NATIONAL CENTER FOR POLICY ANALYSIS
Turning on the Lights 2010
Compete for the Solution: finishing the electricity restructuring task
By Carl Johnston, Lynne Kiesling, Bob Crandall
Preface
Predicting future electricity rates, load levels and fuel costs is perilous. It is even more
difficult to forecast secondary effects like technology and environment restrictions that
have considerable effect on the cost of electricity and the need to invest in new
generation and transmission equipment. This difficulty of predicting future trends in
prices, the economy, technology and regulation is a key reason why regulation by central
planning was not successful in the 1960s and 1970s. The assumptions used to determine
“the right” resources usually prove to be wrong. Customers are forced to shoulder the
costs of major investment mistakes.
More recent experience with competitive markets demonstrates that competition
improves operating performance and utilization of existing infrastructure. Markets do a
better job of attracting investment capital while shielding customers and taxpayers from
investment risk.
As this report will show, prices under a restructured system better reflect costs, and
statistically, are likely to make prices better than they would have been under a regulated
market during a period of declining energy prices. It is true that the nation has
experienced an electricity price spike over the last several years. In real terms, electricity
prices are still below where they were in 1985.
Aside from keeping industry efficiency high, and costs and prices low, there are many
other reasons for continuing the process of electricity market restructuring that began
nearly 20 years ago. Future improvements in energy efficiency, independence, jobs and
overall economic benefit require restructured and competitive markets to expand. Done
properly continued restructuring will help innovators create a wide range of new
businesses on the emerging energy network known as the Smart Grid.
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Freeing electric power: An introduction to the future of the industry
1960s 70s 80s
Power users, a vision of dynamic industry serving consumer values
Crucial Role of Competitive and Flexible Bulk Power Markets
Today, the U.S. is in a technological revolution in electricity generation and delivery. The
changes are just as vast as those that motivated Edison. They are as profound as those
that transformed the 1960s-era standard black dial telephone into today’s Internet-based
mobile and fixed line digital computing and telecom technology.
An abundance of new, environmentally safe technologies (such as solar, wind, and
others) will permit consumers to buy electricity from utilities, or sell it back on the Grid.
Decentralized power management controls (such as a thermostat that turns the air
conditioning down when power prices are high) will help everyone monitor costs, shop
for the best prices, waste less and save resources.
Electricity may well become the fuel replacement of choice for high-performance automobiles. It can
compete directly or coupled with gasoline and diesel to power many types of transportation. This would
make the U.S. less dependent on foreign oil and help the environment. An electric grid with Distributed
Generation1 will be less prone to sabotage and accidents. When catastrophes occur, damage will be less
and recovery quicker.
Integration of Bulk power and Retail Price Signals
New technologies by themselves will not help consumers. This technology revolution
requires smooth-functioning power markets to drive new products to buyers. Transparent
pricing of both bulk power and retail electricity can produce huge benefits.
Clear pricing in wholesale markets linked to meaningful feedback from retail markets
creates the clearest incentives for generators to operate at greatest efficiency with lowest
cost fuel.
1
A power grid in which generators are located close to the particular load that it is intended to serve. General,
but non-exclusive, characteristics of these generators include: an operating strategy that supports the served load;
and interconnection to a distribution or sub-transmission system (138 kV or less)
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Linking bulk power markets to retail prices helps consumers to purchase electricity
power in the most efficient way. It will open markets to new products and services
consumers want. And it will allow consumers to benefit from the choices they make.
Consumer Driven Values
Much of this report will focus on public policy issues and the relationship between public
policy and uses in the electric power industry. Fundamentally, our interests lie in helping
energy consumers get the electric power they want on the best terms practical.
Consumers are diverse. Some consumers want reliable power—one aspect of
convenience—even at high cost. Others will accept somewhat less reliability to get
cleaner, safer, or cheaper power. A focus on consumers requires us to acknowledge that
the “best terms practical” is not a singular goal. Electricity markets should be free to
serve the whole range of personal preference and economic value. Associated profit
opportunity from product differentiation aimed at home buyers and all other types of
consumers will create a pay-off for producers who make the extra effort required to
differentiate power products and consumers who buy them.
A Brief History of Electric Power in the United States.
To fully understand the issues facing the modern electric power industry and form well
thought out policies to help the industry better satisfy consumer demand, we must first
explore the history of the electric power industry in the United States.
Thomas Edison believed invention and competition were strongly linked. “I can only
invent under powerful incentive,” Edison said, “No competition means no invention.”2
The early history of the electric power industry seems to support Edison’s views.
Competition was everywhere in the at the beginning of the industry: Edison was in fierce
competition to develop a practical light bulb, and at the same time developing generators,
power systems, and the business practices necessary to allow an industry to grow.
2
Robert Conot, A Streak of Luck, Bantam Books (1980), quoted in Richard Munson, From Edison to Enron, Praeger
(2005), p. 18.
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Electric lights competed against kerosene lamps, whale oil lamps, and natural gas fixtures
as the power industry tried to get off the ground.
Perhaps Edison’s grandest design, that for large, central-station power plants intended to
serve the surrounding community, competed against buyer-specific systems developed by
George Westinghouse. Edison’s central-station model, as implemented by Samuel Insull,
prevailed and became the industry standard, versus Westinghouse’s view of fairly standalone generating stations serving discrete buyers. Edison lost out in the larger debate
about whether the country should adapt his own Direct Current (DC), or Westinghouse’s
more volatile but flexible Alternating Current (AC). But Edison remained a believer in
competition.3
Indeed, at the beginning of the 20th century, numerous competing electric utilities served
most large cities. Electric power service was growing in popularity and prices were
falling. The competition was hectic, even chaotic, as the industry grew rapidly. During
this time devices from the light bulb to electric washer to motion picture camera to radios
and electric trolleys, which were an part of the early electric industry and a deep
influence on the way cities were built.4
Local electric companies were not always monopolies - firms with the power to make money by
restricting production and raising prices. Before 1910, the United States had competing local
electric companies:10

In 1887 alone, six electric companies organized in New York City.

By 1907, 25 electric companies were operating in Chicago.

Duluth, Minn., had five electric lighting companies operating before 1895, and by 1906,
Scranton, Pa., had four.
3
Munson, pp. 18-42.
Much of this section is borrowed from Vernon L. Smith and Stephen Rassenti, “Turning on the Lights:
Deregulating the Market for Electricity,” National Center for Policy Analysis (1999).
4
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
As late as the 1930s, Cleveland and Columbus, Ohio, each had direct competition between
two private electric companies.
"Local electric companies were not always monopolies."
Furthermore, power generating capacity was widely dispersed and broadly owned. Thus in 1900
over 59 percent of electricity-generating capacity in the United States was located at industrial
sites.11 Electricity production surged from 4.5 million to 17.2 million megawatt hours between
1900 and 1910 while prices fell by more than 26 percent, and because of competition, consumers
benefited from new services - offered without government help or mandates. For example:

Private companies began offering electric trolley service, balancing out the nighttime demand
for electricity with a daytime market.

Unlike the regulated natural gas utilities, which offered service for a fixed monthly price, the
electric industry introduced metering and pricing based on usage.

Through voluntary teamwork, a committee of the Institute of Electrical Engineers found ways
to standardize electrical machinery, which lowered costs and improved service.

The National Board of Fire Underwriters, a private insurance association, helped develop
safety procedures
Then, in 1907, the idea that electric power utilities should be granted protected
monopolies with rates regulated by the state began to be implemented in state law. First
in New York, Massachusetts, and Wisconsin, but then two-thirds of the states adopted the
state regulated monopoly model for electric power by 1914, and by 1920 most of the rest
of the states had followed.5
Over the next fifty years existing technologies improved slowly, but steadily; electric
companies grew, and regulated rates tended slowly down. But the industry saw little in
the way of the revolutionary uses that characterized its early years. As competition was
squeezed out of the electric power business, much of the inventiveness drained away as
well.
5
John E. Kwoka, Jr., Power structure: ownership, integration, and competition in the U.S. Electricity Industry,
Kluwer Academic Publisher (1996).
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Early Regulation and Reforms
For most of the last century, major decisions and new directions were pursued within the
electric power industry’s complex regulatory review process. Consumer interests were
not neglected in regulatory processes. But regulatory process naturally mixes consumer
interests with government bureaucracy, industry lobbying and other interest groups
wheeling-and-dealing in ways which drive the industry away from a buyer focus.
With its emphasis on due process and consensus-based politics, regulation has proven
particularly awkward for innovators during periods of rapid changes in consumer values
and economic conditions. For example, the period from just after the beginning of utility
regulation until about 1970 comprised the era of Classic Regulation. During much of that
period, the industry was growing, prices were falling and profits were increasing. Utility
regulation, perhaps best suited for managing “business as usual,” had a harder time
managing an industry that needed to change. Classic Regulation began to have problems
with the combination of growing environmental interests in the 1960s and the price
growth and other economic dislocations of the 1970s.6
End of an Era
“The ultimate effect of … rising fuel costs, capital cost escalation and environmental
concerns and demand uncertainty—and the policymakers’ response to them was to create
an unmitigated disaster for electricity consumers and utility shareholders,” wrote
Huntowski, Fisher and Patterson. They note that between 1970 and their peak in 1985
nominal electric rates rose by more than 300%, while real rates rose 60%, to a level that
has not been seen before or since.7
6
Munson (2005), Ch. 3, 4.
Huntowski, Frank, Neil Fisher, and Aaron Patterson, ‘Embrace Electric Competition or It's Deja Vu All Over Again’,
The NorthBridge Group, 2008.
7
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Ensuing upheavals, in particular the OPEC oil embargoes and fuel shortages, caused the
federal government to reconsider all energy policies, including the Classic Regulation
regime . Over time, this process led to the creation of federally supervised bulk power
market reforms as well as the beginnings of consumer choice in retail markets and the
creation of a whole new class of competitive merchant generator companies that
competed directly with big utilities.
When a growing interest in environmental issues in the late 1960s ran into the price
growth and petroleum-based energy shocks of the early 1970s, the rigidities inherent in
then-current regulatory practices made it hard for the industry to keep up. The cultural
and economic changes were hard on all capital intensive industries, but the regulated
electric power industry was especially hard hit. The period could be called the end of the
Classic Era for the electric power industry.8
8
Munson (2005).
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Shifts in values – increasing attention to environmental impact of electricity
generation and consumption
In the 1960s and 1970s, the industry began to discover that buyers differ in their values in
ways relevant to their energy supply and consumption patterns. Some consumers
preferred their electricity to have a high renewable energy content; others placed a higher
premium on power quality and reliability, and still others simply preferred low cost.
Also, consumers began to sense major problems in utilities’ capital investment choices.
During good times, rate base or cost of service regulation (guaranteeing investors a return
established by political concerns and not economic efficiency) resulted in a great deal of
spending on plant and equipment that was hugely expensive (for example, nuclear
plants), and not efficiently run—this is a widely observed phenomenon known as the
Averch-Johnson effect.9 Regulation also failed to correctly predict inflation and
consumer trends.
When energy prices surged in the 1970s, resulting in high inflation and a stagnant
economy, it undermined all of the good faith assumptions made by utilities to support
nuclear construction. In 1979, when the Three Mile Island10 facility in Pennsylvania
nearly melted down, costs of nuclear construction soared making other investments in
atomic power uneconomic. Oil prices actually fell instead of rising as forecast; inflation
was higher, and demand growth slower than projected. Natural gas turned out to be
plentiful, cheap and well-suited for electricity production—whereas before it had been
illegal. New generator designs made natural gas even more efficient, and competitive
with coal and nuclear for some applications. The economics of the power industry began
to unravel and utilities credit ratings plunged. Public Service Co. of New Hampshire
(which built the Seabrook nuclear power plant) went bankrupt.11
* http://www.nbgroup.com/publications/Embrace_Electric_Competition_Or_Its_Deja_Vu_All_Over_Again.pdf
The Averch-Johnson effect occurs when a company’s profits to capital ratio is regulated at a certain percentage.
The company then has a tendency to invest in excessive amounts of capital accumulatio in order to boost profit.
This was frequently the case in regulated utilities.
10
“Three Mile Island accident - Wikipedia, the free encyclopedia,” n.d.,
http://en.wikipedia.org/wiki/Three_Mile_Island_accident.
11
John Rowe, Conference on Competition in Wholesale Energy Markets, 2007.
9
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When the energy crisis of the 1970s kicked off a round of record-high price growth, Rateof-Return regulation actually created incentives for investors to back out of utility
investments just at the time that they should have been spending on more efficient
equipment.
Deregulation of Airlines, Gas, Telephone Industries …
To this story should be added the examples provided by deregulation in other network or
utility-type industries, including natural gas, telecommunications, airlines, trucking, and
railroads. A survey of the deregulation experiences in these industries concluded that
competition after deregulation, while not necessarily perfect, was far better for consumers
than economic regulation had been. In each of these industries, a survey found prices at
least 25 percent lower than pre-reform prices within ten years after deregulation.12 There
was a strong presumption that restructuring electric power would lower prices for power
consumers and promote buyer-oriented innovation, too.13
a) PURPA and emergence of independent power
Historical studies of restructuring in electric power often trace the beginnings of the
process to the Public Utilities Regulatory Policy Act of 1978, which guaranteed a small
market for the output of certain independent power producers14 and led to the emergence
of numerous non-utility generation companies. Independent Power Producers could be:

An industrial company that makes electricity for use in its factory;

An owner of a small generator who sells power into the grid at peak hours when
the system needs extra power—for example on a hot summer afternoon.
12
Robert Crandall and Jerry Ellig, “Electric restructuring and consumer interests: lessons from other industries,”
The Electricity Journal, Volume 11, Issue 1, January-February 1998, Pages 12-16. See also Crandall and Ellig,
Economic Deregulation and Buyer Choice: Lessons for the Electric Industry, (Fairfax, VA: Center for Market
Processes, 1997).
13
Crandall and Ellig also emphasize that post-reform competition bring benefits other than lower prices. They said
post-reform competition had spurred “waves of entrepreneurial ingenuity that we simply do not find in highly
regulated industries.” (1998, p. 16)
14
Independent Power Producer: a corporation, person, agency, authority, or other entity with a facility for the
generation of electricity for use primarily by the public, and that is not an electric utility.
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
An investor-owned generation facility that sells power primarily for public
consumption—but is not a public utility.
EPACT of 1992
As the bulk market grew, and as transmission-dependent utilities increasingly sought
access to new suppliers, political pressure mounted to allow non-utility buyers and sellers
of power access to the transmission grid. The non-utility market got a boost with the
Energy Policy Act of 1992, which allowed the FERC to open bulk power markets15 for
competitive purposes. FERC eventually adopted rules (Orders 888 and 889) requiring all
utilities owning transmission lines to provide open and equal access to all electricity
generators. The EPAct also gave FERC the authority to open transmission lines to
competing electricity providers, even when they competed with the incumbent
transmission owner’s own generation.16 Bulk power marketers and brokers began to do
business.
FERC also created a number of regional regulators, called independent system operators
(ISOs)17 to operate and monitor these growing new markets and the new “merchant”
class of generation dependent upon markets, rather than captive buyers, for the returns
needed to justify investment. Bulk power markets were formalized late in 1999 when
FERC encouraged all participants in the power markets to join a Regional Transmission
Organization (RTOs) with FERC Rule No. 2000.18
15
Defined by EIA as: The wholesale sale, purchase, and interchange of electricity among electric utilities. Bulk
power transactions are used by electric utilities for many different aspects of electric utility operations, from
maintaining load to reducing costs. Bulk power markets evolved from informal voluntary markets, or power pools,
where utilities traded large quantities of power over high voltage lines in order to meet reserve requirements.
16
Today, the FERC approves rates for bulk power sales of electricity and for electricity transmission in interstate
commerce for investor-owned utilities, merchant power generators, power marketers, power pools, power
exchanges and independent system operators (ISOs) It reviews rates set by the federal power marketing
administrations.
17
ISO’s are defined by FERC as: An independent, Federally regulated entity established to coordinate regional
transmission in a non-discriminatory manner and ensure the safety and reliability of the electric system.
18
http://www.ferc.gov/legal/maj-ord-reg/land-docs/RM99-2A.pdf
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Early state efforts
Congress had already provided the legal changes in the Energy Policy Act of 1992, and
FERC Orders 888 and 889 established open access transmission rules to govern thirdparty use of the transmission grid.19
Congressional efforts to open the transmission grid to support third-party access turned a
small flame of bulk power competition into a bonfire. A broad-based coalition of large
industrial buyers, transmission-dependent cooperative and municipal utilities, and
independent power producers seized the opportunity to begin doing more business with
each other. While the terms surrounding transmission access and bulk power change
remained unsettled for a time, the industry rapidly embraced more competitive bulk
power markets.
States were slower to embrace regulatory reform affecting the retail market. High-cost
California led the way in 1996, when state legislators blessed a reform plan with
unanimous votes of support. Several years of debate in many of the 50 states and in the
District of Columbia led to about half of the states experimenting with at least
preliminary reform of retail regulations of the electric industry.
Background on deregulation/restructuring debate in c. 1997
Bulk power markets subject to FERC authority were allowed to grow more or less
organically. But retail markets were subject to the utility laws in each state, making it
impossible to create a uniform restructuring plan for retail markets. All states agreed that
serving consumer interests was the main objective in any restructuring of the electric
power industry. The big debate was about how to serve those interests:
Entrepreneurship…Free markets permit investors to channel the vast wealth available
in the world markets to efficient energy production and transmission without saddling
electricity end-users with the costs of investment mistakes. Competition among power
sellers is the best way to control prices. Investors can also implement the range of new
technologies that are on the horizon including renewable energy, decentralized
19
http://thomas.loc.gov/cgi-bin/bdquery/z?d102:HR00776:@@@D&summ2=m&
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generation, and computerized electricity management, sale of electricity as fuel for
automobiles and other new uses.
…Or maintain the classic regulatory environment Some believe that they are better
off with the 100-year-old regulatory model with vertically integrated utilities, guaranteed
return on capital investment and regulated pricing. This model might still work for some
now. Nevertheless, we know that restructuring has been popular where states applied it
properly and consistently.
Moreover, deficiencies of Classic Regulation, such as rate-of-return regulations20 on
investment returns and bureaucracy, were the reasons why restructuring began in the first
place. Classic Utility regulation in the price growth-driven 1970s caused much waste and
inefficiency. Any rapid economic change today that outpaces bureaucratic processes,
such as a return of price growth, would cause the same problems today that occurred in
Classic Regulation systems 40 years ago.
Chapter 2: In 1999 Smith-Rassenti Write “Turning on the lights”
The essential debate as of 199921
The difference between proponents of restructuring and its opponents boils down to a
deep disagreement about how businesses should treat costs. Restructuring opponents
argue that the “fair” way to divide the costs of electricity among ratepayers is by simple
division—everyone should pay their share of the “Average Cost”.
Economists and those who support restructuring, however, argue that this leads to
inefficiencies when new technologies emerge or costs ebb and flow. Average prices look
back into history to see what ratepayers should pay. Marginal prices foresee the future as
they look at what goods cost now. In a dynamic environment, marginal pricing works
best. This does not imply that prices should always equal marginal costs in free market
infrastructure industries. Marginal pricing still involves the wholesale and retail sellers
20
Rate-of-Return Regulation is when the regulator limits net operating income earned to a certain percentage of
the utility’s rate base.
21
Smith and Rassenti, Turning on the Lights (1999)
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charging prices that are sufficient to enable them to cover their fixed costs. Rather, we are
referencing the market’s ability to keep participants from using market power to boost
prices well over market costs and charging extremely high prices known in the industry
as “scarcity rents.”
Without marginal prices, ratepayers always shell out either too much or too little. Utilities
always have either too much or too little money to spend when planning. The only people
who benefit are bondholders who receive a regulated investment return equal to average
cost of an investment plus a little profit. And even they become unhappy during times of
fast rising prices.
There are other problems with regulation. Cost-plus accounting gave power companies
the incentives to build infrastructure they did not need—the more expensive the better. In
the Classic Era of regulation through the 1970s, utilities made costly investments in
nuclear power plants and sank a lot of money in doomed fusion projects, but they ignored
consumer preferences. And they neglected investment in things like power transmission
lines that were more urgently neeed but were also politically more difficult to implement.
Smith-Rassenti proposed model
Gradually, the industry began looking for solutions. Energy companies began trading
electricity in voluntary bulk power markets in the 1980s. As discussed, regulatory
reforms expanded these markets in the early 1990s. Various analysts suggested efficient
designs for the markets and began to speculate about what a market-based industry would
look like.
In “Turning on the Lights,” a 1999 report written by professors Vernon Smith, who won
a Nobel Prize in economics three years later, and Stephen Rassenti, the professors
suggested reforms intended to lead to a competitive market. It would resolve many of the
contradictions and faulty incentives in the Classic Regulatory system.
Specifically, Smith and Rassenti called for removing all barriers between consumers and
generators of electricity. Vertically integrated utilities would be split, with the utility
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choosing whether to sell their generating capacity or their transmission wires with the
result that two discrete kinds of businesses would be formed:

“Supply” companies involved in power generation;

“Wires” companies, i.e. the former integrated utilities minus their generating
capacity. They would continue to operate a competitive distribution business and
a monopoly in transmission over the electricity ‘grid.’
Divestiture would force generators (the former utilities and new shareholder-owned
“merchant” generators) to compete against each other for buyers over a neutral “open to
all” electrical grid. Competition would drive up efficiencies, attract new entrants, and
consumers would reap the benefits.
Supply Companies
Generation is the most costly activity. Deregulating that end of the business would
produce immediate and substantial benefits to consumers and open new opportunities to
entrepreneurs. The new competitive distribution companies (retailers) would buy power
from the generators in a wholesale (or “bulk power”) market, and contract with the wire
company owners for transportation services. They then sell the power to the end-uses
who could be a residence, or a commercial or industrial business.
In a restructured market, consumers would have a variety of different companies’ service
and pricing plans to choose from, as long-distance and cellular telephone service
consumers do now. They would have access to the latest price information, so they could
make intelligent decisions about buying for the short term or contracting for the longer
term.
New service options tailored to the consumer’s needs could emerge, such as Demand
Response, allowing the utility to cut off or reduce power during peak demand periods in
return for reduced rates for the consumer. For example, in New Zealand and Australia
consumers pay less for electricity under a service option that allows utilities to turn off
residential hot water heaters by remote control at peak demand periods. These features
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transformed their respective power markets by giving individuals more granular control
to automate their responses to dynamic prices using digital technology and continuous
two-way communications between the power seller and buyer.
In Spain, residential electricity consumers can get a better price by agreeing to activate a
simple circuit breaker that shuts power off until the homeowner can shut off enough air
conditioners or computers to bring their load back beneath an agreed level. Then the
power comes back on. Many appliances, air conditioners and water heaters, are already
able to go into a low-use mode during parts of the day. Nevertheless, consumers seldom
have much incentive to switch. The new market would pass more savings to consumers,
allowing them to benefit from their decisions.
In addition, buyers would be able to bypass the grid and generate their own electric
power. Efficient gas generators, fuel cells, windmills solar cells, and geothermal
technologies were already available in 1999. Entrepreneurs were developing other power
sources. Smith and Rassenti foresaw competition spurring innovation and hastening the
introduction of new technologies to consumer markets.
Local Wires Companies
Local wires companies would focus on service. Competition would prevail in the
production of the commodity (electricity), but familiar local hands would restore power
in emergencies. Privately owned transmission companies would have powerful incentives
to invest in the grid. The more they built, the more they could compete. Wires would
automatically follow demand. Security-enhancing redundancy would arise as individual
power transmission companies competed against each other or business. Little regulation
would be required.
If Congress and the states had taken the divestiture route Smith/Rassenti proposed, most
— or even all — of the complexities of restructuring would have disappeared. No
expansion of state or federal regulatory powers would have been necessary to manage
competition — it would occur naturally anyway — and consumers would have realized
the full benefits of market competition: better service at lower cost.
Turning on the Lights 2010
16
From 1999 Turning on the Lights
One could even argue that Smith/Rassenti did not go quite far enough. Leaving sole
access to the last mile of wire to the buyer’s home in the hands of local utilities gave
utilities effective control of the buyer’s front door. Telephone utilities no longer enjoy
this monopoly privilege in the telecommunications market—they share it with cable
companies and satellite networks among others.
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The Emergence of a Bulk power Market and ISO/RTO Structure
While the retail market restructuring debate continued, bulk power electricity markets
grew. Initially, just a few utilities engaged in a few transactions between themselves.22
Individual parties could schedule exchange of power across the transmission grid simply.
Over time, however, the number of participants grew. The system became more
dependable; supplies of power traveled over greater distances. Even more utilities and
independent power producers traded electricity as a result. The market became more
refined and complex. Scheduling grew harder. By 2000, a full-fledged bulk power market
evolved along with interconnections that smoothed out the scheduling problems.
As markets grew more complex, FERC layere on yet another regulator on top of the
existing ISO framework. The Federal Energy Regulatory Commission (FERC) created
Regional Transmission Organizations (RTOs)23 as a voluntary system to organize and
monitor this market. RTOs ensured that all merchant generators and utilities have nondiscriminatory access to the grid. They forecast load and schedule generation to assure
the system operates without interruptions and at a reasonable cost. In addition, they
operated day-ahead and spot bulk power electricity markets.
FERC formalized RTO’s with Order No. 2000 which encouraged transmission utilities to
join an RTO. Seven ISOs and RTOs currently operate in the U.S. 24
22
In an electricity grid, supply of power always has to equal the amount being distributed (after accounting for line
losses) or else the system may collapse causing a blackout.
23
RTOs were created by FERC in the late 1990s after ISO’s. Their function was to operate in tandem with
Independent System Operators (ISOs), to regulate bulk power markets and transmission systems.
24
They are the California Independent System Operator (California ISO); the Electric Reliability Council of
Texas (ERCOT, an ISO); ISO New England (ISO-NE, an RTO); the Midwest Independent Transmission System
Operator (Midwest ISO, an RTO); the New York Independent System Operator (NYISO); PJM
Interconnection (PJM, an RTO); and the Southwest Power Pool (SPP, an RTO). States without ISO/RTOs
include most of the south, central and mountain west and Florida.
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18
Chapter 3. 2001: Two Steps Forward, One Step Back
California Markets Crisis, Enron
The California market crisis and the bankruptcy of Enron in 2001, cast a pall on efforts to
build up the market. The vestiges are still felt today. As a direct result, California,
Oregon, and Virginia ended restructuring and efforts were more or less permanently
delayed in New Mexico, Oklahoma, Arkansas, Arizona, Nevada and Montana. Michigan
capped its retail choice market25 at 10% of the base, but it allowed modest retail choice to
continue. Other states remained regulated.
Nonetheless, of the 26 states that had begun regulatory reform in the late 1990s26 only 13
states and the District of Columbia stuck to their plans. A number of Canadian territories
have implemented some form of restructuring legislation, but terms vary from territory to
territory.
http://www.eia.doe.gov/cneaf/electricity/page/restructuring/restructure_elect.html
•
Insert here Figure 4-8 on page 258 of the 2009 State of the Market Report for PJM—
25
Retail sales of electricity are sales of power made directly to the customer that consumes the power. In a market
with a regulated utility, 100% of retail customers are served by a single utility. In a market with “Retail Choice”,
more than one distribution service competes to sell electricity to retail customers. Under Michigan’s current law as
of Spring 2010, no more than 10% of the load could be served by an entity other than the incumbent utilities.
26
Restructuring states were: Maine, New Hampshire, Massachusetts, Rhode Island, Connecticut, New York, New
Jersey, Illinois, Michigan, Pennsylvania, Ohio, Delaware, Maryland and the District of Columbia.
Turning on the Lights 2010
19
With the exception of Michigan, utilities within the restructured states spun-off or sold
generating assets into entities that were separate from distribution and transmission—just
as Smith and Rassenti envisioned it. The competitive merchant suppliers were allowed to
operate in the state and participate in bulk power markets. However, the oversight
regulation of the new markets was not exactly the one that Smith and Rassenti had in
mind. They described an industry in which there were generators and consumers and only
a privately owned wire transmission company between them. Instead, FERC constructed
a more complex system. It used government-chartered ISO/RTO organizations to manage
the day-to-day operations of the grid. Smith and Rassenti had worried that involvement of
the ISO/RTO organizations would add bureaucracy and unnecessary costs. Certainly
many market participants have had occasion to complain that management was not
responsive to their needs. That the California ISO took over seven years to enact changes
to the market that may have caused the system to collapse in 2001 may suggest a less
than responsive management system. On balance, though, ISO/RTO management has
been more flexible and constructive than critics feared.27
Comparative bulk power market analysis
Studies show that RTO-driven bulk power markets have faithfully reflected the cost of
generation as determined by fuel prices and other costs—as intended. For example, 2009
spot prices of electricity traded between PJM and MISO territories, were down more than
40% compared with 2008, in line with Natural Gas prices which fell by about the same
amount.28 That is an important response to critics who accused markets of jacking up
spot prices to make excess profit.
INSERT CHART FROM PJM STATE OF THE MARKETS REPORT @))(
27
J.P. Torgerson, “The Value of Independent Regional Grid Operators,” Jan. 2010.
28
PJM State of the Markets Report for 2009
Turning on the Lights 2010
20
Meanwhile, generating efficiency in areas overseen by ISO/RTOs has been improving
faster than in regulated states29. Market competition pressure added to three basic factors
that caused the advance:

Plant Replacement: Operators retired inefficient and costly generators and
supplied new equipment that used less fuel to make more power;

Efficient Dispatch: The ISO/RTO market forced the grid to use the most costefficient plants first, giving an advantage to generators with economical
equipment;

Better Maintenance and Upgrades: Investors in power generation benefit directly
from lowering the amount of time that equipment is idle or awaiting repair.
As a result, many studies found improvements in operating efficiency in ISO/RTO states.
Measured in terms of heat rates, or the amount of heat required to generate electricity,
efficiency improved 9.4% in the period 1998-2007, and nuclear power plant utilization
rates rose from 81% to 93% in the same period.30 Power price growth has been slower in
RTO states than in non-restructured states. Between 1997 (the year before restructuring
took hold) and 2009, power costs have climbed a nominal 47.1% and real 13.4% in RTO
states but 42.44% nominal and 9.8% real in non-restructured states. This was during a
period of generally rising fuel costs. Between 2008 and 2009, a period of falling fuel
costs, prices declined a real 2.2% in RTO states and only 1.2% in regulated states.31
Bulk power market prices have improved even more. For example, the New England ISO
reported that the average wholesale price of wholesale electricity dropped 48% to $41.99
in 2009 to a level beneath the comparable low of $48.55/MWh set in 2003, the year that
29
“Electricity Restructuring : What Has Worked, What Has Not, and What is Next,”
http://www.justice.gov/atr/public/eag/232692.htm.
K. R Fabrizio, N. L Rose, and C. D Wolfram, “Do markets reduce costs? Assessing the impact of regulatory
restructuring on US electric generation efficiency,” American Economic Review 97, no. 4 (2007): 1250–1277.
30
31
EIA data. EIA.gov
Turning on the Lights 2010
21
competitive markets were launched in New England. Prices in the New York ISO
wholesale market fell to their lowest level since that market began operations in 1999.32
a)
b)
c) Evolution of RTO Market Design
As a recent study by John Chandley and William Hogan explained, the RTO market
design has been changed and improved numerous times since the late 1990s.33
These changes in the design or structure of the RTO bulk power markets created
incentives to generator firms to build new generators or to operate old systems in ways
that provide new services to buyers at competitive costs. And it made it easier for small
producers to enter the wholesale market.
Locational (Nodal) Marginal Pricing of Energy and Reserves When utilities first
began trading power, they had no need for an elaborate price structure, and nobody paid
32
FERC Market Oversight, “State of the Markets 2009”, http://www.ferc.gov/market-oversight/st-mkt-ovr/st-mktovr.asp
33
Chandley, Hogan, “APPA’s Journey Down the Wrong Path.”
Turning on the Lights 2010
22
attention to how much it cost to transmit power from Point A to Point B. As the bulk
power market grew, these simple markets became unwieldy. Chandley and Hogan34
conclude: “There are many ways to fail, but a common thread in the failed models
included contract-scheduling restrictions on the spot market, inconsistent pricing models,
and reliance on bilateral transactions without the support of a well-designed spot market.”
For example, before restructuring really got going in 1997, FERC ordered PJM to
implement a simplified single-zone power market relying primarily on bilateral trades.
This “imploded on the first hot day in 1997,” said Chandley and Hogan.
PJM quickly switched to a Locational Marginal Price (LMP) design. What’s that?
LMP forces people to bid for transmission capacity needed to sell electricity generated at Point A
to end-users at Point B at a specific moment in time. It also takes into account whether or not the
grid is congested or not. The greater the distance and the more congested the grid, (generally) the
higher the price. This gives a reason to all participants to keep the system going based on lowest
cost. If lines are congested in a particular area, the price of transporting electricity through that
portion of the grid goes up. LMP provides an engineering-based technique for allocating costs,
including congestion35,36 and marginal cost of line losses37,38 to those who create the costs or benefit
most from transporting power over the system. It also provides a way for measuring the
34
FERC Market Oversight, “FERC: State of the Markets,” n.d., http://www.ferc.gov/market-oversight/st-mkt-ovr/stmkt-ovr.asp.
35
Congestion costs arise because transmission capacity limits the number of generators that can be used efficiently
to get electricity from the generator to the end user. For example, if it were possible to somehow costlessly
transmit power through the air in unlimited amounts, there would be no congestion costs. Any combination of
generators could be used to satisfy any power demand. Because power lines are limited and costly, however,
regulators can only use certain combinations of generators to match demand that fall within physical power line
constraints. Often, the combination of generators that ends up being used is a little less efficient than what ideally
would be used if you could send power through the air in any quantity and without losses. The difference in
efficiency amounts to the congestion cost.
37
Line losses occur when electricity moves over wires and some fraction of useable electricity is wasted as
unuseable heat energy
39
NERC Energy Reliability Study for 2009.
Turning on the Lights 2010
23
economic value of transmission lines, allowing grid-owners to profit from adding capacity to the
grid. The LMP model is now used in virtually all ISO/RTOs.
The ISO operates the system to minimize total system costs.
Demand Response has become a major influence in bulk power markets and is growing
rapidly. In a Demand Response program, buyers agree to limit their power use to a
certain amount during peak use periods such as on hot summer afternoons when
requested by the utility in exchange for payment or reduced rates .
The North American Reliability Council (NERC), predicts that DR (together with smaller
Energy Efficiency programs) will reduce growth in demand by four years by 2018
compared with previous forecasts.39
Nationwide, generators currently use about 32,000 MW of DR to control peak demand
(about half of that in ISO/RTO markets), and that number will increase to 38,000 MW by
2018. That is not large compared to total installed capacity of nearly 1.1 million MW in
the U.S.40 It is enough to affect the cost of marginal power during a peak period. This is
important because market prices are set by the cost of the last dispatched generator
(marginal cost)—usually the one with a somewhat higher cost of output than those that
were already dispatched.41 Influencing the use (or non-use) of that one slightly more
expensive generator affects the entire price structure. It can have a profound effect on
new investment, system efficiency, and reliability calculations.
Several ISO/RTO systems, PJM in particular, but also ISO-NE and ERCOT, have been
revamping their wholesale market rules to enable suppliers to use demand-resources to
bid into the wholesale market. This ability to use demand response to bid in to the supply
39
40
NERC Energy Reliability Study for 2009.
http://www.eia.doe.gov/cneaf/electricity/epa/epat1p2.html
41
Eric Hirst, ‘Price-Responsive Retail Demand: Key to Competitive Electricity Markets’, 2001
<http://www.pur.com/pubs/3676.cfm> [accessed 7 May 2010].
Turning on the Lights 2010
24
stack is a significant move and represents remarkable leadership at institutions such as
PJM where generators are significant stakeholders.
What benefits does Demand Response create?

Power producers need fewer peaking generators, generators that are too expensive
to operate except during peak demand periods when power is most valuable.

Less New capacity needed overall. Current Demand Response programs replace
the need to build about 32 giant base load power plants, and many smaller
generators that operate only during “peak” power periods (known as loadfollowers).
Most of the growth in Demand Response has occurred in ISO/RTO markets.42
Capacity Markets Since around 2005, regulators have worried that power producers
don’t earn enough money in competitive markets to build new generation capacity. PJM,
New England and New York ISOs have introduced capacity markets to address this
concern.43 In a Capacity Market, generators make long-term commitments of capacity for
which they are held accountable. The result is a market that puts a price on long-term
availability of capacity in the expectation that this will serve as a market indication of the
value of adding new generators. MISO and Texas ERCOT have not taken the capacity
markets path. Instead generators are left to make independent decisions about the
adequacy of their generation stock given their requirements. PJM has a somewhat
broader capacity market that includes commitments to demand reduction and other forms
of capacity over a three-year period. It also takes locational costs into account.44
42
Peter Cappers, Charles Goldman and David Kathan, ‘Demand Response in U.S. Electricity Markets:
Empirical Evidence’, Office of Electricity Delivery and Energy Reliability, Permitting, Siting, and Analysis U.S.
Department of Energy, Ernest Orlando Lawrence Berkeley National Laboratory (2009).
43
Peter Crampton and Steven Stoft, A Capacity Market that Makes Sense, Electricity Journal, 18, 43-54,
August/September 2005. http://docs.cpuc.ca.gov/published/REPORT/48884.htm
44
http://www.pjm.com/markets-and-operations/rpm.aspx
Turning on the Lights 2010
25
Balancing Power Ancillary Services Buying and selling power is complicated. It gets
even more complicated when many solar and wind generators sell their small, variable
power streams into the market. Many things can go wrong. Mistakes and unplanned
spikes in power source or demand can lead to unacceptable events (like blackouts). To
make trading smoother, ISO/RTOs have developed a mind-numbing array of markets in
highly technical “extras” that utilities need to avoid mistakes and accommodate solar and
wind power. This is called the ancillary market . It includes things like load-following,
reactive power and frequency regulating services that make sure that the system has
enough generators to accommodate sudden shifts in power flow. It also assures that
important parameters in AC power such as frequency are kept at the right level.
The importance of this is that it shows how markets have adapted to new power sources.
And it demonstrates the dynamic changes that can happen in restructured markets as
participants experiment with unbundling pieces of their power “product” and price them
in the marketplace. It also reveals how important it is to have a regulator like FERC that
works to encourage and accommodate market adaptions.
Retail power markets in 2001-2010
Compared to regional bulk power markets (where utilities trade with each other), statebased markets for homes and small businesses (the end users in the retail markets) have
been fully functioning for less time and are still somewhat undeveloped.
Home and small business electric power buyer experiences are more diverse than those of
big utilities and power companies, reflecting the variety of policies for retail markets
among the 13 restructured states and the District of Columbia. An examination of retail
markets eight of the restructured states paints a picture of the industry and the retail
market where the “rubber” of restructuring “hits the road.”
New Jersey
New Jersey’s restructuring began in 1999. Rates were reduced 15% and capped until
2003 and then allowed to float. Fitting a pattern we see in most restructured states, the
Turning on the Lights 2010
26
new system was quickly adopted by commercial and industrial buyers who could also
choose hour-by-hour in the real-time energy market set by PJM.
For smaller residential buyers and businesses, New Jersey also introduced a Basic
Generation Service (BGS) that exposed buyers to market prices. But it did so in a way
that spread the risk over a large base. The BGS Auction initially served clients of New
Jersey’s four incumbent electric distribution companies (EDCs). Each year, the
four procure several billion dollars of electricity supply to serve their BGS buyers
through a statewide auction process held in February. Joskow notes that the BGS auction
in New Jersey “conveys bulk power market prices in retail prices and also provides good
incentives for investment.”45 On the other hand, competitive providers as of 2008 only cover
about 20% of New Jersey’s retail electricity needs and some might blame the low
penetration partly on the BGS-style default service arrangement.46 In states like New Jersey,
Illinois, Maryland, Pennsylvania, New York and Massachusetts, the provider of last resort, or
default service contract, is supplied through BGS-style procurement auctions and may be a
substantial and anti-competitive entry barrier preventing potential suppliers from intering the
market and offering competing products and services to residential customers.
There has been some movement away from the default service contract in New York and
Pennsylvania, but in general this BGS/default service is pernicious and anti-competitive, and
would not withstand scrutiny if we applied antitrust analysis to it instead of regulatory analysis.
Texas
In contrast to New Jersey, Texas exposed home buyers and small businesses more
directly to the retail market. Electricity deregulation in Texas, the largest electricity
market in the United States—and bigger than Spain’s—was the result of the enactment of
Texas Senate Bill 7 on January 1, 2002.47 In terms of penetration of both wholesale and
retail markets, it is the largest and most successful restructuring in the U.S. About 40% of
residential buyers in deregulated areas of the state have switched from the former
45
P. L Joskow, “Lessons learned from electricity market liberalization,” The Energy Journal, special issue (2008).
http://www.eia.doe.gov/cneaf/electricity/st_profiles/new_jersey.html
47
Lynne L. Kiesling, Andrew N. Kleit, “Electricity restructuring: the Texas story,” American Enterprise Institute,
Washington D.C., 2009, 244 pages.
46
Turning on the Lights 2010
27
incumbent provider to a competitive Retail Electric Provider (REP). And about 68% of
commercial and industrial users have switched their electric providers (sometimes more
than once).48 Those who view it as a model for the rest of the country point to the effort’s
deep commitment to consumer choice and wide-open trading environment for its
success.49
Texans have more than 16 different electric providers to choose from offering 53
different electric plans available in various combinations around the state. Texas electric
providers compete on price and several other factors—including, types of billing and
service options, payment and credit plans, as well as guaranteed “green” or power from
solar and wind sources.50
Price to Beat (PTB) Regulation
For the first five years, the Texas market operated with a regulated rate concept
governing the pricing behavior of the ex-utility providers known as the “Price to Beat,”
or PTB. The PTB was set by the Public Utilities Commission to reflect the cost of
electricity production and was adjusted every six months.51
Incumbent utilities could not offer prices less than the PTB. This drew new merchant
generators and distributors who were allowed to charge less than PTB because they did
not fear anti-competitive pricing by utilities designed to drive them out of the state. PTB
had its own problems, and probably drove up prices while it was in effect. But it
succeeded in its main goal: drawing new market entrants, and driving residential,
commercial and industrial customers into the new market—and avoiding a Californiastyle calamity. “The consistent increase in the fraction of retail buyers who have
48
H. Sterling Burnett, “Power for the Future: The Debate Over New Coal-Fired Power Plants in Texas,” Texas Public
Policy Foundation, January 2008, http://www.texaspolicy.com/publications.php?cat_level=88.
49
Robert J. Michaels, “Competition in Texas Electric Markets: What Texas did Right and What's Left to Do”
(Center for Economic Freedom, March 2007), www.texaspolicy.com.
50
51
Burnett, p. 2.
http://www.puc.state.tx.us/electric/rates/PBT/PTB_TCRF_Summary.pdf
Turning on the Lights 2010
28
switched reflects this framework’s attributes,” said Joskow.52 PTB was retired at the end of
2007.
80%
70%
60%
50%
40%
30%
20%
10%
0%
Residential Megawatt-hours switched to
Competitive REPs in TX
Oncor
AEP North
Centerpoint
TNMP
AEP Central
Total
Figure 1http://www.puc.state.tx.us/electric/reports/RptCard/index.cfm
Price increases have been widespread in restructuring states and have diverse causes
including fuel prices, taxes, and regulated fees imposed by the state. Texas has been no
exception. Consumers are paying 20% more for power in real terms since restructuring
began. But costs of Natural Gas, the state’s dominant fuel supply, increased by about
50%, indicating that competition in the electricity market absorbed the bulk of the
increase. Some power buyers who shop carefully can do much better on prices. For
example, one study found that variable and 3-month fixed power rates in late March 2010
were 12% to 35% lower in certain serving area than they were in December 2001 after
inflation adjustment.53
52
Joskow, “Lessons learned from electricity market liberalization.”
Barry Smitherman, “KEMA 21st Executive Forum on retail energy - agenda - KEMA,” March 30, 2010,
http://www.kema.com/services/consulting/KEMA-conferences/executive-forum/21st-executiveforum/agenda.aspx.
53
Turning on the Lights 2010
29
Indeed, Texas does not have a great deal of energy diversity when compared to much of
the nation. For instance:54

Coal-fired power plants make up 33 percent of the electric power generating
capacity in the United States, and provide over 52 percent of the electricity.

In Texas though, coal power makes up just 19 percent of electric capacity, and
provides more than 40 percent of the state’s electric power on an annual basis.

Alternatively, for the nation as a whole, natural gas and oil combine account for
45 percent of total generating capacity, while in Texas it accounts for a dominant
72 percent, and generates 43 percent of the electricity (for the US as a whole the
rate is even lower).
Lower prices are filtering into the retail market via the most popular electricity plans with
with longer term contract commitments of up to a year with fixed prices. On the other
hand, energy prices change quickly so predictions are difficult.
There are reasons to expect prices to improve. First, deregulation has spawned the
construction of massive new capacity in Texas, a driver for future competition.55 Second,
natural gas prices have dropped in response to discovery of new local sources of the fuel.
Average price paid for power may drop as annual contracts roll over. Third, the PTB
regulation expired without replacement in 2007. Fourth, introduction of a new day-ahead
bulk power market56 will force more transparent competition on price, and more
transparently reflect the declining cost of fuels such as Natural Gas. Before the day-ahead
market, ERCOT relied entirely on bilateral contracts that handled 95% of the energy in
the restructured part of the state and a small ancillary services market for trading
electricity.
54
H. Sterling Burnett, Power for the Future: The Need for New Coal-Fired Power Plants in Texas, Texas Public Policy
Foundation (2008).
55
Robert J. Michaels, “Competition in Texas Electric Markets: What Texas did Right and What's Left to Do” (Center
for Economic Freedom, March 2007), www.texaspolicy.com.
56
Expected to start experimental operations on May 1, 2010.
http://www.texasenergyreport.com/energypress/energypress.cfm
Turning on the Lights 2010
30
Texas Retail Market Examples c. 2010
A search on an address in Houston in Spring 2010 showed that 25 different options by
nine different competitive providers on the www.chooseenergy.com website were
available to consumers there. Prices ranged from 10.3 cents kw/h with 12 month contract
to a 14.9 cents kw/h one month contract for clients paying cash. Since the site keeps track
of how many purchases are made of each product over the last 30 days, it’s fair to say
that most consumers are buying power at lower rates this year with longer-term contracts
(up to a year).
Searching on the address for the National Center for Policy Analysis in Dallas, we find
25 options by 10 offerors. Prices range from 8.3 cents kw/h for 1 month and 14.9 cents
kw/h for a pay-as-you-go plan requiring cash payments but no credit check. Interestingly,
the high priced cash offer was the fourth most popular plan of the 25 on display. The low
cost plan was the most popular.
Retail competition is only available in areas regulated by ERCOT, which excludes the
northern part of the state, areas served by cooperatives and the Cities of San Antonio,
Brownsville, Lubbock, Austin and 70 other municipalities.
For example, the City of Sinton, Texas in the southern part of the state is served by the
San Patricio Electric Cooperative which has no plans at present to enter the restructured
market.57 San Patricio Electric offers rates that are about in the middle of the range of
offers in nearby restructured markets. For home buyers, there is a standard customer
charge of $21.50/month, a distribution charge of $.035 kw/h and the cost of the actual
power is $.07214 kw/h—placing the cost of generation and distribution at about 10.7
cents kw/h. That is more than the cheapest and most popular plans available in
restructured areas. But it is less than cash-only plans and on a par with rates for some
“Green Power” plans offered by Green Mountain Energy.58
57
58
www.sanpatricioelectric.org
http://www.sanpatricioelectric.org/electricservice/electricservice.asp#Rates
Turning on the Lights 2010
31
An item of concern for ERCOT (as well as power markets in the Midwest ISO) is
whether competitive merchant generators can continue to build enough capacity to keep
up with demand. ERCOT and MISO have followed the philosophy of “energy-only”
markets: that is market prices by themselves should be enough to finance generator
construction and cover the cost of commercial investment. Other ISO/RTOs, however,
have gone to central planning model based on “capacity markets” to decide when to build
more generation capacity.
There is a question about whether ERCOT can continue to rely solely on markets. The
NERC’s latest annual reliability report, for example, warned that ERCOT’s reserve
margin will slip under 15% in 2013.59 However, some of the problem is not directly
related to the design of the bulk power market. The decline in the reliability ratio in 2013,
for example, reflects the delay of the Cobisa Greenville Project, a 1,792 MW natural-gas
fired plant scheduled to open in 2013. Other plans for nuclear and coal-fired plants have
also encountered problems.60,61 The financial return on any new plant depends—in large
part—on the decisions by competitors about whether or not they intend to add capacity to
the market. In Classic Regulation these kinds of market-entry problems would have been
solved in a bureaucratic way that would put a lid on the amount of new capacity that
could be added to the system. It is hard to say that the messier market method is inferior
to the government’s bureaucratic solution which binds the market to a certain kind of
generation technology over a long period of years. Another factor keeping reserve
margins low is that ERCOT only counts 8.7% of wind generation nameplate capacity
when calculating reserve margins.62
Perhaps most importantly, Texas has not let the pricing “trees” block their larger vision
for the Smart Grid “forest.” The move to nodal pricing and consistent consumer-friendly
59
“Reliability Assessments,” NERC-North American Electric Reliability Corporation, October 29, 2009,
http://www.nerc.com/page.php?cid=4|61.
60
John Rowe, Conference on Competition in Wholesale Energy Markets, 2007.
61
Michaels, “Competition in Texas Electric Markets: What Texas did Right and What's Left to Do.”
62
Barry T Smitherman, “Public Priorities and the Role of Competition” (KEMA's 21st Executive Forum, March 30,
2010), www.puc.state.tx.us/about/commissioners/smitherman/.../KEMA_033010.pdf. P. 6.
Turning on the Lights 2010
32
moves in Texas toward implementing smart grid technologies and will enable more retail
participants to offer entirely new differentiated products in the future.
California
After 10 years keeping retail customers out of its restructured markets, California is
beginning to reopen the market for retail power buyers. Early in 2010, California utility
regulators approved a plan to allow more businesses to buy power from independent
marketers and taking advantage of low prices for power in the bulk market.63 With this
small gesture toward opening its electricity markets to consumer choice, the State
signaled it has indeed come a long way since calamity struck the electric power market
10 years ago.
Retail choice was halted in California since the market debacle of 2000-2001. However,
the state continues to pursue efforts to modernize its competitive bulk power market that
trades power between electricity generators and distributors. Indeed, the new bulk power
market, which went into action in April 2009, is on the cutting edge of market design.
Instead of just three regions for pricing electricity, the new system tracks prices of trades
at more than 4,000 “locational nodes.”64
California markets crisis, ENRON bankruptcy stops most momentum
(but federal regulators, some states continue)
On March 31, 1998, California became the first state to allow all residential buyers to buy
competitive retail electric power, starting a roller coaster ride that would end in a market
meltdown three years later.
Smith, Rebecca. “California Revisits Power Shopping.” Wall Street Journal 13 Mar. 2010: n. pag. Online.
http://www.meridianawards.com/entry/view/displaying-4000-locational-prices-in-californias-new-bulk powerelectricity-/
63
64
Turning on the Lights 2010
33
Even before the California electricity markets imploded in 2000 due to poor market rules
and an imbalance in supply and demand,65 the state had been considering revising its
fatally flawed restructuring effort. It has become a case study in how not to restructure.
There were numerous problems, beginning with a dearth of new entrants. Initially, more
than 300 companies expressed interest in marketing electricity directly to consumers. A
year later, all but 33 marketers had pulled out. The disinterest from entrant generators
was matched by consumer indifference. By 1999, according to the California Public
Utilities Commission, only 1.2 percent of utility buyers had switched from their local
utility to a competitor.66
The reasons were clear. California’s retail competition plan lowered existing residential
and small business electric rates by 10 percent from 1996 levels and capped them for up
to four years, so utilities could recoup stranded costs. This gave potential market entrants
– new generators or wholesale marketers – little reason to enter the market facing fixed
rates. It also gave consumers no reason to migrate to the competitive market before the
caps came off, an advantage to incumbents.
There were also problems with the transmission grid. Responsibility for planning,
enforcing and overseeing future electric grid improvements and expansions was given to
Cal-ISO. The ISO, a state-created organization approved by FERC, operates the grid
independent of transmission owners. Questions of enhancing and expanding the
overworked California network were thus left to a patchwork of interests that could not
move fast enough to expand the grid to keep up with the new markets’ extra stress on the
grid infrastructure.
The restructuring design was vulnerable to exploitation on many fronts. Buyers stayed
bonded to their incumbent suppliers after (correctly) assessing that they had little to gain
from changing. New merchant suppliers stayed out of the market, but those already there
had no reason to offer power into the market at regulated rates. So, generators were free
65
http://www.ferc.gov/industries/electric/indus-act/wec.asp
Rebecca Smith, “NRG Energy May Exit Texas Project,” Wall Street Journal (Online) (New York City, January 29,
2010).
66
Turning on the Lights 2010
34
to offer electricity into the market—or not. Lack of merchant and independent generator
investment left the state with a continuing over demand due to low fixed prices served by
interstate electricity imports over a underdeveloped transmission grid owned by
incumbent market participants and controlled by an entity that had limited ability to
extend it. Independent generators able to leave the market without warning and limited
grid access became choke-points.
When the collapse came, California’s utilities suffered dire financial consequences
because they were forced to buy electricity in a faulty bulk power market at many
multiples of the fixed retail rates they were mandated to charge their buyers. Only after
strong encouragement from federal officials, the State of California stepped into the
situation to purchase long-term contracts despite high prices.67
The disintegration of the market was followed closely by the collapse of Enron, a highprofile participant in California’s bulk power market. The two incidents became fused in
people’s minds as evidence that “markets can’t be trusted” to deliver electricity.68
California subsequently re-regulated its market reforms, triggering a chain of similar
moves by several other states.
After the California crisis and Enron collapse, states went many directions. Some states
continued their efforts to promote retail choice; others stopped or backtracked.
Restructuring efforts were entirely suspended in California, Oregon, and Virginia, and
more or less permanently delayed in Arizona, New Mexico, Oklahoma, Arkansas,
Nevada and Montana. But a number of states continued their restructuring efforts. Those
included New Hampshire, Massachusetts, Maine, Rhode Island, Connecticut, New York,
New Jersey, Pennsylvania, Ohio, Illinois, Michigan, Delaware, Maryland, and the
District of Columbia. The state has also been a leader in installing Smart Meters, which
has many uses in both regulated and restructured environments. It may be awhile before
67
Later studies purported to show that California would have been better off paying the high wholesale market
price rather than intervening.
68
See. “Can Energy Markets be Trusted? The Effect of the Rise and Fall of Enron on Energy Markets,” Jacqueline
Lang Weaver, Houston Business and Tax Law Journal. 2004.
Turning on the Lights 2010
35
retail markets come back to California, but the government and CAISO are laying the
infrastructure to make any such new market a national leader when it develops.
Pennsylvania
Competition has only now really got going in Pennsylvania this year. Until quite recently,
a long-standing cap on retail prices in the state that kept prices about 25% below market
level, kept new competition from entering the retail market. Also, under terms of the
restructuring agreement, electric utilities were able to collect $11.4 billion in stranded
costs reflecting costs they incurred when selling off their generation facilities.
Pennsylvania began restructuring in late 1996 after passage of the Customer Choice Act.
Incumbent utilities, Penn Power, Duquesne Light and PECO, sold their generation
businesses consumer began choosing new competitive suppliers in 1999. However, a
series of court cases and settlements in the Eastern part of the state kept rate caps in place
in parts of the state until 2010 and 2011, at which time power prices were expected to
climb 35% or more.
Competition in Western Pennsylvania, where Duquesne Light is located, was better
established. Today 20 percent of Duquesne Light residential customers and 56% of
commercial customers, accounting for 89% of the load, have switched to one of the 15
competing power suppliers since rate caps expired in 2004. Electricity rates fell nearly
30% below 1991 rates in constant dollars. 69
PPL’s service territory began competition in 2010, with the expiration of price caps.
Competitors moved in swiftly after PPL rates rose 30% to reflect high-priced power
purchased in long-term contracts. One, Dominion Retail, guaranteed a savings of 10
percent on PPL’s rates for the first 5,000 customers. As of April, 28% of its customers, or
395,000 have shopped. Of that, 332,000 are residential customers, or 27% of total
residential customers, or 379,000 of its 1.4 million customers and 46% of PPL’s electrical
69
http://www.competecoalition.com/blog/2010/01/pennsylvania-just-the-facts-please/
Turning on the Lights 2010
36
consumption. And 48% of the total load is shopped in the market, including commercial
and industrial customers. There are now seven competing with PPL.70
For New Castle's Penn Power (year-end 2006), 14.4 percent now do. For Wilkes-Barre's
UGI Electric (also year-end 2006), the figure is 0.1 percent.
Rate caps remain in place for Reading's Met Ed, Erie's Penelec, Philadelphia's PECO and
Greensburg's Allegheny Power. A major question for residential power markets is
whether the default service option which offers market rates obtained through a BGS-like
auction to consumers who don’t choose to shop for electricity will remove motivation for
home power buyers to enter the market.
Connecticut
Connecticut’s restructuring has been the subject of considerable controversy since it
began in 1998. The state’s consumers suffered a series of setbacks early in the period as
few alternative producers entered the market. As in New Jersey, ratepayers in
Connecticut had access to an artificially inexpensive default service contract that
effectively acted as a barrier to entry for new market-based suppliers. Ratepayers also
faced big non-generation costs for federal congestion fees and the state utilities’ hefty
exposure to nuclear power plants.
Consumer reluctance, in turn, kept merchant generators from entering the marketplace.
Reluctance of competitive generators to enter the state caused other problems:
insufficient capacity in terms of both generation and transmission. In 2009, the state took
the unusual step of requiring distributors to build peaking generation plants at “cost of
service plus reasonable rate of return as determined by the state.71
All of the problems resulted in steep retail price increases that were far out of line with
neighboring restructured states. This has encouraged the state to start weighing new laws
that would “radically change the electricity market in Connecticut, curtailing consumer
70
71
http://articles.lancasteronline.com/local/4/249934
http://www.cga.ct.gov
Turning on the Lights 2010
37
choice and market competition.”72 Much of the higher prices result from high congestion
and stranded costs that were regulated by the state’s Public Utilities Commission and so
had nothing to do with generation costs, according to a report by ESAI Power LLC.73
Even with continuing government concerns, the Connecticut Department of Public Utility
Control said that about 13% of Connecticut residential and business buyers had chosen an
electric supplier by 2009.74 Nevertheless, EIA statistics suggested that about 49% of
power measured in megawatts is sold competitively with most being sold to commercial
72
Statement by New England Energy Alliance, www.newenglandenergyalliance.org
ESAI Power LLC, “Achievements in Electricity Industry Restructuring in Connecticut,” April 2010.
74
Connecticut Department of Public Utility Control, http://www.ct.gov/dpuc/
73
Turning on the Lights 2010
38
and industrial buyers.75 As of 2010, there were about two dozen suppliers and
aggregators actively marketing to residential buyers.76
New York
New York’s competitive markets began in 1998 with a complete separation of generation
from transmission and delivery resulting in nearly 70 different owners of power plants
and about 60 Electricity Service Companies (ESCOs) competitively serving electric
buyers.77 ESCOs have gotten a warm reception from large customers, but homes and
small businesses have migrated more slowly. About 70% of commercial and industrial
companies’ source power from markets based on hourly market prices and the state is
expanding the popular program, which also allows companies to participate in Demand
Reduction. But only about 20% of homes get their power from competitive markets.
75
www.eia.gov
76
http://www.dpuc.state.ct.us/electric.nsf/$FormByElectricApplicantsView?OpenForm&Start=1&Count=1000&Expa
ndView
77
Maureen Harris, “Retail Competition in New York State” (New York State Public Service Commission, March 30,
2010), http://www.kema.com/services/consulting/KEMA-conferences/executive-forum/21st-executiveforum/agenda.aspx.
Turning on the Lights 2010
39
ESCOs are popular with their customers and have low complaint rates, but the low profit
margins on transactions with home buyers, relatively high cost of billing and other
transaction costs keep ESCOs from pursuing the home market aggressively. From the
home buyers’ point of view, ESCO “product” is not much different from utility offerings
and results in fewer savings since ESCOs only affect generation costs, not transmission
fees and taxes that take a share of the home utility bill. Regulators are planning to
encourage ESCOs to become more innovative in their offerings.78
Meanwhile, retail costs have performed better in New York than most other restructured
states.

Prices were up 51% in New York State at the end of 2009 compared to 1999.

That was less than the 52% gain for all restructured states;

But it was more than the 45% rise in regulated states.79
As in Texas, Illinois and Western Pennsylvania, competitive providers according to latest
EIA figures handle more than 50% of the load for 2008.80
Michigan
Michigan began implementing restructuring in 1998 and retail access in 1999. However,
Michigan’s restructuring was different from other states because it did not require
vertically integrated electricity utilities to separate and sell either the wires and
transmission business or the generating power plants. Consequently, the retail market has
been slow to engage competition, but retail prices have been stable. During the run-up in
energy prices after 2005, Michigan’s retail choice program actually decreased in size,
78
Mareen Harris, Commissioner, New York State Public Service Commission, remarks to KEMA Executive Forum in
Irving, TX, March 30, 2010
79
See monthly electricity data at http://www.eia.doe.gov
80
http://www.eia.doe.gov/cneaf/electricity/st_profiles/new_york.html
Turning on the Lights 2010
40
losing buyers in 2005-2008.81 As electricity prices continued to rise, the state decided to
cap the level of participation in the retail program to no more than 10% of the total base.
Ironically, the cap went into effect in 2008, at the very peak of high electricity
costs.82Since that time, retail participation has reversed trend from earlier in the decade
and increased to 1,092 commercial and industrial buyers in 2009, up more than 66% from
2008.83 That number of clients was far less than the 10% cap, however, and is still below
the levels in 2006. Household participation remained virtually nonexistent. Although 24
alternative suppliers are active in the state, the prospects for future growth in competitive
suppliers seem cloudy.84 The status is unlikely to change without at least a reversal of the
participation cap and a deeper restructuring of the industry.
Illinois
Illinois’ competitive retailers sell more than 50% of the load in the state and control all
but a negligible portion of the generating capacity. In the Commonwealth Edison
(ComEd) service area, 97% of buyers with a demand of more than one megawatt can
choose their electricity source in a competitive market.85
The state fully restructured its electricity system beginning in 1998, and incumbent utilities
ComEd, Illinois Power and Ameren kept their distribution and transmission lines but sold off
their generation equipment. Commercial and industrial buyers were able to participate fully in
competitive markets most of the time since then. Residential retail rates, however, were reduced
20% and capped for a decade.
81
Michigan Public Service Commission, “MPSC - Electric Customer Choice Reports,”
http://www.dleg.state.mi.us/mpsc/electric/restruct/status.htm.
82
Kelderman, E., 2010. States pull the plug on electricity dereg.
Available at: http://www.stateline.org/live/ViewPage.action?siteNodeId=136&languageId=1&contentId=44242 [Accessed January 28, 2010].
84 Energy
Information Agency. 2010. Status of Electricity Restructuring by State. Electricity Restructuring by State. February 15.
http://www.energy.gov/news/archives/print/5538.htm.
85
http://www.icc.illinois.gov
Turning on the Lights 2010
41
Until Jan. 1, 2007, electric rates had been capped at levels below those in the bulk power market,
making it impossible for competitors to offer a better deal to home power buyers. That is why
bulk power markets and large business customers, unable to get the benefit of capped rates,
quickly jumped into the competitive market, but home customers stayed out and few new
suppliers got into the market, and the residential retail market remains dormant. Moreover, as in
New Jersey and Connecticut, home power buyers also had access to the BGS procurementfunded default service contract that acted as an entry barrier in the retail market.
When rate caps did come off, it created a political backlash as consumers used to paying rates as
low as 2.5 cents kw/h suddenly faced a quadrupling of rates to 10 cents in some areas covered by
Ameren’s Illinois Power service area. ComEd customers faced smaller increases.
By 2009, 37 alternative retail electric suppliers were licensed to serve non-residential customers,
and eight suppliers were eligible to serve residential customers. Thirty alternative retail electric
suppliers were actively selling service with eleven alternative retail electric suppliers actively
selling in the Ameren service territory and 19 actively selling in the ComEd service territory.

Alternative retail electric suppliers provide 50% of all kilowatt hours consumed in
Illinois;

Markets also provided about 75% of all non-residential (commercial and industrial
customers) electric load

In the ComEd service territory (in northern Illinois) 97% of all very large-size
commercial and industrial customers and 90% of all large commercial and industrial
customers have switched to alternative retail electric suppliers;

Within the Ameren Illinois Utilities service territory about 96% of all large-size
commercial and industrial customers and about 71% of all large-size commercial and
industrial customers have switched.86
While prospects for retail markets in Illinois seem mixed, the state has put into place a residential
retail market that allows real time pricing since 2007 in the ComEd and Ameren service areas.
This allows retail consumers to observe intra-day prices of electricity and gauge their power
consumption accordingly and get a lower electricity price in return. However, once again, there
is very little, if any, retail competition in this part of the market.
86
“Illinois Competitive Energy Association,” n.d., http://www.illinoiscompetitiveenergy.com/.
Turning on the Lights 2010
42
Comparing outcomes in regulated and restructured states
Ten years into the restructuring movement, we now have some data with which to gauge the
relative merits of the new markets for home buyers and small businesses. There is enough to
show that retail markets are doing a better job of producing clear market signals for home power
buyers that reflect things such as fuel prices, overall demand, and congestion in the system.
The Economic Case for Restructuring
The next major step in restructuring the electricity business is a big one: end-user consumers of
all kinds (residential, commercial and industrial) need to face prices derived in transparent bulk
power markets that reflect the real costs of delivering power to their doorstep, business or
factory. At the same time, they need the ability to respond to these prices—by using more or less
power, or even selling power into the market—thereby collectively disciplining the market. That
means that generators will always be forced to consider the impact on their customers of any
decision they make on building new generators, or selecting a fuel. If they make the wrong
decision, they know their clients will find a smarter, more efficient supplier offering a better
deal.
Before taking this step, however, we should have good evidence that competitive retail markets
do a better job of reflecting the real cost of power. That is what this next set of data is intended to
show.
The Table below represents a set of four “regressions” in each of the four columns reserved for
1. Total market, 2. Residential market, 3. Commercial market and 4. Industrial market. On the
left hand side are “co-efficients”, that stand for the mathematical ingredients of electricity prices
nationwide during the 120 months from January 1999 through December 2009. The ingredients
are: the price of natural gas (labeled NatGasPrice); natural gas prices (again) but only in states
during months in which electricity restructuring was taking place and price caps have been
removed (labeled ngXfreeprices); followed by what is known as a “dummy” variable that takes
the value of 1 when electricity restructuring was taking place and price caps have been removed
(labeled freeprices); and finally a “Constant” which describes generic prices for the type of
customer at the top of the page minus all of the other “ingredients” in the price. An overly
Turning on the Lights 2010
43
simplified way of interpreting this data is to start with the Constant, and then add or subtract a
coefficient “ingredient” if it applies.
The panel data offer good evidence that indeed restructured prices are more responsive to
changes in the natural gas price than prices in non-regulated states. The regressions show a
positive correlation between prices in actively restructuring states where price caps have been
lifted (freeprices states) and market natural gas prices (natgasprices).
There is a negative
correlation between the levels of prices in freeprices states that can be ascribed to the long
periods of price caps in those states. However, the variable ngXfreeprice looks at the effect of
changes in NatGas price only when a restructuring program is active and the price caps are off.
The effects are the same across all four groups of customer types but vary slightly in magnitude.
Turning on the Lights 2010
44
Appendix 1
Prices In Regulated v Restructured States
(1)
All
(2)
Res
(3)
Comm
(4)
Industrial
natgasprice
0.344***
0.355*** 0.329*** 0.325***
(50.43)
(47.48)
(46.98)
(44.94)
ngXfreeprice
0.263***
0.251*** 0.181*** 0.270***
(12.77)
(11.13)
(8.59)
(12.39)
freeprices
-0.635***
(-3.74)
Constant
5.586***
7.001*** 5.947*** 3.787***
(118.54) (135.67) (123.31)
(75.90)
Observations
Adjusted R-squared
6,659.00
0.43
-0.515**
(-2.77)
6,659.00
0.39
(0.19) -0.920***
(-1.09)
(-5.13)
6,646.00
0.37
6,646.00
0.37
t statistics in parentheses
* p<0.05, ** p<0.01, *** p<0.001
NOTE: Regression of monthly aggregate costs per kilo-watt-hour (levels) in
each state and the District of Columbia for the years 1999-2009. Prices are
for the overall market (1), residential (2), commercial (3), and industrial (4).
The panel regression includes dummy variables marking those states that
implemented and continue to implement restructuring programs, and another
dummy variable to mark those times when price caps were in place. In turn,
those periods when BOTH restructuring was in place and price caps were
withdrawn were marked by another dummy variable called freeprices. The
regression also includes another variable equal to zero when caps were in
place and the natural gas price when caps were off in restructured states
called ngXfreeprice. The regression uses state-level fixed effects to account
for differences in generator fuel composition, state regulations, geography
and other state-specific factors. The variable natgasprice stands for the
Natural Gas Price at city gate for each month.
.
The Opponents’ Argument
Restructuring opponents have the same data but have used it somewhat lopsidedly to
bolster their views. Over the last three years, the public policy group American Public
Turning on the Lights 2010
45
Power Association (APPA) has been distributing a series of reports comparing retail price
trends in “deregulated” and “regulated” states.
In the latest such report, average retail prices were calculated for each state using Energy
Information Administration (EIA) data and a number of comparisons are made between
average prices in states they list as deregulated and states listed as regulated.
Main Studies/Findings
The primary result reported by APPA was a sharp increase of the difference between the
average prices in the two groups of states, from 3.1 cents per kwh in 1997 to 4.4 per kw/h
in 2007. They concluded that deregulation had raised consumer costs beyond what they
had been 13 years ago.
According to the APPA:
“In most deregulated states, investor-owned utilities (IOUs) sold off their electric
generating facilities as part of the implementation of the retail choice regime, as it was
expected that after a short transition period, alternative providers would serve virtually all
buyers. Instead, retail competition failed to develop as anticipated, so these IOUs must
now purchase power from the wholesale market to serve the large majority of constomers
that are still taking utility service.”87
Survey data
Following APPA methods, but also taking natural gas prices into account, we
examinedthe prices for total delivered cost (generation, transmission, distribution) to all
buyers in a state, and include sales by investor-owned utilities, consumer-owned utilities,
and private energy marketers and providers. All data is from the U.S. Department of
Energy, Energy Information Administration (EIA). We differ from APPA in our
selection of restructured states, but the differences in average prices are slight.
87
APPA, “Retail Electric Rates in Deregulated and Regulated States: 2009 Update,” March 2010. www.APPAnet.org
Turning on the Lights 2010
46
The two major differences are that we do not include California or Montana as
“deregulated” in our analysis. We do include Ohio and Pennsylvania where retail
restructuring is still occurring. Classification issues will be discussed below.
16
Average retail prices by PPI classification, 1990-2009 (Nominal$)
Diff
Restructured
14
Regulated
NGPrice
12
10
8
6
4
2
3.5
1.7
2.0
2.2
2.3
2.4
2.5
2.5
2.6
1991
1992
1993
1994
1995
1996
1997
2.4
2.3
2.1
2.2
1.8
1.9
2.0
1998
1999
2000
2001
2002
2003
2004
4.0
4.2
4.1
2007
2008
2009
2.5
0
1990
2005
2006
Figure A-1: Graphic shows the coincidence of the gain in natural gas prices (broken blue line) with a sharper gain of restructured
state prices (green line) compared to regulated states (red line). The gap between the two (shaded gray area with numbers at
the bottom) increases with natural gas prices then begins to fall. Source: EIA
The APPA discussion begins with 1997, the approximate time that several states began
restructuring their state electric power regulations. Price patterns earlier in the 1990s are
of interest, however, as they show that the later deregulated states already had prices
higher than the national average.88 In addition, while prices in the states that remained in
the regulated category were essentially flat in the 1990s, the to-be-restructured states
showed prices increased for the first few years of the decade and then modest drops in
prices. That small differences emerged even when all states remained regulated suggests
the two groups were exposed to somewhat different economic influences.
88
Indeed, a key motivation in many of the states that chose to restructure was the presence of above-average
electric power costs.
Turning on the Lights 2010
47
For 1997, our numbers show the eventually restructured states with prices averaging 8.8
cents/kwh and regulated states at 6.1 cents/kwh, a difference of 2.7 cents. Both
restructured and regulated states show increasing costs during the 2000s through 2008,
and small drops in prices in the first half of 2009.
The pace of the increases was higher in the restructured states, however, resulting in
increasingly larger differences between the two groups in annual average prices. By the
end of 2007, a point comparable to the most recent data reflected in the APPA report, the
difference had widened to approximately 4 cents/kwh (12.0 cents/kwh for the
restructured group and 8.0 cents/kwh for the regulated states) on its way up to 4.2 cents in
2008. The difference is now down to 4.1 cents in 2009 using annualized data but there
was a downward trend. The gap was 3.85 cents looking at the month of December.
A major problem with APPA’s approach is that numbers are not adjusted for overall
inflation, so simple comparisons across years can be misleading. In APPA Figure 6 they
correct for price growth by using a Department of Commerce price index. Figure A-2
below includes a similar adjustment, following APPA to show constant 2008 dollar
Turning on the Lights 2010
48
values.
15
Diff
13
Average retail prices by PPI classification, 19902009 (2008$)
11
9
7
5
3
1
3.6 4.0 4.1 4.0
3.1 3.1 3.3 3.2 3.2 3.0 2.8 2.5
2.9
2.8
2.7
2.5 2.0 2.1 2.2
2.4
-1
Figure A-2: Average retail prices by PPI classification (Constant 2008$)
Natural Gas Prices
FigureA-3 below shows annual average prices for four states: two with a high proportion
of natural gas fueled generation, and two with a large proportion of coal fired generation.
Each pair has one state that has been restructured while the other has remained regulated.
Turning on the Lights 2010
49
Figure A-3: Comparison of prices in four states
Texas obtained more than 49% of its power from natural gas fueled plants in 2007, while
Florida obtained almost 45% of power from natural gas plants in 2007. The states have
similar coal-driven production, and remainder in both states in mainly nuclear power.
Both states import small amounts of electric power from nearby states. In the chart,
“restructured” Texas and “regulated” Florida show similar average price profiles except
that Texas was initially about two cents cheaper than Florida, then closed the gap for
several years, and then dropped below Florida again in 2009.
Contrast that pair of “gas heavy” states with two “coal heavy” states: Michigan, in
APPA’s deregulated class, and Pennsylvania, listed in APPA’s regulated class. Both
generated more than 50 percent of their power from coal in 2007, and show
approximately 10 percent of their power from natural gas. Both states also participated in
restructured bulk power market – Pennsylvania since 1998 and Michigan beginning in
2005 – and both import and export power to neighboring states.
Turning on the Lights 2010
50
Indeed, as the four state comparison shows, prices in Pennsylvania and Florida were level
or increasing slightly from 2008 to 2009, while the two “deregulated” states listed
featured falling retail prices.
Looking at just those states with heavy exposure to Natural Gas generation in both
restructured and deregulated states, we obtain a graph that looks very much like Figures
A1 and A2—that is, they show the widening price gap between restructured and
regulated states. (Label the graphic)
16.000
14.000
12.000
10.000
diff
8.000
Gas-heavy restructured
Gas-heavy regulated
6.000
4.000
2.000
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
0.000
•
Add graphic gas-heavy states tab A5 in annual EIA statistics—
However, the increasing differential effect disappears when we look at coal-heavy
restructured states versus coal-heavy regulated states.
Turning on the Lights 2010
51
12.000
10.000
8.000
diff
6.000
Coal-heavy restructured
Coal-heavy regulated
4.000
2.000
0.000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
•
Add graphic coal heavy states tab A6 in annual EIA statistics—
Just as in the coal-heavy regulated states, coal-heavy restructured states wind up with
prices slightly lower in real terms than they were in 1990.89
Just wait
Recently developed natural gas resources in the United States present a new “more likely
scenario,” at least for the next several years: ample supplies of natural gas will help keep
power prices lower, especially in the states using a lot of natural gas—and those happen
to be restructured states. Ample supplies of gas will also keep prices low on coal, too.
But particularly in the year or two after the fuel price peak in July of 2008, the
89
It is also important to note that coal prices also increased along with Natural Gas prices during the mid-to late
2000s, although not by as much as natural gas.
Turning on the Lights 2010
52
restructured states should start looking more attractive on average price grounds.
0.16
14
0.14
12
0.12
10
0.1
8
0.08
"Price Difference"
Restructured
6
0.06
Regulated
NGPrices
4
0.04
2
0
0
1999/1
1999/7
2000/1
2000/7
2001/1
2001/7
2002/1
2002/7
2003/1
2003/7
2004/1
2004/7
2005/1
2005/7
2006/1
2006/7
2007/1
2007/7
2008/1
2008/7
2009/1
2009/7
0.02
•
Insert Figures A6-A8 from Monthly Price Data Here—
Turning on the Lights 2010
53
1999/1
1999/3
1999/5
1999/7
1999/9
1999/11
2000/1
2000/3
2000/5
2000/7
2000/9
2000/11
2001/1
2001/3
2001/5
2001/7
2001/9
2001/11
2002/1
2002/3
2002/5
2002/7
2002/9
2002/11
2003/1
2003/3
2003/5
2003/7
2003/9
2003/11
2004/1
2004/3
2004/5
2004/7
2004/9
2004/11
2005/1
2005/3
2005/5
2005/7
2005/9
2005/11
2006/1
2006/3
2006/5
2006/7
2006/9
2006/11
2007/1
2007/3
2007/5
2007/7
2007/9
2007/11
2008/1
2008/3
2008/5
2008/7
2008/9
2008/11
2009/1
2009/3
2009/5
2009/7
2009/9
2009/11
0.015
Restr…
Regul…
0.01
0.005
2E-17
-0.005
-0.01
Turning on the Lights 2010
54
0.006
14
0.005
0.004
Positive values when REST states price increase more than
REG states (or fall less than)
12
10
0.003
0.002
8
0.001
6
0
-0.001
4
-0.002
2
-0.003
Negative values when REST states price decrease more than REG
states (or increase less than)
0
1999/2
1999/4
1999/6
1999/8
1999/10
1999/12
2000/2
2000/4
2000/6
2000/8
2000/10
2000/12
2001/2
2001/4
2001/6
2001/8
2001/10
2001/12
2002/2
2002/4
2002/6
2002/8
2002/10
2002/12
2003/2
2003/4
2003/6
2003/8
2003/10
2003/12
2004/2
2004/4
2004/6
2004/8
2004/10
2004/12
2005/2
2005/4
2005/6
2005/8
2005/10
2005/12
2006/2
2006/4
2006/6
2006/8
2006/10
2006/12
2007/2
2007/4
2007/6
2007/8
2007/10
2007/12
2008/2
2008/4
2008/6
2008/8
2008/10
2008/12
2009/2
2009/4
2009/6
2009/8
2009/10
2009/12
-0.004
Grid-Related Connection to High Prices in Restructured States
Little attention has been paid to the role that the relatively congested transmission grid
structure has played in the Northeast as a factor driving prices higher. The states that have
shown the steepest price increases are largely on the East Coast where the transmission
grid is stretched to its limit due to heavy demand in crowded areas. Getting permissions
for extending or building new grid capacity is nearly impossible. Restructuring has added
a number of new burdens to the system.90
90
National Corridor includes certain counties in Ohio, West Virginia, Pennsylvania, New As a result, the Department of Energy’s
designated the Mid-Atlantic Area as a National Interest Electric Transmission Corridor in order to focus the industry’s attention on
making it more robust. The DOE based its designations on data and analysis showing that persistent transmission congestion exists
in these two areas. The Mid-Atlantic Area York, Maryland, Virginia, and all of New Jersey, Delaware, and the District of Columbia.
Turning on the Lights 2010
55
Transmission congestion costs add to the price of delivered electricity. Congestion can
also warp decisions about which power plants to dispatch and make the system less
efficient.91 The increased cost adds to “congestion costs” paid by transmission buyers that
eventually find their way into buyer bills. (see, for example, Connecticut)
91
See, for example, ESAI Power’s report on “Achievements in Electricity Industry Restructuring in Connecticut” which notes the
role of high distribution costs in pushing up Connecticut prices.
Turning on the Lights 2010
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16
14
12
10
Difference
8
Restructured Non-Congested
States
6
Restructured Congested States
4
2
-2
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009p
0
Figure 9: Congested versus Non-Congested Restructured States
Figure 9 above looks separately at restructured states that touch the historically congested
major Northeast Corridor power lines cited in the NIETC report (all of the states in the
NIETC plus Connecticut) and separate them from restructured states that do not touch
those lines. This gives us a look at states that are facing the same regulatory changes and
fuel price increases so that we can look specifically at the transmission question. It
appears that the spread between Congested States minus non-Congested states swings
from negative to positive around 2005—coincident with the sharp increase in restructured
state retail prices. By the end of 2009, the spread is a little more than 2 cents per kw/h.
That accounts for most of the size of the spread between restructured and regulated states.
Removing congested states gives the remaining restructured areas approximately the
same price curve shape as monopoly-regulated states.
Turning on the Lights 2010
57
Investment
Initial concerns that market competition might lead to a lack of generator investment
appear to have been contradicted by events. Low natural gas prices and high electricity
prices around 1990-1991 led to a boom in natural gas-fired generation in the following
years as depicted in Figure 10. This burst of investment combined almost as much
investment as occurred in the previous 20 years into a single 5-year period at the peak of
the transition into restructured markets.
Another way of looking at generation investment is to examine generators’ rated capacity
compared to the summer peak demand period. The difference is known as the Reserve
Capacity Margin. Since the adequacy of generating capacity is determined by its relation
to the amount of electricity demanded during peak usage times, one can argue that this is
a better gauge of generation investment than raw increases in output capacity.
Ratio(Rest/Reg)
1.8
1.6
1.4
Ratio(Rest-Reg)
1.2
Turning on the Lights 2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
1993
1992
1991
1990
1
58
Here we see the boom in generation construction in the middle part of the last decade
adding a lot to Reserve Capacity. This extra cushioning was enhanced after the major
recession began late in 2008. The reason for the greater capacity additions in restructured
markets was that plant owners in those states could capture the costs of construction and
pass it on to consumers in the form of future production potential that will in due course
keep a lid on costs. Regulated states, on the other hand, do not have the ability to respond
so flexibly to changes in the market.
In restructured states, higher costs lead directly to higher prices for end-users. This means
that end-users feel cost increases more quickly and sharply than they did under Classic
Regulation. However, failure to pass on fuel cost increases (keeping electricity rates
constant while costs rise) means that utilities have to cut back on other things in order to
buy fuel. Those “other things” might be maintenance or overhead, but they might also be
investment in new generators and improved energy efficiency. This means utilities often
cut back on investments in fuel efficient plants when energy prices rise—exactly the
reverse of the long-term interest of power consumers. When costs are falling (as typically
happens during a recession) utilities might have money for investment, but they have less
scope for cutting electricity rates to accommodate hurting customers. Utilities wind up
delaying projects when they should be accelerating them, and raising rates when they
should be cutting them.
For example, as the U.S. economy was hitting the bottom of a major recession in late
2009, utilities were filing for rate increases of between 5% and 10%. The reason given
for the increase was that the utilities needed more money to invest in their electricity
grids, (which would have been more useful during the previous economic expansion).92
The rate increases came as U.S. electricity output fell 3.7% in 2009, the steepest drop
since 1938.93
92
93
Smith, Rebecca. “Utilities Push for Round of Rate Increases.” Wall Street Journal 27 Nov. 2009: A4. Print.
Smith, Rebecca. “Turmoil in Power Sector; Falling Electricity Demand Trips Up Utilities Plans for Infrastructure Projects.”
Wall Street Journal 14 Jan. 2010: n. pag. Print.
Turning on the Lights 2010
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Figure 10: Capacity Additions1957-2008
Source: Energy Velocity
Note: Summer Capacity by Commercial Online Year
Chapter 4. Preparing for the Revolution(s) Ahead: 2010-2020
Over the next 10 years the power business will have to keep up with revolutionary
changes in all areas of the industry: generation, transmission and distribution,
consumption, emerging technologies, and markets.
The Revolution in Generation: Fuel costs are changing as are environmental
regulations. As a result, power plants are burning more natural gas and lower proportions
of coal.94 By 2011, NERC expects natural gas to overtake coal as the dominant fuel
source for peak capacity generation in North America and to account for 32% of the onpeak resource mix.95
Merchant generators are boosting the role of solar, wind and other non-carbon sources.
Society is going through a second wave of environmental awareness since the 1960s, this
94
Basheda, Gregory, Marc Chupka, Peter Fox-Penner, Johnannes Pfeifenberger, and Adam Schumacher. 2006. Why
are Electricity Prices Increasing? An Industry-Wide Perspective. The Edison Foundation.
95
“Reliability Assessments,” Reliability Assessment for 2009, http://www.nerc.com/page.php?cid=4|61.
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time centered on global climate change concerns.96 At the same time, there is again a
growing doubt as to future energy supplies and a recent petroleum-based price shock.
Novel technologies are opening the way to new services that save energy and open
entirely new commercial possibilities.
Renewable Energy:
Renewable fuel sources including solar, and wind, are taking an increasing share of the
load in RTO states. Wind-power is the fastest growing new electricity source.9798An
assessment of data from the Energy Information Administration indicates that renewable
power output grew almost twenty 20 times faster in restructured states as compared to
states remaining regulated over the period 2000 through 2005.99 100 The growth of
renewable energy promises to solve several concerns, including the desire to reduce
emissions of carbon-dioxide and other Green House Gasses (GHG) and to preserve
potentially limited carbon fuels.101 On the other hand, observers note that “green” energy
are not a cure-all. Because wind is an intermittent resource, conventional power plants
need to keep more generation equipment in fuel-consuming “spinning reserve” status in
96
Bird, Lori, Claire Kreycik, and Barry Friedman. “Green Power Marketing in the United States: A Status Report
(2008 Data).” Alliance for Sustainable Energy Sept. 2009. Web. 31 Mar. 2010.
97
Christensen Associated Energy Consulting, LLC, National Rural Electric Cooperation Assoc. “The Regional
Transmission Report Card: Wholesale Electricity Markets and RTO Performance Evaluation 3rd Edition.” 18 Feb.
2009: n. pag. Print.
98
“2009_LTRA.pdf,” n.d., http://www.nerc.com/files/2009_LTRA.pdf p. 9.
99
Energy Information Administration.
100
A major reason wind-producers prefer to sell to restructured RTO markets is that they can get market-based
prices for balancing energy rather than punitive energy imbalance penalties associated with traditional utility
transmission tariffs. The fairer treatment of wind power’s variable output removes a barrier to use of wind power.
Analysis by the U.S. Department of Energy concluded, “Experience has shown that using well-functioning hourahead and day-ahead markets and expanding access to those markets are effective tolls for dealing with wind’s
variability.”100 The American Wind Energy Association, Natural Resources Defense Council, the Environmental Law
and Policy Center, and other groups agree, saying, “Well-structured regional bulk power electricity markets
operated independently allow far greater amounts of renewable energy and demand response resources to be
integrated into the nation’s electric grid.” 100
101
Lori Bird, Claire Kreycik, and Barry Friedman, “Green Power Marketing in the United States: A Status Report
(2008 Data),” n.d., http://www.nrel.gov/docs/fy09osti/46581.pdf.
Turning on the Lights 2010
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case clouds block the sun, or the wind dies. Wind generators may also be regarded by
some as unsightly and their safety for wildlife has been questioned.102
•
Place here a graphic of Power by Fuel Source in the Year 2007: Regulated and
Restructured using data from Energy Information Agency’s Annual Electricity Report.
This should simply be a bar chart with two parallel bars with proportions of fuel sources
of regulated and restructured states side by side. –
Demand Reduction
Demand reduction is already reshaping the energy business in many parts of the country
by smoothing out peak demand periods. Efforts to expand demand reduction techniques
should be encouraged as should more careful study of its long-term effects on the
reliability of the bulk power system. Regulations should respond flexibly to new uses in
this rapidly growing area.
•
Insert here a table you can download from EIA called “Table 8.13 Electric Utility
Demand-Side Management Programs, 1989-2007” You should be able to Google it—
Policy Proposals: Government should reconsider imposing subsidies or quotas for renewable
fuel. In particular, subsidies for solar panels seems particularly inefficient.Yet solar modules are
accounting for ever greater proportions of some states’ electricity. As those figures grows it will
begin to account for a disproportionate share of household spending on energy and increase the
political pressure to find cheaper ways of abating carbon emissions than building forests of solar
panels. Wind power, by comparison, is much closer to being competitive with other standard
forms of electrical production.
The Revolution in Distribution: As of 2010, the nation still has a creaky power grid
needing an update. Smart Grid103 will add more wires and redundancies. Modern
transmission technologies must be implemented. It will change the current analog grid
system where power flows from generator to buyer, into a system where both power and
102
H. Sterling Burnett, Power for the Future: The Debate Over New Coal-Fired Power Plants in Texas,” NCPA
report, January 2008. www.NCPA.org
103
The name given to an electric transmission grid that permits two-way communications between utilities and
their customers
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digitized data flow in all directions, permitting an interactive market with real-time
prices. Higher capacity lines owned by merchant distributors will span greater distances
allowing power to flow across North America and linking in more consumers and
generators, including windmills, solar farms, and small home-size systems.
The current electricity grid consists of a mix put together over the course of the 19th and
20th centuries in a way that sprawled after population growth. It has none of the
redundancies or room for extra growth that would be planned into a system if we were
building it from scratch. Instead, many regions of the country exist as power islands.
Need to develop new transmission capacity to alleviate chronic congestion in the
Northeast Corridor and Southern California, as well as accommodate new stresses from
restructured bulk power markets.
There are numerous problems to building and financing new power grid capacity:
Conflicts of Interest: A power line that is needed to link generation and load at points A
and B might take traffic away from a seemingly unrelated link between C and D making
it uneconomical. So, it becomes difficult for the grid operator to know for certain if the
proposed extension creates a net benefit or not.
Regulated markets
They are incapable of delivering the services needed to expand services of the next
generation of electricity distribution networks.
Investments to realize the promise of Smart Grid as well as other major problems of the
grid infrastructure and generation could amount to a $1.5 trillion over the next 20 years.104
The heart of the Smart Grid is a new type of device that is replacing the old electricity
meters in many homes and businesses.The Federal Stimulus Bill of 2009 will spend about
104
The Brattle Group, Transforming America’s Power Industry: The Investment Challenge 2010-2030, Edison
Foundation, November 2008.
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$4.5 billion on smart-grid projects.105 The stimulus will triple the number of Smart
Meters to 28 million by the end of 2010, permitting two-way communications between
utilities and customers in nearly a third of U.S. households.106 This infrastructure will
allow many new industries to develop, generating many new jobs.
Policy Recommendation: Encourage new forms of grid ownership that draw private
investor funds. Regulators should seriously consider allowing entrepreneurs to build a
second level of utility power lines into homes that could carry Smart Grid
technologies,107 or eventually act as a replacement for the existing Power Grid. The new
grid connections need not exactly duplicate the functions of the old grid, thereby avoiding
any chance of inefficient investment in redundant public goods. Instead, the second wire
might be a light duty 9 volt wire that mainly carries data, drives some low-power fullyautomated appliances, and can also be used to upload home-manufactured power onto the
grid. This would not change the economics of the full-power grid, but its physical
separation from utility-controlled wires would guarantee that Old Grid owners could not
stifle new Smart Grid products and businesses.
The Revolution in Consumption: Smart use of power by buyers is already re-shaping
use patterns. Each time more buyers give up their right to use power during peak periods
in exchange for lower rates and/or payments (Demand Response), they move more of the
power demand cycle into off-peak periods. This cuts the need for new generators
designed to meet peak power loads. This is a deep change that affects new generator
financing and makes real-time data about power use more valuable.
Buyers will get new tools to manage their energy use in a cost-effective way. The new
technologies will open the door to a whole range of new ways to participate in the energy
market, from electricity fueled automobiles to allowing residential buyers and businesses
105
Rebecca Smith and Ben Worthen, “Stimulus Funds Speed Transformation Toward 'Smart Grid\',” wsj.com,
September 28, 2009, sec. Technology, http://online.wsj.com/article/SB125409459487544787.html.
106
Jeff St John, “The Top Ten in Smart Grid in 2009 : Greentech Media,” greentechgrid, December 29,
2009, http://www.greentechmedia.com/articles/read/the-top-ten-in-smart-grid-in-2009.
107
“Electricity 2.0: Unlocking the Power of the Open Energy Network (OEN) | NDN,” http://ndn.org/electricity20.
Turning on the Lights 2010
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to generate their own electricity and sell surplus into the market. The dramatic technology
changes in telecom are a very real example for energy markets to follow.
Micro-nets and community nets (also known as Power Parks in some parts of the world)
would allow small groups of consumers—residential, commercial or industrial—to
produce electricity and other byproducts such as steam for heating, cooling or industrial
processes in a cooperative way. Under current regulatory schemes such activities are
possible but extremely difficult because they cause planning and operational problems for
regulators, utilities and grid operators. As authorities become better at managing loads in
a decentralized market where prices are determined at specific locations and they have
better information, resistance to these operations may decrease over time and make
everyone better off.
The Revolution in New Technologies/Businesses: New businesses and technologies are
emerging at an impressive rate and target every level of the power market value chain.
From new technologies to pull natural gas out of “depleted” oil fields, to new software
being invented at places like Google to help market traders and home power buyers track
and value their power use.

Power storage is an example of a technology and a business model specifically
designed to benefit from the new power market. Storage is invaluable for keeping
the system balanced even when a lot of power comes from variable sources, such
as wind or solar.

Real-time pricing and dissemination of market information will allow consumers
to fine-tune their energy consumption using services that they can buy
commercially. As buyers become sellers who can bid their home-grown power
production into the grid, consumers will also be able to fine-tune their production
and sales to the grid.
Turning on the Lights 2010
65

For example, Google has made available its Power Meter software that tracks
electricity use at home. Another way to cut power costs is by promising to reduce
load by a certain amount during peak use periods.
Another business that could arise would be energy management, which would give
buyers one stop shopping for transportation fuel, heating, lighting, air conditioning,
across all energy markets such as natural gas, electrical power, and other fossil fuels.
Plug-in Hybrid Electric Vehicles (PHEV) are one of the more intriguing possibilities for
the next generation of Smart Grid use because they could exemplify how consumers can
play a number of different roles in the new Smart Grid economy. As consumers, PHEV
owners could choose to consumer domestically-produced electricity rather than (largely)
foreign produced gasoline to fuel their transportation needs—assuming that current
concerns with high cost, battery capacity and the need for fast-recharging are solved.
PHEV also gives consumers the ability to act as sellers of power since the PHEV could
be used to store electric power generated by wind or solar panels until such time as it can
be profitably sold back onto the Smart Grid, according to the wholesale market price.
Much like EBay, home consumers can open up their own power generation-storage-and
resale businesses holding near continuous auctions for buying or selling power from the
front porch.
Additionally, powering a car on electricity would result in 93% less smog-forming
volatile organic compounds and 31% less nitrogen oxide emissions than powering a car
on gasoline. Running an electric care would cost 3-5 cents per mile, the equivalent of
$0.75 to $1.25 per gallon of gasoline.108
Other new Smart Grid businesses would include:
108
Barry T Smitherman, “Public Priorities and the Role of Competition” (KEMA's 21st Executive Forum, March 30,
2010), www.puc.state.tx.us/about/commissioners/smitherman/.../KEMA_033010.pdf.Smitherman, “Public
Priorities and the Role of Competition.”
Turning on the Lights 2010
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
Demand Response Aggregators: Businesses that collect commitments to reduce
power use during peak use periods and assemble them into large groups of power
users (they might be retail, commercial or industrial) that could allow more types
of power users to participate in the Demand Response market.

Networked Appliances. Makers of home appliances around the world are already
building into their devices the ability to switch into a power-saving “brown out”
mode, or even to turn themselves off when they receive a command. Automated
devices are plugged into a home network that also monitors market prices for
electricity and responds to changes in prices.

The ‘Wired’ Grid. Just as appliances within the home can be networked together,
so can the devices used to operate the grid itself.

Home Operating Systems. If your home is generating electricity and using it at the
same time, deciding which generators to run and what devices to use to be most
efficient quickly becomes a complex calculation. Eventually, many homes will
need an overall “operating system” to run all of the other systems in the house
such as vehicle charging, home energy monitoring, demand response
management, solar panels, batteries, plug-in vehicle chargers serving as “virtual
power plants.”
Policy Recommendation: There is considerable public suspicion of Smart Meters in the
general public and policy-makers will face pressure to limit their use, or severely regulate
them. Restricting the use of Smart Meters would be a mistake as would a narrow federal
definition for who owns what information stored in the Smart Meter. On the other hand,
consumers’ rights of property and choice should be respected, including the right to
replace or remove a Smart Meter when no contracts are violated. People should be
allowed to take themselves “off the grid” And have legal recourse when technology is
misused.
Turning on the Lights 2010
67
The Revolution in Markets: Ever more sophisticated and dependable markets spring up
as more participants enter the markets and more energy and ancillary services are traded
over greater distances. Hurdles for moving power between the three major grid
interconnections are getting smaller. But the need for short-term capacity and redundancy
becomes greater as wind and solar get more important.
To meet the economic and environmental needs of the 21st Century requires a public
policy approach to electric power promoting a more dynamic, buyer-oriented electric
power industry. To many working in the industry, the goal will sound a little strange;
almost every investment, plan, and operation done in the industry is done with the goal of
selling electric power where and when buyers want it.
But there is a “one size fits all” mentality in utility offerings – the product of decades of
regulation of electric utilities – that screens out much of the diversity among consumers’
values and interests and reduces the consumer to a small number of simple statistics:
energy bought, peak load, rate structure. We need a new measure for the market, and that
measure should be based on the consumer.
Recommendation: Bulk power markets need better demand side participation to become
more effective, but demand side participation requires retail market openness. Allowing
retail choice and competition will create meaningful demand-side buyers in bulk power
markets and make the markets more robust, transparent and liquid.
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4E85C6-7EAC-40A0-8DC3003829518EBD%257D/Value_of_Independent_Regional_Grid_Operators.pdf+value+of
+independent+regional+grid+operators&cd=1&hl=en&ct=clnk&gl=us&client=firefox-a.
43. Vernon L. Smith and Stephen Rassenti, “Turning On The Lights: Deregulating The Market
for Electricity - Study #228,” October 1999, http://www.ncpa.org/pub/st228.
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44. Ali Hortacsu and Steven Lawrence Puller, “Understanding Strategic Bidding in Restructured
Electricity Markets: A Case Study of Ercot,” SSRN eLibrary (February 2005),
http://papers.ssrn.com/sol3/papers.cfm?abstract_id=667164.
45. James B Bushnell, Erin T Mansur, and Celeste Saravia, “Vertical Arrangements, Market Structure,
and Competition: An Analysis of Restructured US Electricity Markets,” American Economic
Review 98, no. 1 (3, 2008): 237-266.
46. John A. Sautter, “Where Have All the Benefits Gone? Cost Allocation Toward Residential
Ratepayers in Restructured Electricity Markets,” The Electricity Journal 20, no. 2 (March 2007):
36-43.
GLOSSARY
Agregator: Any marketer, broker, public agency, city, county, or special district that combines the loads of multiple end-use customers in facilitating
the sale and purchase of electric energy, transmission, and other services on behalf of these customers.
Ampere: The unit of measurement of electrical current produced in a circuit by 1 volt acting through a resistance of 1 ohm.
Ancillary Services: Necessary services that must be provided in the generation and delivery of electricity. As defined by the Federal Energy
Regulatory Commission, they include: coordination and scheduling services (load following, energy imbalance service, control of transmission
congestion); automatic generation control (load frequency control and the economic dispatch of plants); contractual agreements (loss compensation
service); and support of system integrity and security (reactive power, or spinning and operating reserves).
Average Revenue per Kilowatthour: The average revenue per kilowatthour of electricity sold by sector (residential, commercial, industrial, or other)
and geographic area (State, Census division, and national), is calculated by dividing the total monthly revenue by the corresponding total monthly
sales for each sector and geographic area.
Base Bill: A charge calculated through multiplication of the rate from the appropriate electric rate schedule by the level of consumption.
Baseload: The minimum amount of electric power delivered or required over a given period of time at a steady rate.
Baseload Capacity: The generating equipment normally operated to serve loads on an around-the-clock basis.
Baseload Plant: A plant, usually housing high-efficiency steam-electric units, which is normally operated to take all or part of the minimum load of a
system, and which consequently produces electricity at an essentially constant rate and runs continuously. These units are operated to maximize
system mechanical and thermal efficiency and minimize system operating costs.
Bilateral Agreement: Written statement signed by a pair of communicating parties that specifies what data may be exchanged between them.
Bilateral Contract: A direct contract between the power producer and user or broker outside of a centralized power pool or power exchange.
Black Out: The shutdown of a generating unit, transmission line or other facility, for emergency reasons or a condition in which the generating
equipment is unavailable for load due to unanticipated breakdown.
Boiler: A device for generating steam for power, processing, or heating purposes or for producing hot water for heating purposes or hot water supply.
Heat from an external combustion source is transmitted to a fluid contained within the tubes in the boiler shell. This fluid is delivered to an end-use at
a desired pressure, temperature, and quality.
Btu (British Thermal Unit): A standard unit for measuring the quantity of heat energy equal to the quantity of heat required to raise the temperature
of 1 pound of water by 1 degree Fahrenheit.
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Bundled Utility Service: All generation, transmission, and distribution services provided by one entity for a single charge. This would include
ancillary services and retail services.
California Power Exchange: The California Power Exchange Corporation, a State chartered, non-profit corporation charged with providing DayAhead and Hour-Ahead markets for energy and ancillary services, if it chooses to self-provide, in accordance with the power exchange tariff. The
power exchange is a Scheduling Coordinator and is independent of both the Independent System Operator and all other market participants.
Capacity: The amount of electric power delivered or required for which a generator, turbine, transformer, transmission circuit, station, or system is
rated by the manufacturer.
Cogenerator: A generating facility that produces electricity and another form of useful thermal energy (such as heat or steam), used for industrial,
commercial, heating, or cooling purposes. To receive status as a qualifying facility (QF) under the Public Utility Regulatory Policies Act (PURPA), the
facility must produce electric energy and "another form of useful thermal energy through the sequential use of energy," and meet certain ownership,
operating, and efficiency criteria established by the Federal Energy Regulatory Commission (FERC). (See the Code of Federal Regulations, Title 18, Part
292.)
Combined Cycle: An electric generating technology in which electricity is produced from otherwise lost waste heat exiting from one or more gas
(combustion) turbines. The exiting heat is routed to a conventional boiler or to a heat recovery steam generator for utilization by a steam turbine in the
production of electricity. This process increases the efficiency of the electric generating unit.
Combined Cycle Unit: An electric generating unit that consists of one or more combustion turbines and one or more boilers with a portion of the
required energy input to the boiler(s) provided by the exhaust gas of the combustion turbine(s).
Commercial: The commercial sector is generally defined as nonmanufacturing business establishments, including hotels, motels, restaurants,
wholesale businesses, retail stores, and health, social, and educational institutions. The utility may classify commercial service as all consumers whose
demand or annual use exceeds some specified limit. The limit may be set by the utility based on the rate schedule of the utility.
Congestion: A condition that occurs when insufficient transfer capacity is available to implement all of the preferred schedules for electricity
transmission simultaneously.
Contract Price: Price of fuels marketed on a contract basis covering a period of 1 or more years. Contract prices reflect market conditions at the time the
contract was negotiated and therefore remain constant throughout the life of the contract or are adjusted through escalation clauses. Generally,
contract prices do not fluctuate widely.
Cooperative Electric Utility: An electric utility legally established to be owned by and operated for the benefit of those using its service. The utility
company will generate, transmit, and/or distribute supplies of electric energy to a specified area not being serviced by another utility. Such ventures
are generally exempt from Federal income tax laws. Most electric cooperatives have been initially financed by the Rural Electrification Administration,
U.S. Department of Agriculture.
Cost: The amount paid to acquire resources, such as plant and equipment, fuel, or labor services.
Cost-of-Service Regulation: Traditional electric utility regulation under which a utility is allowed to set rates based on the cost of providing service to
customers and the right to earn a limited profit.
Customer Choice: Allowing all customers to purchase kilowatthours of electricity from any of a number of companies that compete with each other.
Day-Ahead Market: The forward market for energy and ancillary services to be supplied during the settlement period of a particular trading day that
is conducted by the Independent System Operator, the power exchange, and other Scheduling Coordinators. This market closes with the Independent
System Operator's acceptance of the final day-ahead schedule.
Delivery Only Providers: Owners and/or operators of transmission and distribution system equipment who provide billing and related energy
services for the transmission and delivery of electricity.
Demand (Electric): The rate at which electric energy is delivered to or by a system, part of a system, or piece of equipment, at a given instant or
averaged over any designated period of time.
Demand-Side Management: The planning, implementation, and monitoring of utility activities designed to encourage consumers to modify patterns
of electricity usage, including the timing and level of electricity demand. It refers only to energy and load-shape modifying activities that are
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undertaken in response to utility-administered programs. It does not refer to energy and load-shape changes arising from the normal operation of the
marketplace or from government-mandated energy-efficiency standards. Demand-Side Management (DSM) covers the complete range of load-shape
objectives, including strategic conservation and load management, as well as strategic load growth.
Deregulation: The elimination of regulation from a previously regulated industry or sector of an industry.
Distribution: The delivery of electricity to retail customers (including homes, businesses, etc.).
Divestiture: The stripping off of one utility function from the others by selling (spinning-off) or in some other way changing the ownership of the
assets related to that function. Stripping off is most commonly associated with spinning-off generation assets so they are no longer owned by the
shareholders that own the transmission and distribution assets.
Electric Plant (Physical): A facility containing prime movers, electric generators, and auxiliary equipment for converting mechanical, chemical, and/or
fission energy into electric energy.
Electric Service Provider: An entity that provides electric service to a retail or end-use customer.
Electric Utility: A corporation, person, agency, authority, or other legal entity or instrumentality that owns and/or operates facilities within the United
States, its territories, or Puerto Rico for the generation, transmission, distribution, or sale of electric energy primarily for use by the public and files
forms listed in the Code of Federal Regulations, Title 18, Part 141. Facilities that qualify as cogenerators or small power producers under the Public
Utility Regulatory Policies Act (PURPA) are not considered electric utilities.
Energy: The capacity for doing work as measured by the capability of doing work (potential energy) or the conversion of this capability to motion
(kinetic energy). Energy has several forms, some of which are easily convertible and can be changed to another form useful for work. Most of the
world's convertible energy comes from fossil fuels that are burned to produce heat that is then used as a transfer medium to mechanical or other means
in order to accomplish tasks. Electrical energy is usually measured in kilowatthours, while heat energy is usually measured in British thermal units.
Energy Charge: That portion of the charge for electric service based upon the electric energy (kWh) consumed or billed.
Energy Efficiency: Refers to programs that are aimed at reducing the energy used by specific end-use devices and systems, typically without affecting
the services provided. These programs reduce overall electricity consumption (reported in megawatthours), often without explicit consideration for the
timing of program-induced savings. Such savings are generally achieved by substituting technically more advanced equipment to produce the same
level of end-use services (e.g. lighting, heating, motor drive) with less electricity. Examples include high-efficiency appliances, efficient lighting
programs, high-efficiency heating, ventilating and air conditioning (HVAC) systems or control modifications, efficient building design, advanced
electric motor drives, and heat recovery systems.
Energy Only Providers: Power marketers or other electricity vendors who provide an unbundled service and bill for only the energy component of the
electricity consumed by the end-use customer.
EPACT: The Energy Policy Act of 1992 addresses a wide variety of energy issues. The legislation creates a new class of power generators, exempt
wholesale generators, that are exempt from the provisions of the Public Holding Company Act of 1935 and grants the authority to the Federal Energy
Regulatory Commission to order and condition access by eligible parties to the interconnected transmission grid.
Federal Energy Regulatory Commission (FERC): A quasi-independent regulatory agency within the Department of Energy having jurisdiction over
interstate electricity sales, wholesale electric rates, hydroelectric licensing, natural gas pricing, oil pipeline rates, and gas pipeline certification.
Fossil Fuel: Any naturally occurring organic fuel, such as petroleum, coal, and natural gas.
Fuel: Any substance that can be burned to produce heat; also, materials that can be fissioned in a chain reaction to produce heat.
Full Service Providers: Utilities, municipalities, cooperatives and others who provide both electricity and the transmission services necessary to
delivery it to end use customers.
Futures Market: Arrangement through a contract for the delivery of a commodity at a future time and at a price specified at the time of purchase. The
price is based on an auction or market basis. This is a standardized, exchange-traded, and government regulated hedging mechanism.
Generation (Electricity): The process of producing electric energy by transforming other forms of energy; also, the amount of electric energy produced,
expressed in watthours (Wh).
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Generation Company: A regulated or non-regulated entity (depending upon the industry structure) that operates and maintains existing generating
plants. The generation company may own the generation plants or interact with the short-term market on behalf of plant owners. In the context of
restructuring the market for electricity, the generation company is sometimes used to describe a specialized "marketer" for the generating plants
formerly owned by a vertically-integrated utility.
Generator: A machine that converts mechanical energy into electrical energy.
Generator Nameplate Capacity: The full-load continuous rating of a generator, prime mover, or other electric power production equipment under
specific conditions as designated by the manufacturer. Installed generator nameplate rating is usually indicated on a nameplate physically attached to
the generator.
Gigawatthour (GWh): One billion watthours.
Greenhouse Effect: The increasing mean global surface temperature of the earth caused by gases in the atmosphere (including carbon dioxide,
methane, nitrous oxide, ozone, and chlorofluorocarbon). The greenhouse effect allows solar radiation to penetrate but absorbs the infrared radiation
returning to space.
Grid: The layout of an electrical distribution system.
Independent Power Producers: Entities that are also considered nonutility power producers in the United States. These facilities are wholesale
electricity producers that operate within the franchised service territories of host utilities and are usually authorized to sell at market-based rates.
Unlike traditional electric utilities, Independent Power Producers do not possess transmission facilities or sell electricity in the retail market.
Independent System Operators (ISO): An independent, Federally-regulated entity that coordinates regional transmission in a non-discriminatory
manner and ensures the safety and reliability of the electric system.
Industrial: The industrial sector is generally defined as manufacturing, construction, mining agriculture, fishing and forestry establishments Standard
Industrial Classification (SIC) codes 01-39. The utility may classify industrial service using the SIC codes, or based on demand or annual usage
exceeding some specified limit. The limit may be set by the utility based on the rate schedule of the utility.
Interruptible Load: Refers to program activities that, in accordance with contractual arrangements, can interrupt consumer load at times of seasonal
peak load by direct control of the utility system operator or by action of the consumer at the direct request of the system operator. It usually involves
commercial and industrial consumers. In some instances the load reduction may be affected by direct action of the system operator (remote tripping)
after notice to the consumer in accordance with contractual provisions. For example, loads that can be interrupted to fulfill planning or operation
reserve requirements should be reported as Interruptible Load. Interruptible Load as defined here excludes Direct Load Control and Other Load
Management. (Interruptible Load, as reported here, is synonymous with Interruptible Demand reported to the North American Electric Reliability
Council on the voluntary Form EIA-411, "Coordinated Regional Bulk Power Supply Program Report," with the exception that annual peakload effects
are reported on the Form EIA-861 and seasonal (i.e., summer and winter) peakload effects are reported on the EIA-411).
Investor-Owned Utility: A class of utility whose stock is publicly traded and which is organized as a tax-paying business, usually financed by the sale
of securities in the capital market. It is regulated and authorized to achieve an allowed rate of return.
Kilowatt (kW): One thousand watts.
Kilowatthour (kWh): One thousand watthours.
Load (Electric): The amount of electric power delivered or required at any specific point or points on a system. The requirement originates at the
energy-consuming equipment of the consumers.
Locational Marginal Pricing: LMP is a way for wholesale electric energy prices to efficiently reflect the variations in supply, demand, and
transmission system limitations wherever electric energy enters or exits the high-voltage physical transmission system controlled by the ISO. In
New England, wholesale electricity prices are set at 900 pricing points (i.e., pnodes) on the bulk power grid. LMPs differ among these locations as a
result of each location’s marginal cost of congestion and marginal cost of line losses. The congestion cost component of an LMP arises because of the
need to dispatch individual generators to provide more or less energy because of transmission system constraints that limit the flow of economic
power. Line losses occur during the physical process of transmitting electric energy, which produces heat and results in less power being
withdrawn from the system than was injected. Line losses and their associated marginal costs are inherent to transmission lines and other grid
infrastructure as electric energy flows from generators to loads. As with the marginal cost of congestion, the marginal cost of losses has an impact
on the amount of generation that needs to be dispatched. The ISO operates the system to minimize total system costs.
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Market-Based Pricing: Electric service prices determined in an open market system of supply and demand under which the price is set solely by
agreement as to what a buyer will pay and a seller will accept. Such prices could recover less or more than full costs, depending upon what the buyer
and seller see as their relevant opportunities and risks.
Market Clearing Price: The price at which supply equals demand for the Day Ahead and/or Hour Ahead Markets.
Megawatthour (MWh): One million watthours.
Monopoly: One seller of electricity with control over market sales.
Natural Gas: A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in porous geological formations beneath the earth's
surface, often in association with petroleum. The principal constituent is methane.
Nuclear Power Plant: A facility in which heat produced in a reactor by the fissioning of nuclear fuel is used to drive a steam turbine.
Open Access: A regulatory mandate to allow others to use a utility's transmission and distribution facilities to move bulk power from one point to
another on a nondiscriminatory basis for a cost-based fee.
Outage: The period during which a generating unit, transmission line, or other facility is out of service.
Peak Demand: The maximum load during a specified period of time.
Peaking Capacity: Capacity of generating equipment normally reserved for operation during the hours of highest daily, weekly, or seasonal loads.
Some generating equipment may be operated at certain times as peaking capacity and at other times to serve loads on an around-the-clock basis.
Planned Generator: A proposal by a company to install electric generating equipment at an existing or planned facility or site. The proposal is based
on the owner having obtained (1) all environmental and regulatory approvals, (2) a signed contract for the electric energy, or (3) financial closure for
the facility.
Power: The rate at which energy is transferred. Electrical energy is usually measured in watts. Also, used for a measurement of capacity
Power Marketers: Business entities engaged in buying, selling, and marketing electricity. Power marketers do not usually own generating or
transmission facilities. Power marketers, as opposed to brokers, take ownership of the electricity and are involved in interstate trade. These entities file
with the Federal Energy Regulatory Commission for status as a power marketer.
Power Pool: An association of two or more interconnected electric systems having an agreement to coordinate operations and planning for improved
reliability and efficiencies.
Price: The amount of money or consideration-in-kind for which a service is bought, sold, or offered for sale.
Profit: The income remaining after all business expenses are paid.
Providers of Bundled Retail Energy: Similar to full service providers, except for their operation in deregulated markets, as in Texas (Retail Electricity
Providers).
PURPA: The Public Utility Regulatory Policies Act of 1978, passed by the U.S. Congress. This statute requires States to implement utility conservation
programs and create special markets for co-generators and small producers who meet certain standards, including the requirement that States set the
prices and quantities of power the utilities must buy from such facilities.
Rate Base: The value of property upon which a utility is permitted to earn a specified rate of return as established by a regulatory authority. The rate
base generally represents the value of property used by the utility in providing service and may be calculated by any one or a combination of the
following accounting methods: fair value, prudent investment, reproduction cost, or original cost. Depending on which method is used, the rate base
includes cash, working capital, materials and supplies, and deductions for accumulated provisions for depreciation, contributions in aid of
construction, customer advances for construction, accumulated deferred income taxes, and accumulated deferred investment tax credits.
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Reactive Power: The portion of electricity that establishes and sustains the electric and magnetic fields of alternating-current equipment. Reactive power must be
supplied to most types of magnetic equipment, such as motors and transformers. Reactive power is provided by generators, synchronous condensers, or electrostatic
equipment such as capacitors and directly influences electric system voltage. It is a derived value equal to the vector difference between the apparent power and the
real power. It is usually expressed as kilovolt-amperes reactive (kVAR) or megavolt-ampere reactive (MVAR). See Apparent Power, Power, Real Power.
Ratemaking Authority: A utility commission's legal authority to fix, modify, approve, or disapprove rates, as determined by the powers given the
commission by a State or Federal legislature.
Regional Transmission Group: A utility industry concept that the Federal Energy Regulatory Commission embraced for the certification of voluntary
groups that would be responsible for transmission planning and use on a regional basis.
Regulation: The governmental function of controlling or directing economic entities through the process of rulemaking and adjudication.
Reliability: Electric system reliability has two components--adequacy and security. Adequacy is the ability of the electric system to supply to
aggregate electrical demand and energy requirements of the customers at all times, taking into account scheduled and unscheduled outages of system
facilities. Security is the ability of the electric system to withstand sudden disturbances, such as electric short circuits or unanticipated loss of system
facilities. The degree of reliability may be measured by the frequency, duration, and magnitude of adverse effects on consumer services.
Renewable Resources: Naturally, but flow-limited resources that can be replenished. They are virtually inexhaustible in duration but limited in the
amount of energy that is available per unit of time. Some (such as geothermal and biomass) may be stock-limited in that stocks are depleted by use, but
on a time scale of decades, or perhaps centuries, they can probably be replenished. Renewable energy resources include: biomass, hydro, geothermal,
solar and wind. In the future, they could also include the use of ocean thermal, wave, and tidal action technologies. Utility renewable resource
applications include bulk electricity generation, on-site electricity generation, distributed electricity generation, non-grid-connected generation, and
demand-reduction (energy efficiency) technologies.
Reregulation: The design and implementation of regulatory practices to be applied to the remaining regulated entities after restructuring of the
vertically-integrated electric utility. The remaining regulated entities would be those that continue to exhibit characteristics of a natural monopoly,
where imperfections in the market prevent the realization of more competitive results, and where, in light of other policy considerations, competitive
results are unsatisfactory in one or more respects. Regulation could employ the same or different regulatory practices as those used before
restructuring.
Reserve Margin (Operating): The amount of unused available capability of an electric power system at peakload for a utility system as a percentage of
total capability.
Residential: The residential sector is defined as private household establishments which consume energy primarily for space heating, water heating,
air conditioning, lighting, refrigeration, cooking and clothes drying. The classification of an individual consumer's account, where the use is both
residential and commercial, is based on principal use. For the residential class, do not duplicate consumer accounts due to multiple metering for
special services (water, heating, etc.). Apartment houses are also included.
Restructuring: The process of replacing a monopoly system of electric utilities with competing sellers, allowing individual retail customers to choose
their electricity supplier but still receive delivery over the power lines of the local utility. It includes the reconfiguration of the vertically-integrated
electric utility.
Retail: Sales covering electrical energy supplied for residential, commercial, and industrial end-use purposes. Other small classes, such as agriculture
and street lighting, also are included in this category.
Retail Competition: The concept under which multiple sellers of electric power can sell directly to end-use customers and the process and
responsibilities necessary to make it occur.
Retail Market: A market in which electricity and other energy services are sold directly to the end-use customer.
Retail Wheeling: The process of moving electric power from a point of generation across one or more utility-owned transmission and distribution
systems to a retail customer.
Revenue: The total amount of money received by a firm from sales of its products and/or services, gains from the sales or exchange of assets, interest
and dividends earned on investments, and other increases in the owner's equity except those arising from capital adjustments.
Sales: The amount of kilowatthours sold in a given period of time; usually grouped by classes of service, such as residential, commercial, industrial,
and other. Other sales include public street and highway lighting, other sales to public authorities and railways, and interdepartmental sales.
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Sales for Resale: Energy supplied to other electric utilities, cooperatives, municipalities, and Federal and State electric agencies for resale to ultimate
consumers.
Scheduling Coordinators: Entities certified by the Federal Energy Regulatory Commission that act as a go-between with the Independent System
Operator on behalf of generators, supply aggregators (wholesale marketers), retailers, and customers to schedule the distribution of electricity.
Spinning Reserve: That reserve generating capacity running at a zero load and synchronized to the electric system.
Spot Purchases: A single shipment of fuel or volumes of fuel, purchased for delivery within 1 year. Spot purchases are often made by a user to fulfill a
certain portion of energy requirements, to meet unanticipated energy needs, or to take advantage of low-fuel prices.
Stranded Costs: Prudent costs incurred by a utility which may not be recoverable under market-based retail competition. Examples are undepreciated
generating facilities, deferred costs, and long-term contract costs.
System (Electric): Physically connected generation, transmission, and distribution facilities operated as an integrated unit under one central
management, or operating supervision.
Transmission System (Electric): An interconnected group of electric transmission lines and associated equipment for moving or transferring electric
energy in bulk between points of supply and points at which it is transformed for delivery over the distribution system lines to consumers, or is
delivered to other electric systems.
Unbundling: The separating of the total process of electric power service from generation to metering into its component parts for the purpose of
separate pricing or service offerings.
Utility Distribution Companies: The entities that will continue to provide regulated services for the distribution of electricity to customers and serve
customers who do not choose direct access. Regardless of where a consumer chooses to purchase power, the customer's current utility, also known as
the utility distribution company, will deliver the power to the consumer's home, business, or farm.
Vertical Integration: An arrangement whereby the same company owns all the different aspects of making, selling, and delivering a product or
service. In the electric industry, it refers to the historically common arrangement whereby a utility would own its own generating plants, transmission
system, and distribution lines to provide all aspects of electric service.
Wheeling Service: The movement of electricity from one system to another over transmission facilities of intervening systems. Wheeling service
contracts can be established between two or more systems.
Wholesale Power Market: The purchase and sale of electricity from generators to resellers (who sell to retail customers), along with the ancillary
services needed to maintain reliability and power quality at the transmission level.
Wholesale Transmission Services: The transmission of electric energy sold, or to be sold, at wholesale in interstate commerce (from EPACT).
Wires Charge: A broad term which refers to charges levied on power suppliers or their customers for the use of the transmission or distribution wires.
Zonal Pricing: A feature of a wholesale market where electricity trades are quoted at a single price throughout all geographic locations in a market and
transmission costs are not taken into account in the price of the trade. This is different than Locational Marginal Pricing where trades are quoted at a
price specific to the geographic location of the node in the Grid where the electricity is drawn from the system (see LMP above).
Adapted from
Electric Power Industry Terms and Definitions. Energy Information Agency, Department of Energy,
http://www.eia.doe.gov/cneaf/electricity/page/glossary.html
And the 2008 Annual Markets Report of ISO New England Inc.
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