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CHAPTER 3

COST, ECONOMIC, AND ENERGY IMPACTS 

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

performed for the Mercury and Air Toxics Standards (MATS). EPA used the Integrated Planning 

Model (IPM), developed by ICF Consulting, to conduct its analysis. IPM is a dynamic linear 

programming model that can be used to examine air pollution control policies for SO2, NOx, Hg, 

HCl, and other air pollutants throughout the United States for the entire power system.

Documentation for IPM can be found at http://www.epa.gov/airmarkets/progsregs/epa-ipm, 

and updates specific to the MATS modeling are in the “Documentation Supplement for EPA 

Base Case v.4.10_MATS – Updates for Final Mercury and Air Toxics Standards (MATS) Rule” 

(hereafter IPM 4.10 Supplemental Documentation for MATS).

3.1 Background

Over the last decade, EPA has on several occasions used IPM to consider pollution

control options for reducing power-sector emissions.

1 Most recently EPA used IPM extensively 

in the development and analysis of the impacts of the Cross-State Air Pollution Rule (CSAPR).2

As discussed in Chapter 2, MATS coincides with a period when many new pollution controls are 

being installed. Many are needed for compliance with NSR settlements and state rules, while 

others may have been planned in expectation of CAIR and its replacement, the CSAPR.

The emissions scenarios for the RIA reflects the Cross-State Air Pollution Rule (CSAPR) as 

finalized in July 2011 and the emissions reductions of SOX, NOX, directly emitted PM, and CO2

are consistent with application of federal rules, state rules and statutes, and other binding, 

enforceable commitments in place by December 2010 for the analysis timeframe.

3

 

1Many EPA analyses with IPM have focused on legislative proposals with national scope, such as EPA’s IPM 

analyses of the Clean Air Planning Act (S.843 in 108th Congress), the Clean Power Act (S.150 in 109th Congress), 

the Clear Skies Act of 2005 (S.131 in 109th Congress), the Clear Skies Act of 2003 (S.485 in 108th Congress), and 

the Clear Skies Manager's Mark (of S.131). These analyses are available at EPA’s website: 

(http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html). EPA also analyzed several multi-pollutant 

reduction scenarios in July 2009 at the request of Senator Tom Carper to illustrate the costs and benefits of 

multiple levels of SO2 and NOX control in the power sector.

2

Additionally, IPM has been used to develop the NOX Budget Trading Program, the Clean Air Interstate Rule 

programs, the Clean Air Visibility Programs, and other EPA regulatory programs for the last 15 years. 

3

Consistent with the mercury risk deposition modeling for MATS, EPA did not model non-federally enforceable 

mercury-specific emissions reduction rules in the base case or MATS policy case (see preamble section III.A). 

Note that this approach does not significantly affect SO2 and NOX projections underlying the cost and benefit 

results presented in this RIA
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EPA has made these base case assumptions recognizing that the power sector will install 

a significant amount of pollution controls in response to several requirements. The inclusion of 

CSAPR and other regulatory actions (including federal, state, and local actions) in the base case 

is necessary in order to reflect the level of controls that are likely to be in place in response to 

other requirements apart from MATS. This base case will provide meaningful projections of 

how the power sector will respond to the cumulative regulatory requirements for air emissions 

in totality, while isolating the incremental impacts of MATS relative to a base case with other air 

emission reduction requirements separate from today’s action. 

The model’s base case features an updated Title IV SO2 allowance bank assumption and 

incorporates updates related to the Energy Independence and Security Act of 2007. Some 

modeling assumptions, most notably the projected demand for electricity, are based on the 

2010 Annual Energy Outlook from the Energy Information Administration (EIA). In addition, the 

model includes existing policies affecting emissions from the power sector: the Title IV of the 

Clean Air Act (the Acid Rain Program); the NOx SIP Call; various New Source Review (NSR) 

settlements4; and several state rules5affecting emissions of SO2, NOx, and CO2 that were 

finalized through June of 2011. IPM includes state rules that have been finalized and/or 

approved by a state’s legislature or environmental agency, with the exception of non-federal 

mercury-specific rules. The IPM 4.10 Supplemental Documentation for MATS contains details

on all of these other legally binding and enforceable commitments for installation and 

operation of pollution controls. This chapter focuses on results of EPA’s analysis with IPM for 

the model’s 2015 run-year in connection with the compliance date for MATS.

MATS establishes National Emissions Standards for Hazardous Air Pollutants (NESHAPS) 

for the “electric utility steam generating unit” source category, which includes those units that 

combust coal or oil for the purpose of generating electricity for sale and distribution through 

the national electric grid to the public.

 

4

The NSR settlements include agreements between EPA and Southern Indiana Gas and Electric Company (Vectren), 

Public Service Enterprise Group, Tampa Electric Company, We Energies (WEPCO), Virginia Electric & Power 

Company (Dominion), Santee Cooper, Minnkota Power Coop, American Electric Power (AEP), East Kentucky 

Power Cooperative (EKPC), Nevada Power Company, Illinois Power, Mirant, Ohio Edison, Kentucky Utilities, 

Hoosier Energy, Salt River Project, Westar, Puerto Rico Power Authority, Duke Energy, American Municipal Power, 

and Dayton Power and Light. These agreements lay out specific NOx, SO2, and other emissions controls for the 

fleets of these major Eastern companies by specified dates. Many of the pollution controls are required between 

2010 and 2015.

5

These include current and future state programs in Alabama, Arizona, California, Colorado, Connecticut, 

Delaware, Georgia, Illinois, Kansas, Louisiana, Maine, Maryland, Massachusetts, Michigan, Minnesota, Missouri, 

Montana, New Hampshire, New Jersey, New York, North Carolina, Oregon, Pennsylvania, Tennessee, Texas, Utah, 

Washington, West Virginia, and Wisconsin the cover certain emissions from the power sector.
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Coal-fired electric utility steam generating units include electric utility steam generating 

units that burn coal, coal refuse, or a synthetic gas derived from coal either exclusively, in any 

combination together, or in any combination with other supplemental fuels. Examples of 

supplemental fuels include petroleum coke and tire-derived fuels. The NESHAP establishes 

standards for HAP emissions from both coal- and oil-fired EGUs and will apply to any existing, 

new, or reconstructed units located at major or area sources of HAP. Although all HAP are 

pollutants of interest, those of particular concern are hydrogen fluoride (HF), hydrogen chloride 

(HCl), dioxins/furans, and HAP metals, including antimony, arsenic, beryllium, cadmium, 

chromium, cobalt, mercury, manganese, nickel, lead, and selenium.

This rule affects any fossil fuel fired combustion unit of more than 25 megawatts electric 

(MWe) that serves a generator that produces electricity for sale. A unit that cogenerates steam 

and electricity and supplies more than one-third of its potential electric output capacity and 

more than 25 MWe output to any utility power distribution system for sale is also considered 

an electric utility steam generating unit. The rule affects roughly 1,400 EGUs: approximately 

1,100 existing coal-fired generating units and 300 oil-fired steam units, should those units 

combust oil. Of the 600 power plants potentially covered by this rule, about 430 have coal-fired 

units only, 30 have both coal- and oil- or gas-fired steam units, and 130 have oil- or gas-fired 

steam units only. Note that only steam electric units combusting coal or oil are covered by this 

rule.

EPA analyzed for the RIA the input-based (lbs/MMBtu) MATS control requirements 

shown in Table 3-1. In this analysis, EPA does not model an alternative SO2 standard. Coal 

steam units with access to lignite in the modeling are subjected to the “Existing coal-fired unit 

low Btu virgin coal” standard. For further discussion about the scope and requirements of 

MATS, see the preamble or Chapter 1 of this RIA.
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Table 3-1. Emissions Limitations for Coal-Fired and Solid Oil-Derived Fuel-Fired Electric 

Utility Steam Generating Units

Subcategory Filterable

Particulate Matter

Hydrogen Chloride Mercury

Existing coal-fired unit not low Btu 

virgin coal

0.030 lb/MMBtu 

(0.30 lb/MWh)

0.0020 lb/MMBtu

(0.020 lb/MWh)

1.2 lb/TBtu

(0.020 lb/GWh)

Existing coal-fired unit low Btu 

virgin coal

0.030 lb/MMBtu 

(0.30 lb/MWh)

0.0020 lb/MMBtu

(0.020 lb/MWh)

11.0 lb/TBtu

(0.20 lb/GWh)

4.0 lb/TBtua

(0.040 lb/GWha)

Existing - IGCC 0.040 lb/MMBtu 

(0.40 lb/MWh)

0.00050 lb/MMBtu 

(0.0050 lb/MWh)

2.5 lb/TBtu

(0.030 lb/GWh)

Existing – Solid oil-derived 0.0080 lb/MMBtu

(0.090 lb/MWh)

0.0050 lb/MMBtu 

(0.080 lb/MWh)

0.20 lb/TBtu

(0.0020 lb/GWh)

New coal-fired unit not low Btu 

virgin coal 0.0070 lb/MWh 0.40 lb/GWh 0.00020 lb/GWh

New coal-fired unit low Btu virgin 

coal 0.0070 lb/MWh 0.40 lb/GWh 0.040 lb/GWh

New – IGCC 0.070 lb/MWhb

0.090 lb/MWhc 0.0020 lb/MWhd

0.0030 lb/GWhe

New – Solid oil-derived 0.020 lb/MWh 0.00040 lb/MWh 0.0020 lb/GWh

Note: lb/MMBtu = pounds pollutant per million British thermal units fuel input

lb/TBtu = pounds pollutant per trillion British thermal units fuel input

lb/MWh = pounds pollutant per megawatt-hour electric output (gross)

lb/GWh = pounds pollutant per gigawatt-hour electric output (gross)

a

Beyond-the-floor limit as discussed elsewhere

b

Duct burners on syngas; based on permit levels in comments received

c

Duct burners on natural gas; based on permit levels in comments received

d

Based on best-performing similar source

e

Based on permit levels in comments received
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Table 3-2. Emissions Limitations for Liquid Oil-Fired Electric Utility Steam Generating Units

Subcategory Filterable PM Hydrogen Chloride Hydrogen Fluoride

Existing – Liquid oilcontinental 0.030 lb/MMBtu

(0.30 lb/MWh)

0.0020 lb/MMBtu

(0.010 lb/MWh)

0.00040 lb/MMBtu

(0.0040 lb/MWh)

Existing – Liquid oilnon-continental 0.030 lb/MMBtu

(0.30 lb/MWh)

0.00020 lb/MMBtu

(0.0020 lb/MWh)

0.000060 lb/MMBtu

(0.00050 lb/MWh)

New – Liquid oil –

continental 0.070 lb/MWh 0.00040 lb/MWh 0.00040 lb/MWh

New – Liquid oil –

non-continental 0.20 lb/MWh 0.0020 lb/MWh 0.00050 lb/MWh

EPA used the Integrated Planning Model (IPM) v.4.10 to assess the impacts of the MATS 

emission limitations for coal-fired electricity generating units (EGU) in the contiguous United 

States. IPM modeling did not subject oil-fired units to policy criteria.6Furthermore, IPM 

modeling did not include generation outside the contiguous U.S., where EPA is aware of only 2 

facilities that would be subject to the coal-fired requirements of the final rule. Given the limited 

number of potentially impacted facilities, limited availability of input data to inform the 

modeling, and limited connection to the continental grid, EPA did not model the impacts of the 

rule beyond the contiguous U.S.

Mercury emissions are modeled as a function of mercury content of the fuel type(s) 

consumed at each plant in concert with that plant’s pollutant control configuration. HCl 

emissions are projected in a similar fashion using the chlorine content of the fuel(s). For both 

mercury and HCl, EGUs in the model must emit at or below the final mercury and HCl emission 

rate standards in order to operate from 2015 onwards. EGUs may change fuels and/or install 

additional control technology to meet the standard, or they may choose to retire if it is more 

economic for the power sector to meet electricity demand with other sources of generation. 

See IPM 4.10 documentation and IPM 4.10 Supplemental Documentation for MATS for more 

details.

Total PM emissions are calculated exogenously to IPM, using EPA’s Source Classification 

Code (SCC) and control-based emissions factors. SCC is a classification system that describes a 

generating unit’s characteristics.

 

6

EPA did not model the impacts of MATS on oil-fired units using IPM. Rather, EPA performed an analysis of 

impacts on oil-fired units for the final rule. The results are summarized in Appendix 3A.
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Instead of emission limitations for the organic HAP, EPA is proposing that if requested, 

owners or operators of EGUs submit to the delegated authority or EPA, as appropriate, 

documentation showing that an annual performance test meeting the requirements of the rule 

was conducted. IPM modeling of the MATS policy assumes compliance with these work practice 

standards.

Electricity demand is anticipated to grow by roughly 1 percent per year, and total 

electricity demand is projected to be 4,103 billion kWh by 2015. Table 3-3 shows current 

electricity generation alongside EPA’s base case projection for 2015 generation 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 and the 

performance and cost of electric generation technologies as well as pollution controls.7The 

base case includes CSAPR as well as other existing state and federal programs for air emissions 

control from electric generating units, with the exception of state mercury rules. 

 

7 Note that projected electricity demand in AEO 2010 is about 2% higher than the AEO 2011 projection in 2015. 

Since this RIA assumes higher electricity demand in 2015 than is shown in the latest AEO projection, it is possible 

that the model may be taking compliance actions to meet incremental electricity demand that may not actually 

occur, and projected compliance costs may therefore be somewhat overstated in this analysis.
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Table 3-3. 2009 U.S. Electricity Net Generation and EPA Base Case Projections for 2015-

2030 (Billion kWh)

Historical Base Case

2009 2015 2020 2030

Coal 1,741 1,982 2,002 2,027

Oil 36 0.11 0.13 0.21

Natural Gas 841 710 847 1,185

Nuclear 799 828 837 817

Hydroelectric 267 286 286 286

Non-hydro Renewables 116 252 289 333

Other 10 45 45 55

Total 3,810 4,103 4,307 4,702

Source: 2009 data from AEO Annual Energy Review, Table 8.2c Electricity Net Generation: Electric Power Sector 

by Plant Type, 1989-2010; Projections from Integrated Planning Model run by EPA, 2011.
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Figure 3-1. Geographic Distribution of Affected Units, by Facility, Size and Fuel Source in 

2012

Source/Notes: National Electric Energy Data System (NEEDS 4.10 MATS) (EPA, December 2011) and EPA’s 

Information Collection Request (ICR) for New and Existing Coal- And Oil-Fired Electric Utility Stream Generation 

Units (2010). This map displays facilities that are included in the NEEDS 4.10 MATS data base and that contain at 

least one oil-fired steam generating unit or one coal-fired steam generating unit that generates more than 25 

megawatts of power. This includes coal-fired units that burn petroleum coke and that turn coal into gas before 

burning (using integrated gasification combined cycle or IGCC). NEEDS reflects available capacity on-line by the 

end of 2011; this includes committed new builds and committed retirements of old units. Only coal and oil-fired 

units are covered by this rule. Some of the oil units displayed on the map are capable of burning oil and/or gas. If 

a unit burns only gas, it will not be covered in the rule. In areas with a dense concentration of facilities, the 

facilities on the map may overlap and some may be impossible to see. IPM modeling did not include generation 

outside the contiguous U.S., where EPA is aware of only two facilities that would be subject to the coal-fired 

requirements of the final rule. Given the limited number of potentially impacted facilities, limited availability of 

input data to inform the modeling, and limited connection to the continental grid, EPA did not model the 

impacts of the rule beyond the contiguous U.S. Facilities outside the contiguous U.S. are displayed based on data 

from EPA’s 2010 ICR for the rule.

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 for specific analyses of the power sector. Thus, the model has 

been designed to reflect the industry as accurately as possible. To that end, EPA uses a series of 

capital charge factors in IPM that embody financial terms for the various types of investments 

that the power sector considers for meeting future generation and environmental constraints.
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The model applies a discount rate of 6.15% for optimizing the sector’s decision-making over 

time. IPM’s discount rate, designed to represent a broad range of private-sector decisions for 

power generation, rates differs from discount rates used in other analyses in this RIA, such as

the benefits analysis which each assume alternative social discount rates of 3% and 7%. These 

discount rates represent social rates of time preference, whereas the discount rate in IPM 

represents an empirically-informed price of raising capital for the power sector. Like all other 

assumed price inputs in IPM, EPA uses the best available information from utilities, financial 

institutions, debt rating agencies, and government statistics as the basis for the capital charge 

rates and the discount rate used for 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 (http://www.epa.gov/airmarkets/progsregs/epa-ipm). Updates specific to 

MATS modeling are also in the IPM 4.10 Supplemental Documentation for MATS.

3.2 Projected Emissions

MATS is anticipated to achieve substantial emissions reductions from the power sector.

Since the technologies available to meet the emission reduction requirements of the rule 

reduce multiple air pollutants, EPA expects the rule to yield a broad array of pollutant 

reductions from the power sector. The primary pollutants of concern under MATS from the 

power sector are mercury, acid gases such as hydrogen chloride (HCl), and HAP metals,

including antimony, arsenic, beryllium, cadmium, chromium, cobalt, mercury, manganese, 

nickel, lead, and selenium. EPA has extensively analyzed mercury emissions from the power 

sector, and IPM modeling assesses the mercury contents in all coals and the removal 

efficiencies of relevant emission control technologies (e.g., ACI). EPA also models emissions and 

the pollution control technologies associated with HCl (as a surrogate for acid gas emissions). 

Like SO2, HCl is removed by both scrubbers and DSI (dry sorbent injection). Projected emissions 

are based on both control technology and detailed coal supply curves used in the model that 

reflect the chlorine content of coals, which corresponds with the supply region, coal grade, and 

sulfur, mercury, and ash content of each coal type. This information is critical for accurately 

projecting future HCl emissions, and for understanding how the power sector will respond to a 

policy requiring reductions of multiple HAPs.

Generally, existing pollution control technologies reduce emissions across a range of 

pollutants. For example, both FGD and SCR can achieve notable reductions in mercury in 

addition to their primary targets of SO2 and NOX reductions. DSI will reduce HCl emissions while 
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also yielding substantial SO2 emission reductions, but is not assumed in EPA modeling to result 

in mercury reductions. Since there are many avenues to reduce emissions, and because the 

power sector is a highly complex and dynamic industry, EPA employs IPM in order to reflect the 

relevant components of the power sector accurately, while also providing a sophisticated view 

of how the industry could respond to particular policies to reduce emissions. For more detail on 

how EPA models emissions from the power sector, including recent updates to include acid 

gases, see IPM 4.10 Supplemental Documentation for MATS.

Under MATS, EPA projects annual HCl emissions reductions of 88 percent in 2015, Hg 

emissions reductions of 75 percent in 2015, and PM2.5 emissions reductions of 19 percent in 

2015 from coal-fired EGUs greater than 25 MW. In addition, EPA projects SO2 emission 

reductions of 41 percent, and annual CO2 reductions of 1 percent from coal-fired EGUs greater 

than 25 MW by 2015, relative to the base case (see Table 3-4).8 Mercury emission projections in 

EPA’s base case are affected by the incidental capture in other pollution control technologies 

(such as FGD and SCR) as described above. 

Table 3-4. Projected Emissions of SO2, NOX, Mercury, Hydrogen Chloride, PM, and CO2 with 

the Base Case and with MATS, 2015

Million Tons

Mercury 

(Tons)

Thousand Tons CO2

(Million Metric 

SO Tonnes) 2 NOX HCl PM2.5

Base All EGUs 3.4 1.9 28.7 48.7 277 2,230

Covered EGUs 3.3 1.7 26.6 45.3 270 1,906

MATS All EGUs 2.1 1.9 8.8 9.0 227 2,215

Covered EGUs 1.9 1.7 6.6 5.5 218 1,882

Source: Integrated Planning Model run by EPA, 2011

 

8

The CO2 emissions reported from IPM account for the direct CO2 emissions from fuel combustion and CO2 created 

from chemical reactions in pollution controls to reduced sulfur.
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Figure 3-2. SO2 Emissions from the Power Sector in 2015 with and without MATS

Source: 2015 emissions include coal steam (including IGCC and petroleum coke) units >25 MW from IPM v4.10 

base case and control case projections (EPA, February 2011)

Figure 3-3. NOX Emissions from the Power Sector in 2015 with and without MATS

Source: 2015 emissions include coal steam (including IGCC and petroleum coke) units >25 MW from IPM 

v4.10_MATS base case and control case projections (EPA, 2011)
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Figure 3-4. Mercury Emissions from the Power Sector in 2015 with and without MATS

Source: 2015 emissions include coal steam (including IGCC and petroleum coke) units >25 MW from IPM 

v4.10_MATS base case and control case projections (EPA, 2011)
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Figure 3-5. Hydrogen Chloride Emissions from the Power Sector in 2015 with and without 

MATS

Source: 2015 emissions include coal steam (including IGCC and petroleum coke) units >25 MW from IPM 

v4.10_MATS base case and control case projections (EPA, 2011)

3.3 Projected Compliance Costs

The power industry’s “compliance costs” are represented in this analysis as the change 

in electric power generation costs between the base case and policy case in which the sector 

pursues pollution control approaches to meet the final HAP emission standards. In simple 

terms, these costs are the resource costs of what the power industry will directly expend to 

comply with EPA’s requirements.

EPA projects that the annual incremental compliance cost of MATS is $9.4 billion in 2015

($2007). The annual incremental cost is the projected additional cost of complying with the 

final rule in the year analyzed, and includes the amortized cost of capital investment (at 6.15%) 

and the ongoing costs of operating additional pollution controls, investments in new generating 

sources, shifts between or amongst various fuels, and other actions associated with 

compliance. This projected cost does not include the compliance calculated outside of IPM 

modeling, namely the compliance costs for oil-fired EGUs, and monitoring, reporting, and 

record-keeping costs. See section 3.14 for further details on these costs. EPA believes that the 
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cost assumptions used for the final rule reflect, as closely as possible, the best information 

available to the Agency today.

Table 3-5. Annualized Compliance Cost for MATS Requirements on Coal-fired Generation

2015 2020 2030

Annualized Compliance Cost (billions of 2007$) $9.4 $8.6 $7.4

Source: Integrated Planning Model run by EPA, 2011.

EPA’s projection of $9.4 billion in additional costs in 2015 should be put into context for 

power sector operations. As shown in section 2.7, the power sector is expected in the base case

to expend over $320 billion in 2015 to generate, transmit, and distribute electricity to end-use 

consumers. Therefore, the projected costs of compliance with MATS amount to less than a 3% 

increase in the cost to meet electricity demand, while securing public health benefits that are 

several times more valuable (as described in Chapters 4 and 5).

3.4 Projected Compliance Actions for Emissions Reductions 

Fossil fuel-fired electric generating units are projected to achieve HAP emission 

reductions through a combination of compliance options. These actions include improved 

operation of existing controls, additional pollution control installations, coal switching 

(including blending of coals), and generation shifts towards more efficient units and loweremitting generation technologies (e.g., some reduction of coal-fired generation with an 

increase of generation from natural gas). In addition, there will be some affected sources that 

find it uneconomic to invest in new pollution control equipment and will be removed from 

service. These facilities are generally amongst the oldest and least efficient power plants, and 

typically run infrequently. In order to ensure that any retirements resulting from MATS do not 

adversely impact the ability of affected sources and electric utilities from meeting the demand 

for electricity, EPA has conducted an analysis of the impacts of projected retirements on 

electric reliability. This analysis is discussed in TSD titled: “Resource Adequacy and Reliability in 

the IPM Projections for the MATS Rule” which is available in the docket.

The requirements under MATS are largely met through the installation of pollution 

controls (see Figure 3-6). To a lesser extent, there is a small degree of shifting within and across 

various ranks and types of coals, and a relatively small shift from coal-fired generation to 

greater use of natural gas and non-emitting sources of electricity (e.g., hydro and nuclear)(see 

Table 3-6). The largest share of emissions reductions occur from coal-fired units installing new 

pollution control devices, such as FGD, ACI, and fabric filters; a smaller share of emission 
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reductions come from fuel shifts and unit retirements. Mercury emission reductions are largely 

driven by SCR/FGD combinations and ACI installations. HCl emission reductions are largely 

driven by FGD and DSI installations, which also incidentally provide substantial SO2 reductions 

in the policy case. Mercury, PM2.5, and HCl emission reductions are also facilitated by the 

installation of fabric filters, which boost mercury and HCl removal efficiencies of ACI and DSI, 

respectively.

Figure 3-6. Operating Pollution Control Capacity on Coal-fired Capacity (by Technology) with 

the Base Case and with MATS, 2015 (GW)

Note: The difference between controlled capacity in the base case and under the MATS may not necessarily equal 

new retrofit construction, since controlled capacity above reflects incremental operation of dispatchable 

controls in 2015. Additionally, existing ACI installed on those units online before 2008 are not included in the 

base case to reflect removal of state mercury rules from IPM modeling. For these reasons, and due to rounding, 

numbers in the text below may not reflect the increments displayed in this figure. See IPM Documentation for 

more information on dispatchable controls.

Source: Integrated Planning Model run by EPA, 2011.

As shown in Figure 3-6, this analysis projects that by 2015, the final rule will drive the 

installation of an additional 20 GW of dry FGD (dry scrubbers), 44 GW of DSI, 99 GW of 

additional ACI, 102 GW of additional fabric filters, 63 GW of scrubber upgrades, and 34 GW of 

ESP upgrades. Furthermore, the final rule results in a 3 GW decrease in retrofit wet FGD 

capacity relative to the base, where the SO2 allowance price under CSAPR provides an incentive 

for the additional SO2 reductions achieved by a wet scrubber relative to a dry scrubber.

The difference between operating controlled capacity in the base case and under MATS 

in Figure 3-6 may not necessarily equal new retrofit construction, since total controlled capacity 

in the figure reflects incremental operation of existing controls that are projected to operate 
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under MATS but not under the base case. With respect to the increase in operating ACI, some 

of this increase represents existing ACI capacity on units built before 2008. EPA’s modeling does 

not reflect the presence of state mercury rules, and EPA assumes that ACI controls on units 

built before 2008 do not operate in the absence of these rules. In the policy case, these controls 

are projected to operate and the projected compliance cost thus reflects the operating cost of 

these controls. Since these controls are in existence, EPA does not count their capacity toward 

new retrofit construction, nor does EPA’s compliance costs projection reflect the capital cost of 

these controls (new retrofit capacity is reported in the previous paragraph). 

3.5 Projected Generation Mix

Table 3-6 and Figure 3-7 show the generation mix in the base case and in MATS. In 2015, 

coal-fired generation is projected to decline slightly and natural-gas-fired generation is 

projected to increase slightly relative to the base case. Coal-fired generation is projected to 

increase above 2009 actual levels. 2015 natural gas-fired generation is projected to be lower 

than 2009, due in large part to the smaller relative difference in delivered natural gas and coal 

prices in different areas of the country projected in 2015 than occurred in 2009. The vast 

majority (over 98%) of base case coal capacity is projected to remain in service under MATS. In 

addition, the operating costs of complying coal-fired units are not so affected as to result in 

major changes in the electricity generation mix.

Table 3-6. Generation Mix with the Base Case and the MATS, 2015 (Thousand GWh)

2009 2015

Historical Base Case Policy Case

Change from 

Base Percent Change

Coal 1,741 1,982 1,957 -25 -1.3%

Oil 36 0.11 0.11 0.00 3.6%

Natural Gas 841 710 731 22 3.1%

Nuclear 799 828 831 3 0.4%

Hydroelectric 267 286 288 2 0.8%

Non-hydro Renewables 116 252 250 -1 -0.6%

Other 10 45 45 0.0 0.0%

Total 3,810 4,103 4,104 1 0.0%

Note: Numbers may not add due to rounding.

Source: 2009 data from AEO Annual Energy Review, Table 8.2c Electricity Net Generation: Electric Power Sector 

by Plant Type, 1989-2010; 2015 projections are from the Integrated Planning Model run by EPA, 2011.
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Figure 3-7. Generation Mix with the Base Case and with MATS, 2015-2030

Source: Integrated Planning Model run by EPA, 2011.

3.6 Projected Withdrawals from Service

Relative to the base case, about 4.7 GW (less than 2 percent) of coal-fired capacity is 

projected to be uneconomic to maintain by 2015. This projection considers various regional 

factors (e.g., other available capacity and fuel prices) and unit attributes (e.g., efficiency and 

age). These projected “uneconomic” units, for the most part, are older, smaller, and less 

frequently used generating units that are dispersed throughout the country (see Table 3-7).

Table 3-7. Characteristics of Covered Operational Coal Units and Additional Coal Units 

Projected to Withdraw as Uneconomic under MATS, 2015

Average Age 

(Years)

Average Capacity

MW Factor in Base

Withdrawn as Uneconomic 52 129 54%

Operational 43 322 71%

Source: Integrated Planning Model run by EPA, 2011.

These results should be considered “potential” closures. There are a variety of local 

factors that could make plant owners decide to keep one or more units projected to be 

uneconomic in service. These factors include different costs or demand estimates than what 

1.98 1.96 2.00 1.98 2.03 2.02

0.828 0.831 0.837 0.840 0.817 0.819

0.71 0.73 0.85 0.87 1.18 1.19

0.286 0.288 0.286 0.286

0.286 0.286

0.252 0.250 0.289 0.289

0.333 0.333

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

Base MATS Base MATS Base MATS

Million G

Wh

Generation Mix

Other

Oil

Non-Hydro

Renewables

Hydro

Natural Gas

Nuclear

Coal

2015 2020 2030
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was included in the IPM modeling, and local operating conditions or requirements that are on a 

smaller scale than that represented in EPA’s IPM modeling. To the extent EPA’s modeling does 

not account for plants that continue to operate due to one or more of these local factors, these 

results could be overestimating the capacity removed from service as a result of this rule.

For the final rule, EPA has examined whether the IPM-projected closures may adversely 

impact reserve margins and reliability planning. The IPM model is specifically designed to 

ensure that generation resource availability is maintained in the projected results subject to 

reserve margins in 32 modeling regions for the contiguous US, which must be preserved either 

by using existing resources or through the construction of new resources. IPM also addresses 

reliable delivery of generation resources by limiting the ability to transfer power between 

regions using the bulk power transmission system. Within each model region, IPM assumes that 

adequate transmission capacity is available to deliver any resources located in, or transferred 

to, the region. The IPM model projects available capacity given certain constraints such as 

reserve margins and transmission capability but does not constitute a detailed reliability 

analysis. For example, the IPM model does not examine frequency response. For more detail on 

IPM’s electric load modeling and power system operation, please see IPM documentation 

(http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html) and the TSD on Resource 

Adequacy and Reliability in the IPM Projections for the MATS Rule.

Total operational capacity is lower in the policy scenario, primarily as a result of 

additional coal projected to be uneconomic to maintain. Since most regions are projected to 

have excess capacity above their target reserve margins, most of these withdrawals from 

service are absorbed by a reduction in excess reserves. Operational capacity changes from the 

base case in 2015 are shown in Table 3-8.
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Table 3-8. Total Generation Capacity by 2015 (GW)

2010 Base Case MATS

Pulverized Coal 317 310 305

Natural Gas Combined Cycle 201 206 206

Other Oil/Gas 253 233 233

Non-Hydro Renewables 31 70 70

Hydro 99 99 99

Nuclear 102 104 105

Other 5 4 4

Total 1,009 1,026 1,021

Source: 2010 data from EPA’s NEEDS v.4.10_PTox. Projections from Integrated Planning Model run by EPA.

Note: “Non-Hydro Renewables” include biomass, geothermal, solar, and wind electric generation capacity. 2015 

capacity reflects plant closures planned to occur prior to 2015.

The policy case analyzed maintains resource adequacy in each region projected to 

decrease in coal capacity by using excess reserve capacity within the region, reversing base case

withdrawals of non-coal capacity, building new capacity, or by importing excess reserve 

capacity from other regions. Although any closure of a large generation facility will need to be 

studied to determine potential local reliability concerns, EPA analysis suggests that projected 

economic withdrawals from service under the final rule could have little to no overall impact on 

electric reliability. Not only are projected withdrawals under MATS limited in scope, but the 

existing state of the power sector is also characterized by substantial excess capacity. The 

weighted average reserve margin at the national level is projected to be approximately 25% in

the base case, while the North American Electric Reliability Corporation (NERC) recommends a 

margin of 15%. EPA projects that MATS would only reduce total operational capacity by less 

than one percent in 2015.

Moreover, coal units projected to withdraw as uneconomic are distributed throughout 

the power grid with limited effect at the regional level, such that any potential impacts should 

not adversely affect reserve margins and should be manageable through the normal industry 

processes. For example, in the RFC NERC reliability Region, containing coal-fired generating 

area in Pennsylvania, West Virginia and the Midwest, there is a decrease of less than 2% in the 

reserve margin in the policy case and a remaining overall reserve margin of over 20%.

Furthermore, subregions may share each other’s excess reserves to ensure adequate reserve 

margins within a larger reliability region. EPA’s IPM modeling accommodates such transfers of 

reserves within the assumed limits of reliability of the inter-regional bulk power system. For 
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these reasons, the projected closures of coal plants are not expected to raise broad reliability 

concerns.

3.7 Projected Capacity Additions

Due in part to a low growth rate anticipated for future electricity demand levels in the 

latest EIA forecast, EPA analysis indicates that there is sufficient excess capacity through 2015 

to compensate for capacity that is retired from service under MATS. In the short-term, most 

new capacity is projected as a mix of wind and natural gas in response to low fuel prices 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 in the 2015 timeframe (see Chapter 2 for more discussion on future 

electricity demand). 

Table 3-9. Total Generation Capacity by 2030 (GW)

2010 Base Case MATS Change

Pulverized Coal 317 308 304 -3.9

Natural Gas Combined Cycle 201 275 278 2.9

Other Oil/Gas 253 235 235 0.6

Non-Hydro Renewables 31 79 79 0.1

Hydro 99 99 99 0.0

Nuclear 102 103 103 0.3

Other 5 4 4 0.0

Total 1,009 1,103 1,102 -0.1

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

Source: 2010 data from EPA’s NEEDS v.4.10_PTox. Projections from Integrated Planning Model run by EPA.

3.8 Projected Coal Production for the Electric Power Sector

Coal production for electricity generation under MATS is expected to increase from 

2009 levels and decline modestly relative to the base case without the rule. The reductions in 

emissions from the power sector will be met through the installation and operation of pollution 

controls for HAP removal. Many available pollution controls achieve emissions removal rates of 

up to 99 percent (e.g., HCl removal by new scrubbers), which allows industry to rely more 

heavily on local bituminous coal in the eastern and central parts of the country that has higher 

contents of HCl and sulfur, and it is less expensive to transport than western subbituminous 

coal. Overall demand for coal is projected to be reduced as a result of MATS, with a slight 
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reduction in bituminous coal, and more of a reduction in subbituminous coal (see Tables 3-10 

and 3-11). The trend reflects the projected reduced demand for lower-sulfur coal under MATS, 

where nearly all units are operating with a post-combustion emissions control. In this case, 

because of the additional pollution controls, many of these units no longer find it economic to 

pay a transportation premium to purchase lower-sulfur subbituminous coals. Instead, EGUs are 

generally projected to shift consumption towards nearby bituminous coal, which can achieve 

low emissions when combined with post-combustion emissions controls. This explains the 

increase from the base case in coal supplied from the Interior region, which is located in 

relatively close proximity to many coal-fired generators subject to MATS. This continues a trend 

of increased Interior supply (due to abundant Illinois Basin reserves that are relatively 

inexpensive to mine) and decreased Central Appalachian supply which is forecasted to occur in 

the base case from historic levels. The decline in Appalachia is a result of an increase in the 

relative cost of Central Appalachian extraction due both to rising mining cost (e.g., in 2010 

major producers reported mining cost increases up to 15% with this trend continuing into 2011) 

and shrinking economically recoverable capacity. Growing international demand for 

Appalachian thermal coal is also contributing to its rising price. The increase in lignite use 

occurs at units blending subbituminous and lignite coals, and reflects a small shift in blended 

balance towards a greater use of lignite.

Table 3-10. 2015 Coal Production for the Electric Power Sector with the Base Case and MATS

(Million Tons)

Supply Area 2009 2015 Base 2015 MATS Change in 2015

Appalachia 246 184 172 -6%

Interior 129 216 236 9%

West 553 554 537 -3%

Waste Coal 14 14 13 -5%

Imports 30 30 0%

Total 942 998 989 -1%

Source: Production: U.S. Energy Information Administration (EIA), Coal Distribution — Annual (Final), web site 

http://www.eia.doe.gov/cneaf/coal/page/coaldistrib/a_distributions.html (posted February 18, 2011); Waste 

Coal: U.S. EIA, Monthly Energy Review, January 2011 Edition, Table 6.1 Coal Overview, web site 

http://www.eia.doe.gov/emeu/mer/coal.html (posted January 31, 2011). All projections from Integrated 

Planning Model run by EPA, 2011.
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Table 3-11. 2015 Power Sector Coal Use with the Base Case and the MATS, by Coal Rank 

(TBtu)

Coal Rank Base MATS Change

Bituminous 11,314 11,248 -0.6%

Subbituminous 7,736 7,554 -2%

Lignite 849 895 5%

Total 19,900 19,698 -1%

Source: Integrated Planning Model run by EPA, 2011.

Figure 3-8. Total Coal Production by Coal-Producing Region, 2007 (Million Short Tons)

Note: Regional totals do not include refuse recovery

Source: EIA Annual Coal Report, 2007

3.9 Projected Retail Electricity Prices

EPA’s analysis projects a near-term increase in the average retail electricity price of 3.1%

in 2015 falling to 2% by 2020 under the final rule in the contiguous U.S. The projected price 

impacts vary by region and are provided in Table 3-12 (see Figure 3-9 for regional 

classifications).

Regional retail electricity prices are projected to range from 1 to 6 percent higher with MATS in 

2015. The extent of regional retail electricity increases correlates with states that have 

considerable coal-fired generation in total generation capacity and that coal-fired generation is 

less well-controlled (such as in the ECAR and SPP regions). Retail electricity prices embody 

generation, transmission, and distribution costs. IPM modeling projects changes in regional 
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wholesale power prices, capacity payments, and actual costs of compliance in areas that are 

"cost of service" regions that are combined with EIA regional transmission and distribution 

costs to complete the retail price picture. 
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Table 3-12. Projected Contiguous U.S. and Regional Retail Electricity Prices with the Base 

Case and with the MATS (2007 cents/kWh)

Base Case MATS Percent Change

2015 2020 2030 2015 2020 2030 2015 2020 2030

ECAR 8.2 8.2 9.8 8.5 8.5 9.9 4.5% 2.8% 1.0%

ERCOT 8.9 8.8 11.3 9.2 8.8 11.3 3.3% 0.6% -0.2%

MAAC 9.5 10.4 12.7 9.8 10.4 12.7 2.8% 0.4% -0.2%

MAIN 8.1 8.4 9.7 8.3 8.6 9.7 2.8% 2.2% 0.2%

MAPP 8.0 7.9 8.5 8.5 8.3 8.8 5.3% 5.6% 3.4%

NY 13.8 13.4 16.6 14.1 13.5 16.6 2.2% 0.7% -0.1%

NE 12.3 11.8 13.8 12.6 11.9 13.8 2.0% 0.8% 0.0%

FRCC 10.2 9.7 11.0 10.4 9.8 11.0 2.2% 0.9% 0.4%

STV 7.9 7.8 8.4 8.2 8.0 8.6 3.1% 2.4% 1.6%

SPP 7.7 7.4 8.1 8.1 7.8 8.4 6.3% 6.1% 4.6%

PNW 7.1 6.8 7.6 7.3 7.0 7.6 2.7% 2.6% 1.1%

RM 9.2 9.5 11.0 9.4 9.7 11.1 2.3% 1.9% 1.1%

CALI 13.0 12.5 12.7 13.2 12.6 12.7 1.3% 0.7% 0.0%

Contiguous 

U.S. 

Average

9.0 9.0 10.2 9.3 9.2 10.3 3.1% 2.0% 0.9%

Source: EPA’s Retail Electricity Price Model, 2011.
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Figure 3-9. Retail Price Model Regions

3.10 Projected Fuel Price Impacts

The impacts of the final Rule on coal and natural gas prices before shipment are shown 

below in Tables 3-13 and 3-14. Overall, the national average coal price changes are related to 

changes in demand for a wide variety of coals based upon a number of parameters (e.g., 

chlorine or mercury content, heat content, proximity to the power plant, etc.), and this national 

average captures increases and decreases in coal demand and price at the regional level. 

Generally, total demand for coal decreases slightly under MATS, most notably subbituminous 

coal, which is by far the least expensive type of coal supplied to the power sector on an MMBtu 

basis. This is reflected in the projected average minemouth price of coal, which goes up by 

about 3 percent even though total demand for coal is reduced slightly (1 percent reduction). 

Notwithstanding the projected “mine-mouth” coal price changes, many units may in fact be 

realizing overall fuel cost savings by switching to more local coal supplies (which reduces 

transportation costs) after installing additional pollution control equipment. Gas price changes 

are directly related the projected increase in natural gas consumption under MATS. This 

increase in demand is met by producing additional natural gas at some increase in regional 

costs, resulting over time in a small price increase.
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Table 3-13. Average Minemouth and Delivered Coal Prices with the Base Case and with 

MATS (2007$/MMBtu)

2007

2015 2030

Base Case MATS

Percent 

Change 

from Base Base Case MATS

Percent 

Change 

from Base

Minemouth 1.27 1.35 1.39 2.8% 1.51 1.56 3.3%

Delivered 1.76 2.11 2.15 1.9% 2.29 2.33 1.7%

Source: Historical data from EIA AEO 2010 Reference Case Table 15 (Coal Supply, Distribution, and Prices); 

projections from the Integrated Planning Model run by EPA, 2011.

Table 3-14. 2015-2030 Weighted Average Henry Hub (spot) and Delivered Natural Gas Prices 

with the Base Case and with MATS (2007$/MMBtu)

Base Case MATS Percent Change from Base

Henry Hub 5.29 5.32 0.6%

Delivered - Electric Power 5.56 5.60 0.6%

Delivered - Residential 10.94 10.97 0.3%

Source: Projections from the Integrated Planning Model run by EPA (2011) adjusted to Henry Hub prices using 

historical data from EIA AEO 2011 reference case to derive residential prices.

IPM modeling of natural gas prices uses both short- and long-term price signals to 

balance supply of and demand in competitive markets for the fuel across the modeled time 

horizon. As such, it should be understood that the pattern of IPM natural gas price projections 

over time is not a forecast of natural gas prices incurred by end-use consumers at any particular 

point in time. The natural gas market in the United States has historically experienced 

significant price volatility from year to year, between seasons within a year, and even sees 

major price swings during short-lived weather events (such as cold snaps leading to short-run 

spikes in heating demand). These short-term price signals are fundamental for allowing the 

market to successfully align immediate supply and demand needs; however, end-use 

consumers are typically shielded from experiencing these rapid fluctuations in natural gas 

prices by retail rate regulation and by hedging through longer-term fuel supply contracts. IPM 

assumes these longer-term price arrangements take place “outside of the model” and on top of 

the “real-time” shorter-term price variation necessary to align supply and demand. Therefore, 

the model’s natural gas price projections should not be mistaken for traditionally experienced 

consumer price impacts related to natural gas, but a reflection of expected average price 

changes over the time period 2015 to 2030.
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For this analysis, in order to represent a natural gas price evolution that end-use 

consumers can anticipate under retail rate regulation and/or typical hedging behavior, EPA is 

displaying the weighted average of IPM’s natural gas price projections for the 2015-2030 time 

horizon (see Table 3-14). In that framework, consumer natural gas price impacts are anticipated 

to range from 0.3% to 0.6% based on consumer class in response to MATS.

3.11 Key Differences in EPA Model Runs for MATS Modeling

In this analysis, we use the Integrated Planning Model (IPM), which is a multiregional, 

dynamic, deterministic linear programming model of the U.S. electric power sector. 9The length 

of time required to conduct emissions and photochemical modeling precluded the use of IPM 

version 4.10_MATS. Thus the air quality modeling for MATS relied on EGU emission projections 

from an interim IPM platform that was subsequently updated during the rulemaking process for 

the base case and policy scenario summarized in this chapter. The 2015 base case EGU 

emissions projections of mercury, hydrogen chloride, SO2, and PM used in air quality modeling 

were obtained from an earlier version of IPM, 4.10_FTransport. IPM version 4.10_FTransport 

reflects all state rules and consent decrees adopted through December 2010. Units with SO2 or 

NOX advanced controls (e.g., scrubber, SCR) that were not required to run for compliance with 

Title IV, New Source Review (NSR), state settlements, or state-specific rules were allowed in 

IPM to decide on the basis of economic efficiency whether to operate those controls. Note that 

this base case includes CSAPR, which was finalized in July 2011. Further details on the EGU 

emissions inventory used for this proposal can be found in the IPM Documentation.

The results presented in this chapter, from IPM version 4.10_MATS, reflect updates 

made to the 4.10_FTransport base case. These revisions are fully documented in the IPM 4.10 

Supplemental Documentation for MATS and include: updated assumptions regarding the 

removal of HCl by alkaline fly ash in subbituminous and lignite coals; an update to the fuelbased mercury emission factor for petroleum coke, which was corrected based on reexamination of the 1999 ICR data; updated capital cost for new nuclear capacity and nuclear life 

extension costs; corrected variable operating and maintenance cost (VOM) for ACI retrofits; 

adjusted coal rank availability for some units, consistent with EIA From 923 (2008); updated 

state rules in Washington and Colorado; and numerous unit-level revisions based on comments 

received through the notice and comment process. Additionally, IPM v.4.10_MATS does not 

reflect mercury-specific state regulations (see section 1 above).

 

9

http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html
3-28

3.12 Projected Primary PM Emissions from Power Plants

IPM does not endogenously model primary PM emissions from power plants. These 

emissions are calculated as a function of IPM outputs, emission factors and control 

configuration. IPM-projected fuel use (heat input) is multiplied by PM emission factors (based 

in part on the presence of PM-relevant pollution control devices) to determine PM emissions.

Primary PM emissions are calculated by adding the filterable PM and condensable PM 

emissions. 

Filterable PM emissions for each unit are based on historical information regarding 

existing emissions controls and types of fuel burned and ash content of the fuel burned, as well 

as the projected emission controls (e.g., scrubbers and fabric filters).

Condensable PM emissions are based on plant type, sulfur content of the fuel, and 

SO2/HCl and PM control configurations. Although EPA’s analysis is based on the best available 

emission factors, these emission factors do not account for the potential changes in 

condensable PM emissions due to the installation and operation of SCRs. The formation of 

additional condensable PM (in the form of SO3 and H2SO4) in units with SCRs depends on a 

number of factors, including coal sulfur content, combustion conditions and characteristics of 

the catalyst used in the SCR, and is likely to vary widely from unit to unit. SCRs are generally 

designed and operated to minimize increases in condensable PM. This limitation means that 

IPM post-processing is potentially underestimating condensable PM emissions for units with 

SCRs. In contrast, it is possible that IPM post-processing overestimates condensable PM 

emissions in a case where the unit is combusting a low-sulfur coal in the presence of a scrubber.

EPA plans to continue improving and updating the PM emission factors and calculation 

methodologies. For a more complete description of the methodologies used to post-process 

PM emissions from IPM, see “IPM ORL File Generation Methodology” (March, 2011).

3.13 Illustrative Dry Sorbent Injection Sensitivity

Several commenters believe that EPA’s IPM modeling assumptions regarding the 

efficacy and cost of DSI are based on too little data and are too optimistic. Some commenters 

believe that in practice there will be a need for many more FGD scrubbers for MATS compliance 

than projected by EPA for effective acid gas control, and at a corresponding higher cost. EPA 

disagrees with these opinions for several reasons (see the response to comments document in 

the docket) and believes that EPA’s modeling assumptions regarding DSI cost and performance 

are reasonable.
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However, to examine the potential impacts of limited DSI availability, EPA analyzed a 

scenario that limited total DSI capacity to 35 GW in 2015. In this scenario, which reduces the 

capacity of DSI by 18 GW compared to the primary MATS scenario, an additional 14 GW of coal 

capacity chooses to install scrubbers, and an additional 1.3 GW of capacity is projected to 

withdraw from service. 

Limiting total DSI capacity to 35 GW results in a $1.2 billion (2007$) increase in 

annualized compliance costs in 2015. Additionally, SO2 is further reduced in 2015 by an 

additional 62,000 tons (a 4.7% increase in SO2 reductions and 4.5% increase in health benefits).

3.14 Additional Compliance Costs Analyzed for Covered Units

3.14.1 Compliance Cost for Oil-Fired Units.

As discussed in section 3.1, EPA used IPM to assess impacts of the MATS emission 

limitations for coal-fired EGUs but did not use IPM to assess the impacts for oil-fired units. IPM, 

with its power system and fuel cost assumptions, predicts many dual fuel units switch to 

natural gas and oil-fired units will not operate because IPM focuses on least cost operation of 

the power system. However, despite their apparent economic disadvantages, many of these 

units have run during many of the past five years (2006-2010). Therefore, EPA conducted a 

separate analysis to assess the impacts of the MATS emission limitations for oil-fired units.10

EPA limited this analysis to oil-fired units in the contiguous U.S. Although there are several oilfired units in states and territories outside the contiguous U.S., the final MATS emission 

limitations (shown in Table 3-2) for non-continental units will likely allow these units to 

continue firing residual fuel oil without additional air pollution controls.

For the base case, EPA categorized units by modeled fuels as listed in NEEDS 4.10 (EPA, 

December 2010) and assigned each unit the least-cost fuel among its available fuels. For units 

with natural gas curtailment provisions that might require the firing of residual fuel oil, EPA 

assigned a mixed fuel ratio based on each unit’s 2008-2010 weighted average natural gas-tofuel oil ratio. For the policy case, EPA assessed three compliance options: (1) switching to 

natural gas where available, (2) switching to distillate fuel oil, and (3) installing an electrostatic 

precipitator (ESP) capable of 90% particulate removal efficiency. These compliance options 

address particulate emissions only. However, there might be additional emission reductions 

that result from changes to oil-fired units’ generation due to changes in relative generating 

costs.

 

10 Additional details and methodology for the analysis are presented in appendix 3A.
3-30

Between the base case and policy case, 12 units convert from residual fuel oil to 

distillate fuel oil at a cost of approximately $12 million annually (2007$) to meet the MATS 

emission limitations for oil-fired units. An additional 11 units, eight of which are subject to 

natural gas curtailment, that do not have existing ESP particulate pollution controls install an 

ESP at a cost of approximately $44 million annually (2007$) to achieve the MATS emission 

limitations for oil-fired units (see Table 3-15). EPA believes the emission impacts from these 

potential actions will be relatively small when compared to the full impacts of the MATS 

emission limitations because particulate emissions from oil-fired units are a small fraction of 

the total particulate emissions from EGUs.

Table 3-15. Cost Impacts of Compliance Actions for Oil-Fired Units

Compliance option Number of units affected Capacity of units affected Annual cost (2007$)

Switch to distillate fuel oil 12 2,675 MW $12 million

Install ESP for residual fuel oil 11 4,015 MW $44 million

Total 23 6,690 MW $56 million

3.14.2 Monitoring, Reporting and Record-keeping Costs 

The annual monitoring, reporting, and record-keeping burden for this collection (averaged over 

the first 3 years after the effective date of the standards) is estimated to be $158 million. This 

includes 698,907 labor hours per year at a total labor cost of $49 million per year, and total 

non-labor capital costs of $108 million per year. This estimate includes initial and annual 

performance tests, semiannual excess emission reports, developing a monitoring plan, 

notifications, and record-keeping. Initial capital expenses to purchase monitoring equipment 

for affected units are estimated at a cost of $231 million. This includes 504,629 labor hours at a 

total labor cost of $35 million for planning, selection, purchase, installation, configuration, and 

certification of the new systems and total non-labor capital costs of $196 million. All burden 

estimates are in 2007 dollars and represent the most cost effective monitoring approach for 

affected facilities. See Section 7.3, Paperwork Reduction Act.

3.14.3 Total Costs Projected for Covered Units under MATS

EPA used IPM to analyze the compliance cost, and economic and energy impacts of the MATS 

rule. IPM estimated the costs for coal-fired electric utility steam generating units that burn coal, 

coal refuse, or solid-oil derived fuel. EPA did not use IPM, however, estimate compliance costs 

for most oil/gas steam boilers because IPM projection shows least-cost dispatch in an 
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environment where oil/gas-fired units are primarily selecting natural gas on an economic basis. 

In the separate analysis summarized above, EPA estimates compliance costs for oil-fired EGUs 

in a scenario in which these units continue to burn oil as historically observed and thus take 

compliance measures to remain on oil. This is a reasonable estimate of compliance costs for 

these units, but does not represent a re-balancing of electricity dispatch where these units 

combust oil rather than natural gas. Therefore, the summation of IPM-projected compliance 

costs for least-cost dispatch with the oil-fired compliance costs and the monitoring, reporting, 

and record-keeping costs is a reasonable approximation of total compliance costs, but does not 

represent projected compliance costs under an economically efficient dispatch (see Table 3-16).

Table 3-16. Total Costs Projected for Covered Units under MATS, 2015 (billions of 2007$)

2015

IPM Projection $9.4

Monitoring/Reporting/Record-keeping $0.158

Oil-Fired Fleet $0.056

Total $9.6

3.15 Limitations of Analysis

EPA’s modeling is based on expert judgment of various input assumptions for variables 

whose outcomes are in fact uncertain. Assumptions for future fuel supplies and electricity 

demand growth deserve particular attention because of the importance of these two key model 

inputs to the power sector. As a general matter, the Agency reviews the best available 

information from engineering studies of air pollution controls to support a reasonable modeling 

framework for analyzing the cost, emission changes, and other impacts of regulatory actions.

The IPM-projected annualized cost estimates of private compliance costs provided in 

this analysis are meant to show the increase in production (generating) costs to the power 

sector in response to the final rule. To estimate these annualized costs, EPA uses a conventional 

and widely-accepted approach that applies a capital recovery factor (CRF) multiplier to capital 

investments and adds that to the annual incremental operating expenses. The CRF is derived 

from estimates of the cost of capital (private discount rate), the amount of insurance coverage 

required, local property taxes, and the life of capital. The private compliance costs presented 

earlier are EPA’s best estimate of the direct private compliance costs of MATS.

The annualized cost of the final rule, as quantified here, is EPA’s best assessment of the 

cost of implementing the rule. These costs are generated from rigorous economic modeling of 
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changes in the power sector due to implementation of MATS. This type of analysis using IPM 

has undergone peer review, and federal courts have upheld regulations covering the power 

sector that have relied on IPM’s cost analysis.

Cost estimates for MATS are based on results from ICF’s Integrated Planning Model. The 

model minimizes the costs of producing electricity (including abatement costs) while meeting 

load demand and other constraints (full documentation for IPM can be found at 

http://www.epa.gov/airmarkets/progsregs/epa-ipm and in the IPM 4.10 Supplemental 

Documentation for MATS. IPM assumes “perfect foresight” of market conditions over the time 

horizon modeled; to the extent that utilities and/or energy regulators misjudge future 

conditions affecting the economics of pollution control, costs may be understated as well.

In the policy case modeling, EPA exogenously determines that a subset of covered units 

might require a retrofit fabric filter (also known as a baghouse) retrofit, or might need to 

upgrade existing ESP control in order to meet the PM standard. EPA’s methodology for 

assigning these controls to EGUs in policy case modeling is based on historic PM emission rates 

and reported control efficiencies, and is explained in the IPM 4.10 Supplemental 

Documentation for MATS.

Additionally, this modeling analysis does not take into account the potential for 

advancements in the capabilities of pollution control technologies as well as reductions in their 

costs over time. In addition, EPA modeling cannot anticipate in advance the full spectrum of 

compliance strategies that the power sector may innovate to achieve the required emission 

reductions under MATS, which would potentially reduce overall compliance costs. Where 

possible, EPA designs regulations to assure environmental performance while preserving 

flexibility for affected sources to design their own solutions for compliance. Industry will 

employ an array of responses, some of which regulators may not fully anticipate and will 

generally lead to lower costs associated with the rule than modeled in this analysis. For 

example, unit operators may find opportunities to improve or upgrade existing pollution 

control equipment without requiring as many new retrofit devices (i.e., meeting the PM 

standard with an existing ESP without requiring installation of a new fabric filter).

With that in mind, MATS establishes emission rates on key HAPs, and although this 

analysis projects a specific set of technologies and behaviors as EPA’s judgment of least-cost 

compliance, the power sector is free to adopt alternative technologies and behaviors to achieve 

the same environmental outcome EPA has deemed in the public interest as laid out in the Clean 

Air Act. Such regulation serves to promote innovation and the development of new and 
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cheaper technologies. As an example, cost estimates of the Acid Rain SO2 trading program by 

Resources for the Future (RFF) and MIT’s Center for Energy and Environmental Policy Research 

(CEEPR) have been as much as 83 percent lower than originally projected by the EPA (see 

Carlson et al., 2000; Ellerman, 2003). It is important to note that the original analysis for the 

Acid Rain Program done by EPA also relied on an optimization model like IPM. Ex ante, EPA cost 

estimates of roughly $2.7 to $6.2 billion11 in 1989 were an overestimate of the costs of the 

program in part because of the limitation of economic modeling to perfectly anticipate

technological improvement of pollution controls and economic improvement of other 

compliance options such as fuel switching. Ex post estimates of the annual cost of the Acid Rain 

SO2 trading program range from $1.0 to $1.4 billion.

In recognition of this historic pattern of overestimated regulatory cost, EPA’s mobile 

source program uses adjusted engineering cost estimates of pollution control equipment and 

installation costs.12 To date, and including this analysis, EPA has not incorporated a similar 

approach into IPM modeling of EGU compliance with environmental constraints. As a result, 

this analysis may overstate costs where such cost savings from as-yet untapped improvements 

to pollution control technologies may occur in the future. Considering the broad and complex 

suite of generating technologies, fuels, and pollution control strategies available to the power 

sector, as well as the fundamental role of operating cost in electricity dispatch, it is not possible 

to apply a single technology-improving “discount” transformation to the cost projections in this 

analysis. The Agency will consider additional methodologies in the future which may inform the

amount by which projected compliance costs could be overstated regarding further 

technological development in analyses of power sector regulations.

As configured in this application, IPM does not take into account demand response (i.e., 

consumer reaction to electricity prices). The increased retail electricity prices shown in 

Table 3-13 would prompt end users to increase investment in energy efficiency and/or curtail 

(to some extent) their use of electricity and encourage them to use substitutes.13 Those

responses would lessen the demand for electricity, resulting in electricity price increases slightly 

lower than IPM predicts, which would also reduce generation and emissions. Demand response

would yield certain unquantified cost savings from requiring less electricity to meet the

quantity demanded. To some degree, these saved resource costs will offset the additional costs 

 

11

 2010 Phase II cost estimate in $1995.

12

 See regulatory impact analysis for the Tier 2 Regulations for passenger vehicles (1999) and Heavy-Duty Diesel 

Vehicle Rules (2000).

13 The degree of substitution/curtailment depends on the costs and performance of the goods that substitute for 

more energy consuming goods, which is reflected in the demand elasticity.
3-34

of pollution controls and fuel switching that EPA anticipates from the final rule, although there 

could be some increase in social cost resulting from any decrease in electricity consumption.

Although the reduction in electricity use is likely to be small, the cost savings from such a large 

industry14 are not insignificant. EIA analysis examining multi-pollutant legislation in 2003 

indicated that the annualized costs of MATS may be overstated substantially by not considering 

demand response, depending on the magnitude and coverage of the price increases.15

EPA’s IPM modeling of MATS reflects the Agency’s authority to allow facility-level 

compliance with the HAP emission standards rather than require each affected unit at a given 

facility to meet the standards separately. This flexibility would offer important cost savings to 

facility owners in situations where a subset of affected units at a given facility could be 

controlled more cost-effectively such that their “overperformance” would compensate for any 

“underperformance” of the rest of the affected units. EPA’s modeling in this analysis required 

the average emission rate across all affected units at a given facility to meet the standard. This 

averaging flexibility has the potential to offer further cost savings beyond this analysis if 

particular units find ways to achieve superior pollution control beyond EPA’s assumptions of 

retrofit technology performance at the modeled costs (which could then reduce the need to 

control other units at the same facility).

Additionally, EPA has chosen to express most of the control requirements here as 

engineering performance standards (e.g., lbs/MMBtu of heat input), which provide power plant 

operators goals to meet as they see fit in choosing coals with various pollutant concentrations 

and pollutant control technologies that they adopt to meet the requirements. Historically, such 

an approach encourages industry to engineer cheaper solutions over time to achieve the 

pollution controls requirements.

EPA’s IPM modeling is based on retrofit technology cost assumptions which reflect the 

best available information on current and foreseeable market conditions for pollution control 

deployment. In the current economic environment, EPA does not anticipate (and thus this 

analysis does not reflect) significant near-term price increases in retrofit pollution control 

supply chains in response to MATS. To the extent that such conditions may develop during the 

 

14 Investor-owned utilities alone accounted for nearly $300 billion in revenue in 2008 (EIA).

15 See “Analysis of S. 485, the Clear Skies Act of 2003, and S. 843, the Clean Air Planning Act of 2003.” Energy 

Information Administration. September, 2003. EIA modeling indicated that the Clear Skies Act of 2003 (a 

nationwide cap and trade program for SO2, NOX, and mercury), demand response could lower present value costs 

by as much as 47% below what it would have been without an emission constraint similar to the Transport Rule.
3-35

sector’s installation of pollution control technologies under the final rule, this analysis may 

understate the cost of compliance.

3.16 Significant Energy Impact

MATS would have a significant impact according to E.O. 13211: Actions that Significantly 

Affect Energy Supply, Distribution, or Use. Under the provisions of this rule, EPA projects that 

approximately 4.7 GW of coal-fired generation (less than 2 percent of all coal-fired capacity and 

0.5% of total generation capacity in 2015) may be removed from operation by 2015. These 

units are predominantly smaller and less frequently-used generating units dispersed 

throughout the area affected by the rule. If current forecasts of either natural gas prices or 

electricity demand were revised in the future to be higher, that would create a greater 

incentive to keep these units operational.

EPA also projects fuel price increases resulting from MATS. Average retail electricity

price are shown to increase in the contiguous U.S. by 3.1 percent in 2015. This is generally less 

of an increase than often occurs with fluctuating fuel prices and other market factors. Related 

to this, the average delivered coal price increases by less than 2 percent in 2015 as a result of 

shifts within and across coal types. As discussed above in section 8.10, EPA also projects that 

electric power sector-delivered natural gas prices will increase by about 0.6% percent over the 

2015-2030 timeframe and that natural gas use for electricity generation will increase by less 

than 200 billion cubic feet (BCF) in 2015. These impacts are well within the range of price 

variability that is regularly experienced in natural gas markets. Finally, the EPA projects coal

production for use by the power sector, a large component of total coal production, will 

decrease by 10 million tons in 2015 from base case levels, which is about 1 percent of total coal 

produced for the electric power sector in that year. The EPA does not believe that this rule will 

have any other impacts (e.g., on oil markets) that exceed the significance criteria.

3.17 References

EIA Annual Coal Report 2008. DOE/EIA-0584 (2008). Available at: 

http://www.eia.doe.gov/cneaf/coal/page/acr/acr_sum.html

EIA Annual Energy Outlook 2003. DOE/EIA-0383 (2003). Available at: 

http://www.eia.doe.gov/oiaf/archive/aeo03/index.html

EIA Electric Power Annual 2008. DOE/EIA-0348 (2008). Available at: 

http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.htm

EIA Electric Power Monthly March 2010 with Data for December 2009. DOE/EIA-0226 

(2010/03). Available at: http://www.eia.doe.gov/cneaf/electricity/epm/epm_sum.html
3-36

Freme, Fred. 2009. U.S. Coal Supply and Demand: 2008 Review. EIA. Available at: 

http://www.eia.doe.gov/cneaf/coal/page/special/tbl1.html

Harrington, W., R.D. Morgenstern, and P. Nelson. 2000. “On the Accuracy of Regulatory Cost 

Estimates.” Journal of Policy Analysis and Management 19(2):297-322.

Manson, Nelson, and Neumann. 2002. “Assessing the Impact of Progress and Learning Curves 

on Clean Air Act Compliance Costs.” Industrial Economics Incorporated.
3A-1

APPENDIX 3A

COMPLIANCE COSTS FOR OIL-FIRED ELECTRIC GENERATING UNITS

This appendix highlights the supplemental oil-fired electric generating unit (EGU) 

compliance cost analysis performed for the Mercury and Air Toxics Standards (MATS). EPA used 

the Integrated Planning Model (IPM) to assess the cost, economic, and energy impacts of the 

MATS emission limitations on coal-fired EGUs in the contiguous U.S., but did not use IPM to 

assess the compliance costs for oil-fired EGUs because IPM focuses on the least cost operation 

of the power system and, therefore, predicts the oil-fired units will not operate. These oil-fired 

units, however, do not operate on a purely economic basis. Some oil-fired units may operate as 

“must run”, “black start”, or “spinning reserve”. In addition, some dual fuel fired units which 

IPM predicts will fire natural gas may be required to fire fuel oil when subject to mandatory 

curtailment of natural gas supplies. 

When practicable, this supplemental analysis for oil-fired EGUs was based on the data 

and assumptions used in IPM. Documentation for IPM can be found at 

http://www.epa.gov/airmarkets/progsregs/epa-ipm.

3A.1 Methodology and Assumptions

3A.1.1 Base Case

EPA developed the base case for oil-fired units listed in the National Electric Energy Data 

System (hereafter, NEEDS) (EPA, 2010a). NEEDS lists 302 “oil/gas steam” units greater than 25 

MW for which distillate fuel oil and/or residual fuel oil are among the modeled fuels (see Table 

3A-1).16 For each of these units, EPA projected 2015 heat input and apportioned the heat input 

among the NEEDS modeled fuels. EPA used each unit’s average annual heat input from 2006-

201017 as a proxy for 2015 heat input. For units not subject to mandatory natural gas 

curtailment, EPA assumed the unit fired the least cost fuel available based on regional IPM fuel 

cost projections for 2015. For units that may be required to fire fuel oil due to mandatory 

natural gas curtailment, EPA apportioned the heat input based on the unit’s weighted average 

natural gas and fuel oil apportionment from 2008-2010.18 EPA used the three most recent years 

because, as a percentage of total heat input, fuel oil heat input has fallen steadily since 2007 

(see Figure 3A-1). With increased availability of natural gas in the New York region from new 

 

16 One unit, Charles Poletti unit 001 (ORIS 2491), was removed because the unit retired in 2010 (EPA, 2011). 

17 Designated representatives for each of the oil-fired units included in this analysis certify and report hourly heat 

input and emission data to EPA under 40CFR Part 75.

18 The units subject to mandatory natural gas curtailment report fuel-apportioned heat input to EPA under 40CFR 

Part 75 (Appendix D). EPA categorized “diesel” as distillate fuel oil and “oil” and “other oil” as residual fuel oil. 
3A-2

gas supplies and new gas pipelines (FERC, 2011), it is likely this trend will continue even in the 

absence of the MATS. Therefore, using a longer historical period might significantly 

overestimate the proportion of heat input derived from fuel oil for these units.

Table 3A-1. Oil-fired EGUs by Fuel Type

NEEDS modeled fuel Number of units Capacity (MW)

Distillate fuel oil 10 814

Distillate fuel oil, natural gas 99 19,822

Residual fuel oil 17 5,867

Residual fuel oil, distillate fuel oil 15 1,187

Residual fuel oil, natural gas 149 39,913

Residual fuel oil, distillate fuel oil, natural gas 12 3,706

Source: EPA. 2010. National Electricity Energy Data System (NEEDS 4.10). Available at: 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/toxics.html.

Figure 3A-1. 2006-2010 Heat Input Apportioned by Fuel for Oil-Fired Units Subject to 

Mandatory Natural Gas Curtailment

Source/Notes: EPA. 2011. Data and Maps. Available at: http://epa.gov/camddataandmaps/

Power companies are responding to fuel prices, natural gas supplies, and other market 

factors by replacing some oil-gas steam units with new combined cycle plants (Neville, J. 2011). 

EPA did not, however, factor in the effect of expanded availability of natural gas on the 

Oil-fired heat 

input (% of total 

heat input)

0%

5%

10%

15%

20%

25%

30%

35%

0

50

100

150

200

250

2006 2007 2008 2009 2010

Trillion Btu

Diesel

Oil

Gas
3A-3

utilization of these oil-fired units. As a result, this analysis likely overestimates the impact of the 

MATS emission limitations on oil-fired units.

In the base case, natural gas is the least cost fuel for the majority of units (see Table 3A2). However, 41 units are expected to continue burning some amount of residual fuel oil 

because the units are subject to mandatory natural gas curtailment or may not have access to 

natural gas supplies.19 Of these 41 units, 14 have existing electrostatic precipitator (ESP) 

particulate pollution controls.

Table 3A-2. Least Cost NEEDS Modeled Fuels for Oil-fired EGUs

NEEDS modeled fuel Number of units Capacity (MW)

Distillate fuel oil 19 1,228

Residual fuel oil 23 6,640

Natural gas 242 57,232

Natural gas with mandatory curtailment 18 6,208

3A.1.2 Policy Case

For the policy case, EPA considered three actions to comply with the MATS emission 

limitations: (1) switching to natural gas where available, (2) switching to distillate fuel oil, and 

(3) ESP particulate pollution control capable of 90% particulate removal efficiency. EPA 

modeled the cost of actions 2 and 3 for each unit in the base case. EPA did not model the cost 

of converting to natural gas because, for units with natural gas as a NEEDS modeled fuel, it was 

the least cost fuel and therefore the base case fuel for the unit. The cost of switching a unit’s 

heat input to distillate fuel oil was based on the cost of converting operations, including tank, 

line, and pump cleaning and burner atomizer assembly replacement, and the unit’s 2015 

projected heat input from residual fuel oil multiplied by the cost difference between residual 

fuel oil and distillate fuel oil in the region where the unit is located. Conversion costs were 

annualized using the methodology described in the IPM documentation (EPA, 2010b).

The cost of installing a flat plate-type ESP on oil-fired model units of various sizes was 

calculated using the methodology outlined in EPA’s Cost Manual (EPA, 2002) and adjusted to 

2010 values using the Chemical Engineering Plant Cost Index (CEPCI). EPA developed non-linear 

 

19 To ensure the analysis was not likely to underestimate compliance costs, EPA assumed units that do not include 

natural gas as a NEEDS modeled fuel do not have access to a natural gas pipeline. The cost of obtaining pipeline 

access for these units was assumed to be uneconomical and was not modeled in the analysis.
3A-4

regression power functions similar to those used for costing air pollution controls in IPM. The 

cost functions are shown in equations (3A.1)-(3A.3).

Capital costs = 243,494.4 X (MW capacity)0.7800 (3A.1)

Annual fixed costs = 13,883.4 X (MW capacity)0.7294 (3A.2)

Annual variable costs = 8,108.6 X (MWh generation)0.8632 (3A.3)

Capital costs were annualized using the capital cost recovery factor used in the IPM 

documentation (EPA, 2010b). Annual variable costs were calculated using the predicted 2015 

generation from residual fuel oil based on the unit’s base case 2015 residual fuel oil heat input 

and the unit’s heat rate listed in NEEDS (EPA, 2010a).

3A.1.3 Cost Sensitivities Related to Mandatory Natural Gas Curtailment

There are 18 dual fuel fired units (i.e., units capable of firing both gas and oil) that are 

subject to mandatory natural gas curtailment. Of these units, six have existing ESP particulate 

pollution controls installed. For the remaining 12 units, nine fired natural gas for more than 90 

percent of their total heat input (see Table 3A-3). Because the MATS emission limits do not 

apply to units that fire coal or oil for less than 10 percent of total heat input averaged over 

three years or 15 percent in a single year, EPA analyzed historical oil-fired heat input between 

2006 and 2010 at these units and found that four dual fuel fired units subject to mandatory 

natural gas curtailment did not exceed 15 percent in any single year and averaged less than 10 

percent across all three year periods between 2006 and 2010. EPA did not include the cost of 

control on these units in the summary results. If these four units were to install ESPs, however, 

the annual compliance cost of the MATS emission limits would increase $13 million (2007$).

As noted in 3A.1.1, natural gas supplies to the region are increasing and operating data 

for dual fuel fired units subject to mandatory natural gas curtailment indicate that their 

proportion of heat input from residual oil is declining. There are four units in addition to those 

described in the paragraph above that exceeded 15 percent oil-fired heat input in 2006 and/or 

2007, but between 2008 and 2010 did not exceed 15 percent oil-fired heat input in a single year 

and averaged below 10 percent across all three years. These units were assigned ESP 

particulate pollution controls in this analysis. However, if these four dual fuel fired units do not 

install ESPs, the annual compliance cost of the MATS emission limits would decline $16 million 

(2007$). 
3A-5

Table 3A-3. Percentage of Total Heat Input Derived from Oil for Oil-Fired Units Subject to 

Mandatory Natural Gas Curtailment (2008-2010)

Percentage Number of units

< 1.0% 4

1.0% to 4.9% 1

5.0% to 9.9% 4

10.0% to 15.0% 3

3A.2 Results

For the purpose of estimating the impacts of the MATS emission limitations for oil-fired 

units, EPA had to make assumptions about the compliance actions oil-fired units will take. Table 

3A-4 lists those assumptions based on differences between the base and policy cases. EPA 

assumed that the least cost compliance option for 12 residual fuel oil-fired units would be 

converting to distillate fuel oil at an annual cost of approximately $12 million (2007$). An 

additional 11 units would likely continue to burn residual fuel oil following the installation of an 

ESP at a cost of approximately $44 million annually (2007$). 
3A-6

Table 3A-4. Costs to Achieve the MATS Emission Limitations for Oil-Fired Units

Unit Compliance action Annual cost (2007$)

Cleary Flood, Unit 8 Distillate fuel oil $ 308,000

Jefferies, Unit 1 Distillate fuel oil $ 642,000

Jefferies, Unit 2 Distillate fuel oil $ 673,000

McManus, Unit 1 Distillate fuel oil $ 391,000

McManus, Unit 2 Distillate fuel oil $ 512,000

Montville Station, Unit 6 Distillate fuel oil $ 3,968,000

Possum Point, Unit 5 Distillate fuel oil $ 119,000

Schuylkill Generating Station, Unit 1 Distillate fuel oil $ 2,113,000

Vienna Operations, Unit 8 Distillate fuel oil $ 1,741,000

William F Wyman, Unit 1 Distillate fuel oil $ 783,000

William F Wyman, Unit 2 Distillate fuel oil $ 646,000

Yorktown, Unit 3 Distillate fuel oil $ 119,000

Astoria Generating Station, Unit 30 ESP $ 4,214,000

Astoria Generating Station, Unit 40 ESP $ 4,132,000

Astoria Generating Station, Unit 50 ESP $ 4,202,000

B L England, Unit 3 ESP $ 2,155,000

East River, Unit 60 ESP $ 1,844,000

East River, Unit 70 ESP $ 2,336,000

Herbert A Wagner, Unit 4 ESP $ 4,352,000

Middletown, Unit 4 ESP $ 4,391,000

Ravenswood, Unit 10 ESP $ 3,904,000

Ravenswood, Unit 20 ESP $ 3,898,000

Ravenswood, Unit 30 ESP $ 8,322,000
3A-7

3A.3 References

EPA. 2002. EPA Air Pollution Control Cost Manual. Sixth Edition. EPA/452/B-02-001. Available 

at: http://www.epa.gov/ttn/catc/dir1/c_allchs.pdf

EPA. 2010a. National Electric Energy Data System (NEEDS 4.10). Available at: 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/toxics.html

EPA. 2010b. Documentation for EPA Base Case v. 4.10. Chapter 8: Financial Assumptions. 

Available at: http://www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Chapter8.pdf

EPA. 2011. Data and Maps. Available at: http://epa.gov/camddataandmaps/

FERC. 2011. Major Pipeline Projects Pending (Onshore). Available at: 

http://www.ferc.gov/industries/gas/indus-act/pipelines/pending-projects.asp

Neville, J. 2011. “Top Plant: Astoria II Combined Cycle Plant, Queens, New York,” Power 

Magazine. September.