2011 APPA Neophyte's Guide to Electricity - American Public Power ...

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2011 APPA Neophyte's Guide to Electricity - American Public Power ...

A Neophyte’s

Guide to the

Changing Electric

Utility Industry

SECOND EDITION


The electric utility industry in the United

States is fiendishly complex. It has

myriad industry players and a confusing

mix of regulation and “deregulation”

at both the federal and state levels.

The purpose of this guide is to provide

the basic background knowledge about

the electric utility industry and its institutions

(and, of course, the all-important

acronyms!) necessary to understand

the industry.

Neophytes Guide, Update, May 2011

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Alphabet Soup of Electricity

A

APPAAmerican Public Power Association;

trade association for public power utilities

ARC–aggregator of retail customers; third

party that bundles demand response of retail

electric customers and sells it into the wholesale

electric markets

AWEA–American Wind Energy Association;

trade association for the wind energy industry

B

BPA–Bonneville Power Administration; federal

power agency serving Pacific Northwest

C

CA-ISO–California Independent System

Operator; regional transmission organization

serving California

CSP–curtailment service provider; third

party that bundles demand response of retail

customers for sale into the wholesale markets;

used interchangeably with ARC

E

EEI–Edison Electric Institute; trade association

for investor-owned utilities

ELCON–The Electricity Consumers

Resource Council; trade association of large

industrial users of electricity

EPAct–Energy Policy Act; refers to a comprehensive

federal energy law enacted in

2005 and sometimes an earlier one enacted

in 1992

EPRI–Electric Power Research Institute;

independent organization that conducts

research and development related to

electricity

EPSA–Electric Power Supply Association;

trade association for non-utility independent

power producers

ERO–Electric Reliability Organization; entity

charged with ensuring the reliability of the

bulk (high voltage) transmission system

ERCOT–Electric Reliability Council of

Texas; regional transmission organization

serving Texas

F

FERC–Federal Energy Regulatory

Commission; agency that regulates wholesale

electric markets and wholesale transmission

services provided by RTOs and investorowned

utilities

FPA–Federal Power Act; 1935 law governing

electric utilities

G

G&T co-op–generation and transmission

cooperative; large cooperative utility that

generates and delivers electricity to smaller

distribution co-ops

GW–gigawatt; one billion watts

I

IOU–investor-owned utility; for-profit, shareholder-owned

regulated electric utility

IPP–independent power producer; non-utility

for-profit entity that owns and sells electricity

generation

ISO/RTO–independent system operator/

regional transmission organization; an organization

that operates electricity markets over a

portion of the transmission grid (ISO and RTO

are often used interchangeably)

ISO-NE–Independent System Operator-New

England; the regional transmission organization

serving New England states

J

JAA–joint action agency; a state-authorized

organization serving the power supply needs

of municipal electric distribution utilities

K

kV–kilovolt; measure of the capability of a

transmission line to deliver electricity

kW–kilowatt; a unit of power equal to 1,000

watts

kWh–kilowatt-hour; energy expended in one

hour by one kilowatt of power

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L

LMP–locational marginal pricing; rate for

electric transmission that reflects the availability

of transmission to a given destination

M

MISO–Midwest Independent System

Operator; regional transmission organization

serving all or part of 14 states in the

Midwest.

MW–megawatt; one million watts

MWh–megawatt-hours; energy expended in

one hour by one megawatt of power

N

NARUC–National Association of Regulatory

Utility Commissioners, the trade association of

state public utility commissioners

NASUCA–National Association of State

Utility Consumer Advocates; association of

state advocates representing utility consumers

NERC–North American Electric Reliability

Council; umbrella organization for regional

reliability groups in the United States and

Canada, and North America’s designated ERO

NRECA–National Rural Electric Cooperative

Association; trade association of rural electric

cooperatives

NYISO–New York Independent System

Operator; the regional transmission organization

serving New York state

O

OATT–open-access transmission tariff; a

general rate for electric transmission service

for third parties

P

PJM–PJM Interconnection; the regional

transmission organization serving all or part of

thirteen states in the mid-Atlantic region.

PMA–power marketing administration;

refers to the four federal power agencies that

market hydroelectric power from federal dams

PUC or PSC–public utility commission or

public service commission; state regulatory

body

S

SEIA–Solar Energy Industries Association;

trade association for the solar energy industry

SEPA–Solar Electric Power Association;

non-profit that provides information about

solar power.

SPP–Southwest Power Pool; the regional

transmission organization serving all or part of

nine states between Nebraska, New Mexico

and Louisiana.

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The Basic Building Blocks

Production and delivery

of electricity involves

three basic processes:

generation,

transmission

and

distribution.

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Generation

Electricity, the movement of electrons, occurs naturally. But to serve industrial

and residential needs for lighting, heating, cooling, refrigeration, computers

and many other daily needs, large amounts of moving electrons must

be generated from some other fuel or energy source.

Electricity is created from the conversion of a fuel or other source of energy

into electrons. This process occurs in an electricity generating plant. The

primary electricity generating technologies used in the United States are

coal, nuclear energy, hydro power (falling water), natural gas (not gasoline!),

and fuel oil. A small but increasing portion of the generation portfolio comes

from renewable sources of energy, such as solar, wind, landfill methane gas

and geothermal heat from underground formations.

Each of the various generating technologies used to produce electricity

have their own advantages and disadvantages, as shown in the table below.

Because of this mix of characteristics, the electric power generated and consumed

in a region generally comes from multiple generating units using a

mix of all of these technologies.

Characteristics of Electricity Generating Technologies

Efficiency of High Natural Gas, Hydro

Conversion Low Coal, Nuclear, Solar, Wind

Capital Costs High Coal, Nuclear, Solar, Wind, Hydro

Low

Natural Gas, Oil

Operating Costs High Natural Gas, Oil

Low

Very Low

Coal, Nuclear

Solar, Wind, Hydro

Availability Base Load Coal, Nuclear, Large Hydro

Intermediate or Peak Natural Gas, Oil

Variable

Solar, Wind, Small Hydro

Environmental High Coal, Nuclear

Concerns Medium Gas, Oil, Hydro

Low

Solar, Wind

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Generation

U.S. Electric

Generating Capacity

All Sectors

Nameplate capacity in megawatts.

Data reflect joint ownership.

Source: U.S. Energy Information Administration

Availability

Some sources of power can be ramped up and down fairly easily, while others

must run continuously for operational or financial reasons. Continuously

operating plants are known as “base load resources” and plants that are used

only when energy use increases are known as “intermediate” or “peaking”

units. Renewable sources, such as wind and solar, generate electricity when

there is sufficient energy from wind or the sun, and thus cannot be controlled,

at least in the absence of associated storage technologies which are in

their infancy. They are called “intermittent” or “variable” resources.

Oli

5.6%

Other

4.7%

Water 8.8%

Nuclear

9.5%

Coal

30.2%

Gas

41.2%

Efficiency

A common measure of efficiency is the amount of energy from a fuel or

other energy source that is converted into electricity. For non-renewable

power, such efficiency is measured by the “heat rate” of the plant, which is

the quantity of heat in the fuel (as measured by British Thermal Units or

BTU) that is required to produce a kilowatt-hour of electricity. The greater

the heat rate, the less efficient the unit. Coal and nuclear plants generally

have lower efficiencies than natural gas plants.

As for other types of power, hydro power captures a high percentage of

the kinetic energy contained in the movement of water. Wind and solar

power convert only a small portion of the energy contained in the wind and

sunlight into actual electricity. But because the wind and solar energy do not

need to be purchased and entail minimal maintenance costs, these methods

can also be thought of as highly efficient from a societal and economic perspective.

Another method of measuring the efficiency of a power source is by its

“capacity factor,” which is the total kilowatt-hours of electricity the plant

actually generates over the course of the year compared to the total generating

capacity of the plant. By this measure, natural gas plants used as “peaking”

units would be less efficient than coal and nuclear plants since gas plants

do not use their full capacity throughout the year. These differing capacity

factor efficiencies are strongly influenced by factors such as whether a unit is

used for peaking or baseload, as well as whether it is a variable resource, as

discussed above.

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Capital and Operating Costs

There are two types of costs of electricity generation; capital costs (the construction

of the plant) and operating costs (fuel, daily operations and maintenance).

Included in capital costs are the costs of financing, such as interest

payments on debt and returns to investors.

Coal and nuclear units have higher capital costs and take much more time

to build, but once in service, their operating costs are often cheaper, primarily

due to their lower fuel costs. These units are therefore generally used as

“base load resources” so their owners can recover their high capital costs.

Moreover, nuclear technology makes it difficult and costly to cycle these

plants on and off. Coal and nuclear energy also pose environmental and safety

challenges due to air emissions from coal plants and spent fuel from

nuclear power plants.

In contrast, natural gas plants are relatively inexpensive to build but have

higher operating costs. Generating units with the highest operating costs

(such as plants that burn natural gas or fuel oil) are generally used as “intermediate”

or “peaking” units, meaning their primary function is to produce

electricity during the times of highest usage, known as peak periods. Natural

gas costs have fluctuated significantly over the past few years. Although relatively

low at the present time, natural gas costs remain greater than for other

fossil fuels, making the operating costs of electricity generated from natural

gas-fired generating units the most expensive.

Wind turbines have high capital costs and close to zero operating costs

(wind as a fuel costs nothing), and produce no pollution. But wind projects

are intermittent sources of power, as the wind does not blow all the time and

cannot be stored.

Hydro power’s operating costs are also low, but availability is determined

in part by precipitation levels, agricultural needs for water, fish and wildlife

protection, and recreational uses of rivers and reservoirs.

The practice of using electric power generated from the least expensive

units first and then going up the list of available generating resources in

ascending order of their operating expenses or submitted bids, until sufficient

electricity is committed to meet consumer demand, has been traditionally

referred to as “economic dispatch.”

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Transmission

Once electricity is committed through economic dispatch and generated, it

travels over high-voltage bulk power transmission lines from the generating

unit to the area where it will be consumed. The electric transmission network

in the United States is organized into three “interconnections”—very large

bulk power transmission grids that operate in synch and that must be carefully

coordinated at every moment to prevent widespread blackouts, such as the

one that occurred in the Midwest and Northeast in August 2003.

The three are the “Eastern Interconnection,” (covering the eastern twothirds

of the United States and Canada), the “Western Interconnection” (covering

the western United States and Canada) and the Electric Reliability

Council of Texas (“ERCOT,” covering most, but not all, of Texas).

These interconnections set electrical boundaries. Electrons flow freely

within them, but do not flow freely between them. There are a few places

where the interconnections do connect with each other, but power flows at

these points are carefully controlled.

Transmission Interconnections

Eastern

Interconnection

Western

Interconnection

ERCOT

Interconnection

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Transmission

A regional transmission

grid is like an

ecosystem: everyone

who uses it is affected

by everyone else’s

actions (or failure

to act).

Once electrons flow from the generating unit to the grid, their path cannot

generally be controlled. Electrons follow the path of “least impedance,”

meaning they will go where their movement is least impeded. The path of

least impedance is determined by the laws of physics and a complex interplay

of the capacity of transmission lines to move the electrons, the location of the

generation, and the amount of electricity consumed by homes, factories and

businesses located at different points along the grid.

Therefore, specific electrons cannot be delivered to a specific place on the

interconnected grid. For example, if Consumer A buys power from the

owner of Generator B, Generator B will deliver the power to the point where

the generator’s plant connects to the grid and Consumer A will receive the

power it needs from a different point on grid. The electrons that Consumer

A uses to power lights and computers will likely be a mix of electrons from

Generator B and many other generators, all using different fuels and technologies.

Consumer A will still receive power and Generator B will still be

paid. Problems with the transmission wires or multiple generator outages

would impede the ability of Consumer A to receive electricity, even if

Generator B were operating smoothly. Thus, a regional transmission grid is

like an ecosystem; everyone who uses it is affected by everyone else’s actions

(or failure to act).

To make matters even more complicated, electricity must be produced

and consumed in “real-time.” Electricity cannot be stored (although storage

technologies are now under development), and its generation and use by

consumers must be continuously balanced. Otherwise, blackouts can result.

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Distribution

The consumer does not receive power directly from the transmission system.

Bulk power transmission facilities carry electricity to local electric distribution

systems. Just as cars traveling on our interstate highway system need to

exit and travel on a system of smaller roads to reach their destinations, lower

voltage electric distribution systems interconnect with the bulk power transmission

systems in their regions.

These distribution systems bring electricity to industries, businesses and

residential customers. The wires at the very top of wooden utility poles in a

residential neighborhood are distributing electricity to customers. In many

cities and suburbs, electric distribution wires are buried in underground

conduits, eliminating the need for power poles. Utility workers gain access

to these wires through manholes (maintenance holes) that dot a typical city

street.

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The Various Industry

Players, Old and New

Number of

Electricity Providers

Federal Power

Agencies

0.3%

Investor Owned

Utilities

6.1%

Cooperatives

26.8%

Power

Marketers

5.2%

Publicly

Owned Utilities

61.5%

Publicly Owned Utilities 2,006

Investor-Owned Utilities 200

Cooperatives 875

The electric utility industry in the United States traditionally had three kinds

of electric utilities selling power at the retail level. Retail power is sold to the

final consumer (home or business), also known as the “end user” or “retail

customer.” There are also participants in the industry who sell power at the

wholesale level, involving the delivery to another wholesale entity or to a utility,

which in turn delivers it to end users. Utilities engage in wholesale power

transactions when they sell power to other utilities.

Investor-owned utilities

Investor-owned utilities (often called “IOUs”) are for-profit companies owned

by shareholders. Most are publicly traded. There are approximately 200 of

them, and together they serve 68 percent of electricity customers. Their

national trade association is the Edison Electric Institute (EEI).

Public power utilities

Public power utilities are not-for-profit electric utilities that are owned and

operated by states or political subdivisions of a state (cities, public utility districts,

and utility boards). There are about 2,000 of them (many of them very

small municipal utility systems). Together, they serve over 14 percent of the

nation’s end users. Their national trade association is the American Public

Power Association (APPA).

Federal Power Agencies 9

Power Marketers 171

Total 3,261

Rural electric cooperatives

Electric cooperatives are private, not-for-profit entities owned by the customers

they serve. Thus, they are not governmental entities (although they

are often referred to as “public power”), nor are they for-profit companies.

Approximately 875 cooperatives serve 13 percent of U.S. retail customers.

Their national trade association is the National Rural Electric Cooperative

Association (NRECA).

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Number of Customers

Full-Service Delivery-Only

Customers Customers Total

Publicly Owned Utilities 20,863,842 8,264 20,872,106

Investor-Owned Utilities 94,664,012 3,338,221 98,002,233

Cooperatives 18,286,337 12,793 18,299,130

Federal Power Agencies 39,045 4 39,049

Power Marketers 6,281,963 0 6,281,963

Total 140,135,199 3,359,282 143,494,481

Power

Marketers

4.4%

Publicly Owned

Utilities

14.5%

Cooperatives

12.8%

Investor-Owned

Utilities

68.3%

Delivery-only customers represent the number of customers in a utility’s service territory that purchase energy from an alternative

supplier.

Nearly all of power marketers’ full-service customers are in Texas. Investor-owned utilities in the ERCOT region of Texas no

longer report ultimate customers. Their customers are counted “as full-service customers of retail electric providers (REPs),

which are classified by the Energy Information Administration as power marketers. The REPs bill customers for full service

and then pay the IOU for the delivery portion.

Source: Energy Information Administration Form EIA-861. Does not include U.S. territories.

Federal electricity providers

The federal government produces electricity too and sells it to utilities at

wholesale and at retail to some large industrial customers. You may have

heard of the Tennessee Valley Authority (TVA), and the power marketing

administrations (PMAs)—the Bonneville Power Administration (BPA),

Western Area Power Administration (WAPA), Southwestern Power

Administration (SPA) and Southeastern Power Administration (SEPA). These

are federal government entities that generate and market power (mostly

hydro power from federal dams), some of which are operated by the Corps

of Engineers, and others by the Bureau of Reclamation. Under the applicable

federal statutes, these entities sell their power at cost-based rates (rates

that reflect the cost of producing the power), with a right of first refusal or

“preference” to public power and cooperative utilities. Because these entities

have a statutory priority claim to such power, it is often called “preference

power.”

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Utility Sector Rate Comparison by State, 2009 (cents per kilowatt-hour)

Residential Commercial Industrial

State Public Private Co-op Public Private Co-op Public Private Co-op

Alabama 9.0 10.9 11.8 9.3 10.1 11.4 7.2 5.8 8.3

Alaska 13.8 17.4 17.9 11.3 18.8 16.5 14.7 8.8 13.4

Arizona 10.3 10.9 12.5 8.6 10.2 10.9 6.0 6.9 8.5

Arkansas 8.2 9.6 8.6 7.4 7.5 7.9 6.1 6.2 4.6

California 12.6 15.4 14.7 12.1 14.0 14.9 10.1 11.0 10.4

Colorado 8.4 9.9 11.0 6.8 8.2 9.7 5.6 5.8 7.6

Connecticut 15.0 20.6 - 13.4 18.4 - 11.2 15.5 -

Delaware 15.1 14.4 12.3 15.5 13.7 11.3 12.1 7.0 -

District of Columbia 13.7 15.1 14.4

Florida 12.8 12.4 12.1 11.1 10.7 10.9 9.6 9.2 9.3

Georgia 9.3 10.1 10.2 8.8 8.7 10.0 6.0 6.0 6.7

Hawaii - 23.9 30.1 - 21.5 30.9 - 17.7 28.4

Idaho 6.0 7.9 7.8 5.7 6.5 6.8 4.5 5.3 4.3

Illinois 9.5 11.3 12.0 9.6 9.8 9.8 7.4 5.1 7.4

Indiana 9.3 9.1 10.9 8.8 8.2 9.5 7.3 5.6 7.3

Iowa 8.9 9.8 11.0 7.8 7.4 8.1 6.2 5.0 6.3

Kansas 10.3 9.0 11.1 8.9 7.4 9.3 6.0 5.8 7.4

Kentucky 8.3 7.6 9.4 8.4 7.2 9.3 6.6 5.6 4.6

Louisiana 7.8 8.2 7.8 7.7 7.7 7.7 6.5 5.2 6.6

Maine 14.7 16.0 29.1 12.1 12.2 22.9 12.2 - -

Maryland 10.8 15.1 14.3 11.2 12.7 12.1 9.1 9.3 10.3

Massachusetts 14.0 17.2 - 14.2 17.0 - 12.6 15.2 -

Michigan 9.7 11.7 12.4 8.9 9.3 10.2 7.6 6.9 7.5

Minnesota 9.8 9.9 10.2 9.0 7.7 8.4 7.1 6.0 6.9

Mississippi 9.3 9.6 10.9 9.5 8.8 11.1 7.5 6.4 8.4

Missouri 8.9 8.0 9.6 7.8 6.6 8.6 6.9 4.9 6.5

Montana 6.0 9.5 8.6 5.4 9.0 7.5 8.2 6.1 6.0

Nebraska 8.5 - 10.4 7.4 - 10.9 5.6 - 11.2

Nevada 8.5 13.1 10.3 6.4 11.3 8.7 2.8 9.0 4.4

New Hampshire 14.5 16.0 20.0 15.6 13.6 18.2 13.7 13.6 12.4

New Jersey 16.9 16.3 11.9 16.5 14.6 11.5 13.6 11.5 8.5

New Mexico 9.3 9.6 12.2 8.9 8.3 9.5 6.1 5.2 6.4

New York 16.4 17.5 11.5 16.1 16.3 10.0 4.5 10.7 8.3

North Carolina 11.5 9.3 11.4 9.5 7.5 10.1 7.5 5.8 6.3

North Dakota 6.5 7.6 7.6 6.4 6.8 7.5 6.8 5.6 5.2

Ohio 10.1 10.7 10.5 10.0 9.6 9.7 8.3 6.6 7.0

Oklahoma 8.9 7.9 9.8 8.1 6.3 9.0 5.9 4.5 5.6

Oregon 6.8 9.3 7.8 6.3 7.8 6.7 4.1 6.0 5.0

Pennsylvania 14.0 11.6 11.5 12.9 9.5 10.2 11.3 7.1 7.8

Rhode Island 15.2 15.6 - 16.8 14.1 - 13.8 12.8 -

South Carolina 9.3 10.0 11.7 8.6 8.4 11.0 5.6 5.7 6.9

South Dakota 8.0 8.6 8.5 7.6 7.4 7.7 5.9 5.4 5.7

Tennessee 9.2 7.7 9.6 9.5 7.9 10.3 7.3 5.4 7.7

Texas 9.5 9.0 11.0 8.4 7.7 9.9 6.7 5.1 7.9

Utah 8.6 8.6 6.7 7.8 6.8 6.8 6.3 4.6 6.3

Vermont 14.6 14.5 17.6 13.8 12.6 15.1 12.6 8.7 9.9

Virginia 9.6 10.3 12.6 8.5 7.9 10.9 7.2 6.5 9.2

Washington 6.6 9.1 6.9 5.8 8.7 5.7 3.9 6.9 5.0

West Virginia 8.4 7.9 13.8 8.4 6.8 7.7 6.4 5.2 27.9

Wisconsin 9.9 12.1 12.5 9.1 9.6 9.8 7.0 6.7 6.5

Wyoming 8.6 8.8 8.3 7.4 7.6 7.0 6.7 4.7 5.0

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Other Industry Participants

In the last 25 or so years, additional wholesale industry participants that specialize

primarily in one function have come on the scene. For example, independent power

producers (IPPs) are for-profit entities that develop and operate electric generation

projects, and sell the output to utilities and large end-users. This industry segment was

jump-started by provisions in the Public Utility Regulatory Policies Act of 1978

(PURPA), a federal statute that required traditional utilities in certain situations to buy

power from IPP generation projects. Their national trade association is the Electric

Power Supply Association (EPSA). Some marketers do not own generation, transmission

or distribution facilities, but buy and resell electric power and transmission/

distribution services to both utilities and end-users. To make things even more complicated,

many of these major IPPs and marketers are separate subsidiaries in the same

corporate family as one or more traditional IOUs. Financial services companies (for

example, investment banks and hedge funds) have also gotten into the act, buying

financially distressed generation assets from IPPs and buying and selling both electric

power and financial instruments related to electric power (futures, hedges, virtual

power transactions, congestion rights, etc.).

Top 20 Providers of Energy-Only Service

to Retail Customers, 2009

Sales

(megawatt-hours)

1 Constellation NewEnergy, Inc 41,791,327

2 Hess Retail Natural Gas and Elec. Acctg. 23,577,510

3 Sempra Energy Solutions 19,862,558

4 PEPCO Energy Services 17,665,819

5 New York Power Authority 14,258,689

6 Strategic Energy LLC 14,067,993

7 Suez Energy Resources North America 13,798,890

8 Consolidated Edison Sol Inc 12,158,013

9 “Integrys Energy Services, Inc.” 11,488,639

10 First Energy Solutions Corp. 10,723,065

11 Exelon Energy Company 10,164,885

12 MidAmerican Energy Co 10,091,756

13 Ameren Energy Marketing 6,250,979

14 Washington Gas Energy Services 5,893,058

15 TransCanada Power Mktg Ltd 5,317,439

16 Dominion Retail Inc 5,050,433

17 NextEra Energy Power Marketing LLC 4,154,840

18 Direct Energy Services 3,537,069

19 Hudson Energy Services 3,309,082

20 Coral Power LLC 3,142,003

Source: Energy Information Administration Form EIA-861, 2009 data.

Top 20 Power Marketers Selling at Wholesale, 2009

Sales for Resale

(megawatt-hours)

1 Morgan Stanley Capital Grp Inc 275,969,539

2 Coral Power LLC 224,915,139

3 Sempra Energy Trading Corp 224,307,000

4 Constllation Enrgy Commodities 211,743,538

5 Luminant Energy 138,963,124

6 Calpine Energy Services LP 138,772,940

7 JP Morgan 93,085,419

8 Edison Mission Marktg & Trdg Inc 70,380,760

9 PSEG Energy Resources and Trade 68,040,834

10 Reliant Energy Power Supply LLC 66,000,875

11 Cargill Power Markets LLC 62,270,049

12 PPL EnergyPlus LLC 62,216,621

13 DTE Energy Trading, Inc 53,260,839

14 Allegheny Energy Supply Co LLC 52,436,047

15 Dominion Energy Marketing Inc. 48,758,783

16 Merrill Lynch Commodities 41,961,267

17 Dynegy Power Marketing Inc 40,426,293

18 TransAlta Energy Marketing (U.S.) Inc. 38,820,678

19 FirstEnergy Generation Corp 36,424,451

20 Integrys Energy Services, Inc. 34,220,911

Power Marketers, Sales for Resale 2,240,060,264

All Entities, Sales for Resale 3,736,047,687

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Energy-Only Retail Sales by State (all utilities)

California 17,036,043

Connecticut

13,016,458

4,045,099

Delaware

Illinois

Maine

Maryland

Massachusetts

Michigan

Montana

Nevada

New Hampshire

New Jersey

New York

Ohio

Oregon

Pennsylvania

Rhode Island

Virginia

Washington

Washington, DC

4,046,710

3,049,501

1,479,099

1,921,917

11,132,458

12,952,626

2,311,843

11,021,219

1,940,367

876

5,025,314

8,631,716

26,626,682

24,625,087

21,436,132

62,893,852

62,432,480

0 10,000,000 20,000,000 30,000,000 40,000,000 50,000,000 60,000,000 70000000

Megawatt-hours

Excludes 51 million megawatt-hours produced by California Department of Water Resources on behalf of California investor-owned utilities.

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The Changing Structure of

the Electric Utility Industry

For more than a century, electric utilities were vertically integrated and were

monopoly providers of electricity in their service areas. Vertically integrated

utilities perform all three functions (generation, transmission and distribution)

and thus provide “soup to nuts” electric service to their industrial,

commercial and residential customers. IOUs, which dominate the industry in

terms of number of retail customers served and revenues earned, owned

most of the generation, transmission and distribution facilities.

Until the late 1990s, little competition existed in the industry for retail

customers. Because utilities usually had exclusive “service territories” granted

to them by the states in which they provided service, the customer’s geographic

location determined which utility sold power to the customer.

Utilities rarely competed for retail customers, although there was some competition

at the fringes of service territories for new customers. Competition

served primarily as a yardstick —customers of one utility might notice the

lower rates or better service provided by a neighboring utility and put pressure

on their own utility to measure up to that standard.

To prevent for-profit IOUs from using their monopoly status to charge

exorbitant prices in their exclusive territories, the IOUs are regulated by state

“public utility commissions” (PUCs) or “public service commissions” (PSCs).

Regulatory commissioners are appointed for limited terms or elected by popular

vote in their states. PUCs and PSCs, too, have a national trade association,

called the National Association of Regulatory Utility Commissioners

(NARUC). In most states, public power utilities are regulated locally, either

by an elected or appointed utility governing board or a city council. Rural

electric cooperatives are usually governed by a board of directors, elected by

the members of the cooperative, although they are also subject to PUC oversight

in some states.

PublicPower.org 19


The Changing Structure

of the Electric Utility Industry

Public policy changes in the 1990s encouraged abandonment of the traditional

vertically integrated utility company in some states. These changes

were based on the notion that electric utilities should no longer be regulated

monopolies and instead should be deregulated and face competition, just as

trucks, railroads and airlines did during the 1980s.

In fifteen states, including California, New York, Illinois, Maryland, New

Jersey, Pennsylvania and several New England states, end-use consumers

were allowed “retail choice”—that is, given the right to purchase power from

non-utility providers. In most of these states, the IOUs were required by regulators

to sell their generating plants and to purchase power from independent

generators or power marketers. However, not every state embraced these

changes. Utilities in many states in the Southeast, Midwest, Southwest and

Northwest still have IOUs that use the traditional vertically integrated model

to provide retail electric service to their end-use customers.

Virtually all public power and cooperative utilities use some form of vertical

integration to provide service to their end users. Some public power utilities

and cooperatives are large enough to own and operate their own generation

and bulk transmission facilities, like the IOUs. Other municipal and

cooperative distribution systems are too small to have their own transmission

and generation. Many of them have banded together to form umbrella entities

that build or purchase generation and transmission services for their

members. These “joint action agencies” (for public power utilities) and “generation

and transmission cooperatives” (for rural electric cooperatives) provide

generation and transmission services under long-term contracts to their

member distribution utilities, making them vertically integrated by virtue of

their contracts.

20 PublicPower.org


Federal Regulation

of Electricity Markets

State regulators approve rates for electric power and distribution services

provided to retail customers. The Federal Energy Regulatory Commission

(FERC), an independent regulatory agency located in Washington, D.C.,

regulates wholesale sales of electricity (“called sales for resale”) and interstate

transmission of electricity by “public utilities.” It does so under the Federal

Power Act of 1935 (called the “FPA”).

The FPA’s use of the term “public utility” to refer to the entities that

FERC regulates can be confusing, because it sounds so close to “public

power.” But FERC regulates primarily IOU wholesale sales and interstate

transmission service under the FPA. Public power utilities and most cooperative

utilities are subject only to limited FERC jurisdiction under certain FPA

sections, because they are not-for-profit entities. (So remember that FERCregulated

“public utilities” and “public power utilities” are not the same!)

FERC used to require the public utilities to sell wholesale power under

rates that reflected the cost of producing the power sold, plus a reasonable

profit, called a “rate of return.” (This is called “cost of service” regulation or

“cost-based rates.”) But since the early 1990s, FERC has increasingly relied

on competition in wholesale power markets to set prices.

It has therefore granted “market-based rate authority” to many sellers

of wholesale electric power, subject only to reporting and limited oversight

requirements. This allows electric generators to sell power at market prices.

Power suppliers are permitted to do this only if they can demonstrate that

there are an adequate number of competitors in the market and that no suppliers

have undue market power. FERC’s market-based rate policy has been

controversial, and FERC did re-examine several aspects of its policy in a

rulemaking.

FERC still generally requires IOU providers of transmission service (the

service of moving power over transmission lines, as opposed to the sale of

the power itself) to use cost-of-service pricing. Under this approach, utility

providers of transmission service recoup their costs of providing transmission

service plus a reasonable rate of return. In recent years, the Commission has

awarded a number of transmission rate “incentives” that increase the rate of

return or otherwise allow for collection of increased transmission revenue,

based on the premise that such incentives are needed to compensate these

entities for the risks of transmission investment.

PublicPower.org 21


The Bumpy Journey

to Restructured

Electric Markets

…in 1996, FERC

issues Order No. 888

and Order No. 889.

These landmark

actions directed the

owners of the nation’s

high-voltage transmission

lines to open

these highways for

electrons to third-party

customers at nondiscriminatory

rates.

The Energy Policy Act (EPAct) of 1992 sent the electric utility industry down

the road toward restructured wholesale markets. This process is often erroneously

called “deregulation.” That is a misnomer because regulators always

have and likely always will have a say in how electric power is generated,

delivered and priced. (For example, electric generating plants and transmission

lines must obtain siting and environmental permits before they can be

constructed or expanded.) But certainly wholesale electric rates, and in some

states, retail rates, are more lightly regulated than was once the case.

EPAct 1992 empowered FERC to order owners of transmission lines to

provide access to their lines by other wholesale users. Public power and

cooperative utilities, and large industrial customers, all urged Congress to

make this change so they would have more opportunities to purchase larger

quantities of wholesale electricity from a variety of sources and at lower rates.

Prior to this change in law, these utilities and large end-users who found less

costly sources of electric power often could not purchase it because they did

not own the transmission lines and the utilities that owned the lines denied

them access. These customers saw open access transmission service as a vital

part of a competitive electricity market.

Responsibility for implementing the transmission provisions of EPAct

1992 fell to FERC. But the commission decided that the case-by-case

approach called for under the 1992 law was too slow, so in 1996, FERC

issued Order No. 888 and Order No. 889. These landmark actions directed

the owners of the nation’s high-voltage transmission lines to open these highways

for electrons to third-party customers at non-discriminatory rates.

In Order No. 888, FERC required “public utility” transmission system

operators to file an “Open Access Transmission Tariff” (OATT). This OATT

set out generic terms and conditions for open access transmission service.

In Order No. 889, FERC told transmission owners to publish information

about rates and the transmission capacity available for third parties to use on

a real-time electronic bulletin board called an “OASIS” (open access sametime

information system).

22 PublicPower.org


FERC’s Order No. 888 OATT regime was a big step for regional wholesale

electric markets. OATTs have brought much better transmission access

to many wholesale buyers and sellers. In Order No. 888, FERC also encouraged,

but did not require, transmission owners to hand over the higher level

operating functions of their individual transmission facilities to a regional

organization—which FERC called an independent system operator (ISO).

FERC’s intent was that the ISO would operate the regional transmission network

independently of the various transmission system owners, simplifying

the regional transmission rate structure and ensuring non-discriminatory

access to the regional transmission system by third parties.

Many wholesale transmission customers wanted FERC to mandate public

utilities with transmission facilities to participate in ISOs, because they

believed such a requirement would be the only way to assure a competitive

transmission network. That tension between transmission “haves” and “have

nots” continues to plague the electricity markets today.

Some ISOs did form after FERC issued Order No. 888. There are currently

six FERC-regulated ISOs. (They are considered “public utilities” since

they provide transmission service over the interstate bulk power system and

operate wholesale power supply markets. Therefore FERC regulates their

transmission rates and service offerings.) The six ISOs are: ISO New England

(“ISO NE”); the New York ISO (“NY ISO”); the PJM Interconnection

(“PJM,” which covers the Mid-Atlantic states and some parts of the

Midwest); the Midwest ISO (“MISO,” which covers other parts of the

Midwest); the California ISO (“CAISO”); and the Southwest Power Pool

(“SPP”), which covers parts of Texas, Louisiana, Arkansas, Missouri, Kansas,

Mississippi, Nebraska, New Mexico and Oklahoma. (The Electric Reliablity

Council of Texas (ERCOT) also has an ISO, but since ERCOT does not

operate in interstate commerce, its ISO is not FERC-regulated.) But ISOs

did not form in all regions of the country, as FERC had hoped.

PublicPower.org 23


The Bumpy Journey to Restructured

Electric Markets

The ISOs

California ISO

Electric Reliability Council of Texas

ISO New England

Midwest ISO

New York ISO

PJM Interconnection

Southwest Power Pool

So in 1999, FERC issued Order No. 2000. This order required all FERC

regulated “public utilities” with transmission assets to disclose to FERC their

plans for joining a multi-state “regional transmission organization” (RTO). In

Order No. 2000, FERC set out a list of specific minimum characteristics and

functions that it wanted ISOs to meet. Those ISOs that FERC finds are carrying

out all of these functions are deemed to be full-fledged “RTOs.” FERC

did not make joining an RTO mandatory for public utilities; Order No. 2000

called on them to join RTOs on a voluntary basis.

Even after Orders No. 888 and 2000, however, many “public utilities” did

not join ISOs/RTOs. In 2002 FERC responded by issuing a new proposal,

called “Standard Market Design” (“SMD”). In its SMD proposal, FERC

finally sought to require all FERC-regulated “public utilities” to hand operational

control of their transmission facilities over to RTOs/ISOs. But the

SMD proposal did not meet with smooth sailing. Opposition to the mandatory

RTO requirement was so strong in some regions of the country, chiefly the

Southeast and Pacific Northwest, that FERC abandoned the SMD proposal

altogether in 2005.

The current wholesale electricity market is therefore a patchwork of different

entities and managements. Some regions have ISOs/RTOs, while others

still use Order No. 888-style individual OATTs. It is doubtful that additional

ISOs or RTOs will form in the rest of the country in the foreseeable

future—at least in the same mold as the existing ISOs and RTOs. This means

FERC has to deal with substantial variations in regional power supply and

transmission markets.

24 PublicPower.org


The Markets Operated

by ISOs and RTOs

Congestion and Locational Marginal Pricing

The formation of ISOs/RTOs turned out to be much more difficult than

FERC expected. Much of the controversy over ISOs/RTOs stems from their

operation of centralized power markets, and the use of spot power market

prices to manage “congestion.” Congestion occurs when transmission users

want to move more power than the transmission system can accommodate

at that point in time. (Think about a highway at rush hour, and imagine 20

trucks trying to make an immediate delivery to a single location accessible

only via one exit, and you get the idea.) The immediate solution to congestion

is to turn on additional, potentially more expensive, generators that are located

closer to load or can use uncongested transmission paths. (Go back to the

highway and imagine that the recipient of the goods decides to hire a nearby

taxi service with access to a traffic-free local road to deliver some of the

goods. The buyer will pay much higher costs for transporting those goods.)

Most RTOs manage congestion on their transmission systems by charging

a congestion fee on top of the base rate for transmission. (A base transmission

rate recovers the fixed transmission system costs of the various transmission

owners participating in the ISO, and the ISO’s own administrative costs.)

The congestion fee is based on the difference in spot market power prices

caused by the use of the more expensive generation to ensure that there are

sufficient electrons at the transmission customer’s desired point of delivery.

This congestion pricing system is known as “locational marginal pricing”

(LMP) because when there is transmission congestion, spot market prices

vary by the location of delivery and receipt of power. The conceptual basis

for LMP is that customers who pay higher congestion costs will have an

incentive to build or encourage the construction of new generation or additional

transmission capacity, or to reduce load through conservation or shifting

the times when energy is consumed.

Transmission customers of an RTO have some ability to hedge the congestion

fees they may incur moving power over the RTO transmission system.

RTOs using LMP offer some form of “Financial Transmission Rights” (FTRs)

or Congestion Revenue Rights (CRRs). These FTRs/CRRs can produce revenues

to offset the congestion fees the RTO charges a customer. These FTRs

vary in the revenues they produce, and often are limited to terms of a year or

less. Moreover, they are not necessarily a complete or “perfect” hedge against

congestion fees.

Think about a

highway at rush

hour, and imagine

20 trucks trying to

make an immediate

delivery to a single

location accessible

only via one exit, and

you get the idea.

PublicPower.org 25


The Markets Operated

by ISOs and RTOs

Energy and Ancillary Services

The RTOs operate day-ahead and real-time spot power markets (which they

use to obtain the locational prices for transmission congestion charges.) The

prices for power in these markets are set every hour based on the bids that

sellers submit to the RTO. (Note that these bids need not reflect the sellers’

own costs of generating the power. Rather, the bids are set by the sellers,

unless the prices they bid trigger certain “market mitigation” thresholds set

by the RTO.) The RTO takes all bids in ascending order and stops with the

last bid needed to supply power to buyers in that time interval. The price all

sellers in that time interval receive, however, is the last bid the RTO accepted.

This market design is known as a “single clearing price” market.

RTO markets with these features (LMP-based pricing of transmission congestion

and single-clearing price spot markets) are called “Day 2” markets.

(SPP has not yet implemented a “Day 2” market, although it has announced

plans to transition to this market structure at a future date.)

In addition to energy markets, RTOs ensure the provision of or operate

markets for “ancillary services,” which are additional services needed to support

the delivery of energy and ensure reliable operation of the system.

There are two general categories of ancillary services provided by RTOs: regulation,

which are short-term adjustments in generation to meet actual load

on a continuous basis, and operating reserves, which is backup power available

to meet shortfalls in capacity during emergencies or unexpected variations

in load.

Capacity Markets

Several RTOs also operate what are known as “capacity markets.” The intent

of these markets is to provide revenue to recover the capital cost of constructing

generation and to ensure that there is sufficient generation capacity

standing by to provide power when needed. Capacity payments are paid to

generators standing ready to provide power and to providers of demand

response, which is an agreement by a customer to cut back on its demand for

power when needed. These capacity markets also operate on a single-clearing

price basis. Two of them (PJM and NY ISO) establish different capacity

prices for certain geographic zones where transmission congestion limits the

amount of capacity imports.

26 PublicPower.org


PJM and ISO NE operate centralized mandatory capacity markets that

procure capacity three years in advance of when it is needed. MISO, CA ISO

and NY ISO have voluntary capacity markets intended to supplement capacity

procured through contracts. MISO is developing a proposal to FERC for a

mandatory centralized capacity market. The CA ISO to date has decided not

to implement a centralized capacity market.

Demand Response

Another area of increased emphasis in the last few years has been the integration

of demand response into the RTO markets. Demand response occurs

when factories, businesses, or groups of home owners agree to cut back on

their electricity consumption during peak periods or when there is a shortage

of supply resulting from high demand or unit outages. The use of demand

response can reduce the cost of producing electricity because more expensive

peaking plants do not have to be run, and the construction of additional

plants can be avoided. RTOs generally pay for demand response either

through energy markets where customers voluntarily reduce their consumption

during times of high prices, or through capacity markets where customers

must agree in advance to cut use when called upon. Demand

response selling in the capacity market is often referred to as “emergency

demand response” because the demand response could be utilized during

periods when there is a shortage of supply.

Aggregators of retail customers (ARC) are third-party agents that aggregate

the demand response of individual retail customers. ARCs then sell the

aggregated demand response to utilities, RTOs and ISOs. (ARCs that resell

demand response are also known as curtailment service providers or “CSPs”.)

PublicPower.org 27


The Markets Operated

by ISOs and RTOs

Bilateral Contracts

Not all utilities located in RTO and ISO regions pay the prices set in RTO-run

centralized power markets. A number of them purchase power under bilateral

contracts, whereby the utility pays a generator a fixed price (or a price that

fluctuates with the spot market or fuel costs) to deliver the power the utility

needs to serve its customers. In RTO regions, the majority of bilateral contracts

involve sales in retail choice states by IOUs that must provide power to

their customers who have not chosen an alternative provider. Because these

utilities no longer own generation, they must purchase power, commonly via

shorter term contracts of one to three years. Under bilateral contracts, the

utility still pays administrative, transmission and congestion prices charged

by the RTO. Public power systems and cooperatives, as well as IOUs in states

that did not mandate retail access, but are in RTO regions, also often use

bilateral contracts to meet some portion of their power supply needs.

28 PublicPower.org


Meet the ISOs

PublicPower.org 29


California Independent

System Operator

Began ISO operations

1998

States

California (but interconnected with neighboring states)

Basic facts

25,526 circuit miles of transmission lines.

$6.4 billion in revenue.

286 billion kilowatt-hours

of power delivered.

1,300 power plants and 54,436 MW

of capacity.

Markets Operated

Day-Ahead, Hour-Ahead, and Real-Time

energy markets using locational marginal

pricing.

Congestion Revenue Rights

for hedging congestion costs.

Capacity Procurement Mechanism

(CPM) for voluntary capacity

procurement.

Ancillary Services markets:

Regulation and operating reserves

A Residual Unit Commitment (RUC)

market procures capacity to make up for

differences between the amount cleared

in the day-ahead market and the dayahead

load forecast. RUC capacity must

be bid into the real-time market.

Governance

Five-person independent board of directors nominated by the governor and confirmed

by the state Senate, serving staggered three-year terms.

Source: www.caiso.com

30 PublicPower.org


ERCOT

(Electric Reliability Council of Texas)

Began ISO operations

1996 (Texas utilities interconnected during World War II to support war needs. In

1970, the Texas Interconnected Systems formed ERCOT to meet North American

Electric Reliability Council requirements. In 1996 it became the nation’s first ISO.)

States

Texas (ERCOT serves 75% of the land area in Texas and 85% of the state’s load.)

ERCOT facilities are not interconnected with transmission lines in other states, so the

ISO is not regulated by the FERC, except for reliability purposes.

Basic Facts

40,327 miles of transmission.

$34 billion annual revenue.

About 800 active market participants.

550 generating plants and

84,237 MW of capacity.

Markets Operated

As of December 1, 2010, ERCOT

changed its locational marginal pricing

structure from the determination of

prices at a small number of zones to pricing

at 4,000 different nodes, known as

“nodal pricing.”

Operates Real-Time and Day-Ahead

Markets for energy, and a Day-Ahead

market for ancillary services. (Prior to

December 2010, ERCOT did not have

a Day-Ahead market.)

Ancillary Services:

Short-term balancing services and

operating reserves.

Day-ahead and hour-ahead reliability

unit commitments are required.

Congestion Revenue Rights as a hedge

against congestion costs.

Governance

16-member “hybrid” board of directors, elected by ERCOT members, that includes six

electricity market participants from each sector, three consumer representatives, five

independent (unaffiliated) members, the ERCOT CEO and the Texas Public Utility

Commission chair (non-voting.)

Source: www.ercot.com

PublicPower.org 31


ISO New England

Began ISO operations

1999 (Formed in 1972 as New England Power Pool to facilitate economy energy

exchanges. Renamed ISO New England in 1997 and began operating regional wholesale

power markets in 1999. Became a FERC-certified RTO in 2005.)

States

Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont

Basic Facts

Over 8,000 miles of transmission.

Annual revenue of $9 billion.

More than 400 market participants.

More than 300 generating units and

31,440 MW of generating capacity.

Markets Operated

Day-ahead and Real-time energy markets

with locational marginal pricing.

Financial Transmission Rights to provide

a hedge against congestion costs.

Forward capacity market (FCM) for

generators, demand-response and energy

efficiency, without locational pricing.

Ancillary Services markets:

Forward and real-time operating reserve

markets; and regulation service.

Demand response programs:

Real-time reliability demand response

where the ISO can order curtailment

within 30 minutes or two hours.

Real-time price response, where

participants voluntarily reduce load

during high price periods.

Day-ahead load-response in which

participants can bid demand response

into the day-ahead markets and receive

payments if the demand response clears

the market.

Governance

Independent 10-person board of directors, including the president and CEO (non-voting).

Board members are elected by a majority of the existing directors.

Source: www.iso-ne.com

32 PublicPower.org


Midwest Independent

System Transmission

Operator

Began ISO operations

2002 (MISO was formed in 1996 and began selling transmission service in 2002. In

2001, it became the first FERC-certified RTO.)

States

All or parts of Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri, Montana, North

Dakota, Ohio, Pennsylvania, South Dakota, Wisconsin and Manitoba, Canada.

Basic Facts

55,090 miles of transmission

$23 billion annual revenue

347 market participants

159,000 MW of generating capacity

Markets Operated

Day-ahead and real-time energy markets

using locational marginal pricing.

Financial Transmission Rights that allow

participants to hedge congestion costs.

Ancillary services markets:

Regulation and contingency reserves.

(Implemented in January 2009.)

Voluntary capacity auction for residual

capacity needs. (Initiated in June 2009.)

Governance

Independent seven-person board of directors, elected by MISO members, plus the

president and CEO.

Source: www.midwestiso.org

PublicPower.org 33


New York Independent

System Operator

Began ISO operations

1999 (New York Power Pool was created in 1966 following the Northeast blackout of

1965. The Power Pool responsibilities were transferred to the newly created NY ISO in

1999.)

States

New York (but interconnected with neighboring states)

Basic Facts

10,900 miles of high-voltage

transmission lines.

$11 billion in annual revenue.

About 400 market participants.

More than 500 generating units, and

37,416 MW of generating capacity.

Markets Operated

Real-time and day-ahead energy markets

with locational marginal pricing.

Ancillary Services markets:

Operating reserves and regulation.

Locational capacity market for capacity

not procured through bilateral contracts.

Capacity is procured six months ahead of

need, one month ahead and in real time.

Transmission Congestion Contracts purchased

to hedge congestion costs.

Demand response:

Voluntary emergency

load-curtailment program.

Mandatory emergency demand

response in exchange for capacity market

payments.

Demand response bids into the

day-ahead energy market and ancillary

services market.

Governance

10-person independent board of directors, including the NY ISO president and CEO,

elected by existing board members.

Source: www.nyiso.com

34 PublicPower.org


PJM Interconnection

Began ISO operations

2001 (Formed in 1927 as a tight pool for economy energy exchanges. Began operating

wholesale markets in 1997. Granted provisional RTO status in 2001 and final FERC

approval in 2002.)

States

All or parts of Delaware, Illinois, Kentucky, Maryland, Michigan, New Jersey, North

Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of

Columbia.

Basic Facts

56,350 miles of transmission lines.

Annual billing of $26.6 billion.

More than 500 market participants.

163,500 megawatts of

generating capacity.

Markets Operated

Real-time and day-ahead energy markets

with locational marginal pricing.

Ancillary Services:

Regulation market; synchronized reserves

(available within 10 minutes) and dayahead

scheduling reserves to provide

supplemental 30-minute reserves.

Forward locational capacity market,

known as the Reliability Pricing Model

(RPM), for generation, demand-response

and energy efficiency. Capacity is procured

three-years ahead of time.

Demand response:

Voluntary program where load is reduced

in response to prices.

Demand response participates in the

synchronized reserve market.

Emergency demand response where load

is required to curtail when called upon.

Governance

10-person independent board of directors, including the CEO, elected by the Members

Committee.

Source: www.pjm.com

PublicPower.org 35


Southwest Power Pool

Began ISO operations

1997 (Formed in 1941 to serve war needs. In 1968 joined 11 other regional reliability

councils to form National Electric Reliability Council. FERC-certified RTO operations

began October 1, 2006.)

States

All or parts of Arkansas, Kansas, Louisiana, Mississippi, Missouri, Nebraska, New

Mexico, Oklahoma and Texas.

Basic Facts

50,575 miles of transmission.

$1.63 billion in annual revenue.

196,301 GWh of energy

consumed annually.

847 generating plants, and 66,175 MW

of generating capacity.

Markets Operated

Energy Imbalance Service (EIS) market

for the purchase and sale of power in

real-time.

SPP plans to implement day-ahead

energy and ancillary service markets.

Governance

7-member independent Board of Directors, including the president, elected by SPP

members.

Source: www.spp.org

36 PublicPower.org


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Suite 1200

Washington, DC 20009-5715

202.467.2900

www.PublicPower.org

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