5-1

CHAPTER 5

COSTS, BENEFITS, ECONOMIC AND ENERGY IMPACTS

5.1 Synopsis

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

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

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

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

forecast likely future electricity market conditions with and without the proposed rule.

Because the only capacity additions projected during the analysis period (2020) are 

compliant with the requirements of this rule (e.g. coal boilers with CCS funded in part through 

federal subsidies and combined cycle natural gas), this proposed EGU GHG NSPS is not expected

to change GHG emissions for newly constructed EGUs, nor is it anticipated to impose notable

costs, economic impacts, or energy impacts on the EGU sector or society. EPA performed

sensitivity analyses that also did not forecast new coal in 2020. 

5.2 Background

Over the last decade, EPA has conducted extensive analyses of regulatory actions 

impacting the power sector. These efforts support the Agency’s understanding of key 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 

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).

There are two main reasons why EPA expects no unplanned coal-fired power plants will 

be constructed over the time horizon considered for this analysis. First, the current economic 

situation has dampened electricity demand, and thus there is less need for new generating 

capacity during the analysis period. Second, generating technologies for new plants using

natural gas produce electricity at lower levelized cost than other generating technologies, and 

therefore utilities are expected to rely heavily on combustion turbines and combined cycle 

plants using natural gas when they do need to expand capacity during the time horizon 

considered for this analysis. This circumstance is different than that of a few years ago because 
5-2

current and forecast natural gas prices are considerably lower than the levels seen over the 

past decade. This is a result of new drilling techniques that have substantially increased the 

supply of natural gas potentially available to the marketplace. Based on these market 

conditions, on average the levelized cost of generation from a new natural gas power plant is

expected to be lower than the cost of generation from a new coal-fired power plant.1 This 

trend has already been observed recently, as natural gas-fired capacity was the technology of 

choice for power generation over the last few years (see Figure 5-1).

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

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Capacity (M

W)

Other

Gas (CC and CT)

Renewable/Hydro

Nuclear

Coal

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

 

1

Levelized Cost of New Generation in the Annual Energy Outlook (AEO) 2011, 

http://205.254.135.24/oiaf/aeo/electricity_generation.html 
5-3

Source: National Electric Energy Data System (NEEDS) v4.10_PTox 

Numerous energy sector modeling efforts, including recent projections from both EIA 

and EPA, have provided results that are consistent with these findings. The Annual Energy 

Outlook (AEO) for 2011 shows a very modest amount of CCS-equipped new coal-fired power 

coming online past 2012, however since these plants are CCS-equipped in response to Federal 

incentives, they would be in compliance with this proposal.

2

 According to the AEO 2011, the 

majority of new generating capacity is forecast to be either natural gas-fired or renewable, with 

some lesser amounts of nuclear power. The AEO 2011 is based on existing policy and 

regulations, such as state Renewable Portfolio Standard programs and Federal tax credits for 

renewables.3 The DOE concluded, based on EIA analysis, that “the low capital expense, 

technical maturity, and dispatchability of natural gas generation are likely to dominate 

investment decisions under current policies and projected prices."4 The economics favoring 

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

examined in the AEO. Unplanned additions of coal by 2020 increase in sensitivity cases that

separately examine higher economic growth, lower coal prices, low fossil costs, no concern 

regarding future GHG policy, slow oil and gas technology deployment, low shale gas recovery 

per play, and low shale gas recovery per well. In addition, the early release of AEO 2012 

currently available does not forecast new unplanned coal capacity over the period analyzed. 

Furthermore, it projects an increase over AEO 2011 in the price of coal relative to natural gas, 

strengthening the conclusion that natural gas is likely to be the fossil fuel of choice during the 

analysis period. AEO 2012 also has lower electric demand projections than those used in IPM, 

which would result in 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.5 

EPA has used IPM extensively over the past two decades in order to analyze options for 

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

 

2

AEO 2011 has a small amount of planned coal capacity that is under 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.

3

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

4

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

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

5

http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation
5-4

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.6

The baseline information in this RIA includes the recently finalized Mercury and Air 

Toxics Standards (MATS) and Cross State Air Pollution Rule (CSAPR) In addition to MATS and 

CSAPR, the baseline takes into account emissions reductions associated with the 

implementation of all finalized federal rules, state rules and statutes, and other binding, 

enforceable commitments that are applicable to the power industry and which govern the 

installation and operation of pollution controls during the timeframe covered in the analysis.

As noted above, IPM has been used for evaluating the economic and emission impacts 

of environmental policies for over two decades. The economic modeling presented in this

chapter has been developed 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

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 

 

6

http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html
5-5

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

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

The model has also been used by states (e.g., for Regional Greenhouse Gas Initiative , 

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

State agencies, environmental groups, and industry, 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 analysis over the past decade. 

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

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

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

power sector analyses of legislative climate proposals in 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 Granular Model

EPA typically presents IPM outputs in aggregate, in order to support analysis reflecting 

nationwide impacts of a policy. Some additional regional detail is presented, where 

appropriate. Although the Agency typically focuses on the broader effects when assessing the 

economic impacts of a particular policy, EPA’s application of IPM includes a detailed and 

sophisticated regional representation of key power sector variables. For example, the model 

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, O&M costs, fuel costs 

and emission profiles. The capital costs for new units are regionalized through the application 
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of regional adjustment factors that capture regional differences in labor, material, and 

construction costs. These regional cost differentiation factors are based on assumptions used in 

the EIA’s AEO.

As part of the model’s assessment of the relative economic value of building a new 

power plant, the model incorporates a detailed representation of the fossil-fuel supply system 

that supports fuel price 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

EPA began its analysis of the economic impacts of the proposed NSPS by conducting a 

base case analysis of future generating capacity. This base case incorporates the proposed 

MATS and the proposed Transport Rule (finalized as CSAPR).

9

The IPM base case projection includes a 1 percent growth in electricity demand, similar 

to EIA’s Annual Energy Outlook for 2010, which serves as the basis for IPM’s electric demand 

 

9

http://www.epa.gov/airquality/powerplanttoxics, and http://www.epa.gov/airtransport.
5-7

projection. 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. 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). Relative to current levels, EPA anticipates that the existing 

coal fleet will increase generation while gas-fired sources will not change significantly by 2020. 

This dynamic largely emanates from somewhat atypical supply and demand trends experienced 

in energy markets over the past few years, where overall electricity demand has been soft, 

natural gas prices have dropped considerably, and coal prices have risen. 

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

2010 2020

Pulverized Coal 317 299

Natural Gas Combined Cycle 201 212

Combustion Turbine 138 143

Oil/Gas Steam 115 90

Non-Hydro Renewables 31 73

Hydro 99 99

Nuclear 102 106

Other 5 7

Total 1,009 1,029

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

Source: 2010 data from EPA's NEEDS v.4.10 PTR. 2020 projections from Integrated Planning Model run by EPA.

Note: “Non-Hydro Renewables” include biomass, geothermal, solar, and wind electric generation capacity. The capacity of a 

generating 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.
5-8

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 0.129

Natural Gas 901 873

Nuclear 807 841

Hydroelectric 258 287

Non-hydro Renewables 139 288

Other 4 45

Total 3,972 4,309

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 rojection from IPM run by EPA, 2011.

Forecasts suggesting that new coal is unlikely to be built by 2020 have been shown to be 

robust under a range of alternative assumptions that influence the industry’s decisions to build 

new power plants. For example, EIA typically supplements the AEO with a series of distinct 

scenarios that explore specific issues and examine a future state of the world that deviates 

from the corecentral parameter estimates that underlyunderlie the reference case. Even 

under alternative scenarios where assumptions might improve the relative economic value of 

building new coal-fired power plants, the AEO 2011 shows no new (unplanned) coal builds 

through 2025. Relevant scenarios include higher economic growth forecast, lower cost of coal 

supply, lower capital costs of fossil fuel-fired energy technologies, and less optimistic natural 

gas supply.10 Although new coal capacity is built in some of these scenarios after 2025, CAA 

section 111(b) requires that this standard be reviewed every eight years, thus this regulatory 

requirement will likely be reviewed and potentially revised after the 2020 timeframe, which 

serves as the primary focus of this analysis. Therefore, while the fairly robust expectation is 

that no new unplanned coal capacity will be built within the time horizon of this analysis, there 

remains a very small probability that new coal capacity might be constructed absent this 

regulation. Given this unlikely circumstance, this rule could impose some degree of social cost 

and accrue some degree of social benefit. However, EPA has not quantified the costs or 

benefits associated with this hypothetical and difficult-to-quantify outcome. These scenarios 

lead to the fairly robust conclusion that the economics of new electricity generation are such 

 

10 Conversely, modeling in 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. 
5-9

that there is a very low probability that new unplanned coal capacity would be built in the 

absence of this regulation.

In addition to the alternative scenarios analyzed by EIA, EPA also conducted additional 

sensitivity analyses using IPM. These scenarios included alternative assumptions for natural gas 

supply and future electricity demand, similar in design to the alternative scenarios analyzed by 

EIA. For natural gas, lower shale recovery was assumed, whereby 50 percent less natural gas is 

recovered from each shale play (effectively lowering shale reserves by 50 percent, similar to the 

AEO 2011 low shale gas recovery scenario). For electricity growth, demand was assumed to 

grow at an annual average rate of 1.1 percent, similar to EIA’s high economic growth scenario 

for AEO 2010 (compared to 0.8 percent in the EPA baseline, which is similar to the reference 

case in AEO 2010). EPA ran three separate sensitivities in IPM using the aforementioned 

assumptions: a base case with higher electric demand, a base case with lower shale recovery, 

and a base case with both assumptions. Although EPA and EIA do not typically combine 

scenarios (as EPA did with the natural gas and demand sensitivity in this analysis), this scenario 

was performed to demonstrate that even when considering the occurrence of two independent 

and multiplehighly unlikely assumptionsevents that influence new power plant additions, new 

unpanned coal is not expected to be built inthrough 2020. These scenarios show considerably

higher natural gas prices and higher electricity demand growth than any of the comparable AEO 

2011 scenarios as well.

11

 

11 EPA’s baseline electricity demand forecast used in IPM v4.10 is based on the demand forecast in AEO 2010. AEO 

2010 electricity demand forecast for the year 2020 is roughly 3.5% higher than the 2020 forecast in AEO 2011. 

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

2020 that is 6.5% higher than the reference case AEO 2011 demand for 2020, and 3.4% higher than the demand 

in the AEO 2011 high economic growth scenario. The EPA sensitivity with higher electric demand represents a 

very 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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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

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

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. 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.

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 four types of units or 

actions: newly constructed units, reconstructed units, modified units, and transitional units. 

Analysis performed by EPA, along with information from other sources, suggests that the 
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standards as specified in this proposed rule are not likely to result in notable emission changes, 

energy impacts, monetized benefits, costs, or economic impacts by 2020. This is because 

analyses performed both by EPA and EIA, as well as statements and actions of a number of 

major utilities, demonstrate that generation technologies other than coal (mostly natural gas 

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

current and projected market conditions.12

5.6.1 New Units

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

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

also proposes an alternative standard that would allow new units to meet the 1,000 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.13 No new conventional coal-fired boilers, which would be subject to the 

proposed NSPS, are projected to be built (excluding new coal built with CCS). This implies that 

the NSPS will require no changes in design or construction of new EGUs forecasted in the base 

case. Thus, there would be no expected reduction in emissions and no costs for the new EGUs

whose construction is forecast.

As described above, 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 or combustion turbine generation or coal-fired generation with CCS (the latter 

is assumed to be built with support from federal grants). The EIA’s AEO 2011 modeling makes 

 

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

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

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

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

capacity.

13 Natural gas combustion turbines are not covered by this proposal.
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similar conclusions. A number of major utilities have made public announcements consistent 

with these modeling results.14

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

environment, reaches similar conclusions. If one assumes a delivered natural gas price of $5 

per million British Thermal Units (mmBtu) and a delivered coal price of $2 per mmBtu, which 

conservatively reflect forecasted prices from IPM in 2020,15 electricity generated by natural gas 

combined cycle units is less expensive on average than coal generation. A comparison of 

levelized wholesale electricity costs for differing generation technologies and natural gas prices 

are shown in Figure 5-4 and Table 5-3. It is important to note that both EIA and EPA include a 

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.16 Note that this figure only shows the costs to the generator and does 

not reflect social costs associated with greenhouse gas emissions or conventional air pollutants.

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

Technologies, EPA 

 

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

it is highly likely that we will look to natural 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.

15 EIA projects a U.S. average coal price of $1.65/MMBtu in 2020 ($2009). Bituminous coals are roughly $2. EPA 

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

16 See http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html, and 

http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.
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($2007)

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

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. 

It is only when gas prices reach approximately $9.60/mmBtu, that new coal-fired 

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

cost of electricity generation. For context, even EIA’s most pessimistic gas sensitivity case (“low 

shale gas recovery per well”) only projects an electricity sector gas price of $6.79 in 2020 (the 

“low shale gas recovery per play” scenario projects a price of $5.93/mmBtu in 2020).

However, it is important to note that this analysis is based on assumptions regarding the 

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

to be significant spatial variation in the costs of new generation due to design differences, labor 
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wage and productivity differences, location adjustments, among other potential differences.17 

The analysis also does not explicitly consider new units designed to combust waste coal or 

petroleum coke (pet coke), which may be affected by this rule, but also may exhibit different 

local economics. However, the results are expected to hold for the majority of situations.

Table 5-3. Estimated Levelized Cost of New Generation Resources from EIA, U.S. Average

(2016)

Plant Type Capacity 

Factor (%)

U.S. Average Levelized Costs (2009 $/ MWh)

for Plants Entering Service in 2016

Levelized 

Capital Cost

Fixed 

O&M

Variable

O&M 

(Including 

fuel)

Transmission 

Investment

Total System 

Levelized 

Cost

Conventional Coal 85 65.3 3.9 24.5 1.2 94.8

Advanced Coal 85 74.6 7.9 25.7 1.2 109.4

Advanced Coal with CCS 85 92.7 9.2 33.1 1.2 136.5

Natural Gas-fired

 Conventional Combined 

Cycle 87 17.5 1.9 45.6 1.2 6.1

 Advanced Combined Cycle 87 17.9 1.9 42.1 1.2 63.1

 Advanced CC with CCS 87 34.6 3.9 49.6 1.2 89.1

 Conventional Comb. Turbine 30 45.8 3.7 71.5 3.5 124.5

 Advanced Combustion 

Turbine 30 31.6 5.5 62.9 3.5 103.5

Advanced Nuclear 90 90.1 11.1 11.7 1.0 113.9

Wind 34 83.9 9.6 0 3.5 97.0

Wind - Offshore 34 209.3 28.1 0 5.9 243.2

Solar PV 25 194.6 12.1 0 4.0 210.7

Solar Thermal 18 259.4 46.6 0 5.8 311.8

Geothermal 92 79.3 11.9 9.5 1.0 101.7

Biomass 83 55.3 13.7 42.3 1.3 112.5

Hydro 52 74.5 3.8 6.3 1.9 86.4

Source: EIA, AEO 2011

This rule also proposes an alternative standard that would allow new units to meet the 

1,000 lbs CO2/MWh standard using a 30 year averaging period. To the extent market 

participants have alternative views of both cost and development of CCS, new conventional 

coal-fired capacity (or IGCC) could be built and operated for some time, with the intention to 

apply CCS with high removal efficiency at some later date, in order to achieve the required 

average rate over the 30 year period. Also the above analysis reflects national averages, and in 

turn given their specific situation, a market participant could determine that the economics of 

 

17 http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf
5-16

building a coal-powered facility that immediately achieves a CO2 capture and/or removal rate 

consistent with the emission standard are favorable. 

Others have done research to explore the cost and efficiency of varying levels of capture 

relative to building alternative energy technologies.18 This ongoing research indicates that 

lower levels of carbon capture at new coal facilities could be cost competitive with these 

technologies, and the costs of meeting the proposed emission rate immediately could be 

achievable and economic. For example, The Clean Air Task Force has compiled data that 

indicates the levelized cost of electricity for a new supercritical pulverized coal unit with 50

percent CCS (or 1,080 lb/MWh CO2, which is just above the proposed standard) could be 

$116/MWh compared to $147/MWh for 90 percent removal. However, investment decisions 

will be made on a case by case basis dependent upon a number of factors, all of which are 

difficult to estimate in advance.

5.6.2 Reconstructed Units

The EPA’s CAA 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 the proposed NSPS, EPA is taking comment on different 

approaches to regulation of reconstructed sources. The options for reconstructed sources, in 

general, include (i) establishing the standard of performance at the same level as for new 

sources, (ii) establishing the standard performance at 1,800 lb CO2/MWh, or (iii) not 

establishing a standard of performance for reconstructed units at this time.

EPA would not expect either alternative to change firms’ behavior because they would 

be expected to choose technologies that are compliant with the standard even in the absence 

of the standard. The costs associated with reconstructing coal-fired units are likely to be similar 

to the cost of building a new natural gas-fired unit. Thus, even if this provision is triggered, EPA 

believes that the economic analysis outlined above showing that natural-gas-fired generation is 

significantly more cost effective than building a reconstructed coal plant results in the choice of 

 

18 Technical Options for Lowering Carbon Emissions from Power Plants. Clean Air Task Force (June, 2011). Available 

at: 

http://www.coaltransition.org/filebin/pdf/Technical_Options_for_Lowering_Carbon_Emissions_from_Power.p

df
5-17

natural gas combined cycle or coal with CCS technology (i.e., existing unit operators are likely to 

choose technologies for independent market reasons that are already compliant with the new 

source NSPS included in this proposal).

5.6.3 Modified Units

As explained in the preamble, The EPA does not have a sufficient base of information to 

develop a proposal for the relatively few affected sources that may take actions that would 

constitute “modifications,” as defined under the EPA’s NSPS regulations, and therefore be 

subject to requirements for new sources. A modification is any physical change in, or change in 

the method of operation of, a source that increases the amount of any air pollutant emitted by 

the source or results in the emission of any air pollutant not previously emitted. The EPA is 

soliciting comment on this issue, but in the meantime, the EPA is not proposing standards for 

modifications. The Agency believes that it does not, at present, have adequate information as 

to the type of action, its costs, or the amount of its CO2 emissions, on which to base a proposed 

standard of performance. Therefore, sources that undertake physical or operational changes 

that increase their maximum achievable hourly CO2 emission rate will be treated as existing 

sources, and thus they will not be subject to the proposed EGU GHG NSPS requirements for 

new sources.

5.6.4 Transitional Units

In the proposal, EPA identifies transitional sources as those sources that have received 

final PSD permits, but have not actually commenced construction. EPA is proposing that as long 

as units commence construction within a set amount of time, construction can proceed without 

being affected by this rule. While this proposed rule sets no standard for the transitional 

source subcategory of new sources, these sources may become subject to an existing source 

standard in a subsequent rulemaking. 

EPA believes that there are approximately 15 such units discussed previously in Chapter 

2. Historically, obtaining a permit does not guarantee that a unit will end up being constructed. 

In the last 10 years, 88 coal plants have been permitted. Of those, 40 (or fewer than half) have 

actually commenced construction. Thirty projects have been cancelled and approximately 15

sources (the transitional sources) have active permits. Based on this history and current 

economic conditions, EPA believes that at least some number of these units would not likely 

proceed to construction, regardless of the requirements of this rule. Based on this history, EPA 

believes that at least some number of these units would not likely proceed to construction, 

regardless of the requirements of this rule. For these units, this rule adds no costs. Once a unit 
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has received a final PSD permit, it must commence construction within 18 months. The units 

EPA has potentially identified as “transitional” were permitted prior to this rule being proposed. 

EPA is proposing that as long as units commence construction within 12 months, construction 

can proceed without being affected by this rule. For these units, this rule adds no additional 

costs and will not result in any monetized benefits.

In the absence of this rule, EPA believes the coal units within this transitional category 

that are most likely to commence construction are those that have received public incentives to 

install CCS. Under the proposed rule, these units could commence construction within the 

proposed time-frame without incurring any requirement to reduce CO2 emissions. EPA believes 

that the economics demonstrated above also apply to the other transitional units; such that

building natural gas-fired combined cycle generation is likely to be a less expensive option than 

traditional coal-fired generation, even in the absence of this rule. The developers of the 

projects already permitted are likely considering these economic factors and may ultimately 

choose not to commit to actual construction of these previously proposed coal and petroleum 

coke plants.

5.7 Summary of Costs, Economic, and Energy Impacts of the Proposed Rule for New, 

Reconstructed, Modified, and Transitional Electric Generating Units

EPA does not anticipate that the proposed EGU GHG NSPS will result in notable CO2 

emission changes, energy impacts, or costs for new units constructed by 2020. EPA believes 

that the industry will choose to construct new units that already meet these standards due to 

current and expected economic conditions, regardless of this proposal. Likewise, the Agency 

believes this rule will not have notable impacts on the price of electricity or energy supplies in 

this country. 

This finding is supported by EPA modeling of the base case, which does not project the 

future construction of new coal-fired capacity beyond 2 GW of coal with CCS, which is built in 

response to the financial incentives for CCS included in the Emergency Economic Stabilization 

Act of 2008 and American Recovery and Reinvestment Act of 2009, which authorized and/or

appropriated funding to DOE for CCS deployment. In the short-term, most new capacity is 

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). 

In addition, future electricity demand expectations have trended downwards in recent 

forecasts, reducing the need for new capacity by 2020 (see Chapter 4 for more discussion on 

future electricity demand). Electricity demand is anticipated to grow by roughly 1 percent per 
5-19

year, and total electricity demand is projected to be 4,104 billion kWh by 2015. Table 5-2

shows current electricity generation alongside EPA’s projection for 2020 using IPM. EPA’s IPM 

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. 

5.8 Limitations

Although there is a significant amount of information that points to a future where 

conventional coal (without CCS) is likely to be more costly to build relative to other, lower 

emitting sources of electricity (regardless of whether the power sector is regulated for 

greenhouse gases or not), the Agency acknowledges the possibility that in unusual situations, a 

company could find it advantageous to build a conventional coal facility (or other potentially 

affected facility) if there were no greenhouse gas requirements (i.e., if the social and 

environmental damages of carbon emissions remain as unpriced externalities not reflected in 

project economics). While it is difficult to identify and evaluate hypothetical scenarios where 

this could come to fruition in very limited and localized circumstances, we note that today’s 

action for new sources would likely prevent these occurrences, since new sources would be 

required to meet the proposed NSPS standards. However, in such a case the rule would also 

produce benefits from any reduced emissions of greenhouse gases and other air pollution.

5.9 Benefits of Reduced Regulatory Uncertainty

Most major actors in the power sector anticipate eventual CO2 emissions policy for 

power plants, a performance standard for new sources can reduce uncertainty by setting clear 

parameters for the planning of new generation. The presence of sustained regulatory 

uncertainty may affect the decisions of firms, leading them to potentially forgo more profitable 

investment strategies that would occur in the presence of increased regulatory certainty 

(Teisberg 1993, Hoffmann et al., 2009). In particular, uncertainty regarding future greenhouse 

gas policy may affect firms’ decisions with regards to the timing and types of investments made 

in new electricity generating capital (Blyth et al., 2007). A significant reduction in regulatory 

uncertainty may then increase the expected profits for firms within the electricity generating 

sector by allowing them to optimize investment decisions with a greater understanding as to 

the future operating environment (e.g., Reinelt and Keith, 2007; Patiño-Echeverri et al., 2009). 

EPA is not able to directly quantify or monetize this benefit at this time.
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5.10 Comparison of Emissions Differences of 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 baseline forecast suggests that the proposed EGU GHG NSPS will have no monetized 

benefits or costs, it is instructive to consider the differences in emissions of CO2 and 

conventional air pollutants between the two types of units. EPA does not anticipate any 

incremental changes to coal or natural gas capacity as a result of this rule as proposed, and as 

such, these comparisons are purely for illustrative purposes. 

As Table 5-4 below shows, emissions from a typical new natural gas combined cycle 

facility are significantly lower than those from a traditional coal unit.19 For example, a typical 

new supercritical pulverized coal facility that burns bituminous coal in compliance with new 

utility regulations (e.g., CSAPR and MATS) would have considerably greater CO2, sulfur dioxide 

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

combined cycle facility. A typical natural gas combined cycle unit is expected to emit two 

million metric tons less CO2 per year than a typical new coal unit, as well as, 2,000 fewer short 

tons SO2 and 1,200 fewer short tons of NOx each year. 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.

Table 5-4. Illustrative Emissions Profiles, New Coal and Natural Gas-Fired Generating Units

 

19 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.
5-21

Conventional Coal Natural Gas CC Coal with CCS

SO2 tons/year 2,000 --- Negligible

NOx tons/year 1,400 200 1,100

CO2 tons/year 3.6 million 1.6 million 0.45 million

Notes: SO2 and NOxin short tons, CO2in metric tons. Relative emissions for new well controlled 600 MW (net) units running at 

85 percent capacity factor. Assumed coal is high sulfur bituminous with scrubber and SCR, data is based on EPA assumptions 

used in IPM.

511. Benefits of Reducing GHGs and Conventional Pollutants

As shown in this illustrative example, natural gas combined cycle units are expected to 

be more economical to build and operate on average than new coal units and have lower 

emissions of CO2 and conventional pollutants. While baseline forecasts suggest that the 

proposed NSPS will have no notable costs or monetized benefits, it is instructive to consider the 

benefits associated with the differences in emissions of CO2 and criteria air pollutants in the 

previous illustrative example. EPA does not anticipate any incremental changes to new coal or 

natural gas capacity as a result of this rule, and as such, these comparisons are purely for 

illustrative purposes. 

The social cost of carbon (SCC) is a metric to estimate the monetary value of benefits 

associated with marginal changes in CO2 emissions, and may therefore be utilized to 

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

discussed in section 5.4. The SCC is an estimate of the monetized damages associated with an 

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

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

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

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

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

that included EPA and other executive branch entities, and concluded in February 2010. The 

SCC Technical Support Document (SCC TSD) provides a complete discussion of the methods 

used to develop these SCC estimates.20 

 

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

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

participation by Council of 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
5-22

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.21 The first three values 

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

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

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

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

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

It is included to represent higher-than-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 4-1 presents the SCC estimates for the years 2015 to 2050. In 

order to calculate the dollar value for emission reductions, the SCC estimate for each emissions 

year would be applied to changes in CO2 emissions for that year, and then discounted back to 

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

When attempting to assess the incremental economic impacts of carbon dioxide 

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

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.22 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 non-

 

21 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.

22 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.
5-23

catastrophic impacts, their incomplete treatment of adaptation and technological change, 

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

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

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

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

science incorporated into these models 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.

Table 5-5. 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 are dollar-year and emissions-year specific.

As shown in the Table 5-4, a natural gas unit emits approximately 2,000 tons less SO2

and 1,200 tons less NOx annually when compared to a conventional coal unit. 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 avoiding mortality and 
5-24

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 

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).

EPA is unable to quantify any portion of the potential health or welfare benefits in terms 

of incidences of health effects avoided or monetized value of health or welfare improvements 

due to uncertainty in power plant location and years of operation for this illustrative example. 

However, reducing one thousand tons of annual SO2 from U.S. EGUs in 2020 has been 

estimated 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) of between $30 million and $75 million (2007$) using a 3% discount rate or 

between $28 million and $67 million (2007$) using a 7% discount rate. Additionally, reducing 

one thousand tons of annual NOX from U.S. EGUs in 2020 has been estimated 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 
5-25

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

(2007$) using a 7% discount rate..

23

5.12 Sensitivity Analysis of the Social Costs of New Generating Sources

EPA believes that, given expected energy demand along with fuel and capital prices, 

new conventional coal capacity is unlikely to be constructed over the time horizon of interest in 

this analysis. As part of this explanation we provide an illustrative, but representative, 

comparison of the relative private costs of constructing and operating new conventional coal 

and natural gas combined cycle systems to provide the same generation services (see Figure 

5.4).24 This comparison shows that, at forecast relative fuel prices, there is a significant 

difference in the levelized cost of these two generating technologies. However, in the context 

of a social welfare analysis, the appropriate comparison 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 should account for the 

pollution damages associated with the competing generation technologies in addition to 

private generating costs. This section further explores the social costs of this NSPS standard 

across a wide range of natural gas prices, a key factor in the cost of the policy. It begins by 

estimating illustrative environmental damages per MWh for coal relative to gas generation and 

then uses those estimate to conduct an illustrative breakeven analysis for the social costs of the 

policy. 

 

23 The SO2 and NOX benefit per-ton 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 (Air Quality 

Modeling Technical Support Document for the final Transport Rule; 

http://epa.gov/airtransport/pdfs/AQModeling.pdf) used to develop a previous rulemaking affecting power 

sector emissions of SO2 and NOX to develop these benefit per-ton values, which are methodologically 

consistent with those reported in Fann et al. (2009). As such, the national average benefit per-ton 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 benefit per-ton values are purely illustrative as EPA 

does not assert a specific location for the illustrative coal and natural gas combined cycle units and is therefore 

unable to specifically determine the population that would be affected by their emissions. Therefore, the 

benefits for any specific unit can be very different than the estimates shown here. EPA notes that the benefit 

per-ton estimates do not reflect emission reductions after implementation of EPA’s Mercury and Air Toxics 

Standards. EPA provides two estimates of PM2.5 mortality impacts, a low estimate based on Pope et al. (2002) 

and a high estimate based on Laden et al. (2006).

24 By fixing generation in this comparison, we are assuming that both technologies generate the same benefits in 

the form of electricity generating services. For a discussion of the usefulness of a levelized cost analysis, and 

when it provides informative results and when it does not, see for example Joskow 2010 and 2011. 
5-26

5.12.1 Illustrative Environmental Damages per MWh 

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

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

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

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 5.10. The external costs are defined as the damages associated with 

pollution that are not accounted for in the private investor's decision making.25

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

illustrative emission profiles for the new units, as provided in Table 5-4, and the illustrative 

damage estimates discussed in the previous section.26 Specifically, for each generating 

technology we multiply the CO2 emissions by the estimates of the SCC and add that to the SO2

emissions multiplied by the PM2.5-related SO2 benefit per-ton estimates27, subsequently 

dividing by MWh28 to estimate the external costs per unit of generation. Using this approach 

the damages associated with generation from the illustrative new coal unit are, depending on 

the discount rate and epidemiology study used, $18 to $99 per MWh, while damages 

associated with the illustrative new natural gas combined cycle unit are $3 to $29 per MWh 

(2007$).29 

For any specific epidemiology study and SCC estimate the pollution damages associated 

with new coal generation in this illustrative, but representative, example are significantly higher 

than those associated with new natural gas combined cycle generation. 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 

 

25 See Baumol and Oates, 1988. 

26 Only the direct emissions of three pollutants (CO2, SO2, and Nox) are considered in this illustrative exercise. 

Other pollutants and lifecycle emissions are not considered.

27 See footnote 23 in section 5.11 for a description of the benefit-per-ton values. In this exercise they are 

interpreted as damage per-ton values.

28 See footnote 19 in section 5.10.

29 Different discount rates are applied to SCC than to the other damage estimates because CO2 emissions are 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 

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.
5-27

this example would result in an additional $24 per MWh in pollution damages compared to a 

new NGCC plant. Alternately, damages that reflect the 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 $52 of pollution damages per MWh from a new conventional coal unit 

compared to a new NGCC plant. Table 5-XX reports the additional pollution damages from the 

illustrative new coal plant relative to the illustrative new natural gas plant given different 

mortality risk studies and assumptions about the discount rate. These pollution damages 

should be relatively invariant across natural gas prices and other economic factors.

Table 5-6. Pollution Damages ($/MWh) from Illustrative New Coal Unit Relative to New 

Natural Gas Combined Cycle Unit 

Health Co-Benefits

SCC Discount Rate 3% Discount Rate 7% Discount Rate

5% $17 - $37 $16 - $33

3% $25 - $45 $24 - $42

2.5% $32 - $52 $31 - $49

3% (95th percentile) $50 - $70 $49 - $66

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

related estimates of premature mortality, Pope et al. (2002) representing the low estimate and Laden et al. (2006) represent the high estimate. 

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 NOx and SO2 emissions in the Eastern U.S.

As with the relative investment costs of a new coal unit and a new natural gas combined 

cycle system, a comparison of the environmental damages associated with these two 

technologies depends on the location under consideration and the specific fuels that would be 

used. An ideal social cost comparison of these technologies would account for these local 

circumstances (and consider alternative sources of generation).30 That said, the damages 

associated with CO2 emissions, which is the focus of this rule, do not depend on the location of 

generation. Furthermore, the damages associated with sulfur dioxide emissions from a new 

very well-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. Other studies of the 

social costs of coal and natural gas fired generation provide similar findings (Muller et. al, 2011; 

NRC, 2009).31 

 

30 EPA does not assert a 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 and NOX

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

31 Muller et al. 2011 conclude that, “ coal-fired power plants have air pollution damages larger than their value 

added”, while the same is not true for natural gas plants (see Table 5). However, these 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 
5-28

Overall, these environmental damages suggest that, even if it were the case that the 

private cost of natural gas generation began to rise relative to the private cost of coal 

generation, there would still remain a substantial difference in the overall cost to society 

between these two technologies. In other words, the damages from air pollution suggest that, 

even in cases where new coal may be marginally more economic to operate, these new units 

are still likely to impose a net cost to society relative to a new natural gas plant. This idea is 

discussed in more detail in the next section. 

5.12.2 Social Costs Across A Range of Gas Prices - Breakpoint Analysis

Section 5.11 details illustrative environmental damages associated with a typical coal 

plant compared to a natural gas plant. The social cost of a policy should account for not only 

the difference in private cost between the two technologies, but also the difference in the 

external costs (environmental damages) associated with the two technologies. At today’s gas 

prices the difference in the private levelized cost for these illustrative facilities is roughly $27 

per MWh in favor of natural gas combined cycle at today’s gas prices (see Figure 5-4). Because 

the underlying economics at current gas prices favor the construction of NGCC, the proposed 

NSPS standard does not impose any social costs (or generate monetized net benefits). 

However, the net benefits from a policy interact with the relative generating costs, which in 

turn vary based on the prices of fuels like natural gas and coal. Because the cost of this 

standard is zero under EPA’s baseline scenario, and because the social costs are expected to be 

especially sensitive to the relatively uncertain parameter of natural gas prices, EPA conducted 

an illustrative analysis of the breakpoints where natural gas prices change the sign of the social 

costs of the policy (holding all other parameters constant).32 This analysis describes the pattern 

in social costs as natural gas prices rise across three ranges: projected gas prices, unexpectedly 

high natural gas prices, and unprecedented natural gas prices.

Likely Projected Natural Gas Prices. As described earlier in this chapter, the base case 

modeling that EPA 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 

 

compare new units located in the same place, and so some of the natural gas units with the greatest damages 

may be attributable to their location, and includes natural gas steam boilers, which have a higher emission 

rates per unit of generation than natural gas combined cycle units. 

32 In reality this is unlikely to be the case. For example, high economic growth would increase both natural gas and 

coal prices at the same time - making it harder to alter the underlying cost advantage of NGCC generation.
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grants). As shown earlier in the illustrative analysis, it is only when gas prices reach 

approximately $9.60/mmBtu, that coal-fired generation without CCS becomes competitive in 

terms of dollars per megawatt hour wholesale cost of electricity generation. For context, even 

EIA’s most pessimistic gas sensitivity case (“low shale gas recovery per well”) only projects an 

electricity sector gas price of $6.79 in 2020 (the “low shale gas recovery per play” scenario 

projects a price of $5.93/mmBtu in 2020). In other words, even under pessimistic natural gas 

sensitivity cases, NGCC is likely to remain the economic choice for generation over the next two 

decades even in the absence of this standard. As a result, the social costs of the standard are 

expected to be zero.

Unexpectedly High Natural Gas Prices. In this illustrative analysis, at gas prices above 

$9.60/mmBTU, coal generation without CCS becomes competitive with NGCC, which may mean 

that some new non-CCS coal units might be constructed in the absence of the standard 

provided there is sufficient demand and new coal without CCS is competitive with other 

generating technologies. However, these coal units would also impose social costs in the form 

of global warming pollution and particulate matter (as a result of SOx and NOx emissions) and 

this proposed standard would avoid those social costs. For example, at gas prices of 

$10/MMBTU, the illustrative non-CCS coal unit would generate power for $[3]/MWh less than 

an NGCC unit33, but result in greater pollution damages of $16-70/MWh (see table 5-XX).34 

Under the proposed standard, if the investor built the NGCC unit instead the resulting net social 

benefit would be $[13] to [67]/MWh. For context, we note that these circumstances are less 

likely than the zero cost scenario outlined above. To put this gas price breakpoint into historical 

context, $9.60/MMBTU is higher than any annual gas price observed over the last 10 years, and 

it has only been reached temporarily in 9 of the last 120 months. 35 36 Looking forward, the 

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

prices would actually tend to be towards the lower end of the historical range. As discussed 

above, none of the EIA sensitivity cases (which represent future price trajectories for both gas 

 

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

prices. AWAITING CONFIRMATION

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

previous footnote.

35 See: http://www.eia.gov/dnav/ng/hist/n3045us3A.htm

36 It is important to note that relatively high gases prices in a single month or year will not drive 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.
5-30

and coal) show scenarios where non-compliant coal becomes more economic than NGCC 

before 2020.

Unprecedented Natural Gas Prices. At extremely high gas prices, the private generating 

costs of non-compliant coal are significantly lower than the cost of new natural gas and the net 

social cost of the standard could be positive (negative net benefits) under some assumptions 

for environmental damage costs. For example, at gas prices of $15/MMBTU, the illustrative 

non-CCS coal unit would generate power for roughly $[36]/MWh less than an NGCC unit but 

result in social costs of $16-70/MWh (see table 5-XX). Under the proposed standard, a 

generator would likely build the NGCC unit instead, resulting in a net social benefit of $[-19] to 

[34]/MWh. The point at which this standard would result in net social costs depends heavily 

upon the value for damages from GHGs and SO2; assuming an SCC using a 3% discount rate in 

this illustrative example would generate net social costs at average gas prices of $[13] to 

$[18]/MMBTU. Annual natural gas prices delivered to the electricity sector have not exceeded 

$ 9.26 /MMBTU over the last 15 years.

We emphasize that differences in generating costs, plant design, local factors, and the 

relative differences between fuels costs can all have major impacts on the precise 

circumstances where this standard would be projected to have no costs, net benefits or net 

costs. However, based annual gas prices over the last 15 years, we project that this standard is 

most likely to have no notable costs, that there is some small probability that it produces net 

benefits, and an exceedingly low probability that it results in net costs. 

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

supercricitcal coal and natural gas combined cycle. Because these technologies are well 

developed, there is significantly more certainty about operating costs than for new, emerging 

technologies like coal with CCS. As a result, any analysis which examines the relative social 

costs of coal vs. coal with CCS is considerably more uncertain and should primarily be used as a 

guide to the key sensitivities in the 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 FOR DETAILS].

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

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

requires that approximately 31% 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 
5-31

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 

term, any new coal-fired EGU with CCS would mostly 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 project37 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.38 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). Costs for the IGCC unit with 90% 

capture and the ultra-supercritical coal-fired unit without CCS were derived from IPM version 

4.10.39 These cost estimates are generally consistent with the range of studies estimating the 

cost of CCS that are available, however there is uncertainty around any such projections of 

technology costs, particularly for early movers of this technology. Costs for the IGCC unit with 

30% capture were derived from the costs for the IGCC unit with 90% CCS using best engineering 

judgment. EPA estimated the benefits associated with avoided CO2 and SO2 emissions in a 

similar fashion to the one described above [REFERENCE TECHNICAL MEMO IN THE DOCKET]

Table 5-7. Illustrative Costs and Benefits for two CCS Scenarios Compared to Conventional 

Coal Plant (Millions 2007$) – NOTE – WILL BE REVISED TO $/MWh FOR 

CONSISTENCY

USPC to IGCC with 

30% Capture

USPS to IGCC with 

90% Capture

Additional Gross Annual Private Costs $80.0 $130.3

Revenue from EOR $17.4 (@$15/ton) $143.7 (@$45/ton)

Net Additional Annual Private Costs $62.6 ($13.4)

Value of Quantified Benefits

 

37 http://www.texascleanenergyproject.com/

38 US DOE / NETL studies have assumed a 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).

39http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html
5-32

 SCC 3% with Pope 7% $58 $109

 SCC 3% with Laden 3% $101 $151

Net Benefits

 SCC 3% with Pope 7% ($4.6) $122.4

 SCC 3% with Laden 3% $38.4 $164.4

This analysis suggests that the relative social cost of CCS compared to conventional coal 

is sensitive to the achieved generating costs for CCS units, the revenue stream from EOR, and 

the monetary value of avoided climate and other air pollution damages. However, it also 

suggests that, at relatively low prices for EOR revenue ($15/MWh), CCS generation can 

generate net social benefits compared to conventional coal generation.

EPA recognizes that this illustrative analysis is somewhat novel, and requests comment 

on ways to incorporate uncertainty about future economic factors (and gas prices in particular) 

into the consideration of the social cost of this rule.

5.13 Macroeconomic and Employment Impacts

This proposed EGU GHG NSPS is not anticipated to change GHG emissions for newly 

constructed electric generating units, nor is it anticipated to impose notable costs or have 

notable economic or employment impacts. EPA typically presents the economic impacts to 

secondary markets (e.g., changes in industrial markets resulting from changes in electricity 

prices) and impacts to employment or labor markets 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. 

5.14 References

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Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for 

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U.S. Environmental Protection Agency (U.S. EPA). 2006. Air Quality Criteria for Ozone and 

Related Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. Washington, DC: U.S. 

EPA. February. Available on the Internet at 

<http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923>.

U.S. Environmental Protection Agency (U.S. EPA). 2008. Integrated Science Assessment for 

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