Benchmarking Air Emissions Benchmarking Air... · Th e 2008 Benchmarking report is the sixth collaborative eff ort highlighting environmental performance and progress in the nation’s

Benchmarking Air Emissions

MAY 2008

OF THE 100 LARGEST ELECTRIC POWER PRODUCERS IN THE UNITED STATES

Benchmarking Air EmissionsOF THE 100 LARGEST ELECTRIC POWER PRODUCERS IN THE UNITED STATES

MAY 2008

40 West 20 StreetNew York, NY 10011212 727 2700

www.nrdc.org

99 Chauncy Street 6th FloorBoston, MA 02111617 247 0700

www.ceres.org

80 Park PlazaNewark, NJ 07102973 430 7000

www.pseg.com

One Market Street Spear Tower, Suite 2400San Francisco, CA 94105415 267 7070

www.pgecorp.com

cvanatten

Data Tables Last Updated on May 13, 2008

EXECUTIVE SUMMARY iII

Contents

Acknowledgments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv

Preface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Electric Industry Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Heightened Focus on Climate Change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Emissions of the 100 Largest Electric Power Producers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Allowance Distribution Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Use of the Benchmarking Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Appendices

A: Data Sources, Methodology and Quality Assurance . . . . . . . . . . . . . . . . . . . . . . . . . . 68B: SO2, NOx and Mercury Emission Reduction Programs . . . . . . . . . . . . . . . . . . . . . . . 73C: State and Regional Climate Initiatives and Federal Climate Change Legislation . . . . 76

Endnotes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

iv BENCHMARKING AIR EMISSIONS

Acknowledgments

REPORT AUTHORSChristopher Van Atten, M.J. Bradley & Associates, Inc.Th omas Curry, M.J. Bradley & Associates, Inc.Amlan Saha, M.J. Bradley & Associates, Inc.

REPORT DESIGNDouglas Ekstrand, Art and Anthropology, Inc.

CONTRIBUTORSDan Bakal, CeresDan Mullen, CeresDonald McCloskey, PSEGDaniel Cunningham, PSEGAmy Martin, PSEGMarisa Uchin, PG&E CorporationMelissa Lavinson, PG&E CorporationDan Lashof, NRDCElizabeth Martin-Perera, NRDC

Th is report is the product of a collaborative eff ort among Ceres, the Natural Resources Defense Council (NRDC), Public Service Enterprise Group (PSEG), and PG&E Corporation. Th e project partners would like to acknowledge and thank the following people who made this report possible. Ceres’s participation in this eff ort was made possible by generous grants from the Blue Moon Fund and the Richard and Rhoda Goldman Fund. NRDC’s participation was made possible by the support of the Public Welfare Foundation.

Mixed SourcesProduct group from well-managedforests and recycle wood or fi ber

www.fsc.org Cert no. SW-COC-0000© 1996 Forest Stewardship Council

SW-COC-002387

EXECUTIVE SUMMARY v

Th e 2008 Benchmarking report is the sixth collaborative eff ort highlighting environmental performance and progress in the nation’s electric power sector. Th e Benchmarking series began in 1997 and uses publicly reported data to compare the emissions performance of the 100 largest power producers in the United States. Th e current report is based on 2006 generation and emissions data.

Data on U.S. power plant generation and air emissions are available to the public through several databases maintained by state and federal agencies. Publicly- and privately-owned electric generating companies are required to report fuel and generation data to the Energy Information Administration (EIA). Most power producers are also required to report air pollutant emissions data to the U.S. Environmental Protection Agency (EPA). Th ese data are reported and recorded at the boiler, generator, or plant level, and must be combined and presented so that company-level comparisons can be made across the industry.

Th e Benchmarking report facilitates the comparison of emissions performance by combining generation and fuel consumption data compiled by the EIA with emissions data on sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2) and mercury compiled by the EPA; error checking the data; and presenting emissions information for the nation’s 100 largest power producers in a graphic format that aids in understanding and evaluating the data. For the fi rst time, this year’s report also examines the implications of alternative scenarios for allocating emissions allowances under proposed federal legislation to cap and reduce CO2 emissions. Th e report is intended for a wide audience, including electric industry executives, environmental advocates, fi nancial analysts, investors, journalists, power plant managers, and public policymakers.

Th e report is available in PDF format on the Internet at http://www.ceres.org and http://www.nrdc.org. Plant and company level data used in this report are available on the Internet at http://www.nrdc.org.

For questions or comments about this report, please contact: Christopher Van Atten M. J. Bradley & Associates, Inc. 47 Junction Square Drive Concord, MA 01742 Telephone: 978 369 5533 E-mail: [email protected]

Preface

EXECUTIVE SUMMARY 1

Th is report examines and compares the air pollutant emissions of the 100 largest power producers in the U.S. based on 2006 plant ownership and emissions data. Table ES.1 lists the 100 largest power producers featured in this report ranked by their total electricity generation from fossil fuel, nuclear, and renewable energy facilities. Th ese producers include public and private entities (collectively referred to as “companies” or “producers” in this report) that own nearly 2,300 power plants and account for 85 percent of reported electric generation and 86 percent of the industry’s reported emissions in the U.S.

Th e report focuses on four power plant pollutants for which public emissions data are available: sulfur dioxide (SO2), nitrogen oxides (NOx), mercury, and carbon dioxide (CO2). Th ese pollutants are associated with signifi cant environmental and public health problems, including acid deposition, global warming, fi ne

Executive Summary

TABLE ES.1

100 Largest Electric Power Producers in the U.S., 2006

RANK PRODUCER NAME2006 MWh

(millions) RANK PRODUCER NAME2006 MWh



(millions)

1 Southern 201.7 26 AES 42.4 51 IDACORP 16.1 76 PNM Resources 9.9 2 AEP 187.2 27 E.ON 42.2 52 Sempra 15.9 77 Integrys 9.5 3 Tennessee Valley Authority 155.0 28 Reliant 36.7 53 NiSource 15.5 78 Energy Northwest 9.4 4 Duke 152.7 29 PG&E 33.2 54 US Power Generating Company 15.1 79 Buckeye Power 9.2 5 Exelon 152.5 30 Pinnacle West 32.9 55 JEA 14.7 80 PUD No 1 of Chelan County 9.1 6 FPL 138.5 31 CMS Energy 30.2 56 Intermountain Power Agency 14.5 81 Puget Energy 8.5 7 Entergy 115.0 32 Wisconsin Energy 29.0 57 Sierra Pacifi c 13.8 82 Hoosier Energy 8.2 8 Dominion 103.5 33 New York Power Authority 27.3 58 Los Angeles City 13.7 83 Occidental 8.2 9 Progress Energy 92.9 34 Westar 26.0 59 Tri-State 12.7 84 SUEZ Energy 8.2

10 FirstEnergy 83.8 35 SCANA 25.0 60 Municipal Elec. Auth. of GA 12.7 85 Chevron 8.0 11 Xcel 79.9 36 Tenaska 23.9 61 National Grid 12.4 86 Avista 7.8 12 Calpine 79.5 37 Salt River Project 23.6 62 Dow Chemical 12.1 87 Aquila 7.8 13 Edison International 79.3 38 International Power 23.3 63 Austin Energy 11.9 88 Brazos Electric Power Coop 7.8 14 Ameren 79.3 39 OGE 22.3 64 Seminole Electric Coop 11.7 89 Portland General Electric 7.4 15 NRG 76.9 40 Mirant 22.3 65 Omaha Public Power District 11.3 90 International Paper 7.4 16 MidAmerican 76.0 41 San Antonio City 22.0 66 CLECO 10.9 91 Sacramento Municipal Util Dist 7.2 17 TXU 69.6 42 Santee Cooper 21.9 67 East Kentucky Power Coop 10.9 92 TransAlta 7.0 18 US Corps of Engineers 69.1 43 Oglethorpe 21.5 68 UniSource 10.8 93 Seattle City Light 6.7 19 PSEG 62.7 44 Great Plains Energy 20.5 69 Arkansas Electric Coop 10.5 94 Hawaiian Electric Industries 6.6 20 PPL 52.0 45 TECO 18.2 70 Great River Energy 10.4 95 CA Dept. of Water Resources 6.5 21 Constellation 49.0 46 Alliant Energy 18.0 71 Lower CO River Authority 10.3 96 El Paso Electric 6.4 22 US Bureau of Reclamation 47.8 47 Associated Electric Coop 18.0 72 Goldman Sachs 10.1 97 North Carolina Mun Power Agny 6.3 23 Allegheny Energy 46.8 48 NE Public Power District 17.4 73 PUD No 2 of Grant County 10.0 98 ALLETE 6.1 24 Dynegy 44.4 49 DPL 17.2 74 Exxon Mobil 9.9 99 Big Rivers Electric 6.0 25 DTE Energy 42.9 50 Basin Electric Power Coop 16.4 75 Entegra Power 9.9 100 Vectren 6.0

2 BENCHMARKING AIR EMISSIONS

particle air pollution, mercury deposition, nitrogen deposition, ozone smog, and regional haze. Th e report benchmarks, or ranks, each company’s absolute emissions and its emission rate (determined by dividing emissions by electricity produced) for each pollutant against the emissions of the other companies.

A key focus of the report is CO2 emissions, which are under increased scrutiny due to growing national and international concern about the threat of climate change. Th e U.S. Congress is currently considering the establishment of a national “cap-and-trade” system for regulating CO2 emissions from power plants and other industrial sources. Under a cap-and-trade system, a limit is placed on the overall emissions from covered sources by requiring power plant operators and other regulated sources to surrender “allowances” for the greenhouse gases they release to the atmosphere, and by limiting the number of allowances available each year. An allowance is a permit to emit a discrete quantity of greenhouse gases (e.g., one ton of CO2). Companies can trade or hold allowances for future use, but at the end of each compliance period they must surrender allowances equal to their emissions.

Th is report evaluates diff erent options for allocating emissions allowances within the electric power sector, including options for distributing allowances to electric power producers and local electric utilities for consumer benefi t. Th is analysis is intended to help inform the ongoing policy debate, as well as educate investors and companies which face potential fi nancial risks from foreseeable CO2-reducing regulations.

Major Findings

Electric Industry Emission TrendsSince 1990, power plant emissions of SO2 and NOx have decreased and CO2 emissions have increased.

• SO2 and NOx emissions from power plants have decreased since 1990 due in large part to pollution-reducing regulatory programs implemented under the 1990 Clean Air Act Amendments. In 2006 power plant SO2 emissions were 40 percent lower and NOx emissions were 46 percent lower than they were in 1990.

• CO2 emissions from power plants are not currently regulated at the federal level. According to EPA’s greenhouse gas inventory, in 2006, power plant CO2 emissions were 29 percent higher than they were in 1990. Congress is currently considering legislation that would limit CO2 emissions

EXECUTIVE SUMMARY 3

from power plants and other sources of greenhouse gas emissions, and the U.S. Supreme Court found in April 2007 that the U.S. Environmental Protection Agency (EPA) has clear statutory authority to regulate greenhouse gases (Massachusetts v. EPA), opening up the possibility for regulation of power plant greenhouse gas emissions under existing Clean Air Act authority.

Power plants have only recently begun to report their mercury emissions; therefore, long-term emissions trends are not available.

Overall Emissions from ElectricityTh e electric industry in the U.S. is a major source of air pollution.

• In 2006, power plants were responsible for 70 percent of SO2 emissions, 20 percent of NOx emissions, 68 percent of mercury air emissions, and 40 percent of CO2 emissions in the U.S..

• Th e electric industry accounts for more CO2 emissions than any other sector, including the transportation and industrial sectors.

Air Pollution Rankings and ComparisonsTh e 100 largest power producers generated 85 percent of electric power in the U.S. in 2006. Th e 100 largest producers generated 96 percent of all nuclear power, 90 percent of all coal-fi red power, 84 percent of all hydroelectric power, 73 percent of all natural gas-fi red power, and 47 percent of all non-hydroelectric renewable power.

Air pollution emissions from power plants are highly concentrated among a small number of producers. For example, the three largest producers are responsible for 25 percent of the electric power industry’s SO2 emissions and six producers contribute 25 percent of CO2 emissions. Figure ES.1 summarizes the distribution of emissions among electric power producers.

0%

25%

50%

75%

100%

SO2(9.42 million tons)

NOx(3.49 million tons)

CO2(2.71 billion tons)

Mercury (Hg)(50.71 tons)

3producers

9producers

24producers

100 largestproducers

(93%)


(88%)


(86%)

100 largest producers

(85%)

all othersall others all others all others

4producers

14producers

41producers

4producers

13producers

39producers

6producers

18producers

50 producers

FIGURE ES.1

Concentration of Air Emissions among All Electric Power Producers

Perc

ent o

f ele

ctric

indu

stry

em

issi

ons


Electric power producers’ emission levels and emission rates vary signifi cantly due to the amount of power produced, the effi ciency of the technology used in producing the power, the fuel used to generate the power, and installed pollution controls. CO2 emission levels and emission rates are an important factor in evaluating the potential exposure that power companies and shareholders face from emerging federal CO2 limits. In 2006 total generation among the 100 largest power producers varied from 6 million MWh to nearly 202 million MWh and:

• SO2 emissions ranged from 0 to 1 million tons, and SO2 emission rates ranged from 0.0 lbs/MWh to 18.2 lbs/MWh;

• NOx emissions ranged from 0 to 294,262 tons, and NOx emission rates ranged from 0.0 lbs/MWh to 5.0 lbs/MWh;

• CO2 emissions ranged from 0 to 170 million tons, and CO2 emission rates ranged from 0.0 lbs/MWh to 2,492 lbs/MWh.

Electric power producers’ mercury emissions from coal plants ranged from 0 to 8,719 pounds, and mercury emission rates ranged from 0.0 lbs/GWh to 0.105 lbs/GWh.

Allowance Distribution ScenariosTh ere are several options for distributing emissions allowances to power plant operators subject to a cap-and-trade program. Th e government can sell the allowances to companies through an auction; the government can give the allowances to companies at no cost; or the government can give the allowances to third party entities such as state governments or local electric utilities (distribution companies), which would in turn sell the allowances to facility owners covered by the emissions cap. Th e revenues could then be used to reduce consumer electricity bills, either through direct subsidies or enhanced energy effi ciency programs.

Economists generally agree that the auctioning of allowances is the most effi cient method for distributing emissions allowances. Th e auction approach is consistent with the principle that polluting facilities should pay for the costs of their emissions. Th e auctioning of allowances also provides resources to fund public initiatives that will be important in responding to climate change. Several bills in Congress propose auctioning a growing share of allowances with the proceeds dedicated to various public purposes, including

EXECUTIVE SUMMARY 5

clean technology research and development, incentives for the deployment of energy effi ciency and renewable energy technologies, low income energy assistance, adaptation to climate change, and worker retraining.

Th is report provides some analysis of two additional options for distributing emissions allowances within the electric power sector: (1) a free allocation of allowances to electric generating facilities, and (2) an allocation to local electric utilities (distribution companies) for consumer benefi t. Most Congressional bills have proposed a combination of methods for distributing allowances, including allocations to electric power producers, allocations to local electric utilities, the auctioning of allowances, allocations to states, and allocations to other regulated sources. Th roughout the analysis we assume an allowance price of $10 per ton. Th is price is intended for illustrative purposes only, and is not a prediction of future CO2 allowance costs. Allowance prices will depend on the stringency of the emissions cap, cost containment provisions, and other program features.

Industry stakeholders oft en favor a free allocation of allowances to electric generating facilities as a way of mitigating their CO2 compliance costs. In this report, we present estimates of the number of allowances and the value of the allowances that individual electric power producers would receive under several allocation scenarios. Th e overall allocation quantities are based on two recent legislative proposals—the Lieberman-Warner Climate Security Act and the Low Carbon Economy Act. We focus on these two proposals because they are economy-wide bills that provide detailed specifi cations of how their emissions allowances are to be allocated. Other economy wide bills simply delegate that responsibility to EPA or the President. Th ese allocation scenarios were developed in an eff ort to isolate the eff ect of the diff erent allocation options available to Congress, including the overall quantity of allowances allocated to electricity producers and the metrics used for apportioning the allowances among the companies.

0

1,000

2,000

3,000

4,000

5,000

6,000

0

1,000

2,000

3,000

4,000

5,000

6,000

2050

2049

2048

2047

2046

2045

2044

2043

2042

2041

2040

2039

2038

2037

2036

2035

2034

2033

2032

2031

2030

2029

2028

2027

2026

2025

2024

2023

2022

2021

2020

2019

2018

2017

2016

2015

2014

2013

2012

1

3

4

5

1

2

34

5

6

2

FIGURE ES.2

The Distribution of Allowances under the Lieberman-Warner Climate Security Act & Low Carbon Economy Act The Lieberman-Warner bill and Low Carbon Economy Act proposes distributing allowances to a wide range of entities, including (1) electric power producers, (2) allocations to companies in other industry sectors aff ected by the bill, (3) federal auction, (4) agriculture and forestry projects, (5) states, and (6) electric and natural gas distribution companies for consumer benefi t.

NOTE: Fewer allowances are available for distribution as the emissions caps decline.

Lieberman-Warner Climate Security Act

conditional target

Low Carbon Economy Act


Th e Lieberman-Warner Climate Security Act (the Lieberman-Warner bill) proposes to distribute 1.21 billion tons (1.097 billion metric tons) of free CO2 allowances to power plant operators in 2012. (Th e Lieberman-Warner bill also allocates 573 million tons of allowances to regulated electric distribution companies, which can then auction them off to companies regulated by the program to raise money for consumer programs, as described below.) Th e Low Carbon Economy Act, sponsored by Senators Bingaman and Specter, provides a larger allocation to electric power producers of 2.126 billion tons (1.929 billion metric tons) in 2012. Both bills propose allocating the majority of allowances to electric power producers based on their historic CO2 emissions. For example, a company whose power plants produce fi ve percent of total electric sector CO2 emissions would receive fi ve percent of the allowances allocated to the electricity generators. Th is report also apportions allowances to electric power producers based on their total electricity output (megawatt hours), using both the Lieberman-Warner bill and Low Carbon Economy Act proposed allowance reserves.

• Th e total annual value of the allowances allocated to the 100 largest electric power producers under the Emissions Based Scenario 1—with a total allowance pool equivalent to the Lieberman-Warner Climate Security Act in 2012—is close to $10.4 billion assuming a price of $10 per ton of CO2. Allocations to power plant operators phase out under the Lieberman-Warner bill over a period of 19 years. Th e Lieberman-Warner bill also directs allowance value to regulated electric distribution companies, which is specifi cally directed to consumer benefi t. Th ese consumer allocations are provided through 2050.

• Th e total annual value of the allowances allocated to the 100 largest electric power producers under the Emissions Based Scenario 2—with a total allowance pool equivalent to the Low Carbon Economy Act in 2012—is close to $18.3 billion assuming a price of $10 per ton of CO2. Th e Low Carbon Economy Act caps allowance prices at $10.89 per ton ($12 per metric ton) in 2012, and the price cap escalates by fi ve percent above the rate of infl ation each year aft er 2012. Allocations to power plant operators phase out under the Low Carbon Economy Act over a period of 32 years.

• Th e potential value of the allowances allocated to individual electric generating companies can be substantial. Th e ten largest investor owned utilities would receive an annual allocation valued at $6.2 billion, assuming a CO2 allowance price of $10 per ton, under Emissions Based Scenario 2. To provide a sense of the magnitude of this value, this is equivalent to 16 percent of the companies’ total earnings in 2006.

EXECUTIVE SUMMARY 7

• Research indicates that an over allocation of free allowances to electricity generators can lead to excessive profi ts for companies, while providing limited benefi ts in terms of reducing electricity price impacts for consumers and funding energy effi ciency and other programs that reduce overall greenhouse gas emissions. Th e European Union’s Emissions Trading Scheme (EU ETS) experienced such problems because the program’s pilot phase was overly generous in allocating free allowances to electric generating companies. Europe’s program is now being redesigned with a larger reliance on the auctioning of allowances.

Th e Lieberman-Warner bill also allocates a portion of allowances to local electric utilities (distribution companies), including a provision mandating that the allowance value be returned to low- and middle-income electricity consumers through customer rebates, or proceeds from the sale of allowances can be used to fund consumer energy effi ciency programs. (Th e Low Carbon Economy Act provides no allowances to local electric utilities for consumer benefi ts.)

Th is report calculates the CO2 allowance allocations for the largest electric distribution companies based on the methodology proposed by the Lieberman-Warner Climate Security Act. Individual company allocations are calculated based on their proportionate share of electricity sales (measured in megawatt hours) in 2006 and an allowance pool of 573 million tons (520 million metric tons).

• Th is report calculates the average value to consumers if the allowance proceeds are divided among residential, residential and commercial, or all customer classes (including industrial), assuming an allowance price of $10 per ton of CO2. If the allowance value were distributed among low- and middle-income households only—one of the options proposed by the Lieberman-Warner bill—the value per low- and middle-income consumer would be even higher than presented here.

• Th e median fi nancial benefi t to residential electricity consumers under Distribution Company Scenario 1—with a total allowance pool equivalent to the Lieberman-Warner Climate Security Act in 2012—is estimated at 0.45 cents per kilowatt hour, assuming a CO2 price of $10 per ton.

• An example is provided of how the Lieberman-Warner bill’s combination allocation approach—giving 1.21 billion tons of free allowances to electric power producers based on their historic CO2 emissions and 573 million tons to local electric utilities for the benefi t of their customers—might impact an average household in Indiana. Assuming a CO2 price of $10 per ton, the cost of producing electricity with a coal-fi red power plant will increase by about 1.05 cents per kilowatt


hour. Th e Lieberman-Warner free allocation to electric power producers would reduce this increase to 0.6 cents per kilowatt hour assuming that the generator is fully regulated in a way that ensures that the value of these allowances are passed on to customers. Indiana’s average residential customer would pay an additional $6 per month in CO2 costs on their electricity bill (0.6 cents per kilowatt hour x 993 kilowatt hours per month). Th e allocation to local electric distribution companies is proposed as a method to help mitigate this extra cost to consumers. Indiana’s average residential customer would receive $4.21 per month in allowance value in the form of rebates or energy effi ciency incentives (assuming the allowance value is reserved for residential customers only). As a result, their net CO2 costs would be reduced from $6 per month to $1.52 per month. Households could further mitigate these price impacts by installing compact fl uorescent lighting and other energy saving devices.

Using this ReportTh e information in this report supports informed decision-making in several areas:

• It can be used by policymakers who are addressing the public health and environmental risks of SO2, NOx, mercury, and CO2 emissions.

• It can be used by the investment community to assess the costs and business risks associated with compliance with future additional emission reduction requirements.

• It can be used by electric power companies and the public to assess corporate performance relative to key competitors, prior years, and industry benchmarks.


Electric power production is essential to the growth and operation of the U.S. economy. Th e availability, reliability, and price of electricity have signifi cant impacts on national economic output, energy security and quality of life. At the same time, the production of electricity from fossil fuels results in air pollution emissions that aff ect both public health and the environment.

Th is report focuses on four power plant pollutants for which public emissions data are available: sulfur dioxide (SO2), nitrogen oxides (NOx), mercury, and carbon dioxide (CO2). Collectively, power plants are responsible for about 70 percent of SO2 emissions, 20 percent of NOx emissions, 68 percent of mercury air emissions, and about 40 percent of CO2 emissions in the U.S.1 Th e electric industry accounts for more CO2

emissions that any other sector, including the transportation and industrial sectors.

SO2 and NOx emissions from power plants contribute to acid rain, regional haze, and fi ne particle air pollution. Acid rain damages trees and crops, acidifying soils, lakes, and streams. Fine particle air pollution can be inhaled deep in the lungs aff ecting the heart and lungs. Exposure to fi ne particle air pollution is linked to respiratory illness and other ailments, particularly in children and the elderly. Regional haze impairs visibility, most notably at national parks. NOx emissions are also associated with nitrogen deposition and ground-level ozone. Nitrogen deposition can impair water quality by overloading a water body with nutrients. Ground-level ozone can trigger serious respiratory problems.

Mercury air emissions deposited to lakes and ponds are converted by certain microorganisms to a highly toxic form of the chemical known as methylmercury. Methylmercury then accumulates in fi sh, shellfi sh, as well as birds and mammals that feed on fi sh. Humans are exposed to mercury when they eat contaminated fi sh. High levels of methlymercury can be detrimental to the development of fetuses and young children.

CO2 is the most prevalent of anthropogenic (or human caused) greenhouse gas emissions. Greenhouse gases (or global warming pollutants) trap heat in the atmosphere and at elevated concentrations lead to global climate change.

Electric Industry Overview FIGURE 1

U.S. Electric Industry Contribution to Total Emissions

Residential

Industrial

Commercial

Transporation

Electric

Other

Manufacturing

Industrial

ElectricIncinerators

Other

IndustrialCommercial

Transporation

Electric

Other

Industrial

Commercial

Transporation Electric

ELECTRIC INDUSTRY OVERVIEW 11

FIGURE 2

Location and Relative Size of U.S. Power Plants by Fuel Type

Coal

PLANT FUEL TYPE

Hydro

Natural Gas

Nuclear

Renewable/Other

Oil

2004 GENERATION

25.00 million MWh

12.50 million MWh

6.25 million MWh


Because of their associated public health risks, SO2, NOx, and mercury power plant emissions are regulated under the Clean Air Act. In 2005, the U.S. Environmental Protection Agency (EPA) issued the “Clean Air Interstate Rule” to address interstate transport of SO2 and NOx emissions in the eastern U.S., and the “Clean Air Mercury Rule” to reduce mercury emissions from coal-fi red power plants across the country. Th e Clean Air Interstate Rule goes into eff ect in 2009 (NOx) and 2010 (SO2). Th e U.S. Court of Appeals for the DC Circuit recently found the Clean Air Mercury Rule to be invalid under the Clean Air Act, directing EPA to revisit its rulemaking. Appendix B discusses the status of SO2, NOx, and mercury reduction programs established under the Clean Air Act aff ecting the electric power sector.

Th e EPA does not currently regulate CO2 emissions from power plants despite a decision by the U.S. Supreme Court in April 2007 fi nding that EPA has clear statutory authority to regulate greenhouse gases (Massachusetts v. EPA). CO2 is the primary pollutant contributing to global warming. In the absence of federal standards, members of Congress are seeking to build consensus for a federal response and many state and local governments have developed or are developing strategies to address global warming. Many of these strategies have developed into state commitments to reduce emissions of CO2 and other heat-trapping gases from power plants and other sources. Climate change is discussed in more detail later in this document and in Appendix C.

Sources of PowerOver 5,000 power plants generate electricity in the U.S.. In 2006, these plants generated approximately 4,069 million megawatt hours (MWh) of electricity. Seventy percent of this power was produced by burning fossil fuels (coal, natural gas and oil) resulting in the release of SO2, NOx, mercury, and CO2 into the air. Coal accounted for 49 percent of total power production, and the remaining fossil fuels–natural gas and oil–accounted for 20 percent and 1 percent, respectively. Nuclear power, the largest non-fossil fuel energy source, generated 19 percent of U.S. electric power. Hydroelectricity accounted for nearly 7 percent of total power production and non-hydroelectric renewables (such as wind turbines and solar photovoltaic cells) and other fuel sources accounted for almost 3 percent.2

Large coal plants are located across the nation, most predominantly in the eastern part of the country. Th e heaviest concentrations of coal plants are located along the Ohio and Mississippi Rivers. Natural gas plants

SOURCE: ENERGY INFORMATION ADMINISTRATION. ANNUAL ELECTRIC GENERATOR REPORT: FORM EIA-860 (2006). http://www.eia.doe.gov/cneaf/electricity/page/eia860.html


FIGURE 3

U.S. Electric Generating Capacity by In Service Year

0

10,000

20,000

30,000

40,000

50,000

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70,000

Renewable

Hydro

Nuclear

Oil

Natural Gas

Other

Coal

200

6 2

005

200

4 2

003

200

2 2

001

200

0 1

999

199

8 1

997

199

6 1

995

199

4 1

993

199

2 1

991

199

0 1

989

198

8 1

987

198

6 1

985

198

4 1

983

198

2 1

981

198

0 1

979

197

8 1

977

197

6 1

975

197

4 1

973

197

2 1

971

197

0 1

969

196

8 1

967

196

6 1

965

196

4 1

963

196

2 1

961

196

0 1

959

195

8 1

957

195

6 1

955

195

4 1

953

195

2 1

951

195

0 1

949

194

8 1

947

194

6 1

945

194

4 1

943

194

2 1

941

194

0

Nam

epla

te C

apac

ity (M

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SOURCE: ENERGY INFORMATION ADMINISTRATION, FORM EIA-423, “MONTHLY COST AND QUALITY OF FUELS FOR ELECTRIC PLANTS REPORT,” FEDERAL ENERGY REGULATORY COMMISSION, FERC FORM 423, “MONTHLY REPORT OF COST AND QUALITY OF FUELS FOR ELECTRIC PLANTS.”http://www.eia.doe.gov/cneaf/electricity/epa/fi ges4.html


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FIGURE 4

Costs of Fuels for Electricity Generation: 1993-2006are generally smaller than coal plants and are also spread across the country. Th e heaviest concentrations of natural gas-fi red power plants are in Texas and Louisiana, near the Gulf of Mexico, and in California. Most large nuclear plants are located in eastern and upper-midwestern states, and most hydroelectric facilities are in western states.

Th e average age of the current coal fl eet is about 35 years old (by capacity) with the majority of coal construction taking place in the 1960s and 1970s. Natural gas-fi red power plants are generally younger with an average age of about 15 years and a large spike in construction in the period from 2000-2005. Figure 3 presents the in service year and fuel type of the existing electric generating fl eet in the U.S..

In the period from 2000 to 2006, electric generating companies proposed building more than 150 coal-fi red power plants in the U.S.. By 2007, many of these proposals had been cancelled, abandoned, or put on hold; 10 of the proposed plants had been constructed (2,750 MW); and 23 plants were under construction or near construction (15,000 MW).3

Some of the reasons cited for abandoning these projects include: (1) concerns about regulation of CO2, (2) rising construction costs, (3) insuffi cient fi nancing, and (4) reduced expectations of electricity demand.

Electricity prices vary across the U.S. depending in part on the mix of power plants available in the region. Coal-fi red power plants enjoy a signifi cant fuel cost advantage relative to natural gas- and oil-fi red power plants (Figure 4); although, the capital costs of a coal plant are higher than a natural gas facility. Renewable technologies, such as wind and solar photovoltaic cells, have no fuel costs, but the up-front capital costs can be signifi cant. Because of the high carbon content of coal, the operating costs of a coal-fi red power plant would increase more than other fossil fuel-fi red technologies if CO2 were regulated

Fuel

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SOURCE: ENERGY INFORMATION ADMINISTRATION, U.S. AVERAGE MONTHLY BILL BY SECTOR, CENSUS DIVISION AND STATEhttp://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html


and companies had to pay for their emissions. Because of the signifi cant disparities in fuel prices between coal and natural gas, CO2 prices would need to be at a level of $50-$60 per ton before the operating costs of a conventional coal-fi red power plant (fuel costs plus allowance costs) will equal that of a high effi ciency, natural gas facility.4

Figure 5 presents the average residential electricity rates by state. Figure 5 also presents the average monthly electricity bill by state. Household electricity bills will vary depending in part on energy effi ciency codes and standards, utility energy effi ciency programs, climate and the extent to which a household relies on electricity for space heating and cooling, and other household energy needs.

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FIGURE 5

2006 Average Residential Electricity Prices and Average Monthly Electricity Bills by State

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HEIGHTENED FOCUS ON CLIMATE CHANGE 17

While the impacts of air pollution on public health continue to drive regulation and control of SO2, NOx, and mercury, there has been a dramatic increase in attention focused on climate change in recent years. As direct observations of climate change continue to mount, a growing number of states are requiring greenhouse gas emissions reductions; U.S. mayors (753) have signed voluntary climate agreements to reduce emissions in their cities; and the U.S. Congress, in 2007, convened an unprecedented number of hearings on the issue (more than seven times the number of hearings on climate change that it held in 2005 and 2006 combined).5 Th is heightened focus by local, state, and federal policymakers has been accompanied by strong statements of support for climate change legislation by major U.S. corporations, strong interest by venture capitalists in “green” technologies, as well as a shift in the American public’s concern about climate change.

In the absence of mandatory requirements at the federal level, local, state, and regional initiatives to address climate change have moved forward. Th e Regional Greenhouse Gas Initiative, which puts a cap on CO2 emissions from power plants, now includes ten states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont) and is preparing for a January 1, 2009 start date. At the same time, California is moving ahead with the development of a plan to reduce its own greenhouse gas emissions and is collaborating with Arizona, New Mexico, Oregon, Utah, Montana, and Washington along with two Canadian provinces on a regional greenhouse gas program. States have also taken the lead in developing and managing a common greenhouse gas emissions reporting system. Th e Climate Registry includes 39 states along with the District of Columbia, four Canadian provinces, and two Mexican States. Appendix C includes more information on state and local activity to address climate change.

Heightened Focus on Climate Change

Signs of ChangeAccording to scientists, there is growing evidence that global warming is aff ecting the planet today.One of the most dramatic signs has been the retreat of the polar ice cap. In 2007, the polar ice cap reached its lowest point on record. Over the past 3 decades, more than a million square miles of perennial sea ice — an area the size of Norway, Denmark and Sweden combined — has disappeared.

Photo: National Aeronautics and Space Administration


In January 2007, a diverse coalition of U.S. corporations joined with leading environmental groups to call for immediate federal action to reduce greenhouse gas emissions from major emitting sources. Th is group, the U.S. Climate Action Partnership, has grown from nine companies and four non-profi t environmental policy groups when it was fi rst unveiled to include a total of 26 companies spanning multiple industry sectors and six non-profi t groups. In March 2007, U.S. investors representing $4 trillion in assets joined with a dozen corporate leaders to call for strong federal legislation to achieve 60 to 90 percent reductions in greenhouse gas emissions below 1990 levels by 2050.6 Since these announcements, corporate and investor leaders have appeared before a number of Congressional hearings and are actively encouraging Congress to pass mandatory climate change legislation.

Concern about climate change among the American public has increased in recent years. A survey by researchers at MIT shows a dramatic increase in the number of Americans that rank global warming as one of the top two environmental problems facing the U.S. (out of ten concerns). In 2003, 21 percent of those surveyed ranked global warming among their top concerns. By 2006, this fi gure had increased to 49 percent.7 Th is heightened concern has been accompanied by an increase in support for action to address climate change. A 2007 Washington Post/ABC News/Stanford University survey found that 86 percent of the American public believes that global warming will be a serious problem if nothing is done to address it and 70 percent think the government should do more to deal with global warming.8

FIGURE 6

U.S. CO2 Emissions by Sector (with electric sector emissions apportioned to end-use category): 2005

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SOURCE: U.S. ENVIRONMENTAL PROTECTION AGENCY, INVENTORY OF U.S. GREENHOUSE GAS EMISSIONS AND SINKS: 1990 –2005.


Addressing Emissions from the Electric Power SectorTh e electric power sector is responsible for more CO2 emissions than any other sector of the economy, producing about 40 percent of U.S. CO2 emissions. Figure 6 summarizes the CO2 emissions from fossil fuel combustion by end-use category.

One of the challenges in addressing climate change is the long atmospheric life of CO2. While other greenhouse gases have atmospheric lifetimes measured in years (methane has a lifetime of about 12 years) or decades (the refrigerant hydrochlorofl uorocarbon-22 (HCFC-22) has a lifetime of about 110 years), scientists are unable to defi ne a lifetime for CO2. Some CO2 is removed from the atmosphere within a century but a large fraction (about 20 percent) remains in the atmosphere for thousands of years.9 Th e persistence of CO2 in the atmosphere has a number of implications. First, it means that a signifi cant portion of the CO2 released by power plants over the past 50 years remains in the atmosphere to this day. Figure 7 presents an estimate of the cumulative CO2 emissions from fossil fuel-fi red electric power plants since 1950. Figure 7 also shows the annual emissions from fossil-fi red plants (orange line). Over the past 60 years, fossil-fi red power plants in the U.S. have generated upwards of 77 billion metric tons of CO2. Coal-fi red power plants were responsible for 80 percent of these emissions.

Th e long atmospheric lifetime of CO2 also means that stabilizing atmospheric concentrations of CO2 over the next century will require dramatic reductions in CO2 emissions. Th is not only requires that new sources of electricity have zero or close-to-zero CO2 emissions, it also means that existing sources of electricity need to dramatically reduce emissions or be replaced. Electric generating technologies with low or zero emissions are commercially available but are oft en expensive relative to conventional technologies and can face barriers to implementation such as local opposition or a lack of clear regulatory guidelines.

One of the most cost eff ective strategies available for reducing emissions is to reduce the demand for electricity by eliminating energy waste and through the deployment of energy effi ciency measures, such as high effi ciency appliances, lighting, motors, heating and cooling equipment, and more effi cient building structures.

CO2 emissions can also be reduced by deploying new electric generating technologies with greater fuel effi ciency and low or zero greenhouse gas emissions. Renewable energy sources, such as wind turbines and solar panels, and nuclear power plants generate electricity without producing CO2.

Another potential technological approach is to capture CO2 at fossil fuel-fi red power plants and inject it deep underground in geologic formations in a process called carbon capture and storage (CCS). While the capture and storage of CO2 from


FIGURE 7

Cumulative CO2 Emissions from U.S. Fossil Fuel-Fired Power Plants: 1950-2006

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SOURCE: CALCULATED BASED ON U.S. ENERGY INFORMATION ADMINISTRATION ANNUAL ENERGY REVIEW. POSTED JUNE 27, 2007.


commercial-scale fossil fuel-fi red power plants is currently in the demonstration phase, the technique has been successfully employed in the U.S. by a coal gasifi cation facility in North Dakota. Th e largest and longest running CCS project in the world is at a natural gas operation off the coast of Norway. Th e project has been injecting about one million metric tons of CO2 annually since the late 1990s.

Cap-and-Trade 101Amid growing concern regarding the threat of climate change, members of Congress are increasingly focusing their attention on the strategies available for transitioning to a lower carbon economy, including consideration of a market-based, cap-and-trade regulatory system. In 2005, the Senate adopted a resolution calling for the enactment of “mandatory market-based limits” on U.S. greenhouse gas emissions. In 2007, House and Senate members introduced at least 13 bills proposing cap-and-trade programs for regulating greenhouse gas emissions from power plants and other sectors of the economy (see Appendix C). Industry and environmental stakeholders alike have expressed support for cap-and-trade based regulation.

Under a cap-and-trade system, a limit is placed on the overall emissions from covered sources; a limit enforced by requiring regulated sources to surrender “allowances” for any greenhouse gases released to the atmosphere. An allowance is a permit to emit a discrete quantity of greenhouse gases (e.g., one ton of CO2). Companies can trade or bank allowances for future use, but at the end of each compliance period their emissions must equal their allowance holdings. Policymakers and economists oft en favor this approach because it provides a predictable and enforceable schedule of emissions reductions, while at the same time directing capital investment to the least cost control opportunities, reducing overall program costs. Also, the cap-and-trade approach has a proven track record in reducing SO2 and NOx emissions from power plants. A greenhouse gas cap-and-trade system is currently in eff ect in Europe.

Under a cap-and-trade program, the market will settle on an allowance price based on the cost and availability of pollution control measures, and prices will vary depending on the dynamics of supply and demand including future market expectations (e.g., prices may rise if the government is planning to reduce the supply of allowances by lowering the emissions cap).

One of the challenges in designing a cap-and-trade system is to devise an equitable and effi cient approach for distributing the emissions allowances whose value could range in the hundreds of billions of dollars annually. Th ere are many competing ideas for distributing the allowances under a cap-and-trade program. For example, allowances can be sold (auctioned) with the revenues used to fund public purposes, such as reducing the burden on low-income consumers, incentivizing energy effi ciency improvements, and subsidizing the development of low carbon technologies; they can be given to companies at no


cost in proportion to past emissions or electricity sales; they can be awarded to companies to encourage future investments in clean energy technologies; they can be awarded to states or companies to mitigate energy costs for consumers; or they can be used to reward past investment behavior. Several legislative proposals employ a combination of these approaches. Disagreement regarding the best approach for distributing allowances poses a challenge for policymakers in seeking to build consensus for a national climate bill.

Within the electric power sector, several options have been suggested for distributing emissions allowances, but in general, they can be divided into three basic categories: (1) direct allocations to electric generating facilities; (2) the sale of allowances (through auctions) by a government agency; or (3) allocations to third parties such as local electric utilities (distribution companies) on behalf of their customers.

In allocating free allowances to electric generating companies, the key issues are how many allowances to allocate and on what basis. For example, legislation pending before Congress proposes allocating allowances to power plants equal to about 50 percent of the sector’s current CO2 emissions level with a transition to zero allowances allocated over a period of 19 years (starting in 2012 and ending in 2030), at which point fossil generating facilities would be required to purchase allowances for all of the CO2 they release to the atmosphere.10 In terms of the options for calculating individual facility allocations, allowances can be distributed based on a facility’s proportional share of emissions, fuel consumption, or electricity output. Allowances can be allocated to both emitting and non-emitting facilities. Th e eff ect on a company’s earnings will vary signifi cantly depending on its generation portfolio, how it is regulated, and the allocation formula used in distributing allowances.11

Rather than giving allowances away for free, the government could auction the emissions permits under a cap-and-trade program, as many Northeast states have decided to do under their regional cap-and-trade program and as the federal government has done with other public resources (e.g., timber harvesting rights, radio frequencies). Th e revenues generated from the sale of allowances could be used for any number of initiatives: technology research and development, incentives for the deployment of energy effi ciency and renewable energy technologies, low income energy assistance, adaptation to climate change, and worker retraining. Support for the auctioning of allowances—and dedicating the value to public purposes, in general—has been gaining traction in the U.S. since observing the experience in Europe with its greenhouse gas trading system. Studies suggest that electric generating companies in Europe enjoyed large increases in profi ts as a result of an over-allocation of allowances under the pilot phase of the EU Emissions Trading Scheme (EU ETS).12 Th e Europeans have proposed to alter the design of their cap-and-trade program going forward, including increased reliance on the auctioning of allowances to avoid over compensating industry for the costs of the program.


In the U.S. a similar result could occur if a large number of allowances are allocated to electric power producers at no cost: electricity prices and revenues may increase even though free allowances reduce the companies’ costs of compliance. Whether the free distribution of allowances provides electric power producers and their shareholders revenues that exceed their actual compliance costs will depend on several factors, including how the price of electricity is set in a given power market (this infl uences the extent to which CO2 costs pass through to consumers), the treatment of allowances allocated to regulated utilities by public utility commissions, and whether a utility company purchases or produces a signifi cant share of its electricity supply.

A third alternative—and another option for dedicating allowance value to public purposes—is to give all or a portion of the allowances to third party entities such as state governments. State governments would then decide how to best distribute the allowances. For example, a state might sell the allowances and dedicate the revenues to energy effi ciency programs. A state may be required to “earn” an allocation by adopting certain policy measures, such as advanced building codes and standards, or it may simply be entitled, by virtue of federal law, to receive a share of the allowances. Another option is to allocate allowances to local regulated electric utilities (local distribution companies) with a provision mandating that the allowance value be returned to utility customers through rebates or energy effi ciency programs (e.g., local regulated electric utilities would receive allowances based on their share of national electricity sales, local utilities would then sell the allowances they receive to facilities covered by the emissions cap, and any revenues generated would be returned to their customers).13 Regulated electric utilities are uniquely positioned for this role because (1) they have established fi nancial relationships with electric customers, (2) they are subject to state utility commission or board oversight, and (3) many have existing energy effi ciency programs. Studies indicate that most of the costs associated with the regulation of CO2 from the electric power sector will in the end be passed on to the households and businesses paying for the electricity.14 Th is approach is proposed as a way to at least partially mitigate these higher costs.

In conclusion, there are several options available for distributing or selling emissions allowances under a cap-and-trade program with increased attention on methods for dedicating allowance value to public purposes such as technology research and development and funding for energy effi ciency programs. Based on the current proposals before Congress, the most likely scenario would appear to be a combination of free allocations, a government auction, and allocations to third party entities for public benefi t.

EMISSIONS OF THE 100 LARGEST ELECTRIC POWER PRODUCERS 25

In 2006, the 100 largest power producers in the U.S. generated 85 percent of the nation’s electricity supply and 86 percent of the industry’s air pollution emissions. Table 1 lists the 100 largest electric power producers in order of their total 2006 electric generation in MWh. Th e three largest producers were responsible for 16 percent of the 3,468 million MWh of electricity generated by the 100 largest producers. Th e 100 largest power producers emitted approximately 8.8 million tons of SO2, 3.1 million tons of NOx, 43 tons of mercury, and 2.3 billion tons of CO2. Th e top three producers were responsible for 27 percent of the SO2, 23 percent of the NOx, 24 percent of the mercury, and 19 percent of the CO2 emissions of the 100 largest producers.

Th e average and median emission levels (tons) and emission rates (lbs/MWh) shown in Table 1 provide benchmark measures of overall industry emissions that can be used as reference points to evaluate the emissions performance of individual power producers.

Emissions of the 100 Largest Electric Power Producers

1 Southern investor-owned corporation 201,713,989 168,445,655 140,541,405 1,016,265 214,945 164,634,138 4.36 10.1 2.1 1,632.4 12.1 2.6 1,954.7 14.5 3.0 2,140.0 0.06 2 AEP investor-owned corporation 187,168,591 169,437,420 158,536,029 916,206 294,262 170,403,184 4.06 9.8 3.1 1,820.9 10.8 3.5 2,011.4 11.6 3.5 2,064.3 0.05 3 Tennessee Valley Authority federal power authority 154,997,732 101,229,962 100,455,508 452,799 198,075 108,580,228 1.79 5.8 2.6 1,401.1 8.9 3.9 2,145.2 9.0 3.9 2,150.2 0.044 Duke investor-owned corporation 152,749,850 110,402,597 106,331,455 813,342 153,277 111,384,503 2.03 10.6 2.0 1,458.4 14.7 2.8 1,995.9 15.3 2.9 2,025.6 0.04 5 Exelon investor-owned corporation 152,549,419 10,861,003 8,674,738 46,345 15,165 11,450,383 0.21 0.6 0.2 150.1 8.5 2.8 2,108.3 10.5 3.3 2,281.2 0.05 6 FPL investor-owned corporation 138,508,135 92,164,982 6,081,618 66,712 43,706 51,793,526 0.19 1.0 0.6 747.9 1.4 0.9 1,123.9 5.2 2.2 2,164.2 0.06 7 Entergy investor-owned corporation 115,032,361 37,382,869 15,199,798 57,556 40,191 33,578,887 0.50 1.0 0.7 583.8 3.1 2.1 1,755.2 7.1 2.7 2,151.1 0.07 8 Dominion investor-owned corporation 103,470,645 57,473,927 49,064,814 187,613 82,064 56,991,009 1.31 3.6 1.6 1,101.6 6.5 2.9 1,983.2 7.5 3.3 2,141.1 0.05 9 Progress Energy investor-owned corporation 92,890,185 61,263,494 43,484,549 311,045 94,679 58,040,341 0.96 6.7 2.0 1,249.7 10.2 3.1 1,894.8 12.6 3.8 2,143.9 0.04

10 FirstEnergy investor-owned corporation 83,803,749 54,030,466 53,818,070 260,626 81,302 58,721,627 0.70 6.2 1.9 1,401.4 9.5 3.0 2,116.6 9.6 3.0 2,118.5 0.03 11 Xcel investor-owned corporation 79,899,663 64,829,406 52,541,921 136,088 114,965 67,695,666 1.29 3.4 2.9 1,694.5 4.2 3.5 2,078.2 5.2 4.1 2,294.2 0.05 12 Calpine investor-owned corporation 79,537,181 72,767,833 - 176 5,966 35,344,319 - 0.0 0.2 888.7 0.0 0.2 971.4 - - - - 13 Edison International investor-owned corporation 79,286,055 58,406,906 46,556,072 194,149 78,124 57,890,358 1.29 4.9 2.0 1,460.3 6.6 2.7 1,982.3 8.3 3.3 2,243.8 0.06 14 Ameren investor-owned corporation 79,261,357 68,182,616 67,297,942 259,410 62,130 75,551,621 2.04 6.5 1.6 1,906.4 7.6 1.8 2,216.2 7.7 1.8 2,228.4 0.06 15 NRG investor-owned corporation 76,935,298 67,226,398 52,409,969 160,179 45,930 68,098,780 1.58 4.2 1.2 1,770.3 4.8 1.4 2,007.6 6.1 1.6 2,233.4 0.06 16 MidAmerican investor-owned corporation 76,048,095 66,739,487 59,392,194 156,526 118,824 72,145,048 1.03 4.1 3.1 1,897.4 4.7 3.6 2,162.0 5.3 4.0 2,308.9 0.03 17 TXU investor-owned corporation 69,628,403 49,732,394 45,525,890 275,062 44,863 58,411,267 2.39 7.9 1.3 1,677.8 11.1 1.8 2,349.0 12.1 1.8 2,434.4 0.10 18 US Corps of Engineers federal power authority 69,127,277 - - - - - - - - - - - - - - - - 19 PSEG investor-owned corporation 62,724,489 33,575,011 14,683,904 77,246 25,218 24,898,182 0.29 2.5 0.8 793.9 4.6 1.5 1,481.6 10.4 2.9 2,149.8 0.0420 PPL investor-owned corporation 52,035,451 31,152,182 29,919,419 268,524 45,561 31,901,480 0.55 10.3 1.8 1,226.1 17.2 2.9 2,047.2 17.9 3.0 2,074.6 0.04 21 Constellation investor-owned corporation 48,951,026 17,518,753 16,997,123 123,466 26,885 18,685,103 0.48 5.0 1.1 763.4 14.0 3.0 2,117.2 14.5 3.1 2,156.5 0.06 22 US Bureau of Reclamation federal power authority 47,801,655 4,261,936 4,259,612 934 8,443 4,877,394 0.03 0.0 0.4 204.1 0.4 4.0 2,288.8 0.4 4.0 2,290.1 0.02 23 Allegheny Energy investor-owned corporation 46,842,014 46,683,614 46,182,696 328,458 74,662 48,003,893 1.09 14.0 3.2 2,049.6 14.1 3.2 2,056.6 14.2 3.2 2,066.4 0.05 24 Dynegy investor-owned corporation 44,410,941 44,342,005 23,207,280 58,250 16,500 37,182,657 0.43 2.6 0.7 1,674.5 2.6 0.7 1,672.0 4.8 1.2 2,252.6 0.04 25 DTE Energy investor-owned corporation 42,859,263 35,022,781 34,367,142 193,923 53,963 37,113,125 0.81 9.0 2.5 1,731.9 11.1 3.1 2,118.4 11.3 3.1 2,127.0 0.05 26 AES investor-owned corporation 42,429,218 39,074,577 32,671,230 116,834 40,252 41,854,983 0.52 5.5 1.9 1,972.9 5.9 1.9 2,042.9 7.0 2.2 2,209.0 0.03 27 E.ON foreign-owned corp. (Germany) 42,195,211 41,120,338 40,300,425 182,235 57,930 45,969,107 0.78 8.6 2.7 2,178.9 8.9 2.8 2,186.4 9.0 2.9 2,202.3 0.04 28 Reliant investor-owned corporation 36,686,169 36,686,169 24,967,437 234,601 44,768 32,318,805 1.02 12.8 2.4 1,761.9 12.8 2.4 1,761.9 18.7 3.5 2,146.5 0.08 29 PG&E investor-owned corporation 33,186,239 624,011 - 65 930 474,269 - 0.0 0.1 28.6 0.2 3.0 1,520.1 - - - - 30 Pinnacle West investor-owned corporation 32,857,925 25,857,517 16,150,384 27,591 37,563 22,570,641 0.29 1.7 2.3 1,373.8 2.1 2.9 1,745.8 3.4 4.6 2,234.6 0.04 31 CMS Energy investor-owned corporation 30,162,598 23,774,202 23,274,750 101,680 33,185 26,231,710 0.60 6.7 2.2 1,739.4 8.6 2.8 2,206.7 8.7 2.8 2,225.3 0.05 32 Wisconsin Energy investor-owned corporation 28,959,749 19,913,924 18,454,039 67,710 24,857 23,065,065 0.74 4.7 1.7 1,592.9 6.8 2.5 2,316.5 7.3 2.7 2,423.0 0.08 33 New York Power Authority state power authority 27,276,077 6,729,814 - 698 1,660 3,665,536 - 0.1 0.1 276.4 0.2 0.5 1,089.3 - - - - 34 Westar investor-owned corporation 26,032,844 17,243,179 16,405,993 60,907 28,577 20,310,007 0.41 4.7 2.2 1,560.3 7.1 3.3 2,355.7 7.4 3.3 2,401.6 0.05 35 SCANA investor-owned corporation 24,991,269 19,728,574 17,135,699 106,583 27,306 19,119,640 0.23 8.5 2.2 1,530.1 10.8 2.8 1,938.3 12.4 3.2 2,092.6 0.03 36 Tenaska privately held corporation 23,865,926 23,865,926 - 63 2,291 10,614,474 - 0.0 0.2 889.5 0.0 0.2 889.5 - - - - 37 Salt River Project power district 23,560,396 19,045,133 13,798,809 16,937 29,702 18,499,401 0.36 1.4 2.5 1,570.4 1.8 3.1 1,942.7 2.5 4.2 2,301.7 0.05 38 International Power foreign-owned corp. (U.K.) 23,250,320 23,117,545 5,240,154 14,044 4,483 13,594,365 0.09 1.2 0.4 1,169.4 1.2 0.4 1,176.1 5.3 1.4 2,123.9 0.03 39 OGE investor-owned corporation 22,269,611 22,266,454 16,496,876 45,227 34,984 22,130,867 0.24 4.1 3.1 1,987.5 4.1 3.1 1,973.7 5.5 3.4 2,223.5 0.03 40 Mirant investor-owned corporation 22,254,307 22,210,061 17,046,132 202,912 38,292 22,079,692 0.41 18.2 3.4 1,984.3 18.3 3.4 1,968.2 22.9 4.2 2,118.5 0.05 41 San Antonio City municipality 22,022,417 13,475,109 9,537,064 24,100 10,209 14,353,329 0.39 2.2 0.9 1,303.5 3.6 1.5 2,130.3 5.1 1.7 2,391.3 0.08 42 Santee Cooper state power authority 21,944,698 21,631,152 19,578,538 91,487 16,969 23,005,614 0.18 8.3 1.5 2,096.7 8.4 1.6 2,124.1 9.3 1.7 2,245.0 0.02 43 Oglethorpe cooperative 21,454,696 11,852,953 10,725,617 51,125 9,436 12,264,165 0.29 4.8 0.9 1,143.3 8.6 1.6 2,069.4 9.5 1.7 2,127.2 0.05 44 Great Plains Energy investor-owned corporation 20,508,230 20,402,291 19,793,516 48,142 46,476 22,504,612 0.70 4.7 4.5 2,194.7 4.7 4.6 2,206.1 4.9 4.7 2,238.0 0.07 45 TECO investor-owned corporation 18,176,099 18,176,099 10,946,829 14,910 31,493 16,727,908 0.08 1.6 3.5 1,840.6 1.5 3.4 1,840.6 2.6 5.6 2,460.4 0.02 46 Alliant Energy investor-owned corporation 18,019,884 17,520,356 15,740,225 75,852 28,469 21,321,066 0.55 8.4 3.2 2,366.4 8.7 3.2 2,433.9 9.6 3.6 2,590.2 0.07 47 Associated Electric Coop cooperative 18,009,963 18,009,963 15,311,319 33,179 45,321 18,208,273 0.22 3.7 5.0 2,022.0 3.7 5.0 2,022.0 4.3 5.9 2,214.0 0.03 48 NE Public Power District power district 17,423,436 11,237,419 10,922,774 35,544 25,933 13,264,298 0.17 4.1 3.0 1,522.6 6.3 4.6 2,360.7 6.5 4.7 2,396.6 0.03 49 DPL investor-owned corporation 17,210,596 17,210,596 17,023,750 101,838 28,956 17,596,224 0.39 11.8 3.4 2,044.8 11.8 3.4 2,044.8 12.0 3.4 2,051.0 0.05 50 Basin Electric Power Coop cooperative 16,448,011 16,436,024 16,384,264 59,419 32,532 19,957,246 0.51 7.2 4.0 2,426.7 7.2 4.0 2,428.5 7.3 4.0 2,433.6 0.06 51 IDACORP investor-owned corporation 16,071,921 6,865,770 6,782,998 10,265 13,120 7,536,893 0.07 1.3 1.6 937.9 3.0 3.8 2,195.5 3.0 3.9 2,206.4 0.02 52 Sempra investor-owned corporation 15,905,364 13,141,359 - 31 1,886 6,215,768 - 0.0 0.2 781.6 0.0 0.3 946.0 - - - -

2006 Generation (MWh) 2006 Emissions (tons) Emission Rates (lbs/MWh)

All Generating Sources Fossil Fuel Plants † Coal Plants ††

Rank Owner Ownership Type Total Fossil Fuel Coal SO2 NOx CO2 Hg* SO2 NOx CO2 SO2 NOx CO2 SO2 NOx CO2 Hg†††

TABLE 1

Emissions Data for 100 Largest Power Producersin order of 2006 generation


53 NiSource investor-owned corporation 15,505,727 15,442,868 14,610,597 55,212 31,386 18,256,180 0.35 7.1 4.0 2,354.8 7.2 4.1 2,364.4 7.6 4.3 2,426.8 0.05 54 US Power Generating Company investor-owned corporation 15,050,372 15,050,372 - 3,446 3,335 7,922,227 - 0.5 0.4 1,052.8 0.5 0.4 1,052.8 - - - - 55 JEA municipality 14,734,343 10,114,775 7,732,264 25,734 21,210 15,232,052 0.11 3.5 2.9 2,067.6 3.5 2.9 2,068.5 3.5 3.2 2,235.8 0.02 56 Intermountain Power Agency power district 14,451,689 14,451,689 14,445,440 4,239 28,911 16,035,530 0.11 0.6 4.0 2,219.2 0.6 4.0 2,219.2 0.6 4.0 2,220.2 0.02 57 Sierra Pacifi c investor-owned corporation 13,792,814 13,755,247 6,373,678 5,464 17,092 11,948,061 0.05 0.8 2.5 1,732.5 0.8 2.5 1,737.2 1.7 4.3 2,450.4 0.02 58 Los Angeles City municipality 13,702,821 10,987,638 3,712,423 843 7,553 8,151,398 0.03 0.1 1.1 1,189.7 0.2 1.4 1,483.7 0.4 4.0 2,292.4 0.02 59 Tri-State cooperative 12,696,992 12,694,473 12,530,555 9,088 20,606 14,938,366 0.15 1.4 3.2 2,353.1 1.4 3.2 2,353.5 1.5 3.3 2,369.0 0.02 60 Municipal Elec. Auth. of GA municipality 12,673,559 6,111,173 5,398,560 25,733 4,761 6,207,765 0.15 4.1 0.8 979.6 8.4 1.6 2,031.6 9.5 1.7 2,127.2 0.05 61 National Grid foreign-owned corp. (U.K.) 12,439,185 12,438,389 - 12,401 9,010 9,919,451 - 2.0 1.4 1,594.9 2.0 1.4 1,594.9 - - - - 62 Dow Chemical investor-owned corporation 12,122,590 11,297,856 - 8 353 6,117,185 - 0.0 0.1 1,009.2 0.0 0.1 1,082.9 - - - - 63 Austin Energy municipality 11,911,848 8,492,925 4,994,482 13,730 4,008 8,762,163 0.06 2.3 0.7 1,471.2 3.2 0.9 2,063.4 5.5 1.2 2,706.9 0.02 64 Seminole Electric Coop cooperative 11,704,743 9,804,537 7,669,806 23,212 23,140 10,795,512 0.07 4.0 4.0 1,844.6 4.7 4.7 1,788.9 6.1 6.0 2,025.8 0.02 65 Omaha Public Power District power district 11,337,527 8,207,943 7,958,302 29,309 15,743 9,138,030 0.26 5.2 2.8 1,612.0 7.1 3.8 2,226.6 7.4 3.9 2,252.4 0.07 66 CLECO investor-owned corporation 10,913,534 10,913,534 6,616,977 27,539 17,050 10,127,352 0.16 5.0 3.1 1,855.9 5.0 3.1 1,855.9 8.3 4.6 2,384.5 0.05 67 East Kentucky Power Coop cooperative 10,910,516 10,822,803 10,613,500 68,684 15,925 11,630,336 0.27 12.6 2.9 2,131.9 12.7 2.9 2,149.2 12.9 3.0 2,157.6 0.05 68 UniSource investor-owned corporation 10,801,712 10,790,618 9,794,297 10,689 18,370 12,199,818 0.13 2.0 3.4 2,258.9 2.0 3.4 2,261.2 2.2 3.7 2,378.6 0.03 69 Arkansas Electric Coop cooperative 10,542,593 10,030,730 8,985,690 27,358 13,162 10,836,612 0.22 5.2 2.5 2,055.8 5.5 2.6 2,160.7 6.0 2.9 2,269.6 0.05 70 Great River Energy cooperative 10,365,431 10,218,425 9,632,998 34,145 14,585 12,914,274 0.47 6.6 2.8 2,491.8 6.7 2.9 2,527.6 7.1 3.0 2,594.6 0.10 71 Lower CO River Authority state power authority 10,277,685 10,076,561 4,994,482 13,734 4,969 9,336,218 0.06 2.7 1.0 1,816.8 2.7 1.0 1,853.1 5.5 1.2 2,706.9 0.02 72 Goldman Sachs investor-owned corporation 10,129,415 10,076,383 6,966,059 5 3,051 9,378,718 0.06 0.0 0.6 1,851.8 0.0 0.6 1,861.5 0.0 0.8 2,280.0 0.02 73 PUD No 2 of Grant County power district 10,038,307 45 - - - 56 - - - 0.0 - - 2,503.4 - - - - 74 Exxon Mobil investor-owned corporation 9,930,159 8,614,958 - 52 977 5,123,334 - 0.0 0.2 1,031.9 0.0 0.1 1,098.2 - - - - 75 Entegra Power investor-owned corporation 9,923,822 9,923,822 - 23 1,157 4,520,127 - 0.0 0.2 911.0 0.0 0.2 911.0 - - - - 76 PNM Resources investor-owned corporation 9,897,584 7,448,337 7,279,566 8,397 17,111 8,492,510 0.14 1.7 3.5 1,716.1 2.3 4.6 2,280.4 2.3 4.7 2,300.3 0.04 77 Integrys investor-owned corporation 9,473,300 8,994,482 8,732,568 34,297 17,815 11,405,487 0.21 7.2 3.8 2,407.9 7.6 4.0 2,536.1 7.9 4.1 2,570.6 0.05 78 Energy Northwest municipality 9,433,173 - - - - - - - - - - - - - - - - 79 Buckeye Power cooperative 9,213,682 9,213,682 9,188,455 70,383 15,103 9,278,081 0.24 15.3 3.3 2,014.0 15.3 3.3 2,014.0 15.3 3.3 2,015.0 0.05 80 PUD No 1 of Chelan County power district 9,104,198 - - - - - - - - - - - - - - - - 81 Puget Energy investor-owned corporation 8,525,002 7,201,036 4,848,735 4,708 10,988 7,104,739 0.14 1.1 2.6 1,666.8 1.3 3.1 1,973.3 1.9 4.5 2,473.7 0.06 82 Hoosier Energy cooperative 8,177,172 8,177,172 8,124,447 36,485 11,944 8,831,428 0.11 8.9 2.9 2,160.0 8.9 2.9 2,160.0 9.0 2.9 2,165.3 0.03 83 Occidental investor-owned corporation 8,165,369 6,826,447 - 6 480 3,379,706 - 0.0 0.1 827.8 0.0 0.1 990.2 - - - - 84 SUEZ Energy foreign-owned corp. (France) 8,151,274 7,841,820 - 24 788 3,549,443 - 0.0 0.2 870.9 0.0 0.2 905.3 - - - - 85 Chevron investor-owned corporation 8,042,730 7,817,798 - 4 37 4,138,423 - 0.0 0.0 1,029.1 0.0 0.0 1,024.1 - - - - 86 Avista investor-owned corporation 7,800,180 3,318,581 1,514,986 1,470 3,397 2,624,656 0.04 0.4 0.9 673.0 0.9 2.0 1,581.8 1.9 4.5 2,473.7 0.06 87 Aquila investor-owned corporation 7,779,220 7,745,713 6,962,762 27,727 16,926 8,596,408 0.11 7.1 4.4 2,210.1 7.2 4.4 2,219.1 8.0 4.6 2,298.3 0.03 88 Brazos Electric Power Coop cooperative 7,751,756 7,230,315 2,935,187 11,838 4,429 6,276,923 0.14 3.1 1.1 1,619.5 3.3 1.2 1,736.3 8.1 2.4 2,786.4 0.10 89 Portland General Electric investor-owned corporation 7,449,635 5,449,741 3,916,484 8,927 9,377 5,423,933 0.12 2.4 2.5 1,456.2 3.3 3.4 1,990.5 4.6 4.7 2,394.2 0.06 90 International Paper investor-owned corporation 7,437,698 1,744,577 842,718 22,372 1,407 1,963,186 0.03 6.0 0.4 527.9 7.0 1.6 1,221.6 6.9 2.5 2,054.5 0.08 91 Sacramento Municipal Util Dist municipality 7,184,000 4,502,897 - 11 171 2,233,590 - 0.0 0.0 621.8 0.0 0.1 992.1 - - - - 92 TransAlta foreign-owned corp. (Canada) 6,964,056 6,964,056 6,349,054 1,668 9,705 7,981,435 0.10 0.5 2.8 2,292.2 0.5 2.8 2,292.2 0.5 3.0 2,408.0 0.03 93 Seattle City Light municipality 6,702,967 - - - - - - - - - - - - - - - - 94 Hawaiian Electric Industries investor-owned corporation 6,598,834 6,574,338 - 20,271 14,237 6,110,239 - 6.1 4.3 1,851.9 6.2 4.3 1,858.8 - - - - 95 CA Dept. of Water Resources state power authority 6,453,340 1,122,375 1,120,481 603 2,585 1,545,413 0.01 0.2 0.8 478.9 1.1 4.6 2,753.8 1.1 4.6 2,758.5 0.02 96 El Paso Electric investor-owned corporation 6,440,766 2,646,441 - 8 2,225 1,691,545 - 0.0 0.7 525.3 0.0 1.7 1,278.4 - - - - 97 North Carolina Mun Power Agny municipality 6,336,514 1,197 - - - 806 - - - 0.3 - - 1,346.5 - - - - 98 ALLETE investor-owned corporation 6,059,031 5,612,270 5,600,466 17,137 12,876 6,921,742 0.11 5.7 4.3 2,284.8 6.0 4.3 2,405.3 6.0 4.3 2,391.0 0.04 99 Big Rivers Electric cooperative 6,014,223 3,740,620 3,722,571 16,050 10,855 7,290,792 0.09 5.3 3.6 2,424.5 8.6 5.8 2,365.8 8.6 5.8 2,371.8 0.05

100 Vectren investor-owned corporation 6,006,169 6,006,169 5,914,861 16,942 8,726 6,955,274 0.14 5.6 2.9 2,316.0 5.6 2.9 2,316.0 5.7 2.9 2,331.1 0.05

Total (in thousands) 3,468,525 2,416,848 1,790,301 8,775 3,085 2,330,117 0.04 Average (mean) 34,685,253 24,168,480 17,903,014 87,749 30,848 23,301,172 0.43 5.1 1.8 1,343.6 7.2 2.5 1,916.1 9.6 3.2 2,208.3 0.05 Median 16,259,966 12,145,671 8,703,653 26,546 16,713 12,073,940 0.15 4.0 2.1 1,615.7 4.7 2.9 2,018.0 7.3 3.3 2,244.4 0.05

2006 Generation (MWh) 2006 Emissions (tons) Emission Rates (lbs/MWh)

All Generating Sources Fossil Fuel Plants † Coal Plants ††

Rank Owner Ownership Type Total Fossil Fuel Coal SO2 NOx CO2 Hg* SO2 NOx CO2 SO2 NOx CO2 SO2 NOx CO2 Hg†††

* Mercury emissions are based on preliminary 2006 TRI data for coal plants† Fossil fuel emission rate = pounds of pollution per MWh of electricity produced from fossil fuel †† Coal emission rate = pounds of pollution per MWh of electricity produced from coal††† Mercury emissions rate = pounds of mercury per gigawatt hour (GWh) of electricity produced from coal



Generation by Fuel Type Th e 100 largest power producers in the U.S. accounted for 85 percent of the electricity produced in 2006. Coal accounted for 52 percent of the power produced by the 100 largest companies, followed by nuclear power (22 percent), natural gas (17 percent), hydroelectric power (7 percent), oil (1 percent), and non-hydroelectric renewables and other fuel sources (1 percent). Natural gas was the source of 37 percent of the power produced by smaller companies, followed by coal (33 percent), non-hydroelectric renewables/other (16 percent), hydroelectric power (8 percent), nuclear power (5 percent), and oil (1 percent).

As a portion of total electric power production, the 100 largest companies accounted for 90 percent of all coal-fi red power, 73 percent of natural gas-fi red power, 86 percent of oil-fi red power, 96 percent of nuclear power, 84 percent of hydroelectric power and 32 percent of non-hydroelectric renewable power.

Figure 8 illustrates 2006 electric generation by fuel for each of the 100 largest power producers. Th e generation levels, expressed in million MWh, show production from facilities wholly or partially owned by each producer and reported to the EIA. Coal or nuclear accounted for over half of the output of the largest generators. Th e exceptions are two investor-owned and seven publicly-owned companies that operate large hydroelectric facilities and nine investor-owned companies whose assets are dominated by natural gas-fi red plants. Figure 8 illustrates the modest contribution non-hydroelectric renewable sources made to the total generation of the largest power producers.

Th ese data refl ect the mix of generating facilities that are directly owned by the 100 largest power producers, not the energy purchases that some utility companies rely on to meet their customers’ electricity needs. For example, some utility companies have signed long-term supply contracts for the output of renewable energy projects. In this report, the output of these facilities would be attributed to the owner of the project, not the buyer of the output.


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Emissions RankingsTable 2 shows the relative ranking of the 100 largest power producers by several measures– their contribution to total generation (MWh), total emissions and emission rates (emissions per unit of electricity output). Th ese rankings help to evaluate and compare emissions performance.

Figures 9 through 16 illustrate SO2, NOx, CO2, and mercury emissions levels (expressed in tons for SO2, NOx and CO2, and pounds for mercury) and emission rates for each of the 100 largest producers. Th ese comparisons illustrate the relative emissions performance of each producer based on the company’s ownership stake in power plants with reported emissions information. For SO2 and NOx, the report presents comparisons of total emissions levels and rates for fossil fuel-fi red facilities. For CO2, the report presents comparisons of total emissions levels and rates for all generating sources (e.g., fossil, nuclear, and renewable). For mercury, the report presents comparisons of total emissions levels and rates for coal-fi red generating facilities only.

Th e mercury emissions shown in this report were obtained from EPA’s Toxic Release Inventory (TRI). Th e TRI contains facility-level information on the use and environmental release of chemicals classifi ed as toxic under the Clean Air Act. Because coal plants are the primary source of mercury emissions within the electric industry, the mercury emissions and emission rates presented in this report refl ect the emissions associated with each producer’s fl eet of coal plants only. At the time this report was produced, only preliminary 2006 TRI data were available. Th erefore, caution is urged when comparing producers’ emissions and emission rates for mercury.

Th e emissions data for each pollutant are displayed in two formats to assist with a thorough evaluation of emissions performance. Th e fi rst format emphasizes diff erences in emission rates by ranking producers by their rates. Total tons of emissions are always presented on the upper graph. Th e second format emphasizes diff erences in emission levels by ranking producers according to their total tons of emissions. Th e charts of total emissions provide a break down of emissions by fuel type.


Th e evaluation of emissions performance by both emission levels and emission rates provides a more complete picture of relative emissions performance than viewing these measures in isolation. Total emission levels are useful for understanding each producer’s contribution to overall emissions loading, while emission rates are useful for assessing how electric power producers compare according to emissions per unit of energy produced when size is eliminated as a performance factor.

Th e charts illustrate signifi cant diff erences in the total emission levels and emission rates of the 100 largest power producers. For example, the tons of CO2 emissions range from zero to over 170 million tons per year. Th e NOx emission rates range from zero to over 5.0 pounds of emissions per MWh of generation. Th e total tons of emissions from any producer are infl uenced by the total amount of generation that a producer owns and by the fuels and technologies used to generate electricity. Although the amount of generation owned is an important factor, some producers that generated similar amounts of electricity had signifi cantly disparate total emission levels. For example in the top quartile, eight producers each generated between 100 and 200 million MWh of electricity in 2006. Among these producers, emissions ranged from 46,345 tons to 1 million tons of SO2, 15,165 tons to 294,262 tons of NOx, and 11.4 million tons to over 170 million tons of CO2.

AEP investor-owned corporation 2 1 1 2 1 1 2 10 21 35 13 21 50 14 33 73 28 AES investor-owned corporation 26 19 17 21 22 17 23 32 52 27 42 63 46 42 66 50 57 Allegheny Energy investor-owned corporation 23 16 12 5 11 15 11 3 19 21 5 31 43 8 43 72 39 ALLETE investor-owned corporation 98 85 65 57 60 75 63 30 5 10 41 10 7 47 15 21 48 Alliant Energy investor-owned corporation 46 38 33 27 35 32 22 15 20 5 20 29 5 18 32 6 9 Ameren investor-owned corporation 14 7 5 10 12 5 4 25 57 28 28 64 23 33 67 45 15 Aquila investor-owned corporation 87 74 58 47 50 66 59 20 3 13 30 8 22 31 9 30 55 Arkansas Electric Coop cooperative 69 63 49 50 58 55 43 34 40 20 44 56 29 48 59 36 32 Associated Electric Coop cooperative 47 37 34 45 18 39 44 49 1 23 53 2 48 61 2 49 60 Austin Energy municipality 63 69 69 64 77 65 72 58 75 56 58 79 42 50 76 3 66 Avista investor-owned corporation 86 90 76 77 78 89 74 77 68 85 74 62 76 69 13 8 18 Basin Electric Power Coop cooperative 50 42 31 33 28 34 24 19 8 2 29 15 6 39 25 13 14 Big Rivers Electric cooperative 99 89 73 60 63 72 65 33 11 3 22 1 8 27 3 24 33 Brazos Electric Power Coop cooperative 88 76 75 66 76 76 53 53 62 48 57 76 73 30 64 1 2 Buckeye Power cooperative 79 66 48 28 55 62 41 2 17 24 3 28 49 4 39 78 25 CA Dept. of Water Resources state power authority 95 93 77 81 81 93 78 78 70 90 73 5 1 73 11 2 69 Calpine investor-owned corporation 12 6 - 82 72 20 - 86 88 78 89 89 92 - - - - Chevron investor-owned corporation 85 73 - 94 94 85 - 94 94 72 94 94 89 - - - - CLECO investor-owned corporation 66 55 60 49 48 58 50 36 24 30 46 32 65 29 10 22 34 CMS Energy investor-owned corporation 31 27 20 24 27 24 20 22 44 39 23 50 24 26 60 46 26 Constellation investor-owned corporation 21 39 28 20 37 36 26 37 64 83 6 38 36 6 47 56 20 Dominion investor-owned corporation 8 13 10 15 8 13 8 50 56 69 38 47 54 35 42 62 24 Dow Chemical investor-owned corporation 62 52 - 91 92 79 - 92 91 73 92 93 87 - - - - DPL investor-owned corporation 49 41 27 23 32 40 31 6 16 22 10 26 45 13 36 75 42 DTE Energy investor-owned corporation 25 22 16 14 14 19 15 11 37 41 11 36 35 15 46 66 40 Duke investor-owned corporation 4 3 3 3 4 3 5 7 49 58 4 53 52 5 57 77 47 Dynegy investor-owned corporation 24 17 21 34 51 18 28 55 72 45 62 80 74 59 75 37 50 E.ON foreign-owned corp. (Germany) 27 18 15 16 13 16 16 13 34 15 19 49 27 23 58 52 46 East Kentucky Power Coop cooperative 67 57 44 29 52 52 38 5 27 17 8 41 31 9 51 55 29 Edison International investor-owned corporation 13 12 11 13 10 12 10 38 50 57 37 55 55 28 37 40 21 El Paso Electric investor-owned corporation 96 91 - 90 83 92 - 90 74 89 83 66 81 - - - - Energy Northwest municipality 78 - - - - - - - - - - - - - - - - Entegra Power investor-owned corporation 75 64 - 88 87 84 - 85 83 76 88 86 94 - - - - Entergy investor-owned corporation 7 20 35 35 23 21 25 71 73 87 59 61 70 41 61 57 11 Exelon investor-owned corporation 5 56 51 39 54 53 46 73 84 93 24 51 38 16 38 34 38 Exxon Mobil investor-owned corporation 74 68 - 85 88 82 - 82 85 71 90 91 85 - - - - FirstEnergy investor-owned corporation 10 14 7 9 9 9 18 26 51 60 16 39 37 19 50 69 64 FPL investor-owned corporation 6 5 63 31 21 14 47 70 76 84 68 78 84 55 65 54 12 Goldman Sachs investor-owned corporation 72 62 57 93 80 60 70 93 77 32 93 81 63 78 78 35 73 Great Plains Energy investor-owned corporation 44 32 22 38 15 29 19 40 2 14 49 7 25 58 7 41 8 Great River Energy cooperative 70 59 46 44 56 48 27 24 31 1 36 48 3 40 53 5 3 Hawaiian Electric Industries investor-owned corporation 94 82 - 56 57 80 - 27 4 31 40 9 64 - - - - Hoosier Energy cooperative 82 71 52 41 61 64 62 12 26 16 18 43 30 25 54 53 63 IDACORP investor-owned corporation 51 79 59 68 59 71 68 67 55 75 60 18 26 64 29 51 68 Integrys investor-owned corporation 77 67 50 43 45 54 45 18 10 4 27 14 2 32 21 7 37 Intermountain Power Agency power district 55 45 38 74 33 42 60 74 7 12 76 12 21 74 22 48 77 International Paper investor-owned corporation 90 92 78 55 86 91 75 28 80 88 34 67 82 43 63 74 4 International Power foreign-owned corp. (U.K.) 38 28 67 62 75 46 66 68 79 67 72 84 83 53 74 67 54 JEA municipality 55 60 54 51 42 43 60 51 29 19 55 46 41 62 44 42 71 Los Angeles City municipality 58 54 74 79 71 68 77 79 63 66 82 74 78 76 23 32 75

TABLE 2

Company Rankings for 100 Largest Power Producersin alphabetical order By Generation By Tons of Emissions By Emission Rates

All Generating Sources Fossil Fuel Plants Coal Plants

Owner Ownership Type Total Fossil Coal SO2 NOx CO2 Hg * SO2 NOx CO2 SO2 NOx CO2 SO2 NOx CO2 Hg


Lower CO River Authority state power authority 71 61 68 63 73 61 71 54 65 36 61 77 66 51 77 4 67 MidAmerican investor-owned corporation 16 9 6 18 5 6 12 44 23 29 49 19 28 54 24 27 53 Mirant investor-owned corporation 40 30 26 12 24 31 29 1 14 26 1 23 58 1 19 68 36 Municipal Elec. Auth. of GA municipality 60 83 66 52 74 78 52 47 71 74 26 70 47 21 70 65 23 National Grid foreign-owned corp. (U.K.) 61 50 - 65 68 59 - 60 59 50 65 73 75 - - - - NE Public Power District power district 48 53 42 42 38 47 49 45 25 55 39 4 10 44 5 18 58 New York Power Authority state power authority 33 81 - 80 85 86 - 80 89 91 81 82 86 - - - - NiSource investor-owned corporation 53 43 37 36 30 38 34 21 6 6 31 11 9 34 17 14 35 North Carolina Mun Power Agny municipality 97 95 - - - 95 - - - 95 - - 80 - - - - NRG investor-owned corporation 15 8 9 17 16 7 7 43 61 37 46 75 51 45 73 44 16 Occidental investor-owned corporation 83 80 - 92 91 88 - 91 90 80 91 90 91 - - - - OGE investor-owned corporation 39 29 29 40 26 30 40 46 22 25 52 33 56 52 35 47 59 Oglethorpe cooperative 43 51 43 37 66 49 37 39 67 68 21 68 40 20 69 64 22 Omaha Public Power District power district 65 70 53 46 53 63 39 35 33 49 32 17 20 37 28 38 10 PG&E investor-owned corporation 29 94 - 83 89 94 - 88 92 94 80 40 77 - - - - Pinnacle West investor-owned corporation 30 25 32 48 25 28 36 63 43 62 64 45 71 63 12 43 51 PNM Resources investor-owned corporation 76 75 56 71 46 67 54 62 13 42 63 6 18 67 8 29 45 Portland General Electric investor-owned corporation 89 86 72 70 67 81 58 57 39 59 56 22 53 60 6 19 17 PPL investor-owned corporation 20 24 18 8 17 23 21 8 53 65 2 42 44 3 52 71 49 Progress Energy investor-owned corporation 9 11 14 6 7 11 14 23 48 64 15 35 62 10 30 61 43 PSEG investor-owned corporation 19 23 36 26 39 25 35 56 69 81 50 72 79 17 55 59 44 PUD No 1 of Chelan County power district 80 - - - - - - - - - - - - - - - - PUD No 2 of Grant County power district 73 96 - - - 96 - - - 96 - - 5 - - - - Puget Energy investor-owned corporation 81 77 70 73 62 73 55 69 35 46 71 37 57 70 14 9 19 Reliant investor-owned corporation 28 21 19 11 20 22 13 4 42 38 7 60 69 2 34 60 6 Sacramento Municipal Util Dist municipality 91 87 - 89 93 90 - 89 93 86 86 92 90 - - - - Salt River Project power district 37 35 39 59 31 37 33 65 37 52 67 34 60 66 18 28 27 San Antonio City municipality 41 47 47 53 64 45 32 59 66 63 54 71 33 57 72 20 5 Santee Cooper state power authority 42 31 23 25 49 27 48 16 58 18 25 69 34 22 71 39 70 SCANA investor-owned corporation 35 34 25 22 36 35 42 14 46 54 14 54 61 11 45 70 61 Seattle City Light municipality 93 - - - - - - - - - - - - - - - - Seminole Electric Coop cooperative 64 65 55 54 41 56 69 48 9 33 47 3 68 46 1 76 72 Sempra investor-owned corporation 52 48 - 86 84 77 - 87 82 82 87 85 93 - - - - Sierra Pacifi c investor-owned corporation 57 46 61 72 47 51 73 72 41 40 75 59 72 71 16 11 78 Southern investor-owned corporation 1 2 2 1 2 2 1 9 47 47 9 57 59 7 49 63 13 SUEZ Energy foreign-owned corp. (France) 84 72 - 87 90 87 - 83 86 79 84 87 95 - - - - TECO investor-owned corporation 45 36 41 61 29 41 67 64 12 34 68 24 67 65 4 10 76 Tenaska privately held corporation 36 26 - 84 82 57 - 84 87 77 85 88 96 - - - - Tennessee Valley Authority federal power authority 3 4 4 4 3 4 6 29 36 61 17 16 32 24 27 58 52 TransAlta foreign-owned corp. (Canada) 92 78 62 76 65 69 64 75 32 9 77 52 16 75 48 16 56 Tri-State cooperative 59 49 40 69 43 44 51 66 18 7 70 30 12 72 40 25 65 TXU investor-owned corporation 17 15 13 7 19 10 3 17 60 44 12 65 13 12 68 12 1 UniSource investor-owned corporation 68 58 45 67 43 50 57 61 15 11 66 25 19 68 31 23 62 US Bureau of Reclamation federal power authority 22 88 71 78 70 83 76 81 81 92 79 13 17 77 26 33 74 US Corps of Engineers federal power authority 18 - - - - - - - - - - - - - - - - US Power Generating Company investor-owned corporation 54 44 - 75 79 70 - 76 78 70 78 83 88 - - - - Vectren investor-owned corporation 100 84 64 58 69 74 56 31 28 8 43 44 15 49 56 26 41 Westar investor-owned corporation 34 40 30 32 34 33 30 41 45 53 33 27 11 36 41 17 30 Wisconsin Energy investor-owned corporation 32 33 24 31 40 26 17 42 54 51 35 58 14 38 62 15 7

Xcel investor-owned corporation 11 10 8 19 6 8 9 52 29 43 51 20 39 56 20 31 31

By Generation By Tons of Emissions By Emission Rates

All Generating Sources Fossil Fuel Plants Coal Plants

Owner Ownership Type Total Fossil Coal SO2 NOx CO2 Hg * SO2 NOx CO2 SO2 NOx CO2 SO2 NOx CO2 Hg

A ranking of 1 indicates the highest absolute number or rate in any column: the highest generation (MWh), highest emissions (tons), or highest emission rate (lbs/MWh). A ranking of 100 indicates the lowest absolute number or rate in any column.

* Mercury emissions are in pounds and rankings are based on preliminary 2006 TRI data for coal plants only.



NOx and SO2 Emissions Levels and Rates Figures 9 through 12 display SO2 and NOx emission levels and emission rates for fossil fuel-fi red generating sources owned by each company.

“Fossil only” emission rates are calculated by dividing each company’s total NOx and SO2 emissions from fossil-fi red power plants by its total generation from fossil-fi red power plants. Companies with signifi cant coal-fi red generating capacity have the highest total emissions of SO2 and NOx because coal contains higher concentrations of sulfur than natural gas and oil and coal plants generally have higher NOx emission rates.

Figures 9 through 12 illustrate wide disparities in the “fossil only” emission levels and emission rates of the 100 largest power producers. Th eir total fossil generation varies from 0 MWh to 169 million MWh and:

SO2 emissions range from 0 to 1 million tons, and SO2 emission rates range from 0 lbs/MWh to 18.3 lbs/MWh;

NOx emissions range from 0 to 294,262 tons, and NOx emission rates range from 0 lbs/MWh to 5.8 lbs/MWh.

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FIGURE 11

Fossil Fuel - SO2 Total Emissions and Emission RatesTotal emissions (thousand tons) and emission rates (lbs/MWh) from fossil fuel generating facilities

SO2-

lbs/

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FIGURE 12

Fossil Fuel - SO2 Total Emissions and Emission RatesTotal emissions (thousand tons) and emission rates (lbs/MWh) from fossil fuel generating facilities

SO2-

lbs/

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hPo

unds

of S

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mitt

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Wh

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f SO

2 em

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il fu

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ies


CO2 Emission Levels and Rates Figures 13 and 14 display total CO2 emission levels and emission rates based on all generating sources owned by each company.

“All-source” emission rates are calculated by dividing each company’s total CO2 emissions by its total generation. In most cases, producers with signifi cant non-emitting fuel sources, such as nuclear, hydroelectric and wind power, have lower all-source emission rates than producers owning primarily fossil fuel power plants. Among the 100 largest power producers:

Coal-fi red power plants are responsible for 81.5 percent of CO2 emissions.

Natural gas-fi red power plants are responsible for 15.3 percent of CO2 emissions.

Oil-fi red power plants are responsible 1.9 percent of CO2 emissions.

Figures 13 and 14 illustrate wide disparities in the “all-source” emission levels and emission rates of the 100 largest power producers. Th eir total electric generation varies from 6 million MWh to 202 million MWh and their CO2 emissions range from 0 to 170 million tons, and CO2 emission rates range from 0.0 lbs/MWh to 2,492 lbs/MWh.

•

•

•


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100

150

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Natural Gas

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FIGURE 13

All Source - CO2 Total Emissions and Emission RatesTotal emissions (million tons) and emission rates (lbs/MWh) from all generating facilities

CO2

- lbs

/MW

hPo

unds

of C

O2 e

mitt

ed p

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of e

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ricity

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ll ge

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ons

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tons

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om a

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FPL

Constellation


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FIGURE 14

All Source - CO2 Total Emissions and Emission RatesTotal emissions (million tons) and emission rates (lbs/MWh) from all generating facilities

CO2

- lbs

/MW

hPo

unds

of C

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mitt

ed p

er M

Wh

of e

lect

ricity

pro

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2 - t

ons

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tons

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ed fr

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ll ge

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s


Mercury Emission Levels and RatesFigures 15 and 16 display total mercury emission levels and emission rates from coal-fi red power plants.

Th e EPA had adopted rules regulating mercury emissions from coal-fi red power plants; however, those rules have never taken eff ect and were recently found to be invalid by the U.S. Court of Appeals for the DC Circuit under the Clean Air Act. EPA must revisit its rulemaking. Th erefore, coal plants generally do not have pollution controls specifi cally designed to remove mercury. Th e diff erences in mercury emission rates are largely due to the mercury content and type of coal used, and the eff ect of control technologies designed to lower SO2, NOx and particulate emissions.

Coal mercury emissions range from 21 pounds to 8,719 pounds, and coal mercury emission rates range from 0.015 pounds per gigawatt-hour (a gigawatt-hour is 1,000 megawatt hours) to 0.105 lbs/GWh.

•


0

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FIGURE 15

Coal - Mercury Emission Rates and Total EmissionsEmission rates (lbs/GWh) and total emissions (pounds) from coal plants

1 gigawatt-hour (GWh) = 1,000 MWh

Mer

cury

- po

unds

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ds o

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itted

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per

GW

h of

ele

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prod

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l pla

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ALLOWANCE DISTRIBUTION SCENARIOS 49

Congress is focusing an increasing level of attention on climate change and the options for regulating U.S. greenhouse gas emissions from power plants and other sectors of the economy. In 2007, members of Congress proposed at least 13 bills that would set mandatory limits on U.S. greenhouse gas emissions by establishing a cap-and-trade system similar to the approach used in regulating NOx and SO2 emissions from power plants under the Clean Air Act and the approach adopted in Europe for regulating greenhouse gas emissions.

Under a cap-and-trade system, a limit is placed on the overall emissions from covered sources by requiring power plant operators and other regulated sources to surrender “allowances” for the greenhouse gases they release to the atmosphere, and by limiting the number of allowances available each year. An allowance is a permit to emit a discrete quantity of greenhouse gases (e.g., one ton of CO2). Companies can trade or hold allowances for future use, but at the end of each compliance period, they must surrender allowances equal to their emissions. For additional background on cap-and-trade based regulation, please refer to the section of this report entitled “Cap-and-Trade 101.”

A key issue in designing a cap-and-trade program is the methodology used for distributing emissions allowances. At a price of $10 per ton, the total value of allowances under a comprehensive, economy wide cap-and-trade program would exceed $60 billion annually.15 Th e methodology used for distributing emissions allowances can have a strong infl uence on the energy costs paid by consumers and the profi tability of the companies regulated by the program, making it one of the most critical and contentious issues in designing a cap-and-trade program.

Options for Distributing Emissions AllowancesTh ere are several options for distributing emissions allowances to power plant operators subject to a cap-and-trade program. Th e government can sell the allowances to companies through an auction; the government can give the allowances to companies at no cost; or the government can give the allowances to third party entities such as state governments or local electric utilities (distribution companies) for consumer benefi t.

Allowance Distribution Scenarios

Cap-and-Trade TerminologyAllowance. A permit to emit a discrete quantity of greenhouse gases or other air pollutant (e.g., one ton of CO2).

Distribution of Allowances. A general term encompassing the many options available for distributing emis-sions allowances under a cap-and-trade program, including auctions and free allocations.

Allocation of Allowances. The free distribution of allowances by the government to regulated sources or third party entities.

Allowance Trading. The purchase or sale of allowances by regulated sources, brokers, and other market participants.


Th ese third party entities would not need the allowances for compliance purposes. Rather, they would sell the allowances and dedicate the proceeds to public purposes (e.g., funding for energy effi ciency programs, clean energy technologies, or low income fuel assistance).

Auction Approach. Economists generally agree that the auctioning of allowances is the most effi cient method for distributing emissions allowances.16 Th e auction approach is consistent with the principle that polluting facilities should pay for the costs of their emissions. Th e auctioning of allowances also provides resources to fund public initiatives that will be important in responding to climate change. Several bills in Congress propose auctioning a growing share of allowances with the proceeds dedicated to various public purposes, including technology research and development, incentives for the deployment of energy effi ciency and renewable energy technologies, low income-energy assistance, adaptation to climate change, and worker retraining.

According to John Holdren, an expert on energy and climate at Harvard University and the Woods Hole Research Center, “[c]urrent government spending on energy research, development, demonstration, and incentives for accelerated deployment is woefully inadequate in relation to the challenges and the opportunities that the energy sector presents.”17 In response, scientists have been advocating stepped up funding for alternative energy sources in the range of $30 billion per year.18 Th e auctioning of allowances could help fund such an initiative.

Some within industry have expressed opposition to the auction approach, suggesting that the auctioning of allowances could lead to steep increases in electricity prices.19

Allocations to Electric Power Producers. Another option for distributing emissions allowances would be to give the allowances to power plant owners at no cost. Free allocations to power plant owners reduce the plants’ net compliance costs. Whether the free distribution of allowances provides electric power producers and their shareholders revenues that exceed their actual compliance costs will depend on several factors, including how the price of electricity is set in a given power market (this infl uences the extent to which CO2 costs pass through to consumers), the treatment of allowances allocated to regulated utilities by public utility commissions, and whether a utility company purchases

Legislative ProposalAuction Percentage

2012 2025 2050Lieberman-Warner Climate Security Act (S.2191) 27% 49% 70%

Low Carbon Economy Act (S.1766) 24% 43% 53%


or produces a signifi cant share of its electricity supply. A typical coal-fi red power plant will produce about one ton of CO2 for every megawatt hour of electricity that it generates. A cap-and-trade program—with allowances trading at a price of $10 per ton—would increase the costs of operating such a facility by $10 per megawatt hour. (A typical coal fi red power plant will produce electricity at a cost of around $55 per megawatt hour, assuming no CO2 costs.20) Similarly, a typical power plant using natural gas emits about one-half ton of CO2 per megawatt hour, so its operating costs would increase by about $5 per megawatt hour. However, if the power plant owner receives free allowances, the plant’s net CO2 compliance costs (emissions minus free allowances) may be substantially reduced depending on the number of allowances allocated to the power plant owner.

Allowances can be allocated to individual power plant owners based on a variety of methodologies, including historic CO2 emissions or electricity output. For example, assuming that allowances are apportioned based on historic emissions, a company whose power plants produce fi ve percent of total electric sector CO2 emissions would receive fi ve percent of the available allowances.

Table 3 presents an estimate of the number of allowances and the value of the allowances that individual electric power producers would receive under several allocation scenarios. Th e overall allocation quantities are based on two recent legislative proposals—the Lieberman-Warner Climate Security Act (“the Lieberman-Warner bill”) and the Low Carbon Economy Act. We focus on these two proposals because they are economy-wide bills that provide detailed specifi cations of how their emissions allowances are to be allocated. Other economy wide bills simply delegate that responsibility to EPA or to the President. Th ese allocation scenarios were developed in an eff ort to isolate the

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FIGURE 17

The Distribution of Allowances under the Lieberman-Warner Climate Security Act & Low Carbon Economy Act The Lieberman-Warner bill and Low Carbon Economy Act proposes distributing allowances to a wide range of entities, including (1) electric power producers, (2) allocations to companies in other industry sectors aff ected by the bill, (3) federal auction, (4) agriculture and forestry projects, (5) states, and (6) electric and natural gas distribution companies for consumer benefi t.

NOTE: Fewer allowances are available for distribution as the emissions caps decline.

Lieberman-Warner Climate Security Act

conditional target

Low Carbon Economy Act


eff ect of the diff erent allocation options available to Congress, including the overall quantity of allowances allocated to electricity producers and the metrics (e.g., CO2 emissions or electricity output) used for apportioning the allowances among the companies.

In 2012, the Lieberman-Warner bill distributes 1,210 million tons (1,097 million metric tons) of CO2 allowances to power plant operators, an allocation equivalent to about 45 percent of current electric sector CO2 emissions. Th e Lieberman-Warner bill also allocates allowances to regulated electric distribution companies for consumer benefi t, as described below, for a total electric sector allocation equivalent to about 70 percent of current electric sector CO2 emissions. Th e Low Carbon Economy Act provides a larger allocation to electric power producers in 2012 equal to about 80 percent of current electric sector CO2 emissions, or 2,126 million tons (1,929 million metric tons).21 Th e Low Carbon Economy Act provides no allowances to regulated electric distribution companies for consumer benefi t.

Table 3 also lists the total value of the allowances allocated to each company assuming an allowance price of $10 per ton. Th is price is intended for illustrative purposes only, and is not a prediction of future CO2 allowance costs. Allowance prices will depend on the stringency of the emissions cap, cost containment provisions, and other program features. As of the writing of this report, EPA was refi ning its modeling and EIA was still conducting its assessment of the Lieberman-Warner bill. Th ese assessments will project future CO2 allowance prices under the bill. Readers can calculate allowance values using alternative CO2 prices by simply multiplying the allocation quantities in Table 3 by an alternative price per ton.

Both bills propose allocating the majority of allowances to electric power producers based on their historic CO2 emissions in 2004 through 2006 in the case of the Low Carbon Economy Act and 2005 through 2007 in the case of the Lieberman-Warner bill. Table 3 calculates the company allocations based on 2006 CO2 emissions data, providing a reasonable proxy of the approach proposed by the two proposals.

Rather than divvying up the allowances based on a company’s share of emissions, which would tend to penalize companies that have invested in low- and zero-carbon technologies

Options for Allocating Allowances to Power Plant Owners

There are two basic options for distributing free allowances to power plant owners: (1) historic CO2 emissions, or (2) electricity output. Companies with higher emitting, less effi cient power plants generally benefi t from an emissions-based allocation, while companies with lower emitting, higher effi ciency power plants benefi t from an output-based allocation. In allocating allowances based on electricity output, allowances can be distributed to fossil fuel-fi red power plants only, or both fossil and non-CO2 emitting power plants. The table below compares these diff erent options for some of the largest electric power producers.

NOTE: Allocating 1.0 million tons of CO2 allowances to illustrate relative eff ect of diff erent allocation metrics.

Parent Company

Emissions Based

Allocation

Fossil Output

Based Allocation

Total Output

Based Allocation

Southern 60,645 59,171 49,616AEP 62,770 59,520 46,038TVA 39,997 35,560 38,125Duke 41,030 38,782 37,572Exelon 4,218 3,815 37,523FPL 19,079 32,318 34,069Entergy 12,369 13,132 28,295Dominion 20,993 20,189 25,451Progress 21,380 21,521 22,848FirstEnergy 21,631 18,980 20,613Xcel 24,937 22,773 19,653Calpine 13,020 25,562 19,564Edison Int. 21,325 20,517 19,502Ameren 27,830 23,951 19,496NRG 25,085 23,615 18,924


in advance of the cap-and-trade program, Congress might apportion the allowances based on a company’s share of electricity output. Th is can be done based on a company’s share of total electricity output, or based on the output of only fossil fuel-fi red power plants or only fossil fuel and renewable energy facilities, for example. Table 3 also includes an estimate of the number of allowances and the value of the allowances that individual power companies would receive if apportioned based on total megawatt hours inclusive of all generation types, using the 2012 allocation pool proposed by the Lieberman-Warner bill (1,210 million tons) as well as the allocation pool proposed by the Low Carbon Economy Act (2,126 million tons).

Table 3 shows that:

Th e total annual value of the allowances allocated to the 100 largest electric power producers under the Emissions Based Scenario 1—with a total allowance pool equivalent to the Lieberman-Warner Climate Security Act in 2012—is close to $10.4 billion assuming a price of $10 per ton of CO2. Again, this is not intended as a prediction of future allowance prices. Allocations to power plant operators phase out under the Lieberman-Warner bill over a period of 19 years. Th e Lieberman-Warner bill provides an additional $5.7 billion in allowance value to regulated electric distribution companies assuming a price of $10 per ton of CO2, which is specifi cally directed to consumer benefi t, as discussed below.

Th e total annual value of the allowances allocated to the 100 largest electric power producers under the Emissions Based Scenario 2—with a total allowance pool equivalent to the Low Carbon Economy Act in 2012—is close to $18.3 billion assuming a price of $10 per ton of CO2. Th e Low Carbon Economy Act caps allowance prices at $10.89 per ton ($12 per metric ton) in 2012, and the price cap escalates by fi ve percent above the rate of infl ation each year aft er 2012. Allocations to power plant operators phase out under the Low Carbon Economy Act over a period of 32 years.

Th e potential value of the allowances allocated to individual electric generating companies can be substantial. Th e ten largest investor owned utilities would receive an annual allocation valued at $6.2 billion, assuming a CO2 allowance price of $10 per ton, under Emissions Based Scenario 2. To provide a sense of the magnitude of this value, this is equivalent to 16 percent of the companies’ total earnings in 2006.

Allocations to Th ird Parties for Public Benefi t. A third alternative is to give allowances to third party entities such as state governments or regulated electric distribution utilities for public purposes. Th e Lieberman-Warner bill and the Low Carbon Economy Act have proposed allocating a portion of allowances to state governments, leaving it to the states to decide among a menu of options for distributing the allowance value. Th e Lieberman-

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1 Southern 164,634 73,351 $734 128,959 $1,290 60,011 $600 105,506 $1,055 2 AEP 170,403 75,921 $759 133,477 $1,335 55,684 $557 97,898 $979 3 Tennessee Valley Authority 108,580 48,377 $484 85,051 $851 46,113 $461 81,071 $811 4 Duke 111,385 49,626 $496 87,248 $872 45,444 $454 79,895 $799 5 Exelon 11,450 5,102 $51 8,969 $90 45,384 $454 79,790 $798 6 FPL 51,794 23,076 $231 40,570 $406 41,207 $412 72,446 $724 7 Entergy 33,579 14,961 $150 26,302 $263 34,223 $342 60,167 $602 8 Dominion 56,991 25,392 $254 44,641 $446 30,783 $308 54,120 $541 9 Progress Energy 58,040 25,859 $259 45,463 $455 27,635 $276 48,586 $486

10 FirstEnergy 58,722 26,163 $262 45,997 $460 24,932 $249 43,833 $438 11 Xcel 67,696 30,161 $302 53,026 $530 23,771 $238 41,791 $418 12 Calpine 35,344 15,747 $157 27,685 $277 23,663 $237 41,602 $416 13 Edison International 57,890 25,792 $258 45,346 $453 23,588 $236 41,470 $415 14 Ameren 75,552 33,661 $337 59,180 $592 23,581 $236 41,457 $415 15 NRG 68,099 30,341 $303 53,342 $533 22,889 $229 40,241 $402 16 MidAmerican 72,145 32,143 $321 56,511 $565 22,625 $226 39,777 $398 17 TXU 58,411 26,024 $260 45,754 $458 20,715 $207 36,419 $364 18 US Corps of Engineers - - $ - - $ - 20,566 $206 36,157 $362 19 PSEG 24,898 11,093 $111 19,503 $195 18,661 $187 32,808 $328 20 PPL 31,901 14,213 $142 24,989 $250 15,481 $155 27,217 $272 21 Constellation 18,685 8,325 $83 14,636 $146 14,563 $146 25,604 $256 22 US Bureau of Reclamation 4,877 2,173 $22 3,820 $38 14,221 $142 25,002 $250 23 Allegheny Energy 48,004 21,388 $214 37,602 $376 13,936 $139 24,501 $245 24 Dynegy 37,183 16,566 $166 29,125 $291 13,213 $132 23,229 $232 25 DTE Energy 37,113 16,535 $165 29,071 $291 12,751 $128 22,417 $224 26 AES 41,855 18,648 $186 32,785 $328 12,623 $126 22,192 $222 27 E.ON 45,969 20,481 $205 36,008 $360 12,553 $126 22,070 $221 28 Reliant 32,319 14,399 $144 25,315 $253 10,914 $109 19,189 $192 29 PG&E 474 211 $2 371 $4 9,873 $99 17,358 $174 30 Pinnacle West 22,571 10,056 $101 17,680 $177 9,775 $98 17,186 $172 31 CMS Energy 26,232 11,687 $117 20,547 $205 8,974 $90 15,776 $158 32 Wisconsin Energy 23,065 10,276 $103 18,067 $181 8,616 $86 15,147 $151 33 New York Power Authority 3,666 1,633 $16 2,871 $29 8,115 $81 14,267 $143 34 Westar 20,310 9,049 $90 15,909 $159 7,745 $77 13,616 $136 35 SCANA 19,120 8,519 $85 14,976 $150 7,435 $74 13,072 $131 36 Tenaska 10,614 4,729 $47 8,314 $83 7,100 $71 12,483 $125 37 Salt River Project 18,499 8,242 $82 14,491 $145 7,009 $70 12,323 $123 38 International Power 13,594 6,057 $61 10,649 $106 6,917 $69 12,161 $122 39 OGE 22,131 9,860 $99 17,335 $173 6,625 $66 11,648 $116 40 Mirant 22,080 9,837 $98 17,295 $173 6,621 $66 11,640 $116 41 San Antonio City 14,353 6,395 $64 11,243 $112 6,552 $66 11,519 $115 42 Santee Cooper 23,006 10,250 $102 18,020 $180 6,529 $65 11,478 $115 43 Oglethorpe 12,264 5,464 $55 9,607 $96 6,383 $64 11,222 $112 44 Great Plains Energy 22,505 10,027 $100 17,628 $176 6,101 $61 10,727 $107 45 TECO 16,728 7,453 $75 13,103 $131 5,407 $54 9,507 $95 46 Alliant Energy 21,321 9,499 $95 16,701 $167 5,361 $54 9,425 $94 47 Associated Electric Coop 18,208 8,112 $81 14,263 $143 5,358 $54 9,420 $94 48 NE Public Power District 13,264 5,910 $59 10,390 $104 5,184 $52 9,113 $91 49 DPL 17,596 7,840 $78 13,783 $138 5,120 $51 9,002 $90 50 Basin Electric Power Coop 19,957 8,892 $89 15,633 $156 4,893 $49 8,603 $86

Emissions Based Allocation Scenario 1Total Allowance Pool of 1,210 million short tons allocated based on 2006 CO2 emissions


Output Based Allocation Scenario 1Total Allowance Pool of 1,210 million short tons allocated based on 2006 total electricity output (MWhs)


Rank Owner2006 CO2 Emissions

(‘000 tons)Allocations

(‘000 tons) Value

(million $)Allocations

(‘000 tons) Value


(‘000 tons) Value


(‘000 tons) Value

(million $)

TABLE 3

Allocations to Electricity GeneratorsAllowance Allocations and Allowance Value Assuming a Price of $10 per ton, Under an Emissions Based Allocation Scenario and an Output Based Allocation (Total Megawatt hours) by Company for the 100 Largest Electric Power Producers. Sorted by 2006 MWh generation.








Rank Owner2006 CO2 Emissions

(‘000 tons)Allocations

(‘000 tons) Value


(‘000 tons) Value


(‘000 tons) Value


(‘000 tons) Value

(million $)51 IDACORP 7,537 3,358 $34 5,904 $59 4,781 $48 8,406 $84 52 Sempra 6,216 2,769 $28 4,869 $49 4,732 $47 8,319 $83 53 NiSource 18,256 8,134 $81 14,300 $143 4,613 $46 8,110 $81 54 US Power Generating Company 7,922 3,530 $35 6,206 $62 4,478 $45 7,872 $79 55 JEA 15,232 6,786 $68 11,931 $119 4,348 $44 7,707 $77 56 Intermountain Power Agency 16,036 7,144 $71 12,561 $126 4,299 $43 7,559 $76 57 Sierra Pacifi c 11,948 5,323 $53 9,359 $94 4,103 $41 7,214 $72 58 Los Angeles City 8,151 3,632 $36 6,385 $64 4,077 $41 7,167 $72 59 Tri-State 14,938 6,656 $67 11,701 $117 3,777 $38 6,641 $66 60 Municipal Elec. Auth. of GA 6,208 2,766 $28 4,863 $49 3,770 $38 6,629 $66 61 National Grid 9,919 4,419 $44 7,770 $78 3,701 $37 6,506 $65 62 Dow Chemical 6,117 2,725 $27 4,792 $48 3,607 $36 6,341 $63 63 Austin Energy 8,762 3,904 $39 6,863 $69 3,544 $35 6,230 $62 64 Seminole Electric Coop 10,796 4,810 $48 8,456 $85 3,482 $35 6,122 $61 65 Omaha Public Power District 9,138 4,071 $41 7,158 $72 3,373 $34 5,930 $59 66 CLECO 10,127 4,512 $45 7,933 $79 3,247 $32 5,708 $57 67 East Kentucky Power Coop 11,630 5,182 $52 9,110 $91 3,246 $32 5,707 $57 68 UniSource 12,200 5,435 $54 9,556 $96 3,214 $32 5,650 $56 69 Arkansas Electric Coop 10,837 4,828 $48 8,488 $85 3,136 $31 5,514 $55 70 Great River Energy 12,914 5,754 $58 10,116 $101 3,084 $31 5,422 $54 71 Lower CO River Authority 9,336 4,160 $42 7,313 $73 3,058 $31 5,376 $54 72 Goldman Sachs 9,379 4,179 $42 7,346 $73 3,014 $30 5,298 $53 73 PUD No 2 of Grant County - - $ - - $ - 2,986 $30 5,250 $53 74 Exxon Mobil 5,123 2,283 $23 4,013 $40 2,954 $30 5,194 $52 75 Entegra Power 4,520 2,014 $20 3,541 $35 2,952 $30 5,191 $52 76 PNM Resources 8,493 3,784 $38 6,652 $67 2,945 $29 5,177 $52 77 Integrys 11,405 5,082 $51 8,934 $89 2,818 $28 4,955 $50 78 Energy Northwest - - $ - - $ - 2,806 $28 4,934 $49 79 Buckeye Power 9,278 4,134 $41 7,268 $73 2,741 $27 4,819 $48 80 PUD No 1 of Chelan County - - $ - - $ - 2,709 $27 4,762 $48 81 Puget Energy 7,105 3,165 $32 5,565 $56 2,536 $25 4,459 $45 82 Hoosier Energy 8,831 3,935 $39 6,918 $69 2,433 $24 4,277 $43 83 Occidental 3,380 1,506 $15 2,647 $26 2,429 $24 4,271 $43 84 SUEZ Energy 3,549 1,581 $16 2,780 $28 2,425 $24 4,263 $43 85 Chevron 4,138 1,844 $18 3,242 $32 2,393 $24 4,207 $42 86 Avista 2,625 1,169 $12 2,056 $21 2,321 $23 4,080 $41 87 Aquila 8,596 3,830 $38 6,734 $67 2,314 $23 4,069 $41 88 Brazos Electric Power Coop 6,277 2,797 $28 4,917 $49 2,306 $23 4,055 $41 89 Portland General Electric 5,424 2,417 $24 4,249 $42 2,216 $22 3,897 $39 90 International Paper 1,963 875 $9 1,538 $15 2,213 $22 3,890 $39 91 Sacramento Municipal Util Dist 2,234 995 $10 1,750 $17 2,137 $21 3,758 $38 92 TransAlta 7,981 3,556 $36 6,252 $63 2,072 $21 3,643 $36 93 Seattle City Light - - $ - - $ - 1,994 $20 3,506 $35 94 Hawaiian Electric Industries 6,110 2,722 $27 4,786 $48 1,963 $20 3,451 $35 95 CA Dept. of Water Resources 1,545 689 $7 1,211 $12 1,920 $19 3,375 $34 96 El Paso Electric 1,692 754 $8 1,325 $13 1,916 $19 3,369 $34 97 North Carolina Mun Power Agny 1 - $ - 1 $ - 1,885 $19 3,314 $33 98 ALLETE 6,922 3,084 $31 5,422 $54 1,803 $18 3,169 $32 99 Big Rivers Electric 7,291 3,248 $32 5,711 $57 1,789 $18 3,146 $31

100 Vectren 6,955 3,099 $31 5,448 $54 1,787 $18 3,142 $31

TABLE 3, CONTINUED


Warner bill also allocates a portion of allowances to local electric utilities (distribution companies), including a provision mandating that the allowance value be returned to low and middle-income electricity consumers through customer rebates, or proceeds from the sale of allowances can be used to fund consumer energy effi ciency programs. Th e local electric utility would receive allowances based on their proportional share of electricity deliveries. Th e company would then sell the allowances they receive, perhaps through an auction, to facilities covered by the emissions cap, and any revenues generated would be returned to their customers. Local electric utilities are uniquely positioned for this role because (1) they have established fi nancial relationships with electric customers, (2) they are subject to state utility commission or board oversight, and (3) many have existing energy effi ciency and energy assistance programs to build on.

Table 4 presents the CO2 allowance allocations for the largest electric distribution companies based on the methodology proposed by the Lieberman-Warner Climate Security Act. Individual company allocations are calculated based on their proportionate share of electricity sales (measured in megawatt hours) in 2006 and an allowance pool of 573 million tons (520 million metric tons). Th e table lists both the parent company as well as the utility subsidiaries receiving the allowances. Table 4 also lists the total value of the allowances allocated to each company assuming an allowance price of $10 per ton. Again, this price is intended for illustrative purposes only, and is not a prediction of future CO2 allowance costs. For context, Table 4 lists the megawatt hour sales and average electricity rates across all customer classes in 2006.

Allowance Value as Compared to Earnings

The value of the emissions allowances allocated to electric power producers under a national cap-and-trade program could be substantial. The data below present estimates of the total allowance value allocated to the 10 largest investor owned utilities under two of our allocation scenarios. Values are calculated assuming a CO2 price of $10 per ton (this price is intended for illustrative purposes only). Earnings are presented to provide a sense of the magnitude of the values. Whether the free distribution of allowances provides electric power producers and their shareholders revenues that exceed their actual compliance costs will depend on several factors (see page 23).

* Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) 2006. Source: Capital IQ.† Allowance value to power plant operators assuming CO2 price of $10 per ton, emissions based allocation, and an allowance

reserve of 1,210 million short tons as proposed by the Climate Security Act in 2012. Allowance value to electric distribution companies assuming CO2 price of $10 per ton, emissions based allocation, and an allowance reserve of 573 million short tons as proposed by the Climate Security Act in 2012.

†† Allowance value allocated to electric distribution companies under the Lieberman-Warner bill is to be returned to electricity consumers through rebates and/or energy effi ciency incentives.

‡ Allowance value to power plant operators assuming CO2 price of $10 per ton, emissions based allocation, and an allowance reserve of 1,210 million short tons as proposed by the Climate Security Act in 2012.

Scenario 1† Scenario 2‡

Company

2006 Earnings (millions)*

Allowance Value to

Power Plant Operators

(millions)

Allowance Value to Electric

Distribution Companies

for Consumer Benefi t

(millions)††

Total Allowance

Value (millions)

Allowance Value to

Power Plant Operators

(millions)

AEP $3,930 $759 $221 $980 $1,335Southern $4,810 $734 $250 $984 $1,290Xcel $2,260 $302 $134 $436 $530Duke $4,320 $496 $202 $698 $872ProgressEnergy $2,620 $259 $128 $387 $455FirstEnergy $3,450 $262 $163 $424 $460Dominion $3,470 $254 $118 $372 $446FPL $3,690 $231 $161 $392 $406Entergy $3,000 $150 $156 $305 $263Exelon $6,150 $51 $200 $251 $90


Table 4 shows that:

In allocating allowances to local electric utilities, the value to individual consumers will depend in large part on whether the allowance proceeds are divided among residential, commercial, industrial, or all customer classes. For example, Alabama Power Company would receive $87 million in allowance value under Scenario 1 Allocation to Local Electric Utilities (assuming an allowance pool of 573 million tons and a price of $10 per ton of CO2). Th is translates to a total benefi t of 0.47 cents per kilowatt hour when distributed across the company’s residential customer sales, or 0.26 cents per kilowatt hour when distributed across the company’s residential and commercial customer sales. If the allowance value were distributed among low- and middle-income households only—one of the options proposed by the Lieberman-Warner bill—the value per low- and middle-income consumer would be even higher than presented here.

In the fi nal column of Table 4, we divide the allowance value allocated to each utility across their total electricity sales. Because the allowances are allocated based on total electricity sales, the value per kilowatt hour is constant across all utilities (i.e., 0.16 cents per kilowatt hour).

Th e value aff orded to electricity consumers under Scenario 1 Allocation to Local Electric Utilities is fairly modest relative to current average electricity rates. For example, if the allowance value were divided among residential and commercial customers only, the median annual allowance value is 0.21 cents per kilowatt hour. Th is compares to an average U.S. electricity rate of 8.77 cents per kilowatt hour in 2006.22

Among the top ten electric utility parent companies, in terms of their 2006 electricity sales, seven of these utility owners also appear within the list of top ten power producers evaluated in Table 3 (allocation to generators). Th e top ten electric utility parent companies receive 30.6 percent of the allowances allocated to all electric distribution companies while accounting for 31 percent of all residential customers in the U.S.

Allowances allocated to utility owners range from 35,000 allowances to 16 million allowances (a 466-fold diff erence), and the value of allocated allowances per residential customer range from $26 to $142 (a fi ve-fold diff erence) assuming a CO2 allowance price of $10 per ton. Th e value per residential customer varies in part because of diff erences in average residential electricity consumption as well as diff erences in the proportion of electricity sales by customer class.

Customers paying the highest average electricity rates would generally not receive the highest benefi t per residential and commercial customer. Th is is likely due to a higher concentration of industrial customers in regions with lower average electricity rates (in Table 4 allowances were allocated to utility companies based on total electricity sales).

•

•

•

•

•

•


Example of Allocation to Local Electric Utilities for Consumer Benefi t

According to the U.S. Department of Energy, the average residential customer in Indiana pays $82 per month for electricity or 8.22 cents per kilowatt hour.1

Indiana relies heavily on coal for its electricity supply. Assuming a CO2 price of $10 per ton, the cost of producing electricity with a coal-fi red power plant will increase by about 1.05 cents per kilowatt hour. However, if the power plant receives an allocation equal to about 45 percent of its historic emissions, as proposed by the Lieberman-Warner bill, its electricity production costs, after accounting for the free allowances, will increase by only 0.6 cents per kilowatt hour.2 Indiana’s average residential customer would pay an additional $6 per month in CO2 costs on their electricity bill.

An allocation to local electric distribution companies is proposed as an option to help mitigate the higher costs to consumers, further mitigating the costs faced by the electric utility customer. Assuming that 573 million tons of CO2 allowances are allocated to local electric distribution companies for the benefi t of residential customers, Indiana’s average residential customer would receive $4.21 per month in allowance value in the form of rebates or energy effi ciency incen-tives. Their net CO2 costs would be reduced from $6 per month to $1.52 per month, and their electric bill would total $83 per month, rather than $87 per month, assuming a direct rebate.

By installing compact fl uorescent lighting and other energy saving devices, our average household could reduce its electric bill to its prior level. Reducing average electricity use by 1.8 percent—combined with a rebate of $4.21 per month—would fully compensate for a $10 per ton CO2 allowance price.

1. U.S. Energy Information Administration (U.S. EIA). U.S. Average Monthly Bill by Sector, Census Division and State. Released November 2007.

2. We are assuming that our average household is served by a regulated generator that both produces and distributes its electric supply.

Average Monthly Bill 993.00 kwh× 9.34 cents/kwh $82.00 per month

CO2 Costs 2,100.00 lbs/mwh*× $10.00 per short ton 1.05 cents/kwh

Consumer Allowance Value $5.73 billion**÷ 1,351.00 million Mwhs*** 0.42 cents/kwh

* Typical CO2 emission rate for a coal-fi red power plant.

** $10 per short ton times 573 million tons of CO2

*** Total residential electricity sales in 2006 as reported by U.S. EIA.

A compact fl uorescent bulb will reduce energy use 75% relative to a standard incandescent bulb

Southern Alabama Power 7.09 18,632,935 14,513,912 23,227,952 - 8,746 $87 $74 0.47 0.26 0.16 Georgia Power 7.34 26,206,170 32,594,158 25,577,006 178,557 13,117 $131 $66 0.50 0.22 0.16 Gulf Power 8.33 5,425,491 3,866,950 2,136,439 - 1,773 $18 $49 0.33 0.19 0.16 Mississippi Power 7.21 2,118,106 2,712,904 4,142,947 - 1,392 $14 $94 0.66 0.29 0.16

AEP Appalachian Power 4.83 11,878,136 7,533,505 13,036,690 - 5,034 $50 $62 0.42 0.26 0.16 Columbus Southern Power 7.16 7,270,635 8,522,682 3,822,486 - 3,043 $30 $46 0.42 0.19 0.16 Indiana Michigan Power 5.53 5,783,934 5,149,637 8,049,173 - 2,945 $29 $58 0.51 0.27 0.16 Kentucky Power 5.50 2,409,237 1,402,043 3,311,179 - 1,105 $11 $76 0.46 0.29 0.16 Kingsport Power 4.68 692,635 412,204 893,559 - 310 $3 $77 0.45 0.28 0.16

Ohio Power 5.72 7,207,804 5,733,217 12,321,063 - 3,919 $39 $64 0.54 0.30 0.16

Public Service Co of Oklahoma 7.27 6,021,196 6,167,146 5,657,129 - 2,768 $28 $62 0.46 0.23 0.16 Southwestern Electric Power 5.95 5,538,708 5,810,597 5,643,342 - 2,636 $26 $69 0.48 0.23 0.16 Wheeling Power 4.11 419,410 420,929 1,230,792 - 321 $3 $90 0.77 0.38 0.16

Duke Energy Duke Energy Carolinas 6.24 25,729,097 26,364,756 24,510,480 31 11,884 $119 $61 0.46 0.23 0.16 Duke Energy Indiana 6.43 8,707,170 8,185,201 11,699,459 - 4,436 $44 $67 0.51 0.26 0.16 Duke Energy Ohio 7.93 7,207,067 7,895,934 5,886,523 - 3,256 $33 $54 0.45 0.22 0.16 Union Light Heat & Power 5.94 1,402,220 1,699,854 781,976 - 603 $6 $51 0.43 0.19 0.16

Exelon Commonwealth Edison 6.17 28,330,120 33,859,276 27,875,388 497,764 14,049 $140 $42 0.50 0.23 0.16 PECO Energy 10.87 12,858,078 8,676,681 15,822,011 726,122 5,908 $59 $42 0.46 0.27 0.16

FirstEnergy Cleveland Electric Illum 8.49 5,441,521 4,953,714 8,860,841 37,245 2,993 $30 $44 0.55 0.29 0.16 Jersey Central Power & Light 10.63 9,547,719 9,536,671 2,743,983 87,127 3,400 $34 $35 0.36 0.18 0.16 Metropolitan Edison 8.15 5,286,865 4,542,584 3,995,898 - 2,145 $21 $45 0.41 0.22 0.16 Ohio Edison 7.74 8,889,981 7,220,341 9,321,000 - 3,945 $39 $43 0.44 0.24 0.16 Pennsylvania Electric 7.40 4,380,818 5,001,682 4,677,948 - 2,181 $22 $43 0.50 0.23 0.16 Toledo Edison 7.00 2,430,306 2,879,346 5,138,985 - 1,621 $16 $59 0.67 0.31 0.16

FPL Florida Power & Light 11.22 54,567,510 44,955,896 4,035,750 93,758 16,080 $161 $41 0.29 0.16 0.16 Entergy Entergy Arkansas 7.40 7,655,291 6,089,372 7,587,188 - 3,309 $33 $58 0.43 0.24 0.16

Entergy Gulf States 9.28 10,110,253 9,291,800 15,065,200 - 5,347 $53 $83 0.53 0.28 0.16 Entergy Louisiana 7.91 8,512,776 6,115,379 12,758,647 - 4,249 $42 $76 0.50 0.29 0.16 Entergy Mississippi 9.89 5,386,994 5,162,628 2,927,485 - 2,091 $21 $58 0.39 0.20 0.16 Entergy New Orleans 9.93 913,892 2,295,675 547,171 2,575 583 $6 $52 0.64 0.18 0.16

Edison International Southern California Edison 13.51 30,189,172 46,910,221 11,566,242 63,085 13,765 $138 $33 0.46 0.18 0.16 Xcel Energy Northern States Power 7.24 12,147,165 18,573,762 11,354,144 21,085 6,530 $65 $46 0.54 0.21 0.16

Public Service Co of Colorado 7.53 8,557,673 12,955,311 5,660,827 24,707 4,219 $42 $38 0.49 0.20 0.16 Southwestern Public Service 6.68 3,448,385 5,315,696 8,525,900 - 2,682 $27 $86 0.78 0.31 0.16

PG&E Pacifi c Gas & Electric 12.81 31,013,223 38,242,131 15,165,407 364,437 13,153 $132 $29 0.42 0.19 0.16 Progress Energy Progress Energy Carolinas 7.55 16,177,573 14,749,891 12,364,156 - 6,716 $67 $57 0.42 0.22 0.16

Progress Energy Florida 10.55 20,020,717 15,251,098 4,160,022 - 6,117 $61 $43 0.31 0.17 0.16 Dominion Virginia Electric & Power 6.80 28,543,213 37,272,233 10,188,438 163,283 11,816 $118 $57 0.41 0.18 0.16 Ameren Central Illinois Light 5.54 2,033,744 1,937,152 2,438,883 - 994 $10 $54 0.49 0.25 0.16

Central Illinois Pub Serv 5.73 3,783,958 4,210,304 4,237,135 21,133 1,901 $19 $57 0.50 0.24 0.16 Illinois Power 5.97 5,658,054 6,060,616 6,914,294 88 2,891 $29 $53 0.51 0.25 0.16 Union Electric 5.73 13,081,168 14,056,465 9,707,618 18,935 5,719 $57 $56 0.44 0.21 0.16

MidAmerican MidAmerican Energy 6.06 5,750,164 5,526,078 8,554,831 - 3,076 $31 $50 0.54 0.27 0.16 Pacifi Corp 5.48 15,334,603 16,057,873 20,471,543 41,982 8,052 $81 $57 0.53 0.26 0.16

Consolidated Edison Consolidated Edison Co-NY 11.57 13,634,657 38,665,285 725,411 2,526,404 8,618 $86 $32 0.63 0.16 0.16 Orange & Rockland Utils 9.71 1,572,485 1,922,047 544,836 - 627 $6 $33 0.40 0.18 0.16 Rockland Electric 10.77 755,276 844,267 65,059 - 258 $3 $41 0.34 0.16 0.16

National Grid Granite State Electric 9.88 298,121 472,898 120,330 - 138 $1 $40 0.46 0.18 0.16 Massachusetts Electric 10.77 8,387,253 9,349,544 4,007,788 - 3,373 $34 $31 0.40 0.19 0.16 Narragansett Electric 12.85 2,975,061 3,588,277 1,173,146 - 1,200 $12 $28 0.40 0.18 0.16 Niagara Mohawk Power 10.56 11,146,287 13,039,831 5,311,565 543 4,576 $46 $32 0.41 0.19 0.16

ALLOWANCE DISTRIBUTION SCENARIOS 59Electricity Sales (MWh) Allocations Value Per Customer

Parent Company Utility Subsidiary

2006 Average

electricity rate

(¢/kWh)* Residential Commercial Industrial Other

Distribution Company

Allocations (based on total

MWh sales) (‘000 tons)

Total Value of Distribution

Company Allocations

(in millions)

Annual Allowance Value per

Residential Customer

($/year)

Allowance value per kWh (Residential Sales)

(¢/kWh)

Allowance value per kWh

(Residential + Commercial Sales)

(¢/kWh)


(All Customer Sales) (¢/kWh)**

TABLE 4

Scenario 1 Allocation to Local Electric Utilities for Consumer Benefi t Allowance Allocations and Allowance Value (Assuming an Allowance Pool of 573 Million Short Tons and a Price of $10 per Ton of CO2) for U.S. Electric Distribution Companies, Sorted by Total Electricity Sales by Utility Subsidiaries


DTE Energy Detroit Edison 7.93 15,769,599 20,497,463 14,287,400 - 7,843 $78 $40 0.50 0.22 0.16 PHI Atlantic City Electric 11.17 4,275,137 4,435,352 1,220,043 - 1,541 $15 $33 0.36 0.18 0.16

Delmarva Power & Light 8.04 5,169,900 5,409,631 2,899,155 - 2,091 $21 $46 0.40 0.20 0.16 Potomac Electric Power 7.86 7,653,928 17,645,868 669,368 518,661 4,109 $41 $61 0.54 0.16 0.16

PSEG Public Service Elec & Gas 10.02 13,393,080 24,189,317 5,891,125 204,201 6,776 $68 $37 0.51 0.18 0.16 Allegheny Energy Monongahela Power 5.56 3,280,823 2,551,221 4,514,878 4,350 1,606 $16 $50 0.49 0.28 0.16

The Potomac Edison 6.03 5,968,871 3,403,188 3,530,087 - 2,002 $20 $49 0.34 0.21 0.16 West Penn Power 5.91 6,903,375 4,908,511 8,102,172 10,985 3,091 $31 $50 0.45 0.26 0.16

PPL Pennsylvania Power 6.99 1,609,621 1,362,087 1,696,628 - 724 $7 $52 0.45 0.24 0.16 PPL Electric Utilities 8.38 13,646,639 13,272,006 9,626,583 62,010 5,679 $57 $47 0.42 0.21 0.16

CMS Energy Consumers Energy 7.99 12,975,047 12,834,555 12,189,433 - 5,895 $59 $38 0.45 0.23 0.16 Northeast Utilities Connecticut Light & Power 14.97 10,052,936 10,101,903 3,306,059 176,968 3,667 $37 $34 0.36 0.18 0.16

Public Service Co of NH 13.43 3,087,614 3,365,093 1,581,502 - 1,246 $12 $30 0.40 0.19 0.16 Western Massachusetts Elec 10.39 1,511,025 1,598,836 862,154 - 616 $6 $33 0.41 0.20 0.16

Constellation Baltimore Gas & Electric 6.38 12,885,949 15,687,710 3,216,299 267,675 4,973 $50 $46 0.39 0.17 0.16 Energy East Central Maine Power 4.62 3,414,740 3,235,594 2,262,261 - 1,383 $14 $26 0.40 0.21 0.16

New York State Elec & Gas 9.25 6,148,788 5,499,852 3,422,102 28,114 2,342 $23 $31 0.38 0.20 0.16 Rochester Gas and Electric 6.75 2,577,176 3,057,984 1,548,578 - 1,114 $11 $35 0.43 0.20 0.16

Sierra Pacifi c Nevada Power Company 9.73 9,033,142 4,618,229 7,635,036 8,186 3,303 $33 $47 0.37 0.24 0.16 Sierra Pacifi c Power 10.14 2,480,681 3,148,215 4,159,931 - 1,519 $15 $49 0.61 0.27 0.16

E.ON Kentucky Utilities 5.44 6,312,755 6,065,170 6,318,648 - 2,900 $29 $67 0.46 0.23 0.16 Louisville Gas & Electric 5.87 4,017,524 4,879,464 3,067,655 - 1,856 $19 $53 0.46 0.21 0.16

Wisconsin Energy Edison Sault Electric 6.39 168,700 296,625 200,931 - 103 $1 $54 0.61 0.22 0.16 Wisconsin Electric Power 8.24 8,153,958 8,899,022 11,135,922 - 4,373 $44 $44 0.54 0.26 0.16

Pinnacle West Arizona Public Service 8.97 12,901,612 12,251,092 2,817,693 - 4,339 $43 $46 0.34 0.17 0.16 Alliant Energy Interstate Power and Light 7.88 4,157,306 3,909,651 7,959,174 - 2,486 $25 $55 0.60 0.31 0.16

South Beloit Wtr Gas & Elec 5.98 82,731 50,550 89,118 - 35 $0 $40 0.42 0.26 0.16 Wisconsin Power & Light 8.65 3,430,535 2,290,527 4,858,709 - 1,641 $16 $42 0.48 0.29 0.16

Salt River Project Salt River Project 7.66 12,650,175 10,753,881 2,845,580 - 4,072 $41 $49 0.32 0.17 0.16 OGE Oklahoma Gas & Electric 6.60 8,717,216 9,062,011 7,102,003 - 3,860 $39 $60 0.44 0.22 0.16 City of Los Angeles City of Los Angeles 9.66 7,609,278 14,158,093 2,395,060 151,303 3,772 $38 $30 0.50 0.17 0.16 Puget Energy Puget Sound Energy 7.08 10,654,059 9,123,742 3,405,713 - 3,597 $36 $40 0.34 0.18 0.16 SCANA South Carolina Electric & Gas 7.77 7,598,169 7,799,530 6,182,736 - 3,348 $33 $64 0.44 0.22 0.16 Sempra San Diego Gas & Electric 13.20 7,524,580 8,135,366 4,478,466 98,080 3,139 $31 $26 0.42 0.20 0.16 Long Island Power Authority Long Island Power Authority 18.57 9,278,211 10,066,672 - 251,179 3,040 $30 $31 0.33 0.16 0.16 Westar Kansas Gas & Electric 6.02 3,081,078 2,991,285 3,864,155 - 1,541 $15 $57 0.50 0.25 0.16

Westar Energy 6.27 3,374,963 4,286,572 1,959,493 - 1,493 $15 $48 0.44 0.19 0.16 Portland General Electric Portland General Electric 7.14 7,572,788 7,653,946 4,199,062 5,306 3,014 $30 $44 0.40 0.20 0.16 City of San Antonio City of San Antonio 7.04 8,554,569 9,077,475 1,510,226 - 2,970 $30 $51 0.35 0.17 0.16 TECO Tampa Electric 10.03 8,720,867 8,024,186 2,279,363 648 2,951 $30 $51 0.34 0.18 0.16 NiSource Northern Indiana Pub Serv 7.47 3,293,908 3,951,610 9,503,155 18,146 2,601 $26 $66 0.79 0.36 0.16 Great Plains Energy Kansas City Power & Light 6.22 5,412,876 7,488,544 2,148,004 - 2,335 $23 $53 0.43 0.18 0.16 City of Memphis City of Memphis 7.27 5,675,662 5,045,371 4,140,188 1,431 2,306 $23 $63 0.41 0.22 0.16 DPL Dayton Power & Light Co 6.68 5,217,604 5,256,622 4,286,655 6,380 2,291 $23 $50 0.44 0.22 0.16 AES Indianapolis Power & Light 6.45 5,027,223 1,994,693 7,693,925 - 2,283 $23 $55 0.45 0.33 0.16 IDACORP Idaho Power 4.57 5,067,767 3,760,988 5,110,559 - 2,162 $22 $56 0.43 0.24 0.16 Duquesne Light Company Duquesne Light 5.01 3,990,797 6,524,015 3,182,369 17,164 2,128 $21 $41 0.53 0.20 0.16 JEA JEA 7.80 5,596,010 4,171,144 3,028,495 4,310 1,986 $20 $55 0.35 0.20 0.16 Integrys Upper Peninsula Power 10.88 273,729 255,385 270,537 - 124 $1 $27 0.45 0.23 0.16

Wisconsin Public Service 7.35 2,871,109 3,928,598 4,228,451 - 1,711 $17 $46 0.60 0.25 0.16 Santee Cooper South Carolina Pub Serv Auth 5.54 1,616,868 1,951,064 8,048,694 - 1,802 $18 $142 1.11 0.51 0.16 Aquila Aquila 7.11 4,475,472 4,336,253 2,686,154 - 1,784 $18 $45 0.40 0.20 0.16

60 BENCHMARKING AIR EMISSIONS Electricity Sales (MWh) Allocations Value Per Customer


2006 Average

electricity rate






Company Allocations

(in millions)



($/year)


(¢/kWh)



(¢/kWh)




TABLE 4, CONTINUED

Austin Energy Austin Energy 8.30 4,009,766 5,403,976 1,781,567 - 1,737 $17 $51 0.43 0.18 0.16 UniSource Tucson Electric Power 8.42 3,778,369 1,959,141 3,463,909 - 1,427 $14 $40 0.38 0.25 0.16

UNS Electric 9.79 803,980 616,268 191,172 - 250 $2 $32 0.31 0.18 0.16 Sacramento Municipal Util Dist Sacramento Municipal Util Dist 10.04 4,764,852 668,973 5,332,157 33,248 1,675 $17 $32 0.35 0.31 0.16 Hawaiian Electric Industries Hawaii Electric Light 29.49 442,294 458,252 248,214 - 178 $2 $29 0.40 0.20 0.16

Hawaiian Electric 17.68 2,134,432 2,491,323 3,074,850 - 1,195 $12 $46 0.56 0.26 0.16 Maui Electric 27.16 445,434 415,304 405,729 - 196 $2 $36 0.44 0.23 0.16

NorthWestern Energy NorthWestern Energy 7.80 473,718 590,331 205,294 - 197 $2 $42 0.42 0.19 0.16 NorthWestern Energy LLC 5.91 2,184,189 3,198,583 3,090,095 - 1,314 $13 $51 0.60 0.24 0.16

ALLETE Minnesota Power 4.77 1,011,699 1,283,320 6,782,975 - 1,408 $14 $120 1.39 0.61 0.16 Superior Water, Light and Power 4.79 88,681 132,870 422,625 - 100 $1 $80 1.13 0.45 0.16

Omaha Public Power District Omaha Public Power District 5.81 3,375,561 3,580,906 2,669,393 - 1,493 $15 $52 0.44 0.21 0.16 Seattle City Light City of Seattle 6.17 3,060,651 5,052,063 1,341,505 286 1,467 $15 $43 0.48 0.18 0.16 CLECO Cleco Power 9.76 3,551,702 2,520,911 2,963,261 - 1,402 $14 $62 0.39 0.23 0.16 Avista Avista Corp 6.32 3,577,694 3,147,420 2,061,888 - 1,363 $14 $45 0.38 0.20 0.16 Public Service Co of NM Public Service Co of NM 6.98 2,754,614 3,875,630 1,327,287 - 1,234 $12 $32 0.45 0.19 0.16 El Paso Electric El Paso Electric 10.23 2,113,734 3,502,728 1,204,706 - 1,058 $11 $34 0.50 0.19 0.16 CH Energy Group Central Hudson Gas & Elec 8.37 2,030,379 1,989,496 1,479,537 - 853 $9 $34 0.42 0.21 0.16 Orlando Utilities Comm Orlando Utilities Comm 7.97 1,874,350 3,590,340 - - 848 $8 $57 0.45 0.16 0.16 Vectren Southern Indiana Gas & Elec 6.76 1,475,167 1,528,652 2,376,374 - 835 $8 $66 0.57 0.28 0.16 City of Tacoma City of Tacoma 5.55 1,822,438 323,917 2,584,708 844 734 $7 $51 0.40 0.34 0.16 Empire District Electric Empire District Electric 7.40 1,898,846 1,659,804 1,145,490 - 730 $7 $53 0.38 0.21 0.16 City of Colorado Springs City of Colorado Springs 6.91 1,363,884 1,938,210 1,149,098 - 691 $7 $38 0.51 0.21 0.16 Otter Tail Corporation Otter Tail Power 6.54 1,170,841 2,247,633 572,380 - 619 $6 $62 0.53 0.18 0.16 Imperial Irrigation District Imperial Irrigation District 12.32 1,613,210 1,629,124 89,428 - 517 $5 $44 0.32 0.16 0.16 MGE Energy Madison Gas & Electric 9.80 809,561 2,164,922 284,019 - 505 $5 $43 0.62 0.17 0.16 Central Nebraska Pub P&I Dist Nebraska Public Power District 6.03 793,454 1,044,304 1,294,998 - 486 $5 $70 0.61 0.26 0.16 Lincoln Electric System Lincoln Electric System 6.12 1,088,033 1,428,071 540,433 - 474 $5 $44 0.44 0.19 0.16 City of Springfi eld City of Springfi eld 5.86 992,238 1,524,353 527,631 - 472 $5 $52 0.48 0.19 0.16 City of Lakeland City of Lakeland 10.98 1,437,893 827,665 617,655 - 447 $4 $45 0.31 0.20 0.16 City of Santa Clara City of Santa Clara 8.14 239,026 87,966 2,391,721 - 422 $4 $99 1.76 1.29 0.16 City of Tallahassee City of Tallahassee 11.78 1,097,486 1,616,415 - - 421 $4 $46 0.38 0.16 0.16 City of Eugene City of Eugene 6.44 943,140 974,369 772,414 - 417 $4 $55 0.44 0.22 0.16 City of Anaheim City of Anaheim 9.26 625,186 682,182 1,290,754 - 403 $4 $43 0.64 0.31 0.16 Modesto Irrigation District Modesto Irrigation District 9.79 904,040 858,458 797,267 - 397 $4 $43 0.44 0.23 0.16 Black Hills Black Hills Power 6.94 499,152 700,180 433,020 - 253 $3 $49 0.51 0.21 0.16

Cheyenne Light Fuel & Power 8.83 256,954 539,755 129,462 - 144 $1 $41 0.56 0.18 0.16 MDU Resources Group MDU Resources Group 6.58 885,771 1,170,247 427,230 - 385 $4 $39 0.43 0.19 0.16 City of Kansas City City of Kansas City 7.51 562,350 992,215 908,329 - 382 $4 $67 0.68 0.25 0.16 City of Lansing City of Lansing 6.80 617,508 1,231,182 437,199 - 355 $4 $43 0.57 0.19 0.16 Central Vermont Pub Serv Corp Central Vermont Pub Serv Corp 11.59 959,454 894,662 430,348 - 354 $4 $26 0.37 0.19 0.16 City of Riverside City of Riverside 10.64 747,179 475,568 919,252 - 332 $3 $35 0.44 0.27 0.16 City of Garland City of Garland 11.59 947,235 798,700 342,086 - 324 $3 $52 0.34 0.19 0.16 PNM Resources Texas-New Mexico Power 8.42 256,417 262,502 598,669 - 173 $2 $40 0.68 0.33 0.16 UGI Utilities UGI Utilities 9.10 523,728 349,293 122,985 - 155 $2 $28 0.30 0.18 0.16

ALLOWANCE DISTRIBUTION SCENARIOS 61Electricity Sales (MWh) Allocations Value Per Customer


2006 Average

electricity rate






Company Allocations

(in millions)



($/year)


(¢/kWh)



(¢/kWh)



Table results subject to change due to evolving state and local regulatory requirements and proceedings which could aff ect rates.

* Average electricity rate: Average across all customer classes. Calculated based on data from U.S. EIA Forms 861-1 and 861-2.** Allowances are allocated based on total electricity sales; therefore, the value per kilowatt hour remains constant across all utilities when divided by total electricity sales.


TABLE 4, CONTINUED

USE OF THE BENCHMARKING DATA 63

Th is report provides public information that can be used to evaluate electric power producers’ emissions performance and risk exposure. Transparent information on emissions performance is useful to a wide range of decision-makers, including electric companies, fi nancial analysts, investors, policymakers, and consumers.

Electric CompaniesTh is provision of transparent information supports corporate self-evaluation and business planning by providing a useful “reality check” that companies can use to assess their performance relative to key competitors, prior years and industry benchmarks. By understanding and tracking their performance, companies can evaluate how diff erent business decisions may aff ect emissions performance over time, and how they may more appropriately consider environmental issues in their corporate policies and business planning.

Th is report is also useful for highlighting the opportunities and risks companies may face from environmental concerns and potential changes in environmental regulations. Business opportunities may include increasing competitive advantage of existing assets, the chance to generate or enhance revenues from emission trading mechanisms, and opportunities to increase market share by pursuing diversifi cation into clean energy. Corporate risks that could have severe fi nancial implications include a loss of competitive advantage or decrease in asset value due to policy changes, risks to corporate reputation, and the risk of exposure to litigation arising from potential violations of future environmental laws and regulations. Becoming aware of a company’s exposure to these opportunities and risks is the fi rst step in developing eff ective corporate environmental strategies.

Investors Th e fi nancial community and investors in the electric industry need accurate information concerning environmental performance in order to evaluate the fi nancial risks associated with their investments and

Use of the Benchmarking Data


to assess their overall value. Air emissions information is material to investors and can be an important indicator of a company’s management.

Evaluation of fi nancial risks associated with SO2, NOx and mercury has become a relatively routine corporate practice. Several recent studies point to the growing fi nancial risks of climate change issues for all fi rms, especially those within the electric industry. Changing environmental requirements can have important implications for long-term share value, depending on how the changes aff ect a company’s assets relative to its competitors. Especially in the context of climate change, which poses considerable uncertainty and diff erent economic impacts for diff erent types of power plants, a company’s current environmental performance can shed light on its prospects for sustained value.

As the risks associated with climate change have become clearer and the prospect of regulation more imminent, the fi nancial implications of climate change for the electric industry have drawn the attention of Wall Street. Mainstream fi nancial fi rms such as Citigroup and Sanford C. Bernstein have issued reports evaluating the company-specifi c fi nancial impacts of diff erent regulatory scenarios on electric power companies and their shareholders. Ratings agencies such as Standard and Poor’s and Fitch Ratings have issued reports analyzing the credit impacts of climate change for the electric industry. In January 2008, Standard and Poor’s released a report stating that the three key factors impacting electric company credit ratings all pertain to carbon emissions. Th ese are: (1) integrated resource plans that reduce or eliminate the building of new coal-fi red power plants; (2) the need for carbon sequestration on existing plants; and (3) research and development for cleaner coal technologies.

Shareholder concern about the fi nancial impacts of climate change has increased signifi cantly over the past decade. Much of this concern is directed toward encouraging electric companies to disclose the fi nancial risks associated with climate change, particularly the risks associated with the future regulation of CO2. Th e Carbon Disclosure Project (CDP) was launched in 2000 and annually requests climate change information from companies. CDP now represents institutional investors with combined assets of over $57 trillion under management, and, as of 2008, requests climate strategy and greenhouse gas emissions data from 3,000 of the world’s largest companies. In 2003, the Investor Network on Climate Risk (INCR) was launched to promote better understanding of the risks of climate change among institutional investors. INCR, which now numbers more than fi ve dozen institutional investors representing assets of over $5 trillion, encourages

USE OF THE BENCHMARKING DATA 65

companies in which its members invest to address any material risks and opportunities to their businesses associated with climate change and a shift to a lower carbon economy.

Shareholders have demonstrated increasing support for proxy resolutions requesting improved analysis and disclosure of the fi nancial risks companies face from CO2 emissions and their strategies for addressing these risks. In response to shareholder activity, more than a dozen of the largest U.S. electric power companies have issued reports for investors detailing their climate-related business risks and strategies. Shareholders continue to fi le resolutions with electric power companies that have not yet disclosed this information.

PolicymakersTh e information on emissions contained in this report is useful to policymakers who are working to develop long-term solutions to the public health and environmental eff ects of air pollutant emissions. Th e outcomes of federal policy debates concerning various regulatory and legislative proposals to improve power plant emissions performance will impact the electric industry, either in regard to the types of technologies or fuels that will be used at new power plant facilities or the types of environmental controls that will be installed at existing facilities.

Information about emissions performance helps policymakers by indicating which pollution control policies have been eff ective (e.g. SO2 reductions under the Clean Air Act’s Acid Rain Program), where opportunities may exist for performance and environmental improvements (e.g. SO2 and NOx emissions performance standards for large, older facilities under the Regional Haze Rule), and where policy action is required to achieve further environmental gains (e.g. the environmental and fi nancial risks associated with climate change).

Electricity ConsumersFinally, the information in this report is valuable to electricity consumers. Accurate and understandable information on emissions promotes public awareness of the diff erence in environmental performance and risk exposure. In jurisdictions that allow consumers to choose their electricity supplier, this information enables consumers to consider environmental performance in power purchasing decisions. Th is knowledge also enables consumers to hold companies accountable for decisions and activities that aff ect the environment and/or public health and welfare.


Th e information in this report can also help the public verify that companies are meeting their environmental commitments and claims. For example, some electric companies are establishing voluntary emissions reduction goals for CO2 and other pollutants, and many companies are reporting signifi cant CO2 emission reductions from voluntary actions. Public information is necessary to verify the legitimacy of these claims. Public awareness of companies’ environmental performance supports informed public policymaking by promoting the understanding of the economic and environmental tradeoff s of diff erent generating technologies and policy approaches.


Appendix AData Sources, Methodology and Quality Assurance

Th is report examines the air pollutant emissions of the 100 largest electricity generating companies in the U.S. based on 2006 electricity generation, emissions and ownership data. Th e report relies on publicly-available information reported by the U.S. Energy Information Administration (EIA), U.S. Environmental Protection Agency (EPA), Securities and Exchange Commission (SEC), state environmental agencies, and company websites.

Data SourcesTh e following public data sources were used to develop this report:

EPA ACID RAIN PROGRAM DATABASE: Th e EPA’s Acid Rain Emissions Reporting Program accounts for almost all of the SO2 and NOx emissions, and approximately 45 percent of the CO2 emissions analyzed in this report. Th ese emissions were compiled using EPA’s on-line emissions database available at http://camddataandmaps.epa.gov/gdm/.

EPA TOXIC RELEASE INVENTORY (TRI): Power plants and other facilities are required to submit reports on the use and release of certain toxic chemicals to the TRI. Th e 2006 mercury emissions used in this report are based on preliminary 2006 reports submitted by facility managers and which are available at http://www.epa.gov/tri/tridata/tri06/index.htm.

EIA FORMS 906 & 920 POWER PLANT DATABASES (2006): EIA Forms 906 and 920 provided almost all of the generation data analyzed in this report. EIA Forms 906 and 920 provides data on the electric generation and heat input by fuel type for utility and non-utility power plants. Th e heat input data was used

APPENDIX A 69

to calculate approximately 55 percent of the CO2 emissions analyzed in this report. Th e form is available at http://www.eia.doe.gov/cneaf/electricity/page/eia906_920.html.

EIA FORM 860 ANNUAL ELECTRIC GENERATOR REPORT (2006): EIA Form 860 is a generating unit level data source that includes information about generators at electric power plants, including information about generator ownership. EIA Form 860 was used to identify power plant ownership in this report. Th e form is available at http://www.eia.doe.gov/cneaf/electricity/page/eia860.html.

EIA FORM 861 ANNUAL ELECTRIC POWER INDUSTRY DATABASE (2006): EIA Form 861 provided all of the electricity sales and delivery data analyzed in this report. Th e form contains aggregate information about electricity sales, revenue, and customer counts of all electric utilities in the U.S.. It is available at http://www.eia.doe.gov/cneaf/electricity/page/eia861.html.

EPA U.S. INVENTORY OF GREENHOUSE GAS EMISSIONS AND SINKS (2006): EPA’s U.S. Inventory of Greenhouse Gas Emissons and Sinks report provides in Annex 2 heat contents and carbon content coeffi cients of various fuel types. Th is data was used in conjunction with EIA Forms 906 and 920 to calculate approximately 55 percent of the CO2 emissions analyzed in this report. Annex 2 is available at http://epa.gov/climatechange/emissions/downloads/08_Annex_2.pdf.

Plant OwnershipTh is report aims to refl ect power plant ownership as of December 31, 2006. Plant ownership data used in this report are primarily based on the EIA-860 database from the year 2006. EIA-860 includes ownership information on generators at electric power plants owned or operated by electric utilities and non-utilities, which include independent power producers, combined heat and power producers, and other industrial organizations. It is published annually by EIA.

For the largest 100 power producers, plant ownership is further checked against self-reported data from the producer’s 10-K form fi led with the SEC. If a discrepancy is found, ownership of the plant is updated using data from its 10-K fi led with the SEC for the year 2006. Consequently, in a number of instances, ultimate assignment of plant ownership in this report diff ers from EIA-860’s reported ownership. Th is primarily happens when the plant in question falls in one or more of the categories listed below:


It is owned by a limited liability partnership shareholders of which are among the 100 largest power producers.

Th e owner of the plant as listed in EIA-860 is a subsidiary of a company that is among the 100 largest power producers.

It was sold or bought during the year 2006. Because form 10-K for a particular year is usually fi led by the producer in the fi rst quarter of the following year, this report assumes that ownership as reported in form 10-K is more accurate.

In all cases listed above, information reported in the 10-K form takes precedence over the EIA-860 database. If the partnership or the subsidiary has multiple shareholders, percentage ownership is adjusted accordingly.

Identifying “who owns what” in the dynamic electricity generation industry is probably the single most diffi cult and complex part of this report. In addition to the categories listed above, shares of power plants are regularly traded and producers merge, reorganize, or cease operations altogether. While considerable eff ort was expended in ensuring the accuracy of ownership information refl ected in this report, there may be inadvertent errors in the assignment of ownership for some plants where public information was either not current or could not be verifi ed.

Generation Data and Cogeneration FacilitiesPlant generation data used in this report come from EIA Forms 906 and 920.

Cogeneration facilities produce both electricity and steam or some other form of useful energy. Because electricity is only a partial output of these plants, their reported emissions data generally overstate the emissions associated with electricity generation. Generation and emissions data included in this report for cogeneration facilities have been adjusted to refl ect only their electricity generation. For all such cogeneration facilities emissions data were calculated on the basis of heat input of fuel associated with electricity generation only. Consequently, for all such facilities EIA forms 906 and 920, which report a plant’s total heat input as well as that which is associated with electricity production only, were used to calculate their emissions.

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APPENDIX A 71

NOx and SO2 EmissionsTh e EPA Acid Rain Program collects and reports SO2 and NOx emissions data for nearly all major power plants in the U.S.. Emissions information reported in the Acid Rain database is collected from continuous emission monitoring (CEM) systems. SO2 and NOx emissions data reported to the Acid Rain Program account for almost all of the SO2 and NOx emissions assigned to the 100 largest power producers in this report.

Th e Acid Rain database collects and reports SO2 and NOx emissions data by fuel type at the boiler level. Th is report consolidates that data at the generating unit and plant levels. In the case of jointly owned plants, because joint ownership is determined by producer’s share of installed capacity, assignment of SO2 and NOx emissions to the producers on this basis implicitly assumes that emission rates are uniform across the diff erent units. Th is may cause producers to be assigned emission fi gures that are slightly higher or lower than their actual shares.

CO2 EmissionsCO2 emissions reported through the EPA Acid Rain Program account for approximately 45 percent of the CO2 emissions used in this report. Th e remaining 55 percent was calculated using heat input data from EIA forms 906 and 920 and carbon content coeffi cients of various fuel types provided by the EPA. Th e adjacent table shows the carbon coeffi cients used in this procedure. Non-emitting fuel types, whose carbon coeffi cients are zero, are not shown in the table.

EIA forms 906 and 920 reports heat input data by fuel type at the prime mover level. Th is report consolidates that data at the generating unit and plant levels. In the case of jointly owned plants, because joint ownership is determined by producer’s share of installed capacity, assignment of CO2 emissions to the producers on this basis implicitly assumes that emission rates are uniform across the diff erent units. Th is may cause producers to be assigned emission fi gures that are slightly higher or lower than their actual shares.

FUEL TYPE

CARBON CONTENT COEFFICIENTS

(Tg Carbon/Qbtu)

COALAnthracite Coal and Bituminous Coal 25.49

Lignite Coal 26.30

Sub-bituminous Coal 26.48

Waste/Other Coal (includes anthracite culm, bituminous gob, fi ne coal, lignite waste, waste coal)

25.49

Coal-based Synfuel (including briquettes, pellets, or extrusions, which are formed by binding materials or processes that recycle materials)

25.34

OILDistillate Fuel Oil (Diesel, No. 1, No. 2, and No. 4 Fuel Oils)

19.95

Jet Fuel 19.33

Kerosene 19.72

Residual Fuel Oil (No. 5, No. 6 Fuel Oils, and Bunker C Fuel Oil)

21.49

Waste/Other Oil (including Crude Oil, Liquid Butane, Liquid Propane, Oil Waste, Re-Refi ned Motor Oil, Sludge Oil, Tar Oil, or other petroleum-based liquid wastes)

19.95

Petroleum Coke 27.85

GASNatural Gas 14.47

Blast Furnace Gas 16.99

Other Gas 16.99

Gaseous Propane 14.47


Mercury EmissionsMercury emissions data for coal power plants presented in this report were obtained from EPA’s Toxic Release Inventory (TRI). Mercury emissions reported to the TRI are based on emission factors, mass balance calculations or data monitoring. Th e TRI contains facility-level information on the use and environmental release of chemicals classifi ed as toxic under the Clean Air Act. Because coal plants are the primary source of mercury emissions within the electric industry, the mercury emissions and emission rates presented in this report refl ect the emissions associated with each producer’s fl eet of coal plants only. At the time this report was produced, only preliminary 2006 TRI data were available. Th erefore, caution is urged when comparing producers’ emissions and emission rates for mercury.

APPENDIX B 73

Fossil fuel power plants, particularly coal-fi red power plants, are a signifi cant source of SO2, NOx and mercury emissions. Th ese power plant emissions are controlled through several statutory and regulatory programs. Th e discussion below provides a snapshot of the programs that are currently in force under the Clean Air Act.

Clean Air Act Title IVTitle IV of the 1990 Clean Air Act Amendments created the Acid Rain Program to address concerns over power plant SO2 and NOx emissions. Th e Acid Rain Program required two phases of SO2 emission reductions from fossil fuel-fi red power plants. Phase I of the program began in 1995 and aff ected 445 of the largest high-emitting utility units, primarily in the eastern U.S.. Phase II began in 2000 and covers over 2,000 coal, oil and gas boilers nationwide. Th e program sets a permanent cap on SO2 emissions of 8.95 million tons nationwide—half the amount emitted in 1980. An important feature of the Acid Rain Program is its allowance allocation and tracking system, which enables facilities to trade and bank emissions allowances as part of their compliance strategy. Th is market-based system is credited with signifi cantly lowering the cost of achieving the required SO2 emission reductions.

Th e Acid Rain Program also implemented two phases of NOx reductions at coal-fi red electric utility boilers. Phase I began in 1996 and Phase II began in 2000. Rather than capping NOx emissions, the Acid Rain Program restricts how much NOx a unit can emit for each unit of fuel consumed. By 2000 the mandated emission rates resulted in annual NOx emissions that were two million tons below the levels they would have been without the program.

Appendix B:SO2, NOx and Mercury Emission Reduction Programs


NOx SIP CallOzone formation and transport problems in the eastern U.S. extend far beyond the OTC. In 1998 the EPA fi nalized a rule requiring 22 states and the District of Columbia to submit state implementation plans (SIPs) that signifi cantly reduce NOx emissions from power plants and other sources during the ozone season (May through September). Th is rule, known as the NOx SIP Call, required that states have power plant NOx emission reduction measures implemented by May 1, 2003. Th e NOx SIP Call built upon extensive modeling and air quality analysis of the formation and transport of ozone and ozone precursors in the eastern U.S. that was conducted over several years by the Ozone Transport Assessment Group (OTAG), which was a partnership between the EPA, the Environmental Council of the States, and various industry and environmental groups.

Clean Air Interstate RuleBuilding on progress made under the NOx SIP Call to reduce ozone formation and the transport of fi ne particulates in the eastern U.S., the EPA issued the Clean Air Interstate Rule (CAIR) in 2005. CAIR requires that the District of Columbia and 28 eastern states that contribute to ozone and/or fi ne particulate nonattainment problems in downwind states achieve further reductions in SO2 and NOx emissions from power plants and/or other sources. CAIR establishes emission budgets for aff ected states, and uses Title IV of the Clean Air Act as a framework for a federally administered emissions trading program among power plants that states can choose to participate in to achieve the required emission reductions.

Under CAIR, power plant SO2 emissions in the aff ected region are capped at 3.6 million tons in 2010 and 2.5 million tons in 2015. Power plant NOx emissions in the aff ected region are capped at 1.5 million tons in 2009 and at 1.3 million tons in 2015.

Regional Haze Rule SO2 and NOx emissions from industrial sources impair visibility in national parks and wilderness areas. In 1999 the EPA issued a regional haze rule to improve visibility in these federally protected areas. Th e regional haze rule requires aff ected states, most of which are located in the western U.S., to submit plans to reduce

APPENDIX B 75

SO2 and NOx emissions from power plants and other industrial sources and improve visibility in National Parks and federally designated Class I Wilderness Areas.

Clean Air Mercury RuleIn March 2005, EPA issued the Clean Air Mercury Rule (CAMR), which would have limited mercury emissions from coal-fi red power plants.

On February 8, 2008, however, in New Jersey v. EPA the U.S. Court of Appeals for the D.C. Circuit held that EPA violated the Clean Air Act when it sought to exempt mercury-emitting power plants from maximum achievable control technology (MACT) standards in favor of a cap-and-trade program.23 Specifi cally, the court concluded that “EPA’s removal of these EGUs from the section 112 list violates the CAA because section 112(c)(9) requires EPA to make specifi c fi ndings before removing a source listed under section 112”, and EPA never made such a fi nding. Accordingly, because coal-fi red EGUs remain as listed sources under section 112, the court holds that regulation of existing coal-fi red EGUs’ mercury emissions under section 111 is prohibited.

Th e court noted that its decision “eff ectively invalidate[s] CAMR’s regulatory approach.”

According to John Walke, Clean Air Director and Senior Attorney at the National Resources Defense Council, as a direct consequence of the ruling all new coal-fi red power plants and those currently under construction will have to be reviewed on a case-by-case basis by the permitting authorities to evaluate whether their permits and pollution controls would still comply with federal law.24


A wide range of eff orts are underway to address global warming at the federal, regional, and state levels in the U.S..

Federal InitiativesCongress has been devoting a signifi cant level of attention to the issue of climate change by convening hearings and draft ing new legislation. Members of the current Congress (110th) have introduced numerous bills related to climate change and global warming. By the fi rst quarter of 2008, members had introduced more than 150 bills, resolutions, and amendments targeted specifi cally at climate change and greenhouse gas emissions.25 In addition, on December 5, 2007, America’s Climate Security Act of 2008 (S.2191), also known as the Lieberman-Warner bill, became the fi rst greenhouse gas cap-and-trade bill to be successfully voted out of a Congressional committee. It is now expected to be taken up on the Senate fl oor sometime in 2008.

Many of the bills introduced to date propose a cap-and-trade mechanism to regulate greenhouse gas emissions with various complementary measures. Th e table below summarizes the key features of a sampling of the economy-wide cap-and-trade bills introduced in 2007.

Appendix C:State and Regional Climate Initiatives and Federal Climate Change Legislation

Bill Title & No. Cap-and-tradeAllocation Methodology

Auction Provisions Off sets

Status as of February 2008 Emission Reduction Targets

Lieberman-Warner Climate Security Act (S.2191)

Yes Historic Emissions for Electricity Generators (output based for new electricity generators) MWhs Delivered for Local Distribution Companies

26.5% in 201269.5% in 2050

Yes Reported on December 5, 2007 by the Senate EPW Committee by a vote of 11-8

2005 levels in 2012;15 percent below 2005 levels in 2015;52 percent below 2005 levels in 2040;and 70 percent below 2005 levels in 2050.

Low Carbon Economy Act (S.1766)

Yes Historic Emissions 24% in 201253% in 2030

Yes 6 co-sponsors 2006 levels by 2020;1990 levels by 2030;60 percent below 2006 levels by 2050 (contingent on international eff ort).

The Global Warming Pollution Reduction Act (S.309)

EPA decides N/A N/A N/A 11 co-sponsors 20 percent below 1990 levels by 2050.

APPENDIX C 77

In addition to the cap-and-trade bills, Congress also passed or considered a number of other bills that address greenhouse gas emissions. Th ey include bills directed at energy effi ciency, energy security, technology investments and research, resource management, and national security. In particular, the Energy Independence and Security Act of 2007, signed into law in December 2007, raises corporate average fuel economy (CAFE) standards for passenger cars to 35 miles per gallon by 2020, includes provisions to improve energy effi ciency in lighting and appliances, and seeks to promote green building technology. Also, the omnibus spending bill for FY 2008 (H.R. 2764), passed at the end of 2007, included a provision directing the U.S. Environmental Protection Agency to establish a greenhouse gas reporting system to track emissions from all sectors of the economy.

State and Regional InitiativesAs of February 2008, all but seven states had completed greenhouse gas inventories, 36 states were in the process of implementing state climate action plans, and 17 states had established emission reduction targets.26 In addition, states have come together to establish regional initiatives that now cover 31 states in the U.S. and two provinces in Canada. Th ese include the Western Climate Initiative, Midwestern Regional Greenhouse Gas Reduction Accord, and Regional Greenhouse Gas Initiative.27

Th e regional initiatives and states with emission reduction programs and their stated targets are summarized below.

Regional Initiatives:

Name of Initiative Synopsis Date signed

Regional Greenhouse Gas Initiative (RGGI)

RGGI is a cooperative eff ort by 10 Northeast and Mid-Atlantic states to design a regional cap-and-trade program initially covering carbon dioxide emissions from power plants in the region. RGGI sets a cap on emissions of carbon dioxide from power plants, and allows sources to trade emissions allowances. The program will begin by capping emissions at current levels in 2009, and then reducing emissions 10% by 2019.

20-Dec-05

Western Climate Initiative (WCI)

WCI is an initiative of seven western states—Arizona, California, Montana, New Mexico, Oregon, Utah and Washington—to reduce GHG emissions in their states. The goals of WCI are to reduce economy-wide GHG emissions to 15 percent below 2005 levels by 2020, or approximately 33 percent below business-as-usual levels; to develop, within eighteen months of the signing date of WCI, a design for a regional market-based multi-sector mechanism, such as a load-based cap and trade program, to achieve the regional GHG reduction goal; and to participate in a multi-state GHG registry to enable tracking, management, and crediting for entities that reduce GHG emissions, consistent with member state GHG reporting mechanisms and requirements.

26-Feb-07

Midwestern Regional Greenhouse Gas Reduction Accord

Governors of U.S. midwestern states and the premier of one Canadian province signed an accord under which they agreed to establish long-term GHG reduction targets for their states and provinces, develop a market-based and multi-sector cap-and-trade mechanism, and establish a system to track and manage GHG emissions. They further agreed to complete the undertakings of the accord within 30 months of its signing date.

15-Nov-07


State Initiatives:

State(s) Details of InitiativeRelevant Acts / Bills / Executive Orders Date signed

Arizona Executive order 2006-13 established a statewide goal to reduce Arizona’s GHG emissions to 2000 levels by 2020, and 50 percent below 2000 levels by 2040.

EO 2006-13 8-Sep-06

California Global Warming Solutions Act, AB 32, seeks to reduce California’s GHG emissions to historic 1990 levels by 2020. This is a fi rst of its kind program in the U.S. that mandates an economy-wide emissions cap with enforceable penalties.

AB 32 27-Sep-06

Connecticut, New Hampshire, Massachusetts, Rhode Island, Vermont

Adopted The Climate Change Action Plan of the New England Governors and the Eastern Canadian Premiers. Agreed to reduce GHG emissions to 1990 levels by 2010, 10 percent below 1990 levels by 2020, and 75-85 percent below 2001 levels in the long term.

NEG/ECP Climate Change Action Plan

26-Aug-01

Florida Executive order 07-127 established statewide GHG emission reduction targets of 2000 levels by 2017, 1990 levels by 2025, and 80 percent below 1990 levels by 2050.

EO 07-127 13-Jul-07

Hawaii Act 234, the Global Warming Solutions Act of 2007, caps statewide GHG emissions at 1990 levels by 2020. Act 234 30-Jun-07

Illinois State governor has set statewide GHG emission reduction targets of 1990 levels by 2020 and 60 percent below 1990 levels by 2050.

13-Feb-07

Maine The Provide Leadership in Addressing the Threat of Climate Change Act established GHG reduction targets of 1990 levels by 2010, 10 percent below 1990 levels by 2020, and 75-85 percent below 2003 levels in the long term.

Public Law Chapter 237 21-May-03

Minnesota Next Generation Energy Act established statewide GHG emission reduction targets of 15 percent by 2015, 30 percent by 2025, and 80 percent by 2050, based on 2005 levels.

Session Law Chapter 136 25-May-07

New Jersey Global Warming Response Act, A3301, limits the level of statewide GHG emissions, and GHG emissions associated with imported electricity, to 1990 levels by 2020 and to 80 percent below 2006 levels by 2050.

A3301 6-Jul-07

New Mexico Executive Order 2005-033 established statewide GHG emission reduction targets of 2000 emission levels by 2012, 10 percent below 2000 levels by 2020, and 75 percent below 2000 emission levels by 2050.

EO 2005-033 9-Jun-05

New York The 2002 State Energy Plan and Final Environmental Impact Statement established GHG reduction targets at 5 percent and 10 percent below 1990 levels by 2010 and 2020 respectively.

New York State Energy Plan June, 2002

Oregon House Bill 3543 signed by state governor sets statewide GHG emission targets of stopping growth by 2010, 10 percent below 1990 levels by 2020, and 75 percent below 1990 levels by 2050.

House Bill 3543 6-Aug-07

Washington State Senate Bill 6001, signed into law by WA governor, sets statewide GHG emission reduction goals to 1990 levels by 2020, 25 percent below 1990 levels by 2035, and 50 percent below 1990 levels by 2050.

Senate Bill 6001 3-May-07


EndnotesSO2 and NOx emissions data from U.S. EPA, “1970-2006 Average annual emissions, all criteria pollutants in MS Excel” National Emissions Inventory (NEI) Air Pollutant Emissions Trends Data, July 2007. CO2 emissions data from U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, April 2007. Mercury emissions data from U.S. EPA, Toxics Release Inventory 2005 Public Data Release eReport, April 2007. 2005 is the most recent year EPA has published the inventory of national emissions for greenhouse gases and mercury air emissions. Note that the electric sector data found throughout this document refl ect 2006 emissions. We expect the national share of 2006 CO2 and mercury emissions from the electric sector to be similar to the 2005 share.

U.S. Energy Information Administration (EIA). Power Plant Databases, EIA-906 and EIA-920 (2006).

U.S. Department of Energy, Tracking New Coal-Fired Power Plants. May 1, 2007.

Based on comparison of a conventional coal-fi red power plant with a heat rate of 11,300 Btu/kWh and a combined-cycle natural gas-fi red power plant with a heat rate of 7,900 Btu/kWh. Natural gas was assumed to be priced at $8.24/MMBtu. For a detailed discussion of the calculations, please see the report “Evaluation of Climate Policy Risk to Generation in a Competitive Power Market (January 2007)” by the Electric Power Research Institute.

In the entire 109th Congress (two years, from January 2005 to January 2007) there were nine hearings on climate change between the House and Senate. In the fi rst year of the 110th Congress (January 2007 to January 2008), there were 67 hearings between the two houses.

Ceres. Press Release: “Investors Managing $4 Trillion Call on Congress to Tackle Global Climate Change” (March 19, 2007).

Curry, T.E., S. Ansolabehere and H.J. Herzog, “A Survey of Public Attitudes towards Climate Change and Climate Change Mitigation Technologies in the U.S.: Analyses of 2006 Results,” MIT LFEE 2007-01 WP, April 2007.

Environmental and Energy Study Institute, “Climate Change Fact Sheet: Recent Polling on Public Perceptions of Climate Change”, May 4, 2007. Curry, T.E., S. Ansolabehere and H.J. Herzog, “A Survey of Public Attitudes towards Climate Change and Climate Change Mitigation Technologies in the U.S.: Analyses of 2006 Results,” MIT LFEE 2007-01 WP, April 2007.

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ENDNOTES 81

IPCC, 2007: Climate Change 2007: Th e Physical Science Basis. Contribution of Working Group I to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change [Solomon, S., D. Qin, M. Manning, Z. Chen, M. Marquis, K.B. Averyt, M. Tignor and H.L. Miller (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 996 pp.

Th e Lieberman-Warner Climate Security Act of 2007 (S. 2191) (October 18, 2007).

BernsteinResearch. U.S. Utilities: Th e Implications of Carbon Dioxide Regulation (October 2007).

Jos Sijm, Karsten Neuhoff and Yihsu Chen, CO2 Cost Pass Th rough and Windfall Profi ts in the Power Sector, May 2006. IPA Energy Consulting for the Department of Trade and Industry, Implications of the EU Emissions Trading Scheme for the U.K. Power Generation Sector.

Th e Lieberman-Warner Climate Security Act of 2007 (S. 2191) (October 18, 2007).

Congressional Budget Offi ce (CBO) Economic and Budget Issue Brief – Trade-Off s in Allocating Allowances for CO2

Emissions (April 25, 2007); National Commission on Energy Policy, Allocating Allowances in a Greenhouse Gas Trading System (March 2007).

U.S. EPA reports total greenhouse gas emissions of 7,260.4 million metric tons in 2005. Assuming that 80 percent of these emissions are included under the cap and assuming an allowance price of $10 per short ton of CO2, we calculate a total allowance value of $64 billion.

Cameron Hepburn, Michael Grubb, Karsten Neuhoff , Felix Matthes, Maximilien Tse, Auctioning of EU ETS phase II allowances: how and why? (July 7, 2006).

New York Times. Big Boost in Energy Science Sought in Letter to Elected (and Aspiring) Leaders. March 10, 2008.

Ibid.

See for example, the statements of Jim Rogers, CEO of Duke Energy as reported in E&E News, February 14, 2008. Rogers is critical of the auctioning of allowances.

Electric Power Research Institute. “Evaluation of Climate Policy Risk to Generation in a Competitive Power Market”. January 2007.

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Th is includes an 8 percent set-aside reserved for new power plants that come on-line aft er enactment of the bill.

U.S. Energy Information Administration (U.S. EIA). Average Retail Price of Electricity to Ultimate Customers by End-Use Sector, 2006, All Sectors, Full Service Providers. October 22, 2007.

State of New Jersey, et al., v. Environmental Protection Agency, No. 05-1097 (2008), http://pacer.cadc.uscourts.gov/docs/common/opinions/200802/05-1097a.pdf .

EE News, Mercury: NRDC’s Walke discusses impact of court decision rejecting EPA emissions regulation, http://www.eenews.net/tv/transcript/ 762

Pew Center on Global Climate Change, 110th Congress Index of Proposals at http://www.pewclimate.org/what_s_being_done/in_the_congress/indexbills.cfm

Pew Center on Global Climate Change, Global Warming Solutions – What’s being done, http://www.pewclimate.org/what_s_being_done

Ibid.

21.

22.

23.

24.

25.

26.

27.

40 West 20 StreetNew York, NY 10011212 727 2700

www.nrdc.org

99 Chauncy Street 6th FloorBoston, MA 02111617 247 0700

www.ceres.org

80 Park PlazaNewark, NJ 07102973 430 7000

www.pseg.com

One Market Street Spear Tower, Suite 2400San Francisco, CA 94105415 267 7070

www.pgecorp.comSW-COC-002387

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