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EO12866EGUGHGNSPSRIA2060-AQ9120111104Ch5.docx

Chapter 5

Costs, Economic and Energy Impacts

5.1 Synopsis

Because there are no forecasted additions of non-compliant EGU facilities (e.g., new 

coal-burning power stations without carbon controls) during the analysis period (2020), this 

proposed GHG EGU NSPS is not expected to change GHG emissions for newly constructed 

electric generating units, nor is it anticipated to impose notable costs, economic, or energy 

impacts on the EGU sector or society.

5.2 Background

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

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

variables and provide the framework for how the Agency estimates the 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 a limited new capacity, of any type, expected to be constructed within the foreseeable 

future. A small number of new coal-fired power plants have been built in recent years;

however, EPA does not forecast the construction of any new unplanned coal-fired additions 

over the time horizon of this analysis. 

There are two main reasons why EPA expects there will be no currently unplanned coalfired power plants constructed over the time horizon considered for this analysis. First, the 

current economic and financial situation has dampened electricity demand, and thus there is 

less need for new generating capacity in the foreseeable future. Second, generating 

technologies using natural gas produce electricity at lower cost than other generating 

technologies, and therefore for the foreseeable future utilities are likely to rely heavily on 

generation from combustion turbine and combined cycle plants using natural gas when they do 

need to expand capacity. This circumstance is different than from a few years ago as current 

and forecast natural gas prices are considerably lower than levels seen over the past decade. 

This is because new drilling techniques have brought substantial additional supply to the 

marketplace. Based on these market conditions, on average the cost of generation from a new 

natural gas power plant is expected to be lower than the cost of generation from a new coal-
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fired power plant.1 This trend is already apparent in recent history, where natural gas-fired 

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

5-1).

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

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

Various energy sector modeling efforts, including recent projections from both EIA and 

EPA, show results that are consistent with these findings. The Annual Energy Outlook (AEO) for 

2011 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 will be either natural gas-fired or renewable, with some lesser amounts of 

nuclear power. The AEO 2011 is based on existing policy and regulations, such as state RPS 

 

1

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

http://205.254.135.24/oiaf/aeo/electricity_generation.html 

2

AEO 2011 has a small amount of planned coal capacity that is under construction and expected to come online in 

the next year. It also has 2 GW of unplanned coal capacity, which reflects new coal with CCS in response to Federal 

incentives.

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Capacity (MW)

Other

Gas (CC and CT)

Renewable/Hydro

Nuclear

Coal
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programs and Federal tax credits for renewables.3The Department of Energy (DOE) concluded, 

based on EIA analysis, that “the low capital expense, technical maturity, and dispatchability of 

natural gas generation are likely to dominate investment decisions under current 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. Neither planned nor unplanned 

additions of coal by 2020 increase in sensitivity cases that 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.

EPA uses the Integrated Planning Model (IPM) to support its understanding of the 

economic and emissions impacts of air regulations on the power sector. IPM projections show 

similar patterns of future power plant deployment as AEO 2011, and IPM projections show no 

construction of new conventional coal-fired power plants under the base case.5 

EPA has used IPM to consider control options for reducing power-sector emissions for 

two decades. The model has been used by the Agency to support regulatory initiatives as well 

as legislative proposals designed to address air emissions for the power sector. All of the 

analyses are available at EPA’s website and in the public docket.6

The baseline information in this RIA is based on the same power sector modeling 

platform used for the proposed Mercury and Air Toxics Standards (MATS) from March 2011.7 

This platform includes the parameters and rule requirements from proposed MATS and the 

proposed Transport Rule, which was later renamed as the Cross State Air Pollution Rule (CSAPR)

upon subsequent finalization. The analysis reflected in this RIA was being developed while 

MATS and CSAPR were still being finalized; as a result, the baseline referenced here includes 

those rules in their proposal forms. Modeling results with the rules in their final forms is 

unlikely to materially alter EPA’s base case forecast using IPM. In addition to the proposed 

Transport Rule and MATS, the baseline takes into account emissions reductions associated with 

the implementation of all federal rules, 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 in the timeframe covered in the analysis.

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

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

 

3

http://www.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

6

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

7 http://www.epa.gov/airmarkets/progsregs/epa-ipm/toxics.html
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chapter has been developed for the specific analyses of the power sector. Thus, the model has 

been designed to reflect the industry as accurately as possible. EPA uses the best available 

information from utilities, industry experts, gas and coal market experts, financial institutions, 

and government statistics as the basis for the detailed power sector modeling in IPM. More 

detail on IPM can be found in the model documentation, which provides additional information 

on the assumptions discussed here as well as all other assumptions and inputs to the model.8

5.3 External Review of EPA Applications of the Integrated Planning Model (IPM)

The model undergoes periodic formal peer review, which includes separate expert 

panels on the model itself, and EPA’s key modeling input assumptions. For example, over the 

past ten years several separate panels of independent experts have been convened to review 

IPM’s coal supply and transportation assumptions, natural gas assumptions, and model 

formulation.

The rulemaking process also provides opportunity for expert review and comment by a 

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

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

sector models. The feedback that the Agency receives provides a highly detailed reality check 

of key input 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 (CAIR), the Cross State 

Air Pollution Rule (CSAPR), the proposed Mercury an Air Toxics Standards (MATS), and over a 

dozen legislative analytical efforts to understand the costs, benefits, and power sector impacts 

of various policies to reduce power sector emissions. As part of the rulemaking process, EPA is 

required to respond to every significant comment submitted. 

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

(RGGI), the Western Regional Air Partnership (WRAP), Ozone Transport Assessment Group 

(OTAG), other 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 

 

8

http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation
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1990’s, the Science Advisory Board reviewed IPM as part of the CAAA Section 812 prospective 

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

interagency scrutiny as part of a 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 (RPOs) throughout the U.S. have extensively examined IPM as 

a key element in the SIP process for NAAQS. Lastly, the Agency has exercised the model over 

the past 15 years in a number of comparative modeling exercises sponsored by Stanford 

University’s Energy Modeling Forum.

5.4 Base Case Analysis of Future 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 

Mercury and Air Toxics Standards and the proposed Transport Rule.9

The IPM base case projection includes a 1% growth in electricity demand, similar to EIA. 

This new demand will be fulfilled by existing generating capacity that is currently not being fully 

utilized, and new renewable and gas-fired generating capacity (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 costeffective options, 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 natural gas-fired 

capacity. Although 2 GW of coal with CCS is included in the base case, overall coal capacity is 

forecast to decline in response to current economics, along with some retirements due to 

upcoming air regulations (CSAPR and MATS). Relative to current levels, EPA anticipates that the 

existing coal fleet will increase utilization while gas-fired sources will decrease utilization 

slightly. 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)

 

9

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

Table 5-2. 2009 U.S. Electricity Net Generation and EPA Base Case Projections for 2020 

(Billion kWh)

Historical Projected

2009 2020

Coal 1,756 1,976

Oil 39 0.129

Natural Gas 921 873

Nuclear 799 841

Hydroelectric 273 287

Non-hydro Renewables 144 288

Other 18 45

Total 3,950 4,309

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

Source: 2009 data from EIA Electric Power Annual 2009, Table 2.1; Projections from Integrated Planning Model run by EPA, 2011.

5.5 Analysis of Applicability of Proposed EGU GHG NSPS to Projected New Generating 

Capacity

As the 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.
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The proposed EGU GHG NSPS discusses potential requirements for four types of units or

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

Analysis performed by EPA, along with information from other sources, suggests that the 

standards as specified in this proposed rule are not likely to result in notable emission changes, 

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

analyses performed both by EPA and the U.S. Energy Information Administration (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.

5.5.1 New Units

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

capacity be able to meet an emission rate standard of 1,000 pounds of CO2 per megawatt hour 

(lbs CO2/MWh). It also proposes an alternative standard that would allow 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 carbon capture 

and sequestration technology (CCS). 

Of the new generating capacity projected to be constructed by 2020, only the fossil-fuelfired units would be subject to the proposed GHG NSPS for EGU. The NGCC units, which are the 

basis of the proposed standard, will meet the proposed standard through their inherent design. 

No units projected to be built would be subject to the proposed NSPS. This indicates that the 

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

Thus, there would be no expected reduction in emissions and no costs for the newly 

constructed EGUs forecasted.

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 generation or coal-fired generation with CCS (the latter is assumed to be built 

with support from federal grants). The EIA’s Annual Energy Outlook (AEO) 2011 modeling 

makes similar conclusions. A number of major utilities have made public announcements

consistent with these modeling results.10

 

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

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

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

burning gas, not coal,” Jack Fusco, Calpine, 12/1/2010, Marketplace; “Coal’s most ardent defenders are in no 
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Engineering cost analysis, even outside of a least-cost system dispatch modeling 

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

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

forecasted prices in 2020,

11 electricity generated by natural gas combined cycle units is less 

expensive on average than coal generation. A comparison of wholesale electricity costs for 

differing generation technologies and natural gas prices are shown in Figure 5-2 and Table 5-3.

Figure 5-2. Illustrative Wholesale Levelized Cost of Electricity of Alternative New Generation 

Technologies, EPA ($2007)

Notes: Assumptions derived from EPA’s application of IPM. 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. All values in this graph assume a coal is high sulfur bituminous at $2 mmBtu, with a heat rate of 8,875 net. It is only when gas prices 

reach approximately $8/mmBtu, that coal-fired generation without CCS becomes competitive in terms of dollars per megawatt hour wholesale 

cost of electricity generation. For context, even EIA’s most pessimistic gas sensitivity case (“low shale gas recovery per well”) only projects an 

electricity sector gas price of $8.17 in 2030 (the “low shale gas recovery per play” scenario projects a price of $7.36/mmBtu in 2030).

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

average national cost of 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 

 

hurry to build new ones in this environment.” John Rowe, Exelon, 9/2011, EnergyBiz; “With low gas prices, gasfired generation kind of snowplows everything else” Lew Hay, NextEra, 11/1/2010, Dow Jones.

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

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

0

20

40

60

80

100

120

140

Conventional 

Coal

Natural Gas 

Combined Cycle 

($5 gas)

Natural Gas 

Combined Cycle 

($8 gas)

Coal + CCS

$/M

Wh
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wage and productivity differences, location adjustments, among other potential differences.12 

The comparison also does not explicitly consider units designed to combust waste coal or pet 

coke, which may exhibit different local economics. However, the results are expected to hold 

for the majority of situations.

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

(2016)

Plant Type

Capacity 

Factor (%)

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

for Plants Entering Service in 2016

Levelized 

Capital 

Cost Fixed O&M

Variable O&M 

(Including fuel)

Transmission 

Investment

Total 

System 

Levelized 

Cost

Conventional Coal 85 65.5 3.9 24.5 1.2 95.1

Advanced Coal 85 74.7 7.9 25.9 1.2 109.7

Advanced Coal with CCS 85 92.9 9.2 33.3 1.2 136.5

Natural Gas-fired

 Conventional Combined Cycle 87 17.5 1.9 44.6 1.2 65.1

 Advanced Combined Cycle 87 17.9 1.9 41.2 1.2 62.2

 Advanced CC with CCS 87 34.7 39 48.6 1.2 88.4

 Conventional Comb. Turbine 30 45.8 3.7 69.9 3.5 123

 Advanced Combustion Turbine 30 31.7 5.5 61.3 3.5 102.1

Advanced Nuclear 90 90.2 11.1 11.7 1.0 114.0

Wind 34 83.3 9.5 0 3.4 96.1

Wind - Offshore 34 209.7 28.1 0 5.9 243.7

Solar PV 25 194.9 12.1 0 4.0 211.0

Solar Thermal 18 259.8 46.6 0 5.8 312.2

Geothermal 91 77.4 11.9 9.5 1.0 99.8

Biomass 83 55.4 13.7 42.3 1.3 112.6

Hydro 53 78.5 4.0 6.2 1.8 90.5

Source: EIA, AEO 2011

5.5.2 Reconstructed Units

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

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

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

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

 

12 http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf
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feasible (40 CFR 60.15). The Agency is aware that, in theory, operators of existing power plants 

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

provision is rarely triggered. In the proposed NSPS, EPA is taking comment on different 

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

general, include (i) not taking final action to establish a new standard of performance, which, as 

a practical matter, would mean that reconstructed sources would be treated as existing 

sources; (ii) establishing the standard of performance at either the same level as for new 

sources or at the supercritical efficiency level.

 If reconstructed sources are treated as new sources, this rule would not establish 

applicable requirements for them. 

 If reconstructed sources are regulated as the supercritical efficiency level, EPA would 

not expect the requirement to change firms’ behavior because they would be expected 

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

standard.

 The same is true if reconstructed sources are required to meet the proposed new

source standard. 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 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).

5.5.3 Modified Units

As explained in the preamble, EPA is not aware of any EGUs that would undertake 

actions defined as modifications. A modification is any physical change in, or change in the 

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

source or results in the emission of any air pollutant not previously 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.

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

permits to construct, but have not actually commenced construction. EPA believes that there 

are approximately 18 such units discussed previously in Chapter X. Historically, obtaining a 

permit does not guarantee that a unit will end up being constructed. In the last 10 years, 88

coal plants have been permitted. Of those, 40 (or less than half) have actually commenced 

construction. Thirty projects have been cancelled and approximately 18 sources (the 

transitional sources) have active permits. Based on this history, EPA believes that 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. Furthermore, in its rule, 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. For these units, this rule adds no additional costs 

and will not result in any monetized benefits.

In the absence of this rule, EPA believes the coal units that are most likely to commence 

construction are those that have received public incentives to install CCS. Under the proposed 

rule, these units would be able to commence construction within the proposed rule time-frame

without incurring any requirement to reduce CO2 emissions. EPA also believes that the 

economics demonstrated above also apply to the other transitional units; therefore, building 

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

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

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

choose not to commit to actual construction of these previously proposed coal plants.

5.6 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 GHG EGU 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 
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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 X for more discussion on 

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

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

shows current electricity generation alongside EPA’s projection for 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. 

5.7 Limitations

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

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

emitting sources of electricity (regardless of whether the power sector is 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 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. 

5.8 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 
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the future operating environment (e.g., Reinelt and Keith, 2007; Patiño-Echeverri et al., 2009). 

EPA is not able to directly quantify or monetize this benefit at this time.

5.9 Comparison of Emissions Differences of Generation Technologies

As discussed earlier in this chapter, natural gas units are on average expected to be 

more 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 GHG EGU 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. 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, SO2, and NOx

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

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: Criteria pollutants in short tons, CO2 in metric tons. Relative emissions for new well controlled 600 MW (net) units running at 

85% capacity factor. Assumed coal is high sulfur bituminous with scrubber and SCR. Data is based on EPA assumptions used in IPM.

5.8.1 Benefits of Reducing GHGs and Criteria Pollutants
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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.13 

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.14 The first three values 

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

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

literature shows that the SCC is quite 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. Low probability, high impact (“catastrophic”) events were 

 

13 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

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

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

proposal, but those were not quantified.
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reflected in two of the three models, but the interagency group nonetheless concluded that a 

limitation of the analysis was inadequate treatment of these potential catastrophic events. A

probability density function was used for equilibrium climate sensitivity. Treating climate 

sensitivity probabilistically results in more high temperature outcomes, which in turn lead to 

higher projections of damages.

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

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

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

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

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

modeling assumptions. Table 4-1 presents the SCC estimates for the years 2015 to 2050. When 

attempting to assess the incremental economic impacts of carbon dioxide emissions, the 

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

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

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

and future emissions on the 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.15 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 

 

15 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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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 

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, 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 Regulatory Impact 

Analysis for the Cross-State Air Pollution Rule (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 
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individuals and organizations obtain 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 SO2 from U.S. EGUs has been estimated to yield 

between 5 and 12 incidences of premature mortality avoided and between $39 million and $94

million in PM2.5-related health benefits on average while reducing one thousand tons of NOX

from U.S. EGUs has been estimated to yield between 1 and 2 incidences of premature mortality 

avoided and between $7 million and $17 million in PM2.5-related health benefits on average 

(Fann et. al 2009).16

5.9 Macroeconomic and Employment Impacts

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

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

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

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

prices) and impacts to employment or labor markets associated with proposed rules 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. 

 

16 The results presented here utilize updated health impact assessment inputs, such as updated value of statistical 

life, and therefore differ from the results presented in the 2009 article. The summary results of this update are 

available online at (http://www.epa.gov/air/benmap/bpt.html). Additionally, the article reports benefits per ton. 

For this assessment we multiply the benefit per ton by one thousand to yield benefits per thousand tons. This 

2009 article does not explicitly report the incidences of premature mortality. However, this endpoint is the primary 

driver of the total valued health benefits (which are reported) and thereby provides additional insight into the 

health effects of these emissions. The 2009 article reported the mortality impacts of PM2.5 exposure based on the 

findings of Laden et al. 2006. For this illustrative example, 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. The results shown 

correspond to a 2015 analysis year and a currency year of 2006.
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References

U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for 

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

Environmental Assessment – RTP Division. December. Available on the Internet at 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.

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

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

EPA. February. Available on the Internet at 

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

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

Oxides of Nitrogen and Sulfur –Ecological Criteria National (Final Report). National 

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Internet at <http://www.epa.gov/airtransport/pdfs/FinalRIA.pdf>.

Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. The influence of location, source, and emission type 

in estimates of the human health benefits of reducing a ton of air pollution. Air Qual 

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Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 2006. Reduction in Fine Particulate Air 

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Hoffmann, Volker H. and Trautmann, Thomas and Hamprecht, Jens. Regulatory Uncertainty: A 

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