Rulemaking for Hazardous Air Pollutants

from Coal- and Oil-Fired Electric Utility

Steam Generating Units

SER Outreach Meeting

December 2, 2010

POC: Mary Johnson
Agenda

► Background – EPA’s Regulatory Agenda

► Project History

► Section 112 Overview

► Constraints on Rulemaking

► Affected Facilities

► Data

► Rulemaking Options Under Consideration

► Potential Control Technologies and Estimated Costs

► Applicable Small Entity Definitions

► Small Entities Potentially Subject to Regulation

► Comments/Questions

► Appendix

► Background and Legal History Detail

► List of Potentially Affected Small Entities

► Questions for SERs

2
EPA Regulations Affecting the 

Power Sector 

► Tailoring Rule

► Beginning in 2011, power plant projects that will increase greenhouse gas (GHG) emissions 

substantially will require an air permit

► Finalized in May 2010

► Transport Rule (Clean Air Interstate Rule (CAIR) Remand Response)

► Will reduce SO2 and NOX emissions from existing power plants in 31 states/Washington DC

► Proposed in July 2010; expected to be finalized in late Spring 2011

► New Source Performance Standards (NSPS) for coal- and oil-fired electric utility 

steam generating units (EGUs)

► Will regulate SO2, NOX, and PM emissions from new EGUs

► Proposal anticipated in March 2011; expected to be finalized in November 2011

► Effluent Guidelines for steam electric power generating (wastewater, ash handling, 

wastewater treatment, surface impoundment and landfill operations, etc.)

► Consent decree requires proposal in July 2012; final action in January 2014

► Solid waste regulations for EGU coal ash (coal combustion residuals)

► Proposed in June 2010

► National Emission Standards for Hazardous Air Pollutants (NESHAP) for coal- and 

oil-fired EGUs (Utility NESHAP)

► Will regulate hazardous air pollutant (HAP) emissions from new/existing EGUs

3
Project History

► In December 2000, EPA determined that it was “appropriate and 

necessary” to regulate emissions of hazardous air pollutants (HAP) 

from coal- and oil-fired electric utility steam generating units (EGUs) 

and added such units to the CAA section 112(c) list of sources to be 

regulated under CAA section 112.

► In March 2005, EPA found it was neither “appropriate nor necessary” 

to regulate HAP emissions from EGUs and removed those units from 

the CAA section 112(c) source category list.

► In May 2005, EPA issued the Clean Air Mercury Rule (CAMR), which 

regulated mercury from EGUs through a cap and trade program under 

CAA section 111.

► In February 2008, the Court vacated EPA’s action that removed EGUs 

from the section 112(c) source category list and vacated CAMR.

4
Effect of Vacatur

► Coal- and oil-fired EGUs remain a listed source category for which 

EPA must issue emission standards under CAA section 112(d).

► EPA will address all HAP that are emitted from coal- and oil-fired 

EGUs – not just mercury.

► EPA is operating under a Consent Decree negotiated with litigants

► No later than March 16, 2011, EPA shall sign a notice of proposed 

rulemaking

► No later than November 16, 2011, EPA shall sign a notice of final 

rulemaking

► Additional detail regarding background and legal history can be 

found in the appendix (pages A-1 through A-3).

5
Definition of EGU

► The “electric utility steam generating unit” source category 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.

► Section 112(a)(8) defines an “electric utility steam generating unit” 

as:

► 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 ann 

electric utility steam generating unit.

6
Overview of Section 112

► Section 112 of CAA mandates that EPA develop standards for 

hazardous air pollutants (HAP) for both major and area sources 

listed under section 112(c).

► The section 112 definition of EGU does not distinguish between area and 

major sources.

► Major sources of HAP are those that have the potential to emit 10 tons 

per year (tpy) or more of any one HAP or 25 tpy or more of any 

combination of HAP.

► Section 112(d)(2) states that major source standards must be based 

on the maximum achievable control technology (MACT).

► Section 112(d)(3) sets minimum stringency criteria (MACT Floor) –

costs may not be considered

► For existing sources:

► “The average emission limitation achieved by the best performing 12 percent of 

existing sources..”

► For new sources, the MACT floor is:

► “The emission control achieved in practice by the best controlled similar source

7
Overview of Section 112 (cont.)

► EPA may regulate “beyond the floor” where justified – costs and 

other issues must be considered

► MACT may differ for new and existing sources.

► Section 112(d)(1) provides EPA with authority to distinguish among 

classes, types, and sizes of sources.

► Section 112(d)(4) provides EPA with discretionary authority to 

establish health-based emission standards for HAP for which a 

health threshold has been established.

► Section 112(h) allows the use of work practice standards instead of 

emission standards if enforcement of an emission standard is “not 

feasible”, as that term is defined in that section.

8
Some Legal Constraints on Section 

112 Rulemakings

► Emission standards must be established for EGUs that are located 

at major sources and at area sources.

► Voluntary or incentive-based approaches are not allowed.

► Emission standards must address all HAP emitted from EGUs.

► Standards must set technology-based limits

► Viability of health-based emission standards and work practice standards 

will be explored.

► Method for determining the minimum level of emissions control (i.e., 

MACT floor) must be followed.

► Only units in the MACT floor may be used in determining variability 

unless a demonstrated relationship between the variability of 

sources outside the floor and the variability of sources within the 

floor can be shown.

► Regulatory options more stringent than the MACT floor must be 

considered. 

9
Affected Facilities

Coal, 48%

Oil, 1%

Natural Gas, 21%

Non Hydro Renewables, 3%

Hydro, 6%

Nuclear, 20% ► Approximately 1,350 EGUs at 525 facilities Other, 1% ► Approximately 1,200 coal-fired boilers at 

approximately 450 facilities in 44 States and 

Puerto Rico ► Coal-fired EGUs include 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 (e.g., petroleum coke, tire-

derived fuels). ► Bituminous coal ~ 50% of coal generation ► Subbituminous ~45% of coal generation ► Lignite ~ 5% of coal generation

► Many units are “base-load” with generally high 

capacity factors. ► Capacity factor is the ratio of average electricity 

production to rated capability.

► Base-load units are large units used to meet 

the electricity demand that is relatively 

constant.

► Approximately 48 percent of nationwide net 

generation

10
Affected Facilities (cont.)

► Approximately 150 oil-fired boilers at approximately

75 facilities, mostly in Northeast, Midwest, Florida, Hawaii, Guam, 

and Puerto Rico

► Many units are peaking units with low capacity factor utilization over the 

past 3 – 5 years.

► Peaking units are used to meet the demand for electricity during peak 

periods of the day, and run for shorter periods of time.

► Many co-fire with natural gas or use natural gas preferentially but must 

have oil capability for use during periods of natural gas curtailments to 

industry.

► Approximately 1 percent of nationwide net generation

► Industry includes investor-owned, publicly-owned, and rural 

cooperatives.

► Natural gas was not listed in the December 2000 regulatory 

determination.

► Approximately 21 percent of nationwide net generation

11
Coal Steam Units >25 MW

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Location of Coal Steam EGU units ≥ 25 MW Dataset: NEEDS4.0_Draft_03_17_09v3toEPA

12
Data Needs

► Have considerable data from 1999 for mercury from coal-fired units; limited 

data for all other HAP and for oil-fired units

► EPA must address all HAP emitted from EGUs so data on the remaining HAP 

emitted is required to establish standards.

► There have been changes in emissions control equipment since 2005 that result 

from implementation of CAIR and State-based mercury regulations.

► Completing a major information collection request (ICR) to obtain the 

necessary data from coal- and oil-fired units

► 1,332 units to provide updated facility information on boiler, fuels, controls, etc. 

and all available data from past 5 years

► Requires emission testing of ~800 units

► Approximately 95% of data collection is complete; analyses are ongoing

► “Air Toxics Standards for Utilities” web page can be found at: 

http://www.epa.gov/ttn/atw/utility/utilitypg.html

► Data files of emissions data (Microsoft Access format)

► Extracted data worksheets (Microsoft Excel format) 

► Data necessary for development of legally supportable regulation

► Need sufficient representative data for MACT floor determinations

► Need data on variability 

► Need data on range of fuels

► Need data to demonstrate that any surrogate standards are reasonable

13
Utility MACT ICR

► Testing requirements (some units will test more than one HAP group)

► 170 coal-fired units for acid gas HAP

► e.g., hydrogen chloride (HCl), hydrogen fluoride (HF), hydrogen cyanide (HCN)

► Selected as being among the top performing units

► 170 coal-fired units for non-dioxin/furan organic HAP

► Selected as being among the top performing units

► 170 coal-fired units for metallic HAP

► e.g., mercury, cadmium, chromium, lead

► Selected as being among the top performing units

► 50 coal-fired units for dioxin/furan organic HAP

► Selected at random from the entire coal-fired EGU population

► 50 coal-fired units for acid gas, non-dioxin/furan organic, and metallic HAP

► Selected at random from the population of “non-top performing units”

► 2 coal-fired integrated gasification combined cycle (IGCC) units for all HAP 

(i.e., acid gas, organic, metallic)

► 100 oil-fired units for all HAP

► Selected at random from the oil-fired EGU population

► 16 petroleum coke-fired units for all HAP

14
Data Needs Example

► Surrogacy Example

► Bulk particulate matter (PM) removal as a surrogate for non-Hg metal HAP 

(antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, 

nickel, selenium)

► Testing conducted in EPA’s pilot-scale combustion research facility

► The level of bulk PM control seems to correlate with control of all non-Hg metal 

HAP except selenium – regardless of coal type or control configuration.

► Selenium control appears to be dependent upon fuel-type and configuration.

Selenium control

• Very variable for bituminous coal (ESP)

• 89 % for TX lignite (ESP)

• 99 % for sub-bituminous coal (ESP)

• 99 % for bituminous coal (FF)

• 99 % for TX lignite (FF)

• 99 % for sub-bituminous coal (FF)

15
Rulemaking Options under 

Consideration

► Scope of rulemaking

► Pollutant-specific limits vs. use of surrogates (e.g., PM)

► Approach to assess variability

► Must explore “beyond-the-floor” options

► Subcategorization

► CAA authorizes subcategorization by class, type and size

► Will consider and evaluate bases for subcategorization

► Alternative standards available under CAA section 112

► Work Practice Standards

► Health Based Emission Limits

► Oil-fired units

► Will consider impact on marginal, low-capacity factor, peaking units for 

which compliance could result in closure

16
Pollutants Covered

► All HAP emitted from EGUs must be addressed.

► Surrogate standards are allowed if reasonable.

► Same controls will be installed regardless of use of surrogates.

► Saves on monitoring and testing costs

► Major and Area Source Portland Cement NESHAP – as amended in 2010

► Set emission limits for 5 pollutants (Hg, dioxin/furan, HCl – major sources only, 

PM, and total hydrocarbon (THC))

► Major Source Boiler NESHAP – proposed rule

► Set emission limits for 5 pollutants (Hg, dioxin/furan, HCl, PM and carbon 

monoxide (CO))

► Expect to set limits for 5 pollutants to address all HAP emitted from EGUs

► Mercury

► PM (surrogate for non-mercury HAP metals)

► SO2 or HCl (surrogate for acid gas HAP)

► CO (surrogate for non-dioxin/furan organic HAP) vs. other pollutants (e.g., 

polycyclic aromatic hydrocarbons (PAH) or formaldehyde)

► Dioxin/furan

17
Floors and Variability

► Must adhere to language of section 112 regarding MACT floors

► Determining variability

► May not go outside the top performing 12 percent unless EPA can show a 

demonstrated relationship between the variability of the worst performers and the 

variability of the best performers.

► May include fuel variability and performance variability

► Will look at load variability

► Recent regulatory actions (Portland Cement NESHAP and Major Source Boilers 

NESHAP) have assessed variability based on the 99th percentile upper predictive 

limit (UPL).

► Means that for a future test from a best performing source, there is 99 percent 

confidence that the reported level will fall at or below the UPL value

► Beyond-the-floor options

► Regulatory options more stringent than the MACT floor must be considered.

► Can include additional control technologies, process changes, or other means of 

reducing HAP

► Costs and other impacts are considered.

► Major Source Boilers NESHAP proposed one-time energy audit.

18
Subcategorization

► CAA authorizes subcategorization by class, type and size

► Must be a basis for distinguishing between subcategories (e.g., design 

differences, operating mode, or other characteristics)

► EPA will consider and evaluate various bases for subcategorization

► Boiler design (e.g., units designed to burn coal vs. units designed to burn 

oil vs. IGCC)

► Coal rank (e.g., bituminous, subbituminous, lignite)

► Unit type (e.g., fluidized bed, pulverized coal)

► Oil type (e.g., residual (no. 4 and 6 oils) vs. distillate (no. 2 oil))

► Duty cycle (e.g., peaking units vs. base-load units)

19
Subcategorization (conc.)

► The more we subcategorize, the more data needed to establish the MACT 

floor – 5 data points for each subcategory with less than 30 sources and 

sufficient data to take top 12% of available data for subcategories with 30 or 

more sources. 

► Portland Cement NESHAP – final rule

► No subcategories

► Discussion begins in last paragraph of page 54977 of 75 FR 54970, September 9, 

2010. 

► http://frwebgate2.access.gpo.gov/cgi-bin/PDFgate.cgi?WAISdocID=8SWVqI/0/2/0&WAISaction=retrieve

► Major Source Boilers NESHAP – proposed rule

► Proposed rule included 11 subcategories based on boiler “type”

► 3 coal subcategories (pulverized coal, stokers, fluidized bed units)

► 4 biomass subcategories (stokers, fluidized bed units, suspension burners/dutch

ovens, fuel cells)

► 1 liquid subcategory

► 2 gas subcategories (natural gas/refinery gas, other gases)

► 1 metal processing furnace subcategory

► Discussion begins in last paragraph of page 32016 of

75 FR 32006, June 4, 2010 

http://frwebgate1.access.gpo.gov/cgi-bin/PDFgate.cgi?WAISdocID=e61yXI/0/2/0&WAISaction=retrieve

20
Alternative Standards Available 

under CAA section 112(d)(4)

► EPA has discretionary authority to establish health-based emission 

standards for HAP for which a health threshold has been 

established.

► Provision is intended for cases where a less stringent emission standard 

will still ensure that the health threshold will not be exceeded, with an 

ample margin of safety.

► Pulp and Paper MACT (April 1998) and Lime Manufacturing MACT 

(December 2002) – final rules

► EPA exercised its discretion under section 112(d)(4) for HCl emissions 

for discrete units within the facility.

► Did not set an emission standard based on the health threshold

21
Alternative Standards Available 

under CAA section 112(d)(4) (conc.)

► Portland Cement NESHAP – final rule

► Did not exercise section 112(d)(4) authority

► Setting a standard for HCl also co-controls other acid gas HAP (HF, HCN, and 

chlorine (Cl2)) and other pollutants (SO2, mercury, PM, ammonia, semi-volatile 

compounds).

► Positive health and environmental impacts are associated with those 

reductions.

► Major Source Boilers NESHAP – proposed rule

► Proposed to not exercise section 112(d)(4) authority

► Did not have sufficient information at that time to establish a health-based 

emission standard for HCl or the other acid gases.

– HAP mix where boilers are located and cumulative health impacts from co-located 

sources

► Environmental effects of HCl

► Significant co-benefits of setting a standard for HCl

► Solicited comment on a number of specific issues associated with 

regulation under section 112(d)(4)

22
Alternative Standards Available 

under CAA section 112(h)

► Work practice standards are allowed instead of emission standards 

if it is not feasible to prescribe or enforce an emission standard.

► “Not feasible to prescribe or enforce an emission standard” is defined, in 

part, to mean that “the application of measurement methodology to a 

particular class of sources is not practicable due to technological and 

economic limitations” (emphasis added).

► Portland Cement NESHAP – final rule

► Work practice standard for open clinker piles

► Emissions are fugitive dust for which measurement is not feasible since the 

emissions are not emitted through a conveyance or other device which allows 

their measurement.

► Work practice standard requires containment of pile (e.g., 3-sided barriers with 

roof, wind fences, tarp cover).

23
Alternative Standards Available

under CAA section 112(h) (cont.)

► Reciprocating Internal Combustion Engines NESHAP – final rule

► Work practice standards for some smaller engines and emergency 

engines

► Required test methods are generally not able to accurately sample exhaust 

pipes with very small diameters and lengths

► Cost of performance testing on small engines could approach the cost of the 

engine itself

► Emergency engines number in the hundred-thousands and are typically used 

only a few number of hours per year and emissions testing would require 

increasing the engine’s usual operating hours

► Costs of emission control and testing are not warranted when compared to the 

emission reductions that would be achieved

► Required practices include frequency of oil and filter changes, air cleaner 

inspections, hoses and belts inspections

24
Alternative Standards Available 

under CAA section 112(h) (conc.)

► Major Source Boilers NESHAP – proposed rule

► Proposed work practice standards in two instances

► Small existing boilers (units with capacity below 10 MMBtu/hr)

– Required test methods are generally not able to accurately sample small diameter (less 

than 12 inches) stacks.

– Many existing small units do not currently have sampling ports or platforms for accessing 

the exhaust stack.

– Cost analysis indicated that costs for testing and monitoring alone would have a 

significant adverse economic impact.

– Work practice of a biennial tune-up was proposed.

► New and existing boilers combusting natural gas or refinery gas

– Capital costs estimated for installing controls are extremely high (higher than the 

estimated combined capital cost for boilers in all of the other subcategories).

– Requiring gas-fired boilers to employ the same emission control systems as the other 

fuel types would have the negative effect of providing a disincentive for switching to gas 

as a control technique for boilers in the other fuel subcategories.

– Emission limits on gas-fired boilers may have the negative effect of providing an 

incentive for switching from gas to a “dirtier” but cheaper fuel, resulting in an overall 

increase in HAP emissions.

– Work practice of an annual tune-up was proposed.

– Proposal also presented MACT floor results for natural gas and refinery gas-fired boilers 

and requested comment on whether work practices or emission 

standards should be promulgated. 

25
Control Technologies Potentially 

Required to Meet Standards

► Mercury and PM (surrogate for non-mercury metal HAP)

► A new fabric filter installation is likely to be capable of achieving the PM emission 

limits and will likely assist in achieving the mercury emission limits

► If a unit already equipped with a fabric filter emits Hg above the emission limit, the 

incremental Hg removal required to meet the limit can likely be achieved with 

installation of activated carbon injection (ACI) technology

► SO2 or HCl (surrogate for acid gas HAP)

► Either a wet scrubber or dry sorbent injection system is likely to be capable of 

achieving the SO2 or HCl emission limit

► If a unit already equipped with a wet scrubber or dry sorbent injection system 

emits SO2 or HCl above the emission limit, the incremental required SO2 or HCl 

removal can likely be achieved by increasing the sorbent injection rate into the 

scrubber or the flue gas

► CO (surrogate for non-dioxin/furan organic HAP)

► Organic HAP and CO are likely to be controlled to required levels by improving the 

combustion efficiency of the unit

26
Estimated Costs for Controls

and Monitors

Capacity Pollutants Controlled Type of Cost 100 Megawatt Output 500 Megawatt Output

Fabric Filter Mercury and other metals TCI $235 per kilowatt $173 per kilowatt

TAC $3.12M per year $12.00M per year

Activated 

Carbon Injection

Mercury TCI $29.5 per kilowatt $7.5 per kilowatt

TAC $2.30M per year $10.20M per year

Wet Scrubber HCl and other acid gases TCI $809.00 per kilowatt $512.20 per kilowatt

TAC $13.67M per year $43.89M per year

Dry Sorbent 

Injection System

HCl and other acid gases TCI $171 per kilowatt $85 per kilowatt

TAC $17.15M per year $79.99M per year

PM CEMS* TCI $ 178,000 - 224,000 $ 178,000 - 224,000

Annual Costs $ 48,000 - 63,000 $ 48,000 - 63,000

Hg CEMS TCI $ 261,233 $261,233 

Annual Costs $ 108,354 $ 108,354

TCI = Total Capital Investment 27

TAC = Total Annualized Cost

* Range of costs encompass 3 types of PM CEMS: in-situ, 

extractive, and beta gauge (in order of ascending cost) 
Small Entity Definitions

► Regulations under development will affect a number of 

different industrial, commercial, and institutional sectors.

► Based on the RFA/SBREFA’s definition (5 U.S. Code section 

601(5)) of small government jurisdiction

► Small government: the government of a city, county, town, township, 

village, school district, or special district with a population of less than 

50,000

► Based on the U.S. Small Business size standard for NAICS code 

221112 (fossil fuel electric utility plants)

► Small non-government: < 4 million megawatt hours per year total 

annual electricity generation by all plants owned by the entity

28
Identification of Small Entities

► Utility NESHAP

► EPA identified facilities using the Utility NESHAP ICR responses and 

data from CAIR, Transport Rule actions.

► Revenue, employment, population data were obtained for parent entities:

► Dun & Bradstreet, Standard & Poor’s, and American Business Information

► Energy Information Administration

► U.S. Census Bureau

► Ventyx

► 80 small entities estimated

► Small government: 68

► Small non-government: 12

29
SERs

Entity

1 Atlantic Municipal Utilities

2 Bancroft Municipal Utilities

3 Colstrip Energy LP

4 Central Iowa Power Cooperative*

5 Coon Rapids Municipal Utilities

6 Corn Belt Power Cooperative*

7 Dalton Utilities

8 Geneseo Municipal Utilities*

9 Holland Board of Public Works

10 Jamestown Board of Public Utilities

11 Marquette Board of Light & Power

12 Montezuma Municipal Utilities

13 Muscatine Power & Water

14 San Miguel Electric Cooperative, Inc.*

15 Southern Illinois Power Cooperative*

16 Tes Filer City Station Power Plant - Tondu Corp.

17 Texas Municipal Power Agency

18 Wyandotte Municipal Services

30

*SER for Panel on Clean Air Interstate Rule Federal Implementation Plan

Potential viewers/technical backup that would augment 

the SERs and provide comment but would not act as 

SERs:

1. American Public Power Association

2. National Rural Electric Cooperative Association

3. Edison Electric Institute

4. Hunton & Williams

5. J.E. Cichanowicz, Inc.
Questions?

Project Lead: Bill Maxwell

919-541-5430

maxwell.bill@epa.gov

SBREFA Contacts: Mary Johnson

919-541-5025

johnson.mary@epa.gov

Project Oversight: Bob Wayland

919-541-1045

wayland.robertj@epa.gov

31

Madeline Barch

202-564-0234

barch.madeline@epa.gov
Appendix
Project Background

► On 12/20/2000, pursuant to section 112(n)(1)(A), EPA determined that 

it was “appropriate and necessary” to regulate emissions of hazardous 

air pollutants (HAP) from coal- and oil-fired EGUs under CAA section 

112.

► Based on that determination, EPA listed EGUs for regulation pursuant to 

CAA section 112(c).

► On 03/29/2005, EPA issued the Section 112(n) Revision Rule that 

found it was neither “appropriate nor necessary” to regulate HAP 

emissions from EGUs and removed such units from the section 112(c) 

source category list.

► The reversal of the 2000 “appropriate and necessary” finding was based, in 

large part, on projected mercury reductions achieved as a co-benefit of 

CAIR.

► On 05/18/2005, EPA issued the Clean Air Mercury Rule (CAMR), 

which regulated mercury from EGUs through a cap and trade program 

under section 111.

A-1
Recent Legal History

► 02/08/2008 – D.C. Circuit Court of Appeals vacated the Section 

112(n) Revision Rule and CAMR

► 03/14/2008 – Mandate Issued in Section 112(n) Revision Rule and 

CAMR vacaturs

► 10/17/2008 – U.S. Government filed a petition for writ of certiorari 

with the U.S. Supreme Court

► 12/18/2008 – Mandatory duty suit filed by American Nurses Assn., 

et al., for failure to establish MACT standards for coal- and oil-fired 

electric generating units by 12/20/2002

► 02/06/2009 – U.S. Government moves to withdraw its petition for 

writ of certiorari 

► 02/23/2009 – U.S. Supreme Court denies industry petition for writ 

of certiorari and grants U.S. Government’s request to withdraw its 

petition

A-2
Effect of Vacatur

► Coal- and oil-fired EGUs remain a listed source category for which 

EPA must issue emission standards under CAA section 112(d).

► EPA will address all HAP that are emitted from coal- and oil-fired 

EGUs – not just mercury.

► Operating under a Consent Decree negotiated with litigants 

(American Nurses Assn., et al.; represented by Earthjustice)

► No later than March 16, 2011, EPA shall sign for publication in the 

Federal Register a notice of proposed rulemaking

► No later than November 16, 2011, EPA shall sign for publication in the 

Federal Register a notice of final rulemaking

A-3
Potentially Affected Small Entities

Alexandria, LA (City of) Corn Belt Power Coop Laurens, IA (City of) Richmond Power & Light

Algona Municipal Utilities Dalton, GA (City of) Los Alamos County Sam Rayburn G & T Electric Coop, Inc.

Alta, IA (City of) Dover, DE (City of) Louisiana Energy & Power Authority San Miguel Electric Coop, Inc.

American Consumer Industries, Inc. East Power Corporation Lyndonville Electric Dept. Sikeston Utilities

American Consumers, Inc. East Texas Electric Coop, Inc. Manitowoc Public Utilities South Mississippi Electric Power 

Association

American Hydropower Company Eldridge, IA (City of) Marquette Board of Light & Power Southern Illinois Power Coop

American Power Investors, Inc. Farmington, NM (City of) Milford Municipal Utilities Southern Minnesota Municipal Power 

Agency

Atlantic Municipal Utilities Fort Pierce Utility Authority Missouri River Energy Services Spencer Municipal Utilities

Austin Utilities Fremont Dept. of Public Utilities Montezuma Municipal Utilities Sumner Municipal Light Plant

Azusa, CA (City of) Geneseo Municipal Utilities Municipal Energy Agency of Nebraska Tipton, IA (City of)

Bancroft Municipal Utilities Graettinger Municipal Light Plant Muscatine Power & Water Tondu Corp.

Banning Electric Division Grand Haven Light & Power National Energy & Gas Transmission Utah Associated Municipal Power System

Beowulf Energy LLC Grand Island Utilities New Hampton Municipal Light Plant Wabash Valley Power Association, Inc.

Brazos Electric Power Coop Greenville Electric Utility System North American Power Group Ltd. Waverly Light & Power

Cedar Falls (IA) Utilities Harlan Municipal Utilities Northeast Texas Electric Coop, Inc. Webster City, IA (City of)

Central Electric Power Coop MO Hastings Utilities (NE) Northwest Iowa Power Coop West Bend, IA (City of)

Central Iowa Power Coop Henderson Municipal Power & Light Old Dominion Electric Coop West Memphis Utility Dept.

Central Vermont Public Service Corp. Holland Board of Public Works Osceola, AR (City of) Winfield, KS (City of)

Colstrip Energy LP Jonesboro Water & Light Pacific Northwest Generating Coop Wolverine Power Supply Coop, Inc.

Coon Rapids, IA (City of) KAMO Electric Coop, Inc. Pella Municipal Light & Power WPPI Energy

A-4
Questions for SERs

► Affected Entities

► Is EPA’s list of potentially affected small entities on slide A-4 of this presentation 

accurate? If not, do you have suggested additions or deletions? Could you 

briefly explain the reason for each addition or deletion? (Note: The applicable 

definitions of small entity are on slide 28 of this presentation.)

► Firm Characteristics

► How many units do you have in your facility or facilities? 

► What is the capacity of your installed units?

► What duty cycles do they run?

► Existing Standards 

► What Federal/State/local standards are your EGUs currently subject to?

► What compliance requirements are associated with the other standards that apply 

to your EGU?

► What emissions control technologies do you have installed at your facilities? 

Under what regulatory requirements are they installed? What did they cost to 

install? To operate?

A-5
Questions for SERs (cont.)

► What recordkeeping and reporting requirements are you subject to under other 

standards that apply to your EGU?

► If your EGU is subject to emission limits, are there alternatives to monitoring 

emissions or stack testing that would be less costly to demonstrate compliance 

and, if so, how much less costly are the alternatives?

► Are there recordkeeping and reporting alternatives that would simplify the 

requirements?

► Do you employ any monitors, for emissions or process parameters, to monitor the 

operation of your EGU?

► What type of monitors and how many?

► What were the capital costs and what are annual costs for each monitor?

► Are these monitors in place for environmental regulatory reasons, insurance 

reasons, or other reasons?

► Did you provide any of the monitoring data to the Agency during the recent 

Information Collection Request on Utility Boilers or another information collection 

request?

A-6
Questions for SERs (cont.)

► Do you employ measures to ensure that your EGU operates in an energy efficient 

manner?

► What are the energy efficient measures you employ?

► Are these measures a result of regulatory requirements, initiated voluntarily, or 

employed for other reasons?

► What are the estimated emissions reductions associated with the energy efficient 

measures?

► What are the costs of implementing the energy efficient measures?

► Regulatory Alternatives

► What types of subcategories based on class, type, or size do you think EPA 

should consider and why?

► What surrogate standards do you think are appropriate?

► What means of determining variability do you think EPA should consider?

A-7
Questions for SERs (cont.)

► Which subset(s) of HAP from EGUs, if any, do you think would meet the CAA 

section 112(h) requirements for establishing work practice standards in lieu of 

emission limits and what is the basis for your assertion?

► What work practice standards are available to you?

► What work practice standards would you consider to be reasonable alternatives to 

emission limits? 

► What are the costs of those work practices?

► Do you have the information that would support considering setting health-based 

emission limits under CAA section 112(d)(4) for HAP emissions from EGUs? For 

example, facility-wide HAP emissions, facility configurations, overall fence-line 

characteristics, population proximity to plant, potential adverse environmental 

effects that would otherwise be reduced or eliminated. 

► Are there other regulatory options or small entity flexibilities that EPA should 

consider?

A-8
Questions for SERs (cont.)

► Cost Estimates

► If you employ any of the control technologies listed on slide 26 of this presentation 

as potentially being required to meet the Utility NESHAP, indicate the type of 

control, its size (e.g., the size EGU that the control is associated with, the exhaust 

gas flow rate being routed through the control), what the capital costs were, and 

what the annual operating costs are.

► Do you agree with the control technology and monitoring cost estimates presented 

on slide 27 of this presentation? ? If not, provide your cost estimate(s) along with 

the source(s) of your estimate(s).

► Do you employ other control or monitoring technologies that EPA should consider 

when estimating the impacts of the standards? If so, indicate the type of control 

or monitor, the size boiler it is associated with, what the capital costs were, and 

what the annual operating costs are.

► In ideal circumstances, how long would your facility require to finance and install 

new emissions control and monitoring equipment?

► How long would be required if there were other regulations requiring similar 

investments that had to be implemented consecutively?

► How would new emissions requirements affect your production capacity?

A-9
Questions for SERs (conc.)

► Are there other regulatory requirements that could conflict with new emissions 

standards?

► Are there other regulatory requirements that could increase the cost of compliance 

with new emission standards?

► How does your entity acquire money for capital investments? Is it primarily 

through equity? Or debt? Or a combination of both? 

► Are you an independent power producer?

► Is your entity regulated by a State or local utility commission, or does it operate in 

competitive markets? 

If you had to install additional control equipment that required capital investment, 

would you adjust the rate charged to your customers?

► What is the process for adjusting the rate?

► What is the expected time for that change to occur?

► What are the limits on how much you can raise rates?

► What other constraints exist on your ability to raise capital or fund capital 

investment for regulatory compliance?

A-10