with emissions from 

new sources of electricity generation are greater for coal-fired units than for natural gas 

combined cycle units (even when accounting for compliance with EPA’s recent Mercury and Air 

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 defined as the damages associated with

pollution that are not accounted for in the private investor's decision making.38

To illustrate the external costs associated with new generation options we combine the 

illustrative emission profiles for the new units, as provided in Table 5-5, and the illustrative 

emissions and damage estimates discussed in the previous two sections.

39

 Specifically, for each 

generating technology we multiply the CO2 emissions by the estimates of the SCC and add that 

to the SO2 emissions40 multiplied by the PM2.5-related SO2 benefit per-ton estimates,

41

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 illustrative 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. Depending on the discount rate and 

mortality risk study used, damages associated with generation from a representative new coal 

unit are $11 to $81 per MWh, while damages associated with the illustrative new natural gas 

combined cycle unit are $3 to $31 per MWh (2007$).42 

 

38 See Baumol and Oates, 1988. 

39 Only the direct emissions of two pollutants (CO2 andSO2) are considered in this illustrative exercise. Other 

pollutants and lifecycle emissions are not considered.

40 See footnote 31 in section 5.8.

41 See footnote 33 in section 5.9.2 for a description of the benefit-per-ton values. In this exercise they are 

interpreted as damage-per-ton values.

42 Different discount rates are applied to SCC than to the other damage estimates because CO2 emissions are longlived and subsequent damages occur over many years. Moreover, several rates are applied to SCC because the 

literature shows that it is sensitive to assumptions about discount rate and because no consensus exists on the 

appropriate rate to use in an intergenerational context. The SCC interagency group centered its attention on 

the 3 percent discount rate but emphasized the importance of considering all four SCC estimates. See the “SCC 
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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 

pollution damages associated with new coal generation are significantly higher than those 

associated with new natural gas combined cycle generation in this illustrative, but 

representative example. For example, considering the SO2 per ton damages based on Pope et 

al. 2002 using a 7% discount rate and the SCC estimate based 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 SO2 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. 

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 these two technologies 

depends on the location under consideration and the specific fuels that would be used. An 

ideal benefit-cost analysis would account for these local circumstances (and consider 

alternative sources of generation).43 However, these factors will not change the qualitative 

conclusion. The damages associated with CO2 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-controlled 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.

 

TSD,” Interagency Working Group on Social Cost of Carbon (IWGSC). 2010. Technical Support Document: Social 

Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. Docket ID EPA-HQ-OAR-2009-

0472-114577. http://www.epa.gov/otaq/climate/regulations/scc-tsd.pdf for details.

43 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 SO2 emissions. 

Therefore, the benefits for any specific unit can be very different than the estimates shown here. 
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Table 5-7. Pollution Damages ($/MWh) from Illustrative New Coal Unit Relative to New 

Natural Gas Combined Cycle Unit 44

SCC Discount Rate Damages from CO2

5% $3

3% $11

2.5% $18

3% (95th percentile) $34

Damages from SO2 Only

Discount Rate Applied to Health Co-Benefits

Mortality-Risk 

Study 3% Discount Rate 7% Discount Rate

Pope (2002) $6 $6

Laden (2006) $16 $14

Combined Damages from CO2 and SO2

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% (95th 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 SO2 pollution damages pairing reflects the use of two core 

estimates of PM2.5-related premature mortality, Pope et al. (2002) representing the lower of our core estimates and Laden et 

al. (2006) represent the higher of our core estimates. 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 SO2 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 values 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 that there is no difference in discount rates between intragenerational and intergenerational 

impacts.

 

44 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 generating 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 SO2 and CO2, on an output basis) except for differences in local conditions, as 

discussed below.
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The conclusion from this analysis is that there are significant environmental damages 

associated with electricity generation from a representative new conventional coal unit relative 

to a representative new natural gas combined cycle unit.45 Other studies of the social costs of 

coal and natural gas fired generation provide similar findings (Muller et. al, 2011; NRC, 2009).46

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.47 

5.10.2 Social Benefits and Costs across 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 consistent with EPA’s 

projection, discussed at length above, that the proposed EGU GHG NSPS will not impose any 

social costs (or generate quantified net benefits) under current and likely future market 

conditions. 

 

45 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 SO2

emissions. Therefore, the benefits for any specific unit can be very different than the estimates shown here, 

though the proportion associated with CO2, which is a well dispersed global pollutant, will not be affected by 

location. 

46 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, including natural gas boilers, and are not sensitive to location. The 

NRC 2009 study shows that only the most polluting natural gas units may cause greater damages than even the 

least polluting 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 generation than natural gas combined cycle units. 

47 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 improving for society.
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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 damages 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.

48 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, higher natural gas prices result in a net cost, holding all other 

parameters constant and disregarding benefits that we are unable to monetize.

49 However, it is 

important to note that this analysis is limited in the types of social benefits and costs 

considered, given that it does address the life-cycle pollution associated with fossil fuels along 

with the limitations of current SCC estimates, as previously discussed.

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 generation 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). 

 

48 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.

49 In reality this is unlikely to be the case. For example, 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.
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Projections of future market conditions 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). Even EIA’s most 

pessimistic 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 – and 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 conventional 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.50 However, these coal units would also impose additional 

environmental and health damages in the form of global warming pollution and particulate 

matter (as a result of SO2 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 

illustrative conventional coal unit would generate power for $3/MWh less than an NGCC unit,

51

but result in greater pollution damages of $9 to$50/MWh (see table 5-7).52 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 

 

50 See section 5.4 for a discussion of how local conditions and other factors influencing 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. 

51 Assuming an increase of $6.80/MWh in the cost of gas generation for every $1/MMBtu increase in natural gas 

prices. 

52 Again, assuming that coal prices do not increase along with natural gas prices as they historically have. See 

previous footnote.
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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.53,54 Looking forward, the 

continued development of unconventional natural gas resources in the U.S. suggests that gas 

prices would actually tend to be towards the lower end of the 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.

Unprecedented 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 cost) under some 

assumptions for environmental damages. For example, at gas prices of $15/MMBtu, the 

illustrative conventional coal unit would generate power for roughly $37/MWh less than an 

NGCC unit but result in social costs of $9 to $50/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 $28 to a net benefit of $13/MWh. The point at which this standard would result in 

net social costs depends heavily upon the value for damages from GHGs and SO2. For example,

assuming an SCC using a 3% discount rate, along with a 7% discount rate for estimating benefits 

from reduced SO2 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 

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 annual 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.

55,56

 As a result, based on historical gas 

 

53 See: http://www.eia.gov/dnav/ng/hist/n3045us3A.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).

54 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 be realized.

55 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 reports average monthly delivered natural 

gas prices to the electricity sector over the past 10 years (since 2001).
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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 benefits 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. There is an exceedingly low probability that it 

results in net costs.

5.10.3 Illustrative Costs and Benefits of CCS Compared with Conventional Coal

The analysis above focuses on two well developed control technologies, conventional 

supercritical coal and natural 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 conditions (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 details.

EPA analyzed the cost and emission impacts for two scenarios. In the first scenario, 

partial capture achieves the proposed emissions rate of 1,000 lb CO2/MWh gross output. This 

requires that approximately 39% of the CO2 is captured and stored. EPA has 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 turbine, 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 

 

56 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. 
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term, any new coal-fired EGU with CCS would most likely be located in areas amenable to using 

the captured CO2 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 

Clean Energy project57 is planning to capture 90% of the CO2 and sell it for enhanced oil 

recovery. 

To evaluate the potential revenues from EOR we examined two options. We considered 

a case where CO2 could be sold for $45/ton based on recent DOE studies for the 90% capture 

case.

58

 We also considered a lower revenue sensitivity where CO2 could be sold for $15/ton 

(equivalent to the cost assumed for the transport and storage of CO2 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 4.10.59 These cost estimates 

are generally consistent with the range of studies estimating the cost of CCS that are available, 

however there is uncertainty around any such projections of technology costs, particularly for 

early movers of this technology. 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 CO2 and SO2 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 Generating Units” for more details.

 

57 http://www.texascleanenergyproject.com/

58 US DOE / NETL studies have assumed a delivered CO2 price ranging from $40 - $45/tonne. “Improving Domestic 

Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil Recovery (CO2-EOR)”, 

DOE/NETL-2011/1504 (June 2011); and “Storing CO2 with Enhanced Oil Recovery, DOE/NETL-402/1312 

(February 2008).

59http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html
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Table 5-8. Illustrative Costs and Benefits for two CCS Scenarios Compared to Conventional 

Coal Plant (per MWh 2007$)

SPC to IGCC with 39% 

Capture

SPC to IGCC with 90% 

Capture

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 comparisons omit additional benefits that may be associated with 

the abatement of greenhouse gas emissions.

5.11 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 quantified

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, since the EPA does 

not forecast a change in behavior relative to the baseline in response to this proposed rule, 

there are no notable macroeconomic or employment impacts expected as a result of this

proposed rule. 
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5.12 References

Baumol, W.J. and W. E. Oates, The Theory of Environmental Policy. 2nd Edition. Cambridge 

University Press: New York (1988).

Blyth, W. and Yang, M. and Bradley, R. Climate policy uncertainty and investment risk. 2007. 

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