Rulemaking for Greenhouse Gas Emissions

from Electric Utility Steam Generating Units

April 12, 2011

Ariel Rios North

Room 1332

POC: Mary Johnson

E.O. 13132 “Federalism” Consultation Meeting
Agenda

► Background

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

► Summary of Listening Sessions

► Section 111 Overview

► Section 111 versus Section 112

► Definition of EGU

► Affected Facilities

► CO2 Emissions Emissions Control Control Technologies Technologies

► Key Issues

► State/Local Implementation

► Questions/Comments

► Appendix A 

► What are Greenhouse Gases?

► GHG Emissions Across Sectors

► GHG Emissions – Energy Sector

► GHG Emissions – Electricity Generation

► Appendix B – State & Local Governments 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
Power Sector:

A Major Share of U.S. GHG Emissions

2.6 Billion Tons

40%

Carbon Dioxide (CO2), 2008

6.5 Billion Tons

Electric 

Power

Other 

Sectors

► See Appendix A for additional details

4

3.9 Billion Tons

60%

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
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

5
Section 111 Overview

► 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.

► NSPS affect 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: Exempt: Routine maintenance, Routine maintenance, repair, repair, and replacement and replacement and increased and increased hours of 

operation

► 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 is referred to as best demonstrated technology (BDT).

► NSPS does not require installation and operation of any particular technological 

system of continuous emission reduction (except as authorized under CAA 

section 111(h)).

6
Section 111 Overview (cont.)

► Emission guidelines are established for existing sources 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.

► Guidelines include targets based on demonstrated controls, emission reductions, 

costs and expected timeframes for installation and compliance.

► Guidelines can be less stringent than the requirements for new sources.

► States use the emission guidelines to develop plans for reducing emissions from 

existing sources.

► 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.

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

sources for the purpose of establishing standards.

7
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 wouldn’t be a basis for using this authority in the proposed 

rulemaking for GHG emissions from EGUs

8
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) standards developed by EPA do not directly 

impact existing sources. States use the standards as guidelines in 

establishing implementation plans with standards of performance 

that apply to those sources.

9
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 of its potential electric output capacity capacity and more 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.

10
Affected Facilities

Coal, 48%

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 Oil, 1%

► 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

11
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)

12
Affected Facilities (cont.)

► The regulations would not apply to stationary combustion turbines 

(combined cycle gas turbines or simple cycle gas turbines).

► 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.

► State/local jurisdictions identified as potentially impacted by the Toxics 

Rule would also be potentially impacted by the GHG rulemaking.

► Jurisdictions with gas-fired EGUs also would be potentially impacted.

► 123 State/local jurisdictions are estimated to own EGUs that may be 

affected by this action.

► See Appendix B for list of potentially impacted State/local jurisdictions

13
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.

14
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

15
Efficiency Improvements for Existing EGUs

Efficiency Improvement 

Technology Description EfficiencyIncrease

Replace/Upgrade Burners

Replacement or upgrade of older, incorrectly sized, or 

mechanically deteriorated burners and inoperable dampers, 

broken registers, or clogged nozzles

Up to ~5%

Improved combustion

Tuning of combustion system to optimum settings and 

use/adjustment of instrumentation (e.g., temperature 

sensor, oxygen monitor, excess air setting, CO monitor)

~0.5 to 3%

Heat recovery

Use of heat from boiler exhaust to preheat incoming Up to ~6%

Efficiency Improvements for Existing EGUs

16

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

from Industrial, Commercial, and Institutional Boilers, October 2010

Heat recovery

Use of heat from boiler exhaust to preheat incoming 

combustion air or to preheat boiler feedwater Up to ~6%

Reduce air leakages

Maintenance of boiler system to minimize air leakage 

through routine maintenance procedures and monitoring of 

indicators of air leakage (e.g., oxygen level, fuel 

consumption, gas temperature)

~1.5 to 3%

Capture energy from 

boiler blowdown

Recovery of waste heat (low-pressure steam) from 

blowdown

~1 to 2%

Reduce slagging & fouling 

of heat transfer surfaces

Operation within boiler’s design parameters (including fuel 

quality), use of cleaning system (soot blower - air or steam 

is used to periodically remove deposition on boiler walls and 

tubes), and/or fuel treatment (modifies ash characteristics)

1% to 3%
Efficiency Improvements for Existing

EGUs ( cont.)

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%

Efficiency Improvements for Existing Coal-Fired EGUs

17

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

from Coal-Fired Electric Generating Units, October 2010

Recovery exiting the steam condenser

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 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 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 18

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 Several advanced pre-combustion coal drying technologies combustion coal drying technologies are or nearly 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- 19

Fired Electric Generating Units, October 2010
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 Ta 20 sk Force on Carbon Capture and Storage, August 2010
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?

21
State/Local Implementation

► Envision implementation of the guidelines as similar to what 

State/local jurisdictions are already used to under the SIP process

► This includes:

► Development of a State plan consistent with the emissions guidelines

► Implementation of that plan, including permitting and enforcement

22
Questions?

Project Lead: Christian Fellner

919-541-4003

fellner.christian@epa.gov

Federalism Contacts: Mary Johnson

919-541-5025

johnson.mary@epa.gov

Andrew Hanson

Project Oversight: Bob Wayland

919-541-1045

wayland.robertj@epa.gov

23

Andrew Hanson

202-564-3664

Hanson.andrew@epa.gov

Kevin Culligan

202-564-0611

culligan.kevin@epa.gov
Appendix A
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).

A-1
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

A-2
GHG Emissions Across Sectors 

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

GHG Emissions in U.S.

(million metric tons of CO2 equivalent)

A-3

Incineration of Waste 8 11.1 12.3

Amonia 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

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.) 

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

GHG Emissions in U.S. (cont.)

(million metric tons of CO2 equivalent)

A-4

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

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.) 

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

GHG Emissions in U.S. (cont.)

(million metric tons of CO2 equivalent)

A-5

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 - Energy Sector

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

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

A-6

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.)

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

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

A-7

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

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

Electricity Generation-Related GHG Emissions

(million metric tons of CO2 equivalent)

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)

A-8

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
Appendix B
State & Local Governments Potentially 

Subject to Regulation 

tings Utilities (NE)

Alexandria, LA (City of) Conway Corp Hastings Utilities (NE)

Algona Municipal Utilities Coon Rapids, IA (City of) Heartland Consumers Power District

Alta, IA (City of) CPS Energy Henderson Municipal Power & Light

American Municipal Power Inc Dalton, GA (City of) Holland Board of Public Works

Ames Municipal Electric System Detroit Public Lighting Holyoke Gas & Electric Dept

Anaheim, CA (City of) Dover, DE (City of) Illinois Municipal Electric Agency

Atlantic Municipal Utilities Eldridge, IA (City of) Imperial Irrigation District

Austin Energy Farmington, NM (City of) Indiana Municipal Power Agency

Austin Utilities Florida Municipal Power Agency Intermountain Power Agency

Azusa, CA (City of) (City of) Fremont Fremont Dept of Public Utilities of Public Utilities JEA

Bancroft Municipal Utilities Gainesville Regional Utilities Jonesboro Water & Light

Banning Electric Division Garland Power & Light Kansas City Board Public Utilities

Brownsville Public Utility Board Geneseo Municipal Utilities Kissimmee Utility Authority

Bryan Texas Utilities Glendale Water & Power Lafayette Public Power Authority

Burbank Water & Power Graettinger Municipal Light Plant Lafayette Utilities System

California Dept Water Resources Grand Haven Light & Power Lakeland Dept of Electric Water Utilities

Cedar Falls (IA) Utilities Grand Island Utilities Lansing Board of Water & Light

Coffeyville Municipal Light & Power Grand River Dam Authority Laurens, IA (City of)

Colorado Springs Utilities Greenville Electric Utility System Lincoln Electric System

Colton Electric Utility Dept Harlan Municipal Utilities Littleton, MA (Town of)

B-1
State & Local Governments Potentially 

Subject to Regulation (cont.) 

Los Alamos County New York Power Authority Southern Minnesota Municipal Power Agency

Los Angeles Dept of Water & Power North Attleborough Electric Dept Spencer Municipal Utilities

Louisiana Energy & Power Authority North Carolina Eastern Municipal Power Agency Springfield, MO (City of)

Lower Colorado River Authority Northern Municipal Power Agency Springfield (IL) Water Light & Power Dept

Lubbock Power & Light Dept Oklahoma Municipal Power Authority Sumner Municipal Light Plant

Lyndonville Electric Dept Omaha Public Power District Tallahassee, FL (City of)

Manitowoc Public Utilities Orlando Utilities Commission Taunton Municipal Lighting Plant

Marquette Board of Light & Power Osceola AR (City of) Terrebonne Parish Consolidated

Massachusetts Municipal Wholesale Electric Owensboro Municipal Utilities Texas Municipal Power Agency

Michigan Michigan Public Power Agency Public Power Agency Pasadena Pasadena Water & Power Dept & Power Dept Tipton, Tipton, IA (City of) IA (City of)

Michigan South Central Power Agency Pella Municipal Light & Power Utah Associated Municipal Power System

Milford Municipal Utilities Platte River Power Authority Utah Municipal Power Agency

Missouri River Energy Services Ponca City, OK (City of) Vero Beach Municipal Utilities

Modesto Irrigation District Provo City Corp Waverly Light & Power

Montezuma Municipal Utilities Redding Electric Utility Webster City, IA (City of)

Morgan City, LA (City of) Richmond Power & Light West Bend, IA (City of)

Municipal Electric Authority of Georgia Rochester Dept Public Utilities West Memphis Utility Dept

Municipal Energy Agency of Nebraska Salt River Project Winfield, KS (City of)

Muscatine Power & Water Santa Clara, CA (City of) WPPI Energy

Nebraska Public Power District Santee Cooper Wyandotte Dept of Municipal Service

New Hampton Municipal Light Plant Sikeston Utilities Wyoming Municipal Power Agency

B-2
Regulatory Compliance Obligations

for the Utility Industry

B-3