# 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 ► CO 2 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 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 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 CO 2 5100.2 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 CH 4 674.9 659.9 686.5 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 CO 2 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 N 2O 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 SF 6 34.4 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 CO 2 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 CO 2 equivalent) Gas/Source Type 1990 2000 2009 CO 2 4903.6 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 CO 2 equivalent) Gas/Source Type 1990 2000 2009 CH 4 327.4 318.6 337.0 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 N 2O 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
► CO 2 emissions from fossil fuel combustion are ~99.5% of total GHG emissions from fossil fuel combustion (2009) ► CO 2 emissions from coal -fired combustion are ~81% of total CO 2 emissions from fossil fuel combustion (2009)

17

Gas/Source Type 1990 2000 2009 CO 2 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 CH 4 Stationary Combustion 0.6 0.7 0.7 N 2O Stationary Combustion 8.1 10.0 9.0 

## Electricity Generation - Related GHG Emissions

(million metric tons of CO 2 equivalent)

# Power Sector: A Major Share of U.S. GHG Emissions

18



### 3.9 Billion Tons 60% 2.6 Billion Tons 40% 

## Carbon Dioxide (CO 2

## ), 2008 6.5 Billion Tons

Electric Power Other Sectors

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 -2008 (2010) (CO 2) “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 SO 2 

## , 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
► 

## 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 turbine generators. ► 

## 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 gasi fication 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 steam boilers are co vered 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

# CO 2 

# Emissions Control Technologies

► 

## General types of control measures for CO 2 

## emissions:
► 

## Energy efficiency ► 

### Reduce the amount of fuel used by improving the efficiency of the electrical generation process ► 

## Post- combustion ► 

### Separate the CO2 

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

36 Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal- Fired Electric Generating Units, October 2010

# Technology assessment 

# New sources – costs and emissions ► 

# Table on next slide shows costs and CO 2 

# 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 CO 2 

# . ► 

# 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 $4.00/MMBtu; all units base loaded at 85% annual capacity factor; CO 2 capture removes 90% of CO 2 ; costs are 2009 market prices in 2007$.



## Avoided CO 2 

## Cost vs. Existing Coal Boiler (avg.) Technology Option Thermal Efficiency CO 2

Emission Capital

Cost Generating

Cost (total) Avoided

CO 2 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 CO 2 

## Cost 1. Assumed thermal efficiencies and CO 2 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 + CO 2 capture : Expected to be demonstrated at full size in U.S. this decade. Assumes $15/tonne for CO 2 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 CO 2 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 CO 2 

### from 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 CO 2 

### pipeline or geologic storage. ► 

## Existing Federal programs are being used to deploy at least five to ten large scale 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.
40 Source: Report of the Interagency Task Force on Carbon Capture and Storage, August 2010

# 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 CO 2 

# 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 SO 2 

# removal 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 CO 2 

# avoided costs.)

• Co-firing natural gas in existing coal boilers can provide added reductions, but incremental costs are approx. $60/ton of CO 2 

# (significantly more than NGCC) if plant not near a large gas pipeline.

# Technology assessment 

# Modified and Existing Sources (cont.)

47 Source: EPA White Paper - Available and Emerging Technologies for Reducing Greenhouse Gas Emissions 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 I ntermittent 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 M aintain 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 49 Sources: Sargent & Lundy Final Report
– Coal-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 20 10

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 CO 2

## /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, non affected sources (e.g., generation performance standards or California’s AB 32 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 CO 2 

## equivalent (CO 2

## e)? ► 

## 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 CO 2

## e 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