Rulemaking for Greenhouse Gas Emissions

from Electric Utility Steam Generating Units

Panel Outreach Meeting with SERs

June 17, 2011
Agenda ► Background ► Future Projections 

- Generation and Emissions

► Definition of EGU ► What are Greenhouse Gases? ► Power Sector: A Major Share of U.S. GHG Emissions ► GHG Emissions Across Sectors ► GHG Emissions – Energy Sector ► GHG Emissions – Electricity Generation ► Section 111 Overview ► Affected Facilities ► CO2 Emissions Control Technologies ► Technology Assessment ► New Sources ► Carbon Capture & Storage ► Modified and Existing Sources ► Potential Impacts on Small Entities ► Compliance and Monitoring ► Key Questions ► Summary of Listening Sessions ► Questions for SERs ► Applicable Small Entity Definitions ► Small Entities Potentially Subject to Regulation

2
Background

► On December 15, 2009 (74 FR 66496), EPA published a notice indicating that 

the EPA Administrator found that the current and projected atmospheric 

concentrations of GHGs are reasonably anticipated to endanger the public 

health and welfare of current and future generations (Endangerment Finding).

► On December 23, 2010, EPA announced that it entered into a proposed 

settlement agreement to issue rules that will address GHG emissions from 

certain fossil fuel-fired EGUs.

► Rules would establish new source performance standards (NSPS) for new 

and modified natural gas-, oil-, and coal-fired EGUs and emission guidelines 

for existing natural gas-, oil-, and coal-fired EGUs.

► Under the agreement, EPA commits to issuing proposed regulations by July 

26, 2011 and final regulations by May 26, 2012.

► Agreement addresses, in part, EPA’s September 2007 remand of its February 

2006 final decision not to set GHG standards for boilers.

3
Distribution of Emissions for New and

Existing Subpart Da Sources and Other EGUs

4

0

500

1,000

1,500

2,000

2,500

CO2 SO2 NOX CO2 SO2 NOX CO2 SO2 NOX Million Metric Tonnes (CO2

) Thousand Tons (SO2/NOX

)

< 25 MW

Other EGUs

New NG CC

Existing NG CC

New Da

Existing Da 

(oil/gas)

Existing Da 

(coal)

2015 2020 2030

Emissions from Subpart Da, combined cycle, and other EGUs from units greater than 25 MW 

Source: Integrated Planning Model (IPM) run by EPA, 2011
Distribution of Generation for New and

Existing Subpart Da Sources and Other EGUs

5

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

2015 2020 2030 Million GWh

<25 MW

Other EGUs (>25 MW)

Non-hydro Renewable

Hydro

Nuclear

New NG CC

Existing NG CC

New Da

Existing Da (oil/gas)

Existing Da (coal)

Subpart Da, combined cycle, nuclear, hydro, and non-hydro renewable generation from units 

greater than 25 MW.

Source: Integrated Planning Model (IPM) run by EPA, 2011
Federal Electric Demand Growth 

Projections

► U.S. Energy Information Administration (EIA) 

forecasts significantly lower load growth 

going forward than we have seen historically

►Current projections are for load growth of 7% 

by 2020

►While the short term driver for load growth is 

economic, the longer term driver is an 

increased emphasis at the federal, State and 

local levels on energy efficiency

6
Federal Projections for New Generation

► Major drivers for new generation projections 

include:

► Low projected electric demand growth

► Low projected natural gas prices

► Unused natural gas capacity

► Projected renewable builds to meet increasing 

renewable portfolio standards

► Because of these factors, the only new coal that 

EPA and EIA project beyond that which is 

currently being constructed is a small amount of 

coal with carbon capture and storage incentivized 

by existing federal programs

7
Federal Projections for New Generating 

Capacity by 2020

Note: IPM v.4.10 is calibrated to Annual Energy Outlook (AEO) 2010 demand 

assumptions. Additionally, the IPM v.4.10 case presented above includes 

the proposed Mercury and Air Toxics Standards, which are not included 

in the AEO 2011 reference case.

Projected New Builds, 

2020 (GW)

Projected Total 

Capacity, 2020 (GW)

Plant Type IPM v.4.10

AEO 2011 

Reference 

Case IPM v.4.10

AEO 2011 

Reference 

Case

Coal Steam 2 2 302 318

Natural Gas (CC/CT) 10 8 355 347

Non-Hydro Renewables 27 20 73 60

8
Definition of EGU

► The regulations would apply to each EGU capable of combusting 

more than 250 million British thermal units per hour (MMBtu/hr) heat 

input of fossil fuel.

► Electric utility steam generating unit means any steam electric 

generating unit that is constructed for the purpose of supplying more 

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

25 megawatts electric (MWe) output to any utility power distribution 

system for sale.

► Fossil fuel means natural gas, petroleum, coal, and any form of 

solid, liquid, or gaseous fuel derived from such material for the 

purpose of creating useful heat.

9
What are Greenhouse Gases? 

► GHGs are chemical compounds found in the Earth’s atmosphere

► They allow sunlight to enter the atmosphere freely.

► When sunlight strikes the Earth’s surface, some of it is re-radiated back 

towards space as heat (infrared radiation).

► GHGs absorb the infrared radiation and trap the heat in the atmosphere.

► Over time, if atmospheric concentrations of GHGs remain relatively stable, 

the amount of energy sent from the sun to the Earth’s surface should be 

about the same as the amount of energy radiated back into space, leaving 

the temperature of the Earth’s surface roughly constant.

► Some GHGs occur naturally and are emitted to the atmosphere through 

natural processes and human activities (e.g., carbon dioxide, methane, and 

nitrous oxide).

► Other GHGs are created and emitted solely through human activities (e.g., 

fluorinated gases).

10
What are Greenhouse Gases? (cont.) 

► Principal GHGs that enter the atmosphere due to human activities:

► Carbon Dioxide (CO2)

► Burning of fossil fuels (oil, natural gas, and coal), solid waste, trees and wood products

► Chemical reactions (e.g., manufacture of cement, steel, aluminum)

► Methane (CH4)

► Production and transport of coal, natural gas, and oil

► Livestock and other agricultural practices

► Decay of organic waste in municipal solid waste landfills 

► Nitrous Oxide (N2O)

► Combustion of fossil fuels and solid waste

► Agricultural and industrial activities

► Fluorinated Gases

► Hydrofluorocarbon (HFC), perfluorocarbon (PFC), and sulfur hexafluoride (SF6)

► Typically emitted in smaller quantities, but are potent GHGs

► Synthetic GHGs emitted from a variety of industrial processes

► Sometimes used as substitutes for ozone-depleting substances

► Chlorofluorocarbons (CFCs) - used as refrigerants, solvents, and foam blowing agents

► Hydrochlorofluorocarbons (HCFCs) - used to replace CFCs due to lower ozone depleting 

potential

► Halons - used as fire extinguishing agent

11
GHG Emissions Across Sectors 

12

Gas/Source Type 1990 2000 2009

CO25100.2 5976.2 5508.1

Fossil Fuel Combustion 4741.2 5597.7 5212.0

Non-Energy Use of Fuels 116.2 142.5 122.1

Iron and Steel Production & Metallurgical Coke Production 99.5 85.9 42.6

Natural Gas Systems 37.6 29.9 32.2

Cement Production 33.3 41.2 29.4

Incineration of Waste 8 11.1 12.3

Ammonia Production and Urea Consumption 16.8 16.4 11.8

Lime Production 11.5 14.1 11.2

Cropland remaining Cropland 7.1 7.5 7.8

Limestone and Dolomite Use 5.1 5.1 7.6

Soda Ash Production and Consumption 4.1 4.2 4.3

Aluminum Production 6.8 6.1 3.0

Petrochemical Production 3.3 4.5 2.7

Carbon Dioxide Consumption 1.4 1.4 1.8

Ferroalloy Production 2.2 1.9 1.6

Titanium Dioxide Production 1.2 1.8 1.5

Wetlands remaining Wetlands 1 1.2 1.1

Phosphoric Acid Production 1.5 1.4 1

GHG Emissions in U.S.

(million metric tons of CO2 equivalent)

Source: Table ES-2 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2009, February 15, 2011
GHG Emissions Across Sectors (cont.) 

13

Gas/Source Type 1990 2000 2009

CH4674.9 659.9 686.5

Natural Gas Systems 189.8 209.3 221.2

Enteric Fermentation 132.1 136.5 139.8

Landfills 147.4 111.7 117.5

Coal Mining 84.1 60.4 71.0

Manure Management 31.7 42.4 49.5

Petroleum Systems 35.4 31.5 30.9

Wastewater Treatment 23.5 25.2 24.5

Forest Land remaining Forest Land 3.2 14.3 7.8

Rice Cultivation 7.1 7.5 7.3

Stationary Combustion 7.4 6.6 6.2

Abandoned Underground Coal Mines 6.0 7.4 5.5

Mobile Combustion 4.7 3.4 2.2

Iron and Steel Production & Metallurgical Coke Production 1.0 0.9 0.4

GHG Emissions in U.S. (cont.)

(million metric tons of CO2 equivalent)

Source: Table ES-2 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2009, February 15, 2011
GHG Emissions Across Sectors (cont.) 

14

Gas/Source Type 1990 2000 2009

N2O 315.2 341.0 299.5

Agricultural Soil Management 197.8 206.8 204.6

Mobile Combustion 43.9 53.2 27.8

Manure Management 14.5 17.1 17.9

Nitric Acid Production 17.7 19.4 14.6

Stationary Combustion 12.8 14.6 12.8

Forest Land remaining Forest Land 2.7 12.1 6.7

Wastewater Treatment 3.7 4.5 5.0

N2O from Product Uses 4.4 4.9 4.4

Adipic Acid Production 15.8 5.5 1.9

HFCs 36.9 103.2 125.0

Substitution of Ozone Depleting Substances 0.3 74.3 119.3

HCFC-22 Production 36.4 28.6 5.4

Semiconductor Manufacture 0.2 0.3 0.3

PFCs 20.8 13.5 5.6

Semiconductor Manufacture 18.5 8.6 1.6

Aluminum Production

SF634.4 20.1 14.8

Electrical Transmission and Distribution 28.4 16 12.8

Magnesium Production and Processing 5.4 3.0 1.1

Semiconductor Manufacture 0.5 1.1 1.0

Source: Table ES-2 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2009, February 15, 2011

GHG Emissions in U.S. (cont.)

(million metric tons of CO2 equivalent)
GHG Emissions - Energy Sector

Source: Table 2-4 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2009, February 15, 2011

15

Energy Sector GHG Emissions

(million metric tons of CO2 equivalent)

Gas/Source Type 1990 2000 2009

CO24903.6 5781.7 5379.0

Fossil Fuel Combustion 4741.2 5597.7 5212.0

Electricity Generation 1820.8 2296.9 2154.0

Transportation 1485.9 1809.5 1718.9

Industrial 849.3 853.9 738.4

Residential 338.3 370.7 340.2

Commercial 219.0 230.8 218.8

U.S. Territories 27.9 35.9 41.7

Non-Energy Use of Fuels 116.2 142.5 122.1

Natural Gas Systems 37.6 29.9 32.2

Incineration of Waste 8.0 11.1 12.3

Petroleum Systems 0.6 0.5 0.5
GHG Emissions - Energy Sector (cont.)

Source: Table 2-4 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2009, February 15, 2011

16

Energy Sector GHG Emissions (cont.)

(million metric tons of CO2 equivalent)

Gas/Source Type 1990 2000 2009

CH4327.4 318.6 337.0

Natural Gas Systems 189.8 209.3 221.2

Coal Mining 84.1 60.4 71.0

Petroleum Systems 35.4 31.5 30.9

Stationary Combustion 7.4 6.6 6.2

Abandoned Underground Coal Mines 6.0 7.4 5.5

Mobile Combustion 4.7 3.4 2.2

Incineration of Waste <0.05 <0.05 <0.05

N2O 57.2 68.1 41.0

Mobile Combustion 43.9 53.2 27.8

Stationary Combustion 12.8 14.6 12.8

Incineration of Waste 0.5 0.4 0.4
GHG Emissions – Electricity Generation

Source: Table 2-13 of EPA’s Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2009, February 15, 2011

► CO2 emissions from fossil fuel combustion are ~99.5% of total GHG emissions from fossil fuel 

combustion (2009)

► CO2 emissions from coal-fired combustion are ~81% of total CO2 emissions from fossil fuel 

combustion (2009)

17

Gas/Source Type 1990 2000 2009

CO2

Fossil Fuel Combustion 1820.8 2296.9 2154

Coal 1547.6 1927.4 1747.6

Natural Gas 175.3 280.8 373.1

Petroleum 97.5 88.4 32.9

CH4

Stationary Combustion 0.6 0.7 0.7

N2O

Stationary Combustion 8.1 10.0 9.0

Electricity Generation-Related GHG Emissions

(million metric tons of CO2 equivalent)
Power Sector:

A Major Share of U.S. GHG Emissions

18

3.9 Billion Tons

60%

2.6 Billion Tons

40%

Carbon Dioxide (CO2), 2008

6.5 Billion Tons

Electric 

Power

Other 

Sectors

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (2010) (CO2)

“Other” sources include transportation, other mobile sources, and industrial sources
Section 111 Overview

► In setting the EGU GHG NSPS, there are two particularly relevant 

provisions:

► CAA section 111(b) requires EPA to regulate new and modified sources

► CAA section 111(d) requires EPA to establish regulations under which 

States will regulate existing sources.

► Section 111(d) is only relevant when the source emits pollutants 

that are not regulated under other parts of the CAA (i.e., pollutants 

regulated under NAAQS requirements or NESHAP requirements) 

and to which an NSPS would apply if such existing source were a 

new source.

► EPA may distinguish among classes, types, and sizes within 

categories of sources for the purpose of establishing standards.

► EPA bases standards on demonstrated controls and may not require 

use of any particular technology, except under narrow 

circumstances (as authorized under CAA section 111(h)).

► EPA may waive compliance for sources employing innovative 

technologies with the potential for equivalent or greater reductions 

(“innovative technology waivers”).

19
Section 111 Overview (cont.)

► If EPA determines that it is not feasible to prescribe or enforce a standard of 

performance, CAA section 111(h) authorizes promulgation of a design, 

equipment, work practice, or operational standard, or combination thereof, 

which reflects the best technological system of continuous emission 

reduction which (taking into consideration the cost of achieving such 

emission reduction, and any non-air quality health and environmental 

impact and energy requirements) EPA determines has been adequately 

demonstrated.

► “Not feasible to prescribe or enforce a standard of performance” means 

any situation in which the Administrator determines that:

► a pollutant or pollutants cannot be emitted through a conveyance designed and 

constructed to emit or capture such pollutant, or that any requirement for, or 

use of, such a conveyance would be inconsistent with any Federal, State, or 

local law, or

► the application of measurement methodology to a particular class of sources is 

not practicable due to technological or economic limitations.

► Believe there would not be a basis for using 111(h) authority

20
Section 111(b)

► NSPS implement CAA section 111(b) and are issued for categories 

of sources which cause, or contribute significantly to, air pollution 

which may reasonably be anticipated to endanger public health or 

welfare.

► Section 111(b) requirements apply to both new and modified 

sources.

► New sources are those for which construction or modification is 

commenced after the publication of proposed regulations.

► Modification is any physical change in, or change in the method of 

operation of, a source which increases the amount of any air pollutant 

emitted by the source or which results in the emission of any air 

pollutant not previously emitted.

► Exempt: Routine maintenance, repair, and replacement and increased hours 

of operation

► May set different standards for new and modified sources

► May have different standards for different subcategories

► EGUs are already subject to 111(b) requirements for a number of 

pollutants such as SO2, NOX, and PM.

21
Section 111(b) (cont.)

► Traditionally, these standards have been set at the unit level.

► NSPS are set at the Federal level and States do not have the 

flexibility to approve less stringent requirements.

► NSPS reflect the degree of emission limitation achievable through 

application of the best system of emission reduction which, taking 

into consideration the cost of achieving such reduction, any non-air 

quality health and environmental impact, and energy requirements, 

the Administrator determines has been adequately demonstrated.

► Level of control referred to as Best Demonstrated Technology (BDT)

► When determining Best Available Control Technology (BACT) under 

the New Source Review (NSR) requirements of the CAA, BACT 

determinations may not be less stringent than the 111(b) standards 

the agency has set.

► NSPS are to be reviewed at least every 8 years and revised if 

appropriate.

22
Section 111(d)

► Emission guidelines are established under CAA section 111(d) for 

source categories that emit pollutants not regulated under other 

parts of the CAA and to which an NSPS would apply if such existing 

source were a new source.

► Section 111(d) requirements apply to existing sources.

► Because section 111(d) only applies to pollutants not regulated 

under other parts of the CAA, it has been used very infrequently.

► Only two source categories are currently subject to section 111(d) 

requirements (i.e., sulfuric acid production plants and municipal solid waste 

landfills).

► Solid waste incinerators have also been regulated under a very similar 

provision (CAA section 129) which requires the Agency to regulate those 

sources using the 111(d) process.

► Under section 111(d), EPA does not set explicit emission standards 

on individual sources, rather it develops emission guidelines.

► While called “guidelines,” they go through notice and comment, and are 

binding on States.

► States must promulgate rules that are consistent with the emission 

guidelines.

23
Section 111(d) (cont.)

► Key elements of Emission Guidelines include:

► Description of system of emission reductions that EPA deems 

adequately demonstrated

► Degree of emission limitation achievable, costs, and 

environmental impacts of application

► Time required to implement

► Other information EPA determines is necessary to facilitate 

formation of State Plans

► Different guidelines or compliance times (or both) may 

be specified for different sizes, types, and classes of 

designated facilities when costs, physical limitations, 

geographical location, or other factors make 

subcategorization appropriate.

24
Requirements for 111(d) State Plans

► State Plans are generally due within 9 months after 

publication of the final emission guidelines.

► Other timeframes may be set by EPA for specific standards.

► States may receive exemption from plan submittal requirements 

by certifying no designated facilities exist.

► State Plans must contain:

► Emission standards and compliance schedules “no less stringent 

than emission guidelines”

► Allowable emission rates and possibly allowance system

► Test methods and procedures for determining compliance

► Enforceable increments of progress for compliance schedules 

longer than 12 months

25
Requirements for 111(d) State Plans 

(cont.)

► States may adopt less stringent emission standards or longer 

compliance schedules than those set out in the guidelines where the 

States demonstrate:

► Unreasonable cost of control due to age, location or basic process 

design

► Physical impossibility of installing necessary control equipment

► “Other factors specific to the facility or class of facility that make 

application of a less stringent standard or final compliance time 

significantly more reasonable.”

► States may adopt more stringent standards or shorter compliance 

schedules than those contained in the guidelines.

► EPA has the authorities to prescribe a plan for a State in cases 

where the State fails to submit a satisfactory plan and to enforce the 

provisions of a plan in cases where the State fails to enforce them.

► In applying a standard of performance to any particular source under 

a State implementation plan or in promulgating a standard of 

performance under a plan prescribed by EPA, the remaining useful 

life of the existing source(s) can be considered.

26
Section 111 versus Section 112

► Technology basis of standards

► CAA section 111 standards are based on BDT

► CAA section 112 standards are based on maximum achievable control 

technology (MACT) – very prescriptive

► Other considerations

► Under CAA section 111, the cost of achieving reductions, any non-air 

quality health and environmental impacts, and energy requirements are 

considered in determining BDT

► Under CAA section 112, costs and other impacts can only be considered 

when regulating beyond the minimum MACT level (the MACT floor)

► CAA section 111(d) regulations developed by EPA do not directly 

impact existing sources. States follow the EPA regulations 

developed under section 111(d) to establish implementation plans 

with standards of performance that apply to those sources.

27
Regulatory Compliance Obligations

for the Utility Industry

28
Affected Facilities

Coal, 48%

Oil, 1%

Natural Gas, 21%

Non Hydro Renewables, 3%

Hydro, 6%

Nuclear, 20%

Other, 1%

► Approximately 1,525 EGUs at 605 facilities ► Approximately 1,200 coal-fired boilers at 

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

► Approximately 48 percent of nationwide net 

generation

► Approximately 150 oil-fired boilers at 75 

facilities, mostly in Northeast, Midwest, 

California, Florida, and Hawaii ► Approximately 1 percent of nationwide net 

generation

29
Affected Facilities (cont.)

► Approximately 175 gas-fired boilers at 80 facilities, mostly in 

Midwest, California, Louisiana, and Texas

► Approximately 21 percent of nationwide net generation

► Are not subject to the NESHAP for EGUs

► The regulations would apply to integrated gasification combined 

cycle (IGCC, i.e, “coal gasification”) EGUs.

► Coal is “gasified” in a high-pressure, high-temperature gasifier with a 

limited supply of either oxygen or air to produce synthetic gas (syngas).

► The syngas is cooled, cleaned, and fired in a gas (combustion) turbine.

► The hot exhaust from the combustion turbine passes through a heat 

recovery steam generator (HRSG, i.e., boiler) where it produces steam 

that drives a steam turbine.

► Electric power is produced from both the combustion and steam turbinegenerators.

► There are two IGCC plants currently operating in the U.S.

► Duke Energy Wabash River Power Station in Indiana (operation began in 

1995)

► Tampa Electric Company Polk Power Station in Florida

(operation began in 1996)

30
Affected Facilities (cont.)

► In a combined cycle gas turbine plant, a gas turbine generates electricity 

and the waste heat is used to make steam to generate additional 

electricity via a steam turbine.

► More efficient method of generating electricity 

► Used by most new gas power plants in North America and Europe

► In a simple cycle gas turbine plant, there is no heat recovery.

► Have the ability to be turned on and off within minutes

► Usually used as peaking power plants because they are less efficient

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

cooperative EGUs.

31
Coal Steam Electricity Generating Units by 

Size, Age, Capacity and Efficiency (heat rate)

Unit Size 

Grouping 

(MW)

# of 

Units

% of all 

units

Average 

Age

Avg 

Capacity 

(MW)

Total 

Capacity 

(MW)

% of Total

Capacity

Avg Heat 

Rate 

(Btu/Kwh)

0 to 25 193 15% 45 15 2,849 1% 11,154

>25 to 49 108 9% 42 38 4,081 1% 11,722

50 to 99 162 13% 47 75 12,132 4% 11,328

100 to 

149

269 21% 49 141 38,051 12% 10,641

150 to 

249

81 6% 43 224 18,184 6% 10,303

250 and 

up

453 36% 34 532 241,184 76% 10,193

Totals 1266 316,480

32
Power Plants Likely Covered by the

EGU GHG Rule

Source: National Electric Energy Data System (NEEDS 4.10) (EPA, December 2010)

Note: This map displays facilities that are included in the NEEDS 4.10 data base and that contain at least one coal, oil or gas-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 online by the end of 2011; this includes committed new builds and committed retirements of old units. Only steam boilers are covered by this rule. In areas with a dense concentration of facilities, the 

facilities on the map may overlap and some may be impossible to see. American Indian Reservations / Federally Recognized Tribal Entities shown were provided by the US DOI, BIA, and GDSC; they 

are not a legal representation of reservation boundaries.

33
CO2 Emissions Control Technologies

► General types of control measures for CO2 emissions: 

► Energy efficiency

► Reduce the amount of fuel used by improving the efficiency of the electrical 

generation process

► Post-combustion

► Separate the CO2for long-term storage using carbon capture technology

► Other measures

► Co-firing

► Fuel switching

► Combined heat and power

34
Efficiency Improvements for New EGUs

► Efficiency improvements for new coal-fired EGUs

► Use of supercritical boilers

► Operate at higher pressures and temperatures

► Start-up times are quicker

► National Energy Technology Laboratory (NETL) analysis shows that 

supercritical boilers are approximately 2.3% more efficient than subcritical 

boilers

► Application currently limited to facilities of approximately 200 MWe gross output 

or more due to the availability of steam turbines that are designed for 

supercritical steam conditions 

► Use of ultra-supercritical boilers

► Operate at even higher pressures and temperatures

► Can potentially operate at efficiencies approaching 50%

► Material degradation can be an issue when firing high-sulfur coal

► Use is prevalent in Denmark, Germany, and Japan

► First modern ultra-supercritical EGU in U.S. – Southwest Electric Power 

Company’s John W. Turk, Jr. Power Station near Texarkana, AR

► 600 MWe pulverized coal-fired EGU

► Will burn Powder River Basin subbituminous coal

► Scheduled to begin operation in late 2012

Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal-Fired 35

Electric Generating Units, October 2010
Efficiency Improvements for New EGUs 

(cont.)

► Use of IGCC technology

► Electric output is generated by both the combustion turbine and the steam 

turbine

► NETL analysis of three coal gasification processes shows net efficiencies of 

38.2% to 41.1%

► Coal drying

► Several advanced pre-combustion coal drying technologies are or nearly are 

commercially available

► Reported net gains in overall efficiency of 2% to 4%

► Boiler feedwater heating

► Use of heat sources other than the steam turbine to heat feedwater

► Increases the output of the steam cycle and potentially lowers GHG emissions

Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal- 36

Fired Electric Generating Units, October 2010
Technology assessment

New sources – costs and emissions

► Table on next slide shows costs and CO2 emissions of new 

generation technologies

► Of most interest for new source standards: Coal and NGCC 

options

► On average, new NGCC now has lower generating cost 

(capital plus operating) than the most efficient, commercially 

available, new supercritical coal (which some call “ultra”). 

Also lower capital cost and lower emitting.

► For now, supercritical coal less costly but higher emitting than 

IGCC.

► Average generating cost higher for all new generation options 

than for existing coal. Existing source requirements may 

reduce the gap, especially for units needing to install 

scrubbers and SCR as well as reduce CO2.

► Other technologies may be considered special cases:

► Gas options other than NGCC are more expensive, higheremitting, or both.

37
Technology assessment

New Source Generation Technologies

38

Basis: Bituminous Coal at $2.00/MMBtu; Natural Gas at $4.00/MMBtu; Biomass at $4.00/MMBtu;

all units base loaded at 85% annual capacity factor; CO2 capture removes 90% of CO2;

costs are 2009 market prices in 2007$.

Avoided CO2 Cost vs. Existing Coal Boiler (avg.)

Technology Option

Thermal 

Efficiency

CO2

Emission

Capital 

Cost 

Generating 

Cost (total)

Avoided 

CO2 Cost

% (HHV) tonne/MWh $/kW $/MWh $/tonne

Existing Coal Boiler (avg.) 33% 0.94 --- $30 Base

Coal Supercritical Boiler 38% 0.81 $2,920 $75 $346

Coal IGCC 41% 0.77 $3,270 $80 $294

Coal IGCC + CCS 34% 0.09 $4,720 $122 $108

NG in Existing Coal Boiler (A) 31% 0.60 $1,200 $66 $106

NG Supercritical Boiler 36% 0.51 $1,750 $70 $93

NG in Existing Coal Boiler (B) 31% 0.60 $200 $50 $59

NGCC + CCS 43% 0.04 $2,070 $83 $59

NG Combined Cycle 50% 0.37 $980 $50 $35
Technology assessment

New Generation Technologies

Additional Technology Notes – Avoided CO2 Cost

1. Assumed thermal efficiencies and CO2 emissions for coal technologies are roughly indicative of performance on 

bituminous coal. Performance and costs can vary considerably within and across coal ranks.

2. Capital costs are “overnight costs” indicative of 2009 market conditions, expressed in 2007$ (current CAMD practice in 

IPMv4.10). Generating costs are at the plant gate, including annualized owner’s costs, capital costs, interest during 

construction, and O&M costs.

3. Analysis by EPA engineering staff (CAMD) using assumptions generally consistent with IPMv4.10.

**********************************************

► Existing Coal Boiler (avg.): Generating cost could be as low as $20 for fully amortized units; as high as $40 for units with 

newly retrofitted FGD and SCR controls.

► Coal Supercritical Boiler: Commercially available. Steam conditions of 3750psi/1100F/1100F are considered 

ultrasupercritical by some analysts. Advanced ultrasupercritical steam conditions at 1300F are in R&D phase.

► Coal IGCC: Commercially available. Based on dry feed gasifier.

► Coal IGCC + CO2 capture: Expected to be demonstrated at full size in U.S. this decade. Assumes $15/tonne for CO2 

transport and sequestration (based on IPM v4.10).

► NG in Existing Coal Boiler (A): High capital cost case, assumes new 50-mile gas pipeline required at $10million per 

mile.

► NG in Existing Coal Boiler (B): Low capital cost case, assumes minimal costs for boiler modifications and connection to 

nearby gas pipeline.

► NG Supercritical Boiler: Commercially available. Roughly estimated capital cost as 60% and O&M cost as 50% of Coal 

Supercritical Boiler costs.

► NGCC + CO2 capture: Expected to be demonstrated at full size in U.S. this decade. Assumes $15/tonne for CO2

transport and sequestration.

► NG Combined Cycle: Commercially available. Assumes widely accepted F class technology. G and H class also 

commercially available for higher combined cycle efficiencies at higher capital and O&M costs.

39
Technology assessment

Carbon Capture & Storage

► There are no insurmountable technological, legal, institutional, or other 

barriers that prevent carbon capture and storage (CCS) from playing a role 

in reducing GHG emissions.

► Current technologies could be used to capture CO2from new and existing fossil 

energy power plants; however they are not ready for widespread implementation

primarily because they have not been demonstrated at the scale necessary to 

establish confidence for power plant application.

► CCS retrofits could face challenges at some existing plants due to space and 

configurational limitations or proximity to a CO2 pipeline or geologic storage.

► Existing Federal programs are being used to deploy at least five to ten largescale integrated CCS projects expected to be online by 2016. 

► Federal research, development and demonstration efforts are focused on 

reducing costs of CCS to facilitate widespread cost-effective deployment 

after 2020.

► Approximately 70–90% of CCS cost is associated with capture and compression.

► The cost and performance of CCS technologies will evolve with longer-term 

testing.

Source: Report of the Interagency Task Force on Carbon Capture and Storage, August 2010 40
What is a modified source?

► Under the modified source provisions of the NSPS, an EGU is 

considered modified if it’s maximum hourly emissions of a regulated 

pollutant increase.

► Increase in hourly emissions (“hourly emissions test”) must result from a 

“physical or operational change.”

► Hourly emissions test is pollutant specific.

► Hourly emissions test looks back 5 years for the highest hourly rate 

“achievable.”

► The following are not, by themselves, considered modifications:

► Maintenance, repair, and replacement which the Administrator determines to 

be routine.

► An increase in production rate of an existing facility, if that increase can be 

accomplished without a capital expenditure on that facility.

► An increase in the hours of operation.

► Use of an alternative fuel or raw material if, prior to the date the standards 

become applicable to that source, the existing facility was designed to 

accommodate that alternative use.

41
What is a modified source? (cont.)

► We anticipate two types of scenarios in which 

the modified source provisions can be 

triggered:

► Modifications to the boiler significant enough to 

increase the amount of fuel that can be combusted

► Addition of control equipment that generates CO2

emissions

42
Options for Boiler Modifications

► Modifications to boilers significant enough to 

trigger the NSPS modification provision for 

criteria pollutants are rare

► Options for treatment of such modifications 

include:

► Efficiency improvements (because the action that 

triggered it would usually be related to a fairly 

significant over-haul, more aggressive efficiency 

improvements may be cost effective)

► Standards similar to the new source standards

43
Options for Modifications Due to 

Emission Control Installations

► Most emission controls do not chemically create 

GHGs.

► Particulate control devices such as baghouses and ESPs, and 

mercury control devices such as activated carbon injection do not 

result in chemically created greenhouse gases.

► Some sorbents used in SO2removal devices do 

result in chemically created GHGs.

► Sorbents such as lime (used in dry scrubbing applications and 

some sorbent injection applications) do not result in chemical 

creation of GHGs.

► Sorbents such as limestone (used in some wet scrubbing 

applications) and trona (used in some dry sorbent injection 

applications) do result in the chemical creation of greenhouse 

gases).

44
Options for Treatment of Emission Control 

Projects that Result in GHG Increases

► Treating like all other modifications

► Treating as a separate subcategory of modification

► Because such modifications often do not involve any 

modifications to the boiler or turbine, it might be appropriate to 

consider less aggressive efficiency measures

► Treating as an existing source

► Some stakeholders have suggested this option

► EPA is still evaluating the legal justification

► Using a different size threshold to define applicability 

for certain types of projects

45
Technology assessment

Modified and Existing Sources

46

• Efficiency improvements expected to be low cost

• Average payback is anticipated to be less than 3 years

• Improvements at existing coal facilities could reduce 

fleetwide GHG emissions by as much as 5% at 

relatively low capital costs. (Additional analysis needed 

to quantify $/tonne CO2 avoided costs.)

• Co-firing natural gas in existing coal boilers can provide 

added reductions, but incremental costs are approx. 

$60/ton of CO2(significantly more than NGCC) if plant 

not near a large gas pipeline.
Technology assessment

Modified and Existing Sources (cont.)

Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions 47

from Coal-Fired Electric Generating Units, October 2010

Efficiency Improvement 

Technology Description

Reported 

Efficiency 

Increase

Combustion Control 

Optimization

Adjustment of coal and air flow to optimize steam 

production for the generator 0.15 to 0.84%

Cooling System Heat Loss 

Recovery

Recovery of a portion of the heat loss from cooling water 

exiting the steam condenser 0.2 to 1%

Flue Gas Heat Recovery Recovery of the heat lost when flue gas is sprayed with flue 

gas desulfurization (FGD) reagent slurry and cools 0.3 to 1.5%

Low-rank Coal Drying Drying of subbituminous and lignite coals using waste heat 

from flue gas and/or cooling water systems 0.1 to 1.7%

Sootblower Optimization

Intermittent injection of high velocity gets of steam or air to 

clean coal ash deposits from boiler tube surfaces to 

maintain adequate heat transfer

0.1 to 0.65%

Steam Turbine Design

Maintain mechanical and physical condition of steam 

turbine through use of efficiently designed turbine blades 

and steam seals

0.84 to 2.6%

Efficiency Improvements for Existing Coal-Fired EGUs
Potential Impacts on Small Entities

► Costs are very site-specific

► Potential small entity impacts from emission guidelines include installation/use of efficiency 

improvement technologies for existing EGUs

► Cost varies from ~$3,000 to improve combustion via manual tuning w/parametric testing to ~$2.3 

million to recover heat via an economizer for a 650 MMBtu/hr boiler

48

Efficiency Improvement 

Technology Capital Costs Notes

Replace/Upgrade Burners $2,500 – 5,100 per MMBtu/hr Applicable to all boiler types

Improved combustion

Manual tuning w/parametric testing up to ~$3,000

Software-based system (optimization) $0.1 - $0.2 million

Digital controls (instrumentation/controls) >than $1 million

Applicable to all boiler types; 

typically only larger boilers use 

optimization or 

instrumentation/control systems 

Heat recovery Air preheater $20,000 - $25,000 per MMBtu/hr

Economizer for 650 MMBtu/hr boiler ~$2.3 million

Typically used in large boiler 

applications

Use of turbulators to create 

turbulence $10 - $15 per tube Only applicable to firetube boilers (primarily oil- or gas-fired)

Condensate return system ~$75,000 Applicable to all boiler types; 

typically used by larger boilers

Sootblowing system $50,000 - $125,000 Typically used by coal-fired boilers

Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Industrial, Commercial, and 

Institutional Boilers, October 2010

Efficiency Improvements for Existing EGUs
Potential Impacts on Small Entities 

(cont.)

► Potential small entity impacts for new coal-fired boilers

► New coal-fired supercritical plant with net power output of 800 MWe

► Capital costs of ~$2.7 billion

► Annual cost of ~$0.5 billion/year

► New IGCC plant with net power output of 800 MWe 

► Capital costs of ~$3.5 billion

► Annual cost of ~$0.6 billion/year

Sources: Sargent & Lundy Final Report – Coal 49 -Fired Power Plant Heat Rate Reductions, January 2009; EPA White Paper –

Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal-Fired Electric Generating Units, October 2010

Efficiency Improvement Technology Heat Reduction, 

Btu/kWh Capital Cost, $

Installation of Neural Network process 

controls 25 0.5 million

Installation of new air heaters 92 2.0 million

Steam turbine upgrade 255 10.2 million

Improve steam turbine seals 15 0.3 million

Overhaul/upgrade of boiler feed pump 37 0.3 million

Total 424

~4% from base heat rate 13.3 million

Case Study: 250-MW pulverized coal plant with heat rate of 9,930 Btu/kWh
Compliance & Monitoring

► Considering a lb/MW-hr based standard

► Considering use of emission averaging

► Believe that Part 75 requirements provide a good 

framework

► CO2 monitoring

► Output monitoring

► Data management

► Considerations related to current data

► Quality of output data

► Use of data for annual reporting requirement to support shorter 

term compliance requirement

► Potential for averaging across units

50
Key Questions

► What should emission limits for new sources be based on?

► What should emission limits for modified sources be based on?

► What should emission limits for existing sources be based on?

► What regulatory mechanisms should be used to get reductions?

► How should State equivalency with guidelines be addressed?

51
Summary of Listening Sessions

► Electric Power Industry

► Allow for fleet wide averaging

► Give credit for replacement of older less efficient generation

► Coalition Groups

► Allow for State programs to be deemed equivalent

► Provide market-based flexibility

► Recognize early action

► State and Tribal Representatives 

► Allow for State programs to be deemed equivalent

► Reward the very best possible systems available

► Take a multi-pollutant approach

► Environmental and Environmental Justice 

► Allow for State programs to be deemed equivalent

► Recognize environmental benefit of non-emitting technologies

► No special considerations for biomass

► Aggressive GHG approach will reduce other pollutants as well

52
Questions for SERs

► Applicability

► Is EPA’s description of applicability of these standards on slides 29-31 

appropriate?

► Should applicability include stationary combustion turbines (combined 

cycle gas turbines and simple cycle gas turbines)?

► Current Practices

► 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? 

53
Questions for SERs (cont.)

► Appropriate Control Levels for New Sources 

► Should new source standards be based on fuel and technology specific 

efficiency standards based on the best performing coal units being 

permitted/ built (e.g., IGCC and/or ultra-supercritical coal)?

► Alternatively, should tighter standards that require new coal units to go 

beyond technologies such as IGCC and ultra-supercritical coal and be 

designed/built to perform at lower CO2/MWh levels be considered?

► Given the existence of generation alternatives such as natural gas combined 

cycle and renewables, tighter standards could be based on the use of 

technologies such as co-firing of lower carbon fuels, integration of 

renewables or the use of some level of CCS.

► Should new source standards include emission rate averaging?

► Should the new source standards be fuel neutral (i.e., standards would 

not be fuel or technology specific but instead would be based on use of 

lower GHG fuels such as natural gas)?

54
Questions for SERs (cont.)

► Should EPA consider a phased approach where a fuel and technology 

specific standard based on existing technologies would apply initially 

and, after several years, a tighter standard would apply?

► Are there other options that should be considered?

► Appropriate Control Levels for Modified Sources

► Will compliance with other regulations impacting the power sector cause 

EGUs to become modified sources subject to the GHG standards?

► How should modified sources be addressed in the GHG standards?

► Should modified source standards be based on efficiency 

improvements?

► Alternatively, given that the modifications are likely to involve more 

significant changes to the boiler and/or turbine, is it appropriate to 

consider other options such as fuel switching or co-firing with lower 

carbon fuels?

► Are there other options that should be considered (e.g. different 

applicability thresholds)?

55
Questions for SERs (cont.)

► Appropriate Control Levels for Existing Sources 

► Should existing source guidelines be based on efficiency 

improvements?

► What is an appropriate heat rate reduction to require for existing EGUs?

► Should replacement of older generation be part of the guidelines?

► Should there be a linkage between remaining useful life and tightened 

standards?

► Should guidelines be based on a system wide generation performance 

standard that would decrease as there was fleet turnover?

► Should EPA consider a phased approach where a fuel and technology 

specific efficiency standard based on existing technologies would apply 

initially and, after several years, a tighter standard would apply?

► Should other options such as fuel switching or co-firing with lower 

carbon fuels be considered?

► Should States incorporate considerations of fleet turnover when 

considering potential GHG reductions?

► Are there other options that should be considered?

56
Questions for SERs (cont.)

► Mechanisms to Get Emissions Reductions

► Do output based standards (e.g. lbs/MWh) make sense? ? 

► Does a net output based standard make sense for new facilities?

► Should emission averaging be allowed?

► Traditionally new source standards have been set at the individual unit level.

► If EPA considers alternatives, should different approaches for new, modified 

and existing sources be considered?

► Should all generating sources (e.g., renewables, nuclear) be included?

► Over what universe of sources should emissions averaging be considered?

– Within a facility

– Within a State

– Within a company within a State

– Within a company across State lines

– Across state lines

► Should other alternatives be considered?

► Should EPA develop a model rule that States can follow or just develop 

general guidelines? 

► How should useful thermal output from CHP be credited?

57
Questions for SERs (cont.)

► State Equivalency With the Emission Guidelines

► Should EPA set a more prescriptive set of requirements or a more 

general set of principals?

► Are there certain types of programs that should (or should not) be 

allowed?

► Programs that allow crediting of reductions from, or averaging with, nonaffected sources (e.g., generation performance standards or California’s AB32 program)

► Programs that allow crediting of reductions from, or averaging with, sources 

in other States (e.g., the RGGI program)

► Are there other important factors for EPA to address as it sets forth 

criteria for demonstrating equivalency?

58
Questions for SERs (cont.)

► Compliance, Monitoring, Recordkeeping & Reporting

► Should fewer requirements be placed on low mass emission units?

► If so, what should those requirements be?

► Are there compliance and monitoring alternatives that would simplify the 

requirements?

► Are there recordkeeping and reporting alternatives that would simplify the 

requirements?

► How should useful thermal output from CHP facilities be monitored?

59
Questions for SERs (cont.)

► Issues that may Impact Control Options

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

EPA should consider and why?

► What type of size cut-off, if any, do you think EPA should consider and 

why?

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

should consider?

60
Additionally, OMB and SBA are 

interested in SERs’ views on:

► The use of alternative applicability thresholds (e.g. 50 MWs 

instead of 25 MWs)

► Alternative ways to address modified sources

► How should EPA choose between the regulatory alternatives 

offered?

► What factors should EPA consider?

► What emissions benefits should be included in EPA’s consideration -

just GHGs or all pollutants that would be reduced by either reducing fuel 

utilization or the decommissioning of facilities?

► Should EPA establish an economy-wide emissions goal, an energyintensity goal, or a cost-effectiveness goal for GHG emissions 

reductions?

61
Additionally, OMB and SBA are 

interested in SERs’ views on: (cont.)

► Should EPA establish a cost-effectiveness benchmark for 

energy efficiency or other technological improvements at each 

unit?

► For example, if the social cost of carbon is currently approximately 

$20/ton (understanding that under current guidance this would grow 

over time), should EPA only require improvements at any particular unit 

that cost less than $20/ton CO2 equivalent (CO2e)?

► Should the cost of improvements be based on case-by-case 

engineering evaluations or economy-wide projections?

► Should EPA establish a cost-effectiveness benchmark for energy 

efficiency or other technological improvements for the economy as a 

whole?

► If not $20/ton or the social cost of carbon, what other monetary 

benchmark could be used?

62
Additionally, OMB and SBA are 

interested in SERs’ views on: (cont.)

► Should EPA establish a system of CO2e credits and trading 

among EGUs? Among a broader set of industries and/or 

sources?

► What should credits represent - allowances or emission reductions?

► If allowances, how should the supply of allowances be set? Be 

allocated?

► If emissions reductions, how should EPA establish emissions 

benchmarks?

► Are there any reasons - legal, practical or competitive - that a 

trading scheme should be restricted?

► Should EPA adopt the Best Available Control Technology 

(BACT) guidance as Best Demonstrated Technology (BDT) for 

new and existing sources and rely on case-by-case evaluation 

of facilities for cost-effective improvements?

63
Small Entity Definitions

► 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

64
Identification of Small Entities

► Small entities identified as potentially being impacted by the Toxics 

Rule proposal would also be potentially impacted by the proposed 

GHG rulemaking.

► In addition, small entities that own gas-fired EGUs would be 

potentially impacted.

► 101 small entities estimated

► Small government: 65

► Small non-government: 36

► See Appendix B for list of potentially impacted small entities

65
Potentially Affected Small Entities

Alexandria, LA (City of) East Texas Electric Coop, Inc. Marquette Board of Light & Power Sikeston Utilities

Algona Municipal Utilities Eldridge, IA (City of) Massachusetts Municipal Wholesale Electric Co. South Mississippi Electric Power 

Association

Alta, IA (City of) Farmington, NM (City of) Mid-Kansas Electric Co. Southern Illinois Power Coop

American Consumer Industries, Inc. Fremont Dept. of Public Utilities Milford Municipal Utilities Southern Minnesota Municipal Power 

Agency

American Consumers, Inc. Geneseo Municipal Utilities Minnkota Power Coop Spencer Municipal Utilities

American Hydropower Company Gilberton Power Co. Missouri River Energy Services Square Butte Electric Coop

American Power Investors, Inc. Graettinger Municipal Light Plant Modesto Irrigation District Sumner Municipal Light Plant

Arizona Electric Power Coop Grand Haven Light & Power Montezuma Municipal Utilities Sunflower Electric Power Coop

Atlantic Municipal Utilities Grand Island Utilities Morgan City, LA (City of) Tipton, IA (City of)

Austin Utilities Greenville Electric Utility System Municipal Energy Agency of Nebraska Tondu Corp.

Azusa, CA (City of) Harlan Municipal Utilities Muscatine Power & Water US Renewables Group

Bancroft Municipal Utilities Hastings Utilities (NE) National Energy & Gas Transmission Utah Associated Municipal Power System

Banning Electric Division Heartland Consumers Power District New Hampton Municipal Light Plant Vero Beach Municipal Utilities

Beowulf Energy LLC Henderson Municipal Power & Light North American Power Group Ltd. Wabash Valley Power Association, Inc.

Brazos Electric Power Coop Holland Board of Public Works North Attleborough Electric District Waverly Light & Power

Cedar Falls (IA) Utilities Holyoke Gas & Electric Dept. Northeast Texas Electric Coop, Inc. Webster City, IA (City of)

Central Electric Power Coop MO Jonesboro Water & Light Northwest Iowa Power Coop West Bend, IA (City of)

Central Iowa Power Coop KAMO Electric Coop, Inc. Old Dominion Electric Coop West Memphis Utility Dept.

Central Vermont Public Service Corp. Kansas Electric Power Coop Osceola, AR (City of) Western Farmers Electric Coop

Coffeyville Municipal Light & Power Lafayette Public Power Authority Pacific Northwest Generating Coop Winfield, KS (City of)

Colstrip Energy LP Laurens, IA (City of) Pella Municipal Light & Power Wolverine Power Supply Coop, Inc.

Coon Rapids, IA (City of) Littleton, MA (Town of) Platte River Power Authority WPPI Energy

Corn Belt Power Coop Los Alamos County Ponca City, OK (City of) Wyandotte Dept. of Municipal Service

Dalton, GA (City of) Louisiana Energy & Power Authority Richmond Power & Light

Dover, DE (City of) Lyndonville Electric Dept. Sam Rayburn G & T Electric Coop, Inc.

East Power Corporation Manitowoc Public Utilities San Miguel Electric Coop, Inc. 66
SERs

Entity

1 Bancroft Municipal Utilities*

2 Colstrip Energy LP*

3 Central Iowa Power Cooperative*

4 Coffeyville Municipal Light & Power

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 Mid-Kansas Electric Company (operated by Sunflower Electric)

13 Montezuma Municipal Utilities*

14 Morgan City (operated by Louisiana Energy & Power Authority)

15 Muscatine Power & Water*

16 San Miguel Electric Cooperative, Inc.*

17 Southern Illinois Power Cooperative*

18 Tes Filer City Station Power Plant (Tondu Corp.)*

19 Texas Municipal Power Agency*

20 Wyandotte Municipal Services*

67

*SER for Panel on Toxics Rule

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 Leads: Christian Fellner

919-541-4003

fellner.christian@epa.gov

SBAR Panel Contacts: Mary Johnson

919-541-5025

johnson.mary@epa.gov

Project Oversight: Bob Wayland

919-541-1045

wayland.robertj@epa.gov

68

Nick Hutson

919-541-2968

hutson.nick@epa.gov

Lanelle Wiggins

202-566-2372

wiggins.lanelle@epa.gov

Kevin Culligan

202-564-0611

culligan.kevin@epa.gov