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Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the United States

Full Report at: www.mjbradley.com

JUNE 2018

Benchmarking Air EmissionsOf the 100 Largest Electric Power Producers in the United States

June 2018

Presentation of ResultsData Downloads at: www.mjbradley.com

Report Authors:

Christopher Van Atten

Amlan Saha

Lauren Slawsky

Clement Russell

Luke Hellgren

Contributors:

http://www.mjbradley.com/




JUNE 2018

Preface

The 2018 Benchmarking report is the 14th collaborative effort highlighting environmental performance and progress in the nation’s

electric power sector. The 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. The current report is based on 2016 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 U.S. Energy Information Administration (EIA). Most power producers are also required to report air pollutant emissions data

to the U.S. Environmental Protection Agency (EPA). These 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.

The Benchmarking report facilitates the comparison of emissions performance by combining generation and fuel consumption data

compiled by EIA with emissions data on sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2) and mercury (Hg)

compiled by 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. The report is intended for a wide audience, including electric

industry executives, environmental advocates, financial analysts, investors, journalists, power plant managers, and public

policymakers.

Plant and company level data used in this report are available at www.mjbradley.com.

For questions or comments about this report, please contact:

Christopher Van Atten

M. J. Bradley & Associates LLC

47 Junction Square Drive

Concord, MA 01742, USA

Telephone: +1 978 369 5533

E-mail: [email protected]

2



mailto:[email protected]



JUNE 2018

Key Findings

• In 2016, power plant SO2 and NOx emissions were 91

percent and 82 percent lower, respectively, than they

were in 1990 when Congress passed major

amendments to the Clean Air Act.

• In 2016, power plant CO2 emissions were nearly the

same as 1990 levels (1 percent higher). From 2005

through 2016, power plant CO2 emissions declined by

24 percent. Some of the factors driving this trend

include energy efficiency improvements and the

displacement of coal by natural gas and renewable

energy resources.

• Mercury air emissions from power plants have

decreased 86 percent since 2000. The first-ever

federal limits on mercury and other hazardous air

pollutants from coal-fired power plants went into effect

in 2015.

3

Download plant level data from the 2018

Benchmarking Air Emissions report at:

www.mjbradley.com





JUNE 2018

U.S. Generation by Fuel Type

• In 2016, the U.S. electric system continued

its general shift away from coal toward lower-

and zero-emitting sources. For the first time,

natural gas (34 percent) overtook coal (30

percent) as the largest source of electricity in

the U.S.

• Nuclear plants accounted for 20 percent,

hydroelectric resources 7 percent, oil-fired

resources <1 percent, and non-hydroelectric

renewables and other fuel sources such as

non-biogenic municipal solid waste, tire-

derived fuel, manufactured and waste gases,

etc. accounted for 7 and 2 percent,

respectively.

• This marks a shift away from higher-emitting

power sources compared to a decade ago

(2006), when coal and natural gas accounted

for 49 percent and 20 percent of power

production, respectively.

4

Source: U.S. Energy Information Administration. EIA-923 Monthly Generation and Fuel Consumption 2016 Final Release. January, 2018.

U.S. Electricity Generation by Fuel Type (2016)




JUNE 2018

The 100 Largest Electric Power Producers

5

The report examines and compares the stack air pollutant emissions of the 100 largest power producers in the United States based on their 2016 generation,

plant ownership, and emissions data. The table below lists the 100 largest power producers featured in this report ranked by their total electricity generation

from fossil fuel, nuclear, and renewable energy facilities. These producers include public and private entities (collectively referred to as “companies” or

“producers” in this report) that own roughly 3,000 power plants and account for 84 percent of reported electric generation and 86 percent of the industry’s

reported emissions.

The report focuses on four power plant pollutants for which public emissions data are available: sulfur dioxide (SO2), nitrogen oxides (NOx), mercury (Hg), and

carbon dioxide (CO2). At sufficient concentrations, these pollutants are associated with significant environmental and public health problems, including acid

deposition, mercury deposition, nitrogen deposition, global warming, ground-level ozone, regional haze, and fine particle air pollution, which can lead to asthma

and other respiratory illnesses. The report benchmarks, or ranks, each company’s absolute emissions and its emission rate (determined by dividing emissions

by electricity produced) for each pollutant.

The 100 largest power producers emitted in aggregate approximately 1.26 million tons of SO2, 1.01 million tons of NOx, 5.26 tons of mercury, and 1.70 billion

tons of CO2.

RANK PRODUCER NAME

2016 MWh

(million) RANK PRODUCER NAME

2016 MWh


2016 MWh


2016 MWh

(million)

1 Duke 219.8 26 Salt River Project 28.6 51 The Carlyle Group 13.6 76 Arkansas Electric Coop 9.8

2 Southern 187.0 27 Oglethorpe 27.8 52 Invenergy 13.5 77 Dow Chemical 9.7

3 Exelon 186.9 28 AES 27.7 53 TransCanada 13.1 78 East Kentucky Pow er Coop 9.6

4 NextEra Energy 180.5 29 New York Pow er Authority 26.9 54 Panda Pow er Funds 13.1 79 Tenaska 9.5

5 Tennessee Valley Authority 139.6 30 Pinnacle West 26.0 55 JEA 13.0 80 Los Angeles City 9.3

6 Entergy 134.3 31 EDF 24.9 56 Municipal Elec. Auth. of GA 13.0 81 Austin Energy 9.3

7 AEP 133.0 32 LS Pow er 24.8 57 Portland General Electric 12.9 82 E.ON 9.3

8 Berkshire Hathaw ay Energy 112.8 33 CPS Energy 23.4 58 EDP 12.9 83 PUD No 1 of Chelan County 9.2

9 Dominion 108.8 34 SCANA 22.8 59 IDACORP 12.8 84 El Paso Electric 8.7

10 Calpine 107.7 35 Emera 22.6 60 CLECO 12.4 85 Intermountain Pow er Agency 8.4

11 NRG 103.2 36 Great Plains Energy 22.0 61 Fortis 11.9 86 International Paper 8.2

12 Dynegy 100.4 37 Westar 21.8 62 NiSource 11.8 87 Buckeye Pow er 8.2

13 FirstEnergy 85.0 38 ArcLight Capital 21.6 63 Puget Holdings 11.4 88 Sacramento Municipal Util Dist 7.9

14 Vistra Energy 82.0 39 OGE 21.4 64 Omaha Public Pow er District 11.3 89 BP 7.5

15 Xcel 74.4 40 CMS Energy 21.2 65 ALLETE 11.1 90 Avista 7.4

16 US Corps of Engineers 71.2 41 Santee Cooper 20.4 66 PNM Resources 11.0 91 NC Public Pow er 7.3

17 Riverstone 58.4 42 Ares 20.3 67 Seminole Electric Coop 10.9 92 Southern California P P A 7.3

18 PSEG 52.6 43 Basin Electric Pow er Coop 19.9 68 Occidental 10.8 93 Energy Capital Partners 7.2

19 US Bureau of Reclamation 40.6 44 Avangrid 17.8 69 Exxon Mobil 10.7 94 Starw ood Energy 7.2

20 DTE Energy 40.5 45 Alliant Energy 17.2 70 Tri-State 10.5 95 Cooperative Energy 7.1

21 Ameren 38.7 46 Associated Electric Coop 16.4 71 Brookfield 10.1 96 Pow erSouth Energy Coop 7.1

22 WEC Energy Group 36.0 47 General Electric 15.3 72 PUD No 2 of Grant County 10.1 97 Brazos Electric Pow er Coop 7.1

23 PPL 35.4 48 NE Public Pow er District 14.8 73 Great River Energy 10.0 98 Enel 7.1

24 PG&E 33.5 49 Edison International 14.0 74 Energy Northw est 10.0 99 Hoosier Energy 6.9

25 ENGIE 29.1 50 Low er CO River Authority 13.8 75 J-Pow er 9.9 100 Seattle City Light 6.7




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Rankings by Generation

6

Generation of the 100 Largest Power Producers by Fuel Type (2016)(million MWh)

Renewable/Other

Hydro

Nuclear

Oil

Natural Gas

Coal

Breakdown of ownership categories provided on Endnotes slide: privately/investor owned public power cooperative




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81 of the Top 100 power producers

generated power from zero-emitting

resources in 2016, accounting for 89% of

the national total generated from

resources including nuclear, hydro, and

renewables.

Rankings by Zero-Emitting Generation

7

Zero-Emitting Generation of the 100 Largest Power Producers (2016)(million MWh)





JUNE 2018 8

Important Note on Emission Rankings

The Benchmarking Report presents generation and emissions information of power producers, not distribution utilities that deliver electricity to customers. In

order to apply a uniform methodology to all power producers, the Report assigns electricity generation and associated emissions to power producers according

to their known generating asset ownership as of December 31, 2016.

The above is true even when a producer’s generating facilities are part of one or more contractual agreements (e.g., power purchase contracts, etc.) with other

entities (often utilities). In other words, this Report attributes all generation and emissions to the owner of an asset, not to purchasers of the asset’s output or to

counterparties to the contracts. Publicly available data do not allow the accurate and exhaustive tracking of such agreements.

There are a host of reasons why a company’s generation profile may differ from that of the electricity it delivers to customers. For example, rural cooperatives,

which are non-profit entities and are thus generally unable to directly take advantage of renewable tax credits, tend to rely on power purchase agreements and

other non-asset owning mechanisms to deliver renewable electricity to their customers (see case study slide).

A vertically integrated utility that owns a large fossil generating fleet, but also delivers purchased renewable electricity to its customers, might have lower

average emission rates than the level attributed in this report to the power producer that owns the said fossil fleet, if the renewable energy purchases were

factored into the utility’s performance. By the same token, the utility’s emissions or emission rate would increase if it contracted with a higher emitting facility or

relied on market purchases with associated emissions.

The charts in the next few slides present both the total emissions by company as well as their average emission rates. The 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.

The charts illustrate significant differences 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 nearly 108 million tons per year. The NOx emission rates range from zero to 2.6 pounds of emissions per megawatt hour of

generation. The total tons of emissions from any producer are influenced by the total amount of generation that a producer owns and by the fuels and

technologies used to generate electricity.

Emission Rankings




JUNE 2018

SO2

(million ton)

NOx (million ton)

Mercury (Hg) (ton)

CO2

(billion ton)

100% 1.47 1.22 6.72 2.02

86% 83% 78% 84%

75% 28 45 44 48

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25% 3 5 3 5Perc

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100 largest producers

No. of producers

Emission Contributions

9

Air pollution emissions from power plants are highly concentrated among a small number of producers. For example,

nearly a quarter of the electric power industry’s SO2 and CO2 emissions are emitted by just three and five top 100

producers, respectively.




JUNE 2018

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JUNE 2018

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JUNE 2018

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JUNE 2018

0

200

400

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0 200 400 600 800

2016

2014

Mercury and Air Toxics Standards Impacts

14

Pre-MATS

MATSin effect

Emissions

Increase17% of facilities

Emissions

Decrease83% of facilities

Annual Mercury Emissions by Coal Facility(pounds)

• In 2012, EPA finalized the Mercury and Air Toxics

Standards (MATS), regulating emissions of mercury

and other hazardous air pollutants from coal- and oil-

fired electric generating units. The standards went

into effect on April 16, 2015, although many coal units

obtained a one-year extension to the initial compliance

date. Reported emissions have declined 69 percent

between 2014 and 2016.

• Coal mercury emissions from the top 100 power

producers in 2016 range from less than 1 pound to

2,040 pounds, and coal mercury emission rates range

from 0.0002 pound per gigawatt hour (a gigawatt hour

is 1,000 megawatt hours) to 0.045 pound per gigawatt

hour.

• Compared to 2014 levels mercury emissions declined

at 83 percent of coal facilities that were in operation as

of December 31, 2016 (see adjacent chart). Across

these facilities, emissions decreased by an average of

63 percent.




JUNE 2018

2000 20172000 2017

0

40

80

120

160

200

240

2000 2017

Annual Trends

15

The electric power sector has made significant progress in terms of reducing its NOx and SO2 emissions. From 2000

through 2017, NOx and SO2 emission decreased 79 and 88 percent, respectively. From 2005 to 2017, CO2 emissions

decreased 24 percent while GDP grew 20 percent. Over the same period, generation from renewables grew 92

percent.

Electric Sector Emissions(Indexed; 2000 = 100)

*Includes hydroelectric, wind, solar, biomass, geothermal, and other renewable sources.

**GDP in chained 2009 dollars.

Generation Fuel Mix(Indexed; 2000 = 100)

Macroeconomic Indicators(Indexed; 2000 = 100)

CO2

SO2

NOx

1221

78

Natural Gas

Renewable*

Coal

212

193

61

Total Generation

GDP**

107

136

107Nuclear




JUNE 2018

2,326

2,306

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904

900

889

874

868

0 1,000 2,000 3,000

Montana

North Dakota

Wyoming

Kansas

Nebraska

Rhode Island

California

Connecticut

Maine

Idaho

245%

220%

201%

185%

185%

72%

68%

62%

57%

57%

0 1 2 3

Wyoming

West Virginia

North Dakota

Montana

Vermont

Tennessee

Delaware

Idaho

Maryland

Massachusetts

1,985

1,974

1,973

1,784

1,741

279

272

184

183

7

0 1,000 2,000 3,000

Wyoming

West Virginia

Kentucky

Indiana

Missouri

Maine

New Hampshire

Washington

Idaho

Vermont

238.3

116.6

90.5

89.9

88.7

2.8

2.6

1.6

1.4

0.01

0 200 400

Texas

Florida

Pennsylvania

Indiana

Ohio

South Dakota

New Hampshire

Maine

Idaho

Vermont

State-by-State CO2 Emissions

16

Total CO2 Emissions by State(million ton; top 5 and bottom 5 are shown)

All Sources – CO2 Emission Rate(lb/MWh; top 5 and bottom 5 are shown)

Electricity Exporters/Importers(2016 Net Trade Index; top 5 exporters and importers are shown)

Fossil – CO2 Emission Rate(lb/MWh; top 5 and bottom 5 are shown)

E

X

P

O

R

T

E

R

S

I

M

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Total in-state supply of electricity as % share of total in-state consumption needs; in-state supply includes international imports




JUNE 2018

105

479

499

567

738

805

968

1,094

1,110

1,248

1,280

1,386

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1,498

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1,925

0 400 800 1,200 1,600 2,000

Exelon (3)

NextEra Energy (4)

PSEG (18)

Entergy (6)

Dominion (9)

Calpine (10)

Duke (1)

Southern (2)

Riverstone (17)

Berkshire Hathaway Energy (8)

FirstEnergy (13)

Xcel (15)

NRG (11)

DTE Energy (20)

Vistra Energy (14)

Dynegy (12)

Ameren (21)

AEP (7)

WEC Energy Group (22)

PPL (23)

Rankings by CO2 Emission Rate(Top 20 Privately/Investor Owned Power Producers)

17

All Sources – CO2 Emission Rate(lb/MWh)

Ranking based on

2016 total generation

Note: “Privately/investor owned” power producers include investor owned, privately held, and foreign owned corporations. This chart does not show public power

producers (federal power authorities, state power authorities, municipalities, power districts), or cooperatives.




JUNE 2018

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

194

0

194

2

194

4

194

6

194

8

195

0

195

2

195

4

195

6

195

8

196

0

196

2

196

4

196

6

196

8

197

0

197

2

197

4

197

6

197

8

198

0

198

2

198

4

198

6

198

8

199

0

199

2

199

4

199

6

199

8

200

0

200

2

200

4

200

6

200

8

201

0

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2

201

4

201

6

Renewable/Other

Hydro

Nuclear

Oil

Gas

Coal

Existing Capacity

18

U.S. Electric Generating Capacity by In Service Year: 1940 – 2016(Nameplate Capacity; MW)

Source: U.S. Energy Information Administration. EIA-860 Annual Electric Generator Report. November 9, 2017.




JUNE 2018

Ranking Utility Portfolios

• As described above, the Benchmarking Report presents generation and emissions information of power producers, not utility companies with obligations to deliver electricity to customers. In order to apply a uniform methodology to all power producers, the Report assigns electricity generation and associated emissions to power producers according to their known generating asset ownership as of December 31, 2016.

• If a power producer is also a distribution utility, the fuel mix and emissions associated with the utility’s total supply portfolio may differ substantially from its owned generation, depending on the nature and extent of any power purchase agreements and other contractual agreements to which the utility may be party. The distribution utility might also rely on market purchases to supply its customers (e.g., purchases from the PJM or MISO markets). A power producer might also sell excess supply to the market or to other utilities.

• To highlight the potential implications of these two different approaches, the following slide presents the generation mix and all source CO2 emission rate for a rural electric cooperative—Great River Energy. The graph also reports the CO2 emission rate associated with part of the company’s supply portfolio (owned generation and long-term contracts); the supply portfolio emission rate does not reflect the emissions associated with market purchases, which may be fossil-fired, renewables, or other sources.

• In the example shown, the CO2 emission rate associated with supply is lower because Great River Energy contracts for non-emitting, renewable resources rather than owning wind or solar projects. Rural cooperatives are non-profit entities that are generally unable to take advantage of renewable tax credits, so they will tend to purchase renewable energy under long-term contracts rather than owning the facilities.

• Both approaches—generation and supply—can be helpful in evaluating a company’s performance. Unfortunately, there is no publicly available source for the data that would be required to benchmark utility resource portfolios in the same way that we can benchmark owned-generation assets.

• The following slide illustrates the All Source CO2 emissions rates for Great River Energy. The company voluntarily supplied the information displayed. The charts include the emission rate for Owned Generation only (consistent with the focus and methodology of the Benchmarking report) as well as the All Source emission rate associated with the combination of owned generation and long-term contract purchases.

19




JUNE 2018

Case Study: Owned Generation and Contracted Supply

20

0

2

4

6

8

10

12

14

Great River Energy

Ow

ne

d G

en

era

tio

nC

on

tra

cte

d

Supply Portfolio

All Source CO2 RateOwned Generation

2,077 lb/MWh

TWh

All Source CO2 RateWith Contracted Power

1,626 lb/MWh

Coal Natural Gas Oil Nuclear Hydro Renewable/Other Contracted by Fuel Type

Note: additional supply may be obtained from market purchases; however, these data are not included here.

Renewable/Other

Hydro

Great River Energy’s All Source CO2Emission Rate decreases 22% when factoring in owned generation and contracted supply




JUNE 2018

Capacity factors measure the extent to which a power plant is utilized over the course of time. The technical definition is the ratio of the electrical energy

produced by a generating unit to the electrical energy that could have been produced assuming continuous full power operation.

Coal plant utilization has declined in recent years; the average annual capacity factor of coal plants in the U.S. dropped from 73 percent in 2008 to 55 percent in

2017, while over the same time period, natural gas combined-cycle capacity factors rose from 40 to 55 percent.

Nuclear plants have high utilization rates, consistently running at above 90 percent average capacity factor.

Hydropower and wind capacity factors are lower, but have also remained relatively constant over the past decade.

21

Annual Capacity Factors for Select Fuels and Technologies

Source: U.S. Energy Information Administration. Electric Power Monthly, Tables 6.7A and 6.7B. January 2018.

*Combined Cycle

Nuclear Coal Natural Gas* Hydro Wind

91% 92%

0%

25%

50%

75%

100%

2008 2017

73%

54%

2008 2017

40%

55%

2008 2017

37%

45%

2008 2017

32%37%

2008 2017

Average Capacity Factors




JUNE 2018 22

To supplement the 2018 Benchmarking Report, MJB&A has developed two interactive maps to further visualize the emissions and electricity generation from

power producers in the United States. The primary map (“Main”) provides facility-level emissions and generation data and offers interactive features to filter

facilities by geography, fuel type, company ownership, and other metrics. An additional map (“Trends”) was developed with historical Benchmarking data

(2012-2016 data) to show how facility-level emissions and generation are changing through time.

These maps and accompanying user guide are available at www.mjbradley.com.

Main Map

Trends Map

Benchmarking Maps





JUNE 2018

Appendix: Data Sources

The following public data sources were used to develop this report:

EPA AIR MARKETS PROGRAM DATA (AMP): EPA’s Air Markets Program Data account for almost all of the SO2 and NOx emissions, and

about 20 percent of the CO2 emissions analyzed in this report.

EPA TOXIC RELEASE INVENTORY (TRI): The 2016 mercury emissions used in this report are based on TRI reports submitted by facility

managers.

EIA FORMS 923 POWER PLANT DATABASES (2016): EIA Form 923 provides data on the electric generation and heat input by fuel type for

utility and non-utility power plants. The heat input data was used to calculate approximately 80 percent of the CO2 emissions analyzed in this

report.

EIA FORM 860 ANNUAL ELECTRIC GENERATOR REPORT (2016): EIA Form 860 is a generating unit level data source that includes

information about generators at electric power plants, including information about generator ownership.

EPA U.S. INVENTORY OF GREENHOUSE GAS EMISSIONS AND SINKS (2018): EPA’s U.S. Inventory of Greenhouse Gas Emissions and

Sinks report provides in Annex 2 heat contents and carbon content coefficients of various fuel types. This data was used in conjunction with EIA

Form 923 to calculate approximately 20 percent of the CO2 emissions analyzed in this report.

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JUNE 2018

Appendix: Methodology

Plant Ownership

This report aims to reflect power plant ownership as of December 31, 2016. Plant ownership data used in this report are primarily based on the EIA-860

database from the year 2016. 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 filed with the SEC, listings on

their website, and other media sources. Ownership of plants is updated based on the most recent data available. Consequently, in a number of instances,

ultimate assignment of plant ownership in this report differs from EIA-860’s reported ownership. This primarily happens when the plant in question falls in one

or more of the categories listed below:

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

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

3. It was sold or bought during the year 2016. Because form 10-K for a particular year is usually filed by the producer in the first quarter of the

following year, this report assumes that ownership as reported in form 10-K is more accurate.

Publicly available data do not provide a straightforward means to accurately track lease arrangements and power purchase agreements. Therefore, in order to

apply a standardized methodology to all companies, this report allocates generation and any associated emissions according to reported asset ownership as of

December 31, 2016.

Identifying “who owns what” in the dynamic electricity generation industry is probably the single most difficult 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

effort was expended in ensuring the accuracy of ownership information reflected 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 verified.

Generation Data and Cogeneration Facilities

Plant generation data used in this report come from EIA Form 923.

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 reflect 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 Form 923, which report a plant’s total heat input as

well as that which is associated with electricity production only, was used to calculate their emissions.

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JUNE 2018

Appendix: Methodology (continued)

NOx and SO2 Emissions

The EPA AMP database collects and reports SO2 and NOx emissions data for nearly all major power plants in the U.S. Emissions information reported in the

AMP database is collected from continuous emission monitoring (CEM) systems. SO2 and NOx emissions data reported to the AMP account for all of the SO2

and NOx emissions assigned to the 100 largest power producers in this report.

The AMP database collects and reports SO2 and NOx emissions data by fuel type at the boiler level. This report consolidates this 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 different units. This may cause producers to be

assigned emission figures that are slightly higher or lower than their actual shares.

The appointment of NOx emissions between coal and natural gas at boilers that can burn both fuels may in certain instances sl ightly overstate coal’s share of

the emissions. This situation is likely to arise when a dual-fuel boiler that is classified as “coal-fired” within AMP burns natural gas to produce electricity in

substantial amounts. In most years there would be very little economic reason to make this switch in a boiler that is not part of a combined cycle setup.

Continued low natural gas prices in 2016 led to a small number of boilers switching to natural gas for most or a large part of their electricity output. Because

AMP datasets do not make this distinction, apportioning emissions based on the fuel-type of the boiler would increase coal’s share of emissions.

SO2 and CO2 emissions are mostly not affected by this issue. Natural gas emits virtually no SO2. CO2 emissions can be calculated from the heat input data

reported in EIA Form 923, which allows for the correct apportionment of emissions between coal and natural gas.

CO2 Emissions

A majority of CO2 emissions used in this report were calculated using heat input data from EIA form 923 and carbon content coefficients of various fuel types

provided by EPA. The table on the following slide shows the carbon coefficients used in this procedure. Non-emitting fuel types, whose carbon coefficients are

zero, are not shown in the table. CO2 emissions reported through the EPA AMP account for a small share of the CO2 emissions used in this report.

The datasets report heat input and emissions data by fuel type at either the prime mover or boiler level. This 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 different units. This may cause producers to be assigned

emission figures that are slightly higher or lower than their actual shares.

Mercury Emissions

Mercury 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. The TRI contains facility-level information on the use and environmental

release of chemicals classified as toxic under the Clean Air Act. The TRI contains information on all toxic releases from a facility; mercury emissions in this

report are based on air releases only. Because coal plants are the primary source of mercury emissions within the electric industry, the mercury emissions and

emission rates presented in this report reflect the emissions associated with each producer’s fleet of coal plants only.

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JUNE 2018

Appendix: Carbon Content Coefficients by Fuel Type

From Annex 2 of EPA GHG Inventory 2018

26

Fuel TypeCarbon Content Coefficients

(Tg Carbon/Qbtu)

Coal

Anthracite Coal 28.28

Bituminous Coal 25.44

Sub-bituminous Coal 26.50

Lignite Coal 26.65

Waste/Other Coal

(includes anthracite culm, bituminous gob, fine coal, lignite waste, waste coal)26.05

Coal-based Synfuel, including briquettes, pellets, or extrusions, which are formed by

binding materials or processes that recycle materials25.34

Coal-based Synthetic Gas 18.55

Oil

Distillate Fuel Oil

(Diesel, No. 1, No. 2, and No. 4 Fuel Oils)20.17

Jet Fuel 19.70

Kerosene 19.96

Residual Fuel Oil (No. 5, No. 6 Fuel Oils, and Bunker C Fuel Oil) 20.48

Waste/Other Oil

(including Crude Oil, Liquid Butane, Liquid Propane, Oil Waste, Re-Refined Motor Oil,

Sludge Oil, Tar Oil, or other petroleum-based liquid wastes)

20.55

Petroleum Coke 27.85

Gas

Natural Gas 14.46

Blast Furnace Gas 18.55

Other Gas 18.55

Gaseous Propane 14.46




JUNE 2018

Appendix: Quality Assurance

This report examines the air pollutant emissions of the 100 largest electricity generating companies in the United States based on 2016 electricity generation,

emissions, and ownership data. The 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, company websites, and media articles.

Emission data may include revisions to 2016 data that companies were in the process of submitting or have already submitted to EPA at the time of publication

of this report.

This report relies almost entirely on publicly available information. Data sets published by EIA and EPA are the primary source of the generation and emissions

data used in this report. The organizations that fund this report believe maintaining public access to this information is essential to tracking the industry’s

performance and making accurate and informed analyses and policy decisions.

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JUNE 2018

Endnotes

1. Private entities include investor-owned and privately held utilities and non-utility power producers (e.g., independent power producers). Cooperative

electric utilities are owned by their members (i.e., the consumers they serve). Publicly-owned electric utilities are nonprofit government entities that are

organized at either the local or State level. There are also several Federal electric utilities in the United States, such as the Tennessee Valley Authority.

2. Power plant ownership in this report is divided into three categories: privately/investor owned (investor-owned corporations, privately held corporations,

foreign-owned corporations), public power (federal power authorities, state power authorities, municipalities, power districts), and cooperative.

3. Electric Sector Emissions data from EPA AMP database available at http:// http://ampd.epa.gov/ampd/

Generation data from EIA Monthly Energy Review Table 7.2a Electricity Generation Total for All Sectors available at

https://www.eia.gov/totalenergy/data/monthly/#electricity

Gross Domestic Product (GDP) data from the U.S. Bureau of Economic Analysis available at https://www.bea.gov/national/index.htm#gdp

The sources used in the Annual Trends figure have already made national-level 2017 data available, allowing the trends section to extend through 2017.

Detailed 2017 data used for the company-specific analysis of the top 100 electricity producers was not yet available at the time of report publication.

28


http://ampd.epa.gov/ampd/

https://www.eia.gov/totalenergy/data/monthly/#electricity

https://www.bea.gov/national/index.htm#gdp

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