a

GAO

United States Government Accountability Office

Report to the Chairman, Committee on 

Governmental Affairs, U.S. Senate

August 2004 ELECTRICITY 

MARKETS

Consumers Could 

Benefit from Demand 

Programs, but 

Challenges Remain

GAO-04-844
www.gao.gov/cgi-bin/getrpt?GAO-04-844.

To view the full product, including the scope 

and methodology, click on the link above. 

For more information, contact Jim Wells at 

(202) 512-3841 or wellsj@gao.gov. 

Highlights of GAO-04-844, a report to the 

Chairman, Committee on Government 

Affairs, U.S. Senate 

August 2004

ELECTRICITY MARKETS 

Consumers Could Benefit from Demand 

Programs, but Challenges Remain 

The efficient and reliable 

functioning of the more than $200 

billion electric industry is vital to 

the lives of all Americans. As 

demonstrated in the 2003 blackout in the Northeast and the 2001 

energy crisis in the West, changes 

in the cost and availability of 

electricity can have significant 

impacts on consumers and the 

national economy. The Federal 

Energy Regulatory Commission 

(FERC) supports using demandresponse programs as part of its 

effort to develop and oversee 

competitive electricity markets. 

GAO was asked to identify (1) the 

types of demand-response 

programs currently in use, (2) the 

benefits of these programs, (3) the 

barriers to their introduction and 

expansion, and (4) instances where 

barriers have been overcome. 

Additionally, GAO examined the 

federal government’s participation 

in these programs through the 

General Services Administration 

(GSA). 

GAO recommends that (1) FERC 

consider demand-response in 

making decisions about wholesale 

markets and report to Congress on 

any impediments to doing so and 

(2) GSA make demand-response a 

key factor in its energy decision 

making. 

There are two general types of electricity demand-response programs in use: 

(1) market-based pricing programs enable customers to respond to changing 

electricity prices and (2) reliability-driven programs allow either the 

customer or the grid operator to adjust electricity usage when supplies are 

scarce or system reliability is a concern. The federal government’s GSA 

participates in both types of programs. 

Demand-response programs benefit customers by improving the functioning 

of markets and enhancing the reliability of the electricity system. Some 

recent studies show that demand-response programs have saved customers 

millions of dollars and could save billions of dollars more. The GSA—as 

only one example of federal involvement in these programs—has reported 

saving about $1.9 million through the participation of only a few of its 

buildings in demand-response programs during the past 5 years. However, 

GAO estimates that GSA could potentially save millions of dollars more with 

broader participation in these programs. 

While benefits from demand-response are potentially large, three main 

barriers limit their introduction and expansion: (1) state regulations that 

shield consumers from price fluctuations, (2) a lack of equipment at 

customers’ locations, and (3) customers’ limited awareness about the 

programs and their benefits. Regarding prices, customers do not respond to 

price fluctuations because the retail prices they see do not reflect market 

conditions but are generally set by state regulations or laws. In addition, in 

recent years, moderate weather conditions and other factors have kept 

overall electricity prices low, reducing the benefits of participating in these 

programs. According to GSA, its participation in demand-response programs 

has been limited because it lacks specific guidance on participation and 

tenants have little incentive to reduce their consumption since current leases 

do not provide a way to share in the savings that might occur. 

Two demand-response programs that GAO reviewed illustrate how the 

barriers GAO identified were overcome and also point out lessons on how to 

cultivate new programs. Lessons learned include the necessity to provide 

sufficient incentives to make participation worthwhile, working with 

receptive state regulators and market participants to develop programs, and 

designing programs to include appropriate outreach materials, necessary 

equipment, and easy participation. 

In commenting on the report, FERC and GSA agreed in general with the 

report’s conclusions and recommendations, but GSA expressed concern 

about one recommendation to share potential savings with its tenants. 
Page i GAO-04-844 Electricity Markets

Contents

Letter 1

Results in Brief 4

Background 7

Market-Based and Reliability Programs Allow Demand to Respond 

to Changing Prices and Supply Shortages but Are in Limited

Use 12

Demand-Response Programs Have Saved Millions of Dollars and 

Can Improve the Reliability of the Electricity System 21

Multiple Barriers Make It Difficult to Introduce and Expand 

Demand-Response Programs 31

Certain Programs Show How Barriers Were Overcome and Provide 

Lessons on How to Cultivate New Programs 37

Conclusion 42

Recommendations for Executive Action 43

Agency Comments and Our Evaluation 45

Appendixes

Appendix I: Scope and Methodology 47

Appendix II: Selected Experts Interviewed 50

Appendix III: Comments from the Federal Energy Regulatory 

Commission 51

GAO Comments 56

Appendix IV: Comments from the General Services Administration 59

Appendix V: GAO Contacts and Staff Acknowledgments 62

GAO Contacts 62

Staff Acknowledgments 62

Tables Table 1: Studies of the Benefits of Existing Market-Based Pricing 

Programs for Regions and Specific Programs 22

Table 2: Studies of Potential Benefits of Demand-Response 25

Figures Figure 1: Illustration of Variations in Market-Based Pricing 

Systems 14

Figure 2: Gulf Power's Energy Control System for Residential 

Participants in GoodCents Select 39
Contents

Page ii GAO-04-844 Electricity Markets

Abbreviations

DOE Department of Energy

FERC Federal Energy Regulatory Commission

GSA General Services Administration

ISO Independent System Operator

NEDRI New England Demand Response Initiative

NERC North American Electric Reliability Council

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Page 1 GAO-04-844 Electricity Markets

United States Government Accountability Office

Washington, D.C. 20548

A

August 13, 2004 Letr

The Honorable Susan M. Collins

Chairman, Committee on Governmental Affairs

United States Senate

Dear Chairman Collins:

The efficient and reliable functioning of the electric industry is vital to the 

nation's economy and central to the lives of all Americans. Annual 

expenditures on electricity amount to about $224 billion, and electricity 

provides the power to produce billions of dollars more in revenue in other 

industries. As a result, changes in the price and availability of electricity 

can have substantial impacts on customers and the broader economy. In 

particular, two events have drawn attention to the need to examine the 

operation and direction of the industry. The August 14, 2003, blackout that 

affected New York and seven other states in the eastern section of the 

nation’s electricity system—the largest blackout in U.S. history—caused 

losses in productivity and revenue estimated in the billions of dollars. Just 

a few years earlier, in 2000 and 2001, the energy crisis in the West boosted 

rates for customers, forced some utilities into bankruptcy, created 

additional uncertainty in electricity markets, led to rolling blackouts, and 

demonstrated that the electricity market was subject to price manipulation. 

The federal government and some states are restructuring the electric 

industry with the goal to increase the amount of competition in wholesale 

and retail electricity markets, which is expected to lead to benefits for 

electricity consumers. As such, the industry is restructuring from one that 

is characterized by monopoly utilities that provided customers with 

electricity at regulated rates to a competitive industry in which prices are 

determined largely by supply and demand. Restructuring is already under 

way at the federal level for wholesale markets—markets in which power is 

bought and sold by utilities that are overseen by the Federal Energy 

Regulatory Commission (FERC). As part of this process, FERC is 

responsible for changes to wholesale market rules, including rules to allow 

new suppliers to enter wholesale markets and sell electricity. FERC is also 

responsible for making sure that prices in these markets are “just and 

reasonable” and does so by the promotion of competitive markets and 

issuing related market rules. Restructuring of retail markets—markets 

serving customers—is also under way in 17 states and the District of 

Columbia, while other states have either suspended or delayed previous 

plans or do not have plans to restructure their markets. Despite some state 
Page 2 GAO-04-844 Electricity Markets

initiatives to restructure, almost all retail prices continue to be set by 

regulation or state law and are not determined by supply and demand.

Whether subject to traditional regulation or the rules of a competitive 

market, the electric industry must manage a complex network of power 

plants and power lines. Since electricity travels at the speed of light and 

cannot be easily stored, the output of power plants must be matched 

precisely with demand for electricity to maintain the reliability of the 

network. Because of the need to precisely match supply and demand at all 

times, wholesale and retail markets are operationally joined. However, 

demand varies significantly with the time of day and year, generally 

reaching its highest levels on hot summer afternoons. As demand grows, 

utilities increase output from the power plants already supplying electricity 

and add a sequence of plants to meet the rising levels of demand. The last 

plants used to meet rising demand, so-called “peak demand” plants, are 

generally much more expensive to operate and generally operate the 

equivalent of only a few days per year. As a result, the costs of generating 

electricity can vary dramatically, becoming about 10 times more expensive 

during periods of peak demand than during periods of average demand. 

In both regulated and restructured markets, the system continues to be 

balanced by changes in supply. Historically, grid operators maintain 

reliability by increasing or decreasing the amount of electricity available 

from power plants. The average prices customers pay are determined 

predominantly by the costs associated with these changes in supply. 

However, when prices are set by regulation or law and change infrequently, 

customers are largely insulated from frequent and short-term changes in 

the cost to generate electricity. Industry experts have long said that 

encouraging customers to change their demand for electricity in response 

to ongoing changes in its price may offer cost and operating advantages 

over relying solely upon changes in supply. Toward this end, some utilities 

and system operators have created a variety of electricity pricing and other 

programs that encourage customers to adjust their usage in response to 

changes in prices or market conditions affecting reliability of service. 

These programs are collectively referred to as “demand-response” 

programs. 

According to FERC, demand-response is an important part of wellfunctioning electricity markets but largely missing from today’s markets. 

Further, there is general agreement among industry experts that the 

absence of retail demand-response contributes to problems in wholesale 

markets, allowing higher, more volatile prices and the exercise of market 
Page 3 GAO-04-844 Electricity Markets

power by electricity sellers. For example, FERC determined that the 

absence of consumer response to sharply higher prices in western 

wholesale electricity markets contributed to the financial and energy crisis 

there. FERC has approved proposals by several grid operators to 

incorporate demand-response into the wholesale markets that they 

oversee, but these efforts have met with limited success. As part of a 

broader effort to develop consistent rules for regional markets, referred to 

as its Standard Market Design proposed rule, FERC proposed an effort to 

encourage demand-response in wholesale markets. However, this broad 

effort was delayed because of resistance to certain aspects of the broader 

effort. Because its jurisdiction is largely limited to wholesale markets, 

FERC has said that states bear the primary responsibility for implementing 

demand-response in retail markets. Nonetheless, the wholesale and retail 

markets interact, affecting the supply and price of electricity in both. 

In this context, you asked us to examine the current and potential role for 

demand-response programs. To address this issue, we identified (1) the 

types of demand-response programs currently in use; (2) the benefits of 

these programs; (3) the barriers to their introduction and expansion; and 

(4) where possible, instances in which these barriers have been overcome. 

In addition, we examined the federal government’s participation in these 

programs through the General Services Administration (GSA)—a large 

operator of commercial office space throughout the country. GSA’s 

involvement in these programs is discussed in answering the first three 

objectives.

To assess demand-response programs, their benefits, barriers to expansion, 

ways to overcome barriers, and the federal government’s participation, we 

reviewed the literature, analyzed industry and participant data, and 

conducted interviews with state and federal officials (in FERC, the 

Department of Energy , and the GSA), industry experts, representatives 

from utilities, and customers. We examined four programs, two in states 

with restructured retail markets (California and New York) and two in 

states with traditionally regulated retail markets (Florida and Georgia). We 

selected these programs because they have operated for several years and 

experts consider them innovative and successful models. To determine 

GSA’s participation in demand-response programs, we interviewed 

headquarters and regional staff and obtained information about electricity 

consumption and demand-response activities at 53 buildings where GSA is 

responsible for some or all of the electricity costs. These buildings incurred 

the highest electricity expenses of the about 1,400 GSA-operated buildings 

nationwide and represented about 40 percent of the agency’s total 
Page 4 GAO-04-844 Electricity Markets

electricity expenses in 2003. We used data from GSA’s Energy Usage 

Analysis System and, while we did not do a complete data reliability 

assessment, we reviewed the steps GSA has taken to ensure the data were 

reliable. Further, we did limited testing of the data by comparing it with 

information from our interviews with GSA regional energy managers at the 

53 buildings and found no significant discrepancies. We concluded that the 

data were reliable for the purposes of this report. We obtained information 

on participation and the benefits of demand-response programs for a 5-year 

period—1999 through 2003. We conducted our work from March 2003 

through July 2004 in accordance with generally accepted government 

auditing standards.

Results in Brief Two types of demand-response programs are in limited use: “market-based 

pricing” and “reliability-driven” programs. Market-based pricing programs 

enable customers to adjust their use of electricity in response to changing 

prices. For example, in a Georgia program involving about 1,600 mostly 

business customers, prices varied hourly depending on supply and demand. 

According to customers we interviewed, they turned off specific electric 

equipment or operated their own on-site generation during periods when 

prices were higher and/or shifted activities such as manufacturing to times 

when prices were lower. Market-based pricing programs are only available 

on a limited basis with only a small share of overall demand subject to 

changing prices. Reliability programs enable grid operators to request that 

customers reduce electricity use when hot weather or system malfunctions 

mean that demand will probably exceed supply and cause a blackout. 

Customers told us that they can participate in these types of programs by 

reducing their demand on the grid by shutting down equipment or by 

generating their own electricity. For example, managers of a program in 

New York State have established agreements that allow the utility to reduce 

demand substantially, with short notice. Although reliability programs are 

more widely available than market-based pricing programs, their use is 

limited. The GSA reported that 33 of the 53 buildings with the largest 

electricity consumption are currently registered to participate in a variety 

of both market-based pricing and reliability programs across the country. 

Demand-response programs, according to the literature we reviewed and 

experts we spoke with, can benefit customers in regulated and 

restructured markets by improving market functions and enhancing the 

reliability of the electricity system. First, markets function better when 

prices are more closely linked to the cost of supply. This linkage can lead to 

lower prices and significant savings because utilities have less need to use 
Page 5 GAO-04-844 Electricity Markets

expensive power plants to meet peak demand, price spikes caused by 

market conditions or by market manipulation are reduced, and industry 

has greater incentives for energy efficiency and other innovations. Recent 

studies show that demand-response programs have saved millions of 

dollars—including about $13 million during a heat wave in New York State 

during 2001. A FERC-commissioned study reported that a moderate 

amount of demand-response could save about $7.5 billion annually in 2010. 

The four programs we reviewed also produced significant savings. For 

example, household customers in a Florida program achieved average 

savings of 11 percent per year in 2002. Second, demand-response programs 

may enhance reliability because they afford greater flexibility to grid 

operators, who can change supply or demand to meet their needs. Such 

programs reduced the number of blackouts in California in 2000 and 2001. 

Regarding benefits to the federal government, GSA estimated that it saved 

about $1.9 million from 13 of the 33 buildings that participated in demandresponse programs from 1999 through 2003. The amount of these benefits 

has been limited to some extent because the agency has not actively 

participated in these programs. If GSA was able to achieve the level of 

participation reported to us at all of their large facilities, savings could 

reach $12 million to $114 million over a 5-year period, according to our 

analysis. 

Although demand-response programs can provide benefits, they face three 

main barriers to their introduction and expansion: (1) state regulations 

that shield customers from short-term price fluctuations, (2) the absence of 

equipment installed at customers’ sites required for participation, and (3) 

customers’ limited awareness of programs and their potential benefits. 

First, customers do not respond to price fluctuations because the retail 

prices they see do not reflect market conditions but are generally set by 

state regulations or laws. This lack of response becomes important during 

periods of high demand, when actual costs are highest (because peak 

demand plants are used), but customers remain unaware of the higher 

costs and thus have no incentive to reduce their demand. Because retail 

consumers do not reduce their demand, they can also unknowingly harm 

wholesale markets by driving up prices higher than competitive levels. 

Second, most customers currently lack the necessary equipment, which 

includes meters for measuring when electricity is consumed and cell 

phones, pagers, or other mechanisms for communication with the utility. 

These items are not routinely required of customers, and neither customers 

nor energy companies are eager to pay for this equipment. Third, 

customers are not always aware of demand-response programs and their 

potential benefits. According to the operator of demand-response 
Page 6 GAO-04-844 Electricity Markets

programs in New York State, about half of the customers that it believed 

were well informed about electricity matters were unaware that these 

programs were available to them. In addition, several factors beyond the 

programs’ control—including moderate weather, a slow national economy, 

and surplus generating capacity in some parts of the country—have 

combined to keep overall prices low in recent years, reducing the financial 

benefits for participating in these programs, according to industry experts. 

However, they also note that such programs may be urgently needed later, 

when supplies are limited and prices are high. According to GSA officials, 

the agency’s participation in demand-response programs has been limited 

because it lacks specific internal guidance on participation, tenants have 

little incentive to reduce their consumption, and other factors such as mild 

weather conditions have further diminished participation. 

Two demand-response programs that we reviewed illustrate how these 

barriers can be overcome and also point out three broader lessons on how 

to cultivate new programs. For example, to introduce a market-based 

pricing program in a regulated market, a Florida utility demonstrated to 

state regulators that its program could offer benefits, such as lower prices 

to participants, without increasing costs to nonparticipants. The utility also 

developed outreach materials (such as a video) and provided technology 

that automated consumer response to prices to simplify participation. In 

another instance, officials in New York State overcame the barriers of 

inadequate consumer awareness and infrastructure by educating 

consumers about a new reliability program during a time when supply 

shortages were expected and prices would likely rise. To promote this 

program, the grid operator developed brochures and other sources of 

information that described the problems to be addressed and the potential 

benefits to participants. It also provided equipment to communicate rapidly 

and effectively when supplies were short and reliability was in jeopardy (an 

automated telephone notification system). More broadly, these examples 

offer three important lessons for nurturing such programs. First, programs 

with sufficient incentives, such as a clear price difference between peak 

and off-peak consumption, make customers’ participation worthwhile. In 

other areas, programs have been abandoned when this price difference was 

insufficient to attract participants or to induce participants to reduce their 

usage during critical periods. Second, programs have a higher chance of 

success if they are begun where state regulators and market participants 

are receptive to the potential benefits of demand-response programs in 

their areas. Third, to achieve these benefits and also increase the chances 

of success, the design of programs should include appropriate outreach, 

necessary equipment, and easy participation.
Page 7 GAO-04-844 Electricity Markets

We are making recommendations that FERC consider additional actions to 

ensure that wholesale markets are not unnecessarily harmed by retail 

buyers, broadly review options to implement effective demand-response, 

and outreach with states, among other things. We also recommend that 

GSA make participation in demand-response a key factor in its energy 

decision making, identify programs for participation, educate building 

operators, and align incentives so that it can more fully benefit from these 

programs.

We provided FERC and GSA a draft of our report for review and comment. 

FERC endorsed our conclusions regarding the importance of demandresponse to competitive energy markets and to electricity system 

reliability. FERC generally agreed with the report’s recommendations. GSA 

also agreed with the report’s conclusions regarding the importance of 

demand-response to an efficient and reliable electricity industry. GSA 

stated that it agreed with the majority of our recommendations, but 

expressed concerns about one recommendation for GSA to share savings 

with tenants for successful demand-response participation. GSA stated that 

such sharing would not be practical because the agency, under its current 

leases, would assume all the risks associated with electric costs, while 

sharing the benefits with its tenants. We revised the recommendation to 

reflect GSA’s concerns about risk by adding that risk should also be shared 

between the agency and its tenants. As revised, we believe the 

recommendation provides sufficient flexibility for GSA to develop practical 

approaches in sharing financial incentives as well as penalties with its 

tenants without compromising tenant satisfaction. 

Background

Demand and Supply in 

Regional Electricity 

Systems Must Be 

Continually Balanced and 

Adjusted

To avoid blackouts and other disruptions, the amount of electricity 

customers demand must be continually balanced with the amount of 

electricity power plants supply. This balance is essential because electricity 

cannot be economically stored. The operators of the electricity system, 

who oversee the complex network of thousands of power plants and power 

lines, collectively called the grid, coordinate this process. The continental 

United States is divided into three large regional electricity systems (East, 

West, and Texas). Changes in demand or supply within each of the three 

regions can affect the entire region, reinforcing the need for coordination. 
Page 8 GAO-04-844 Electricity Markets

Preserving this balance is challenging because customers use sharply 

different amounts of electricity through the course of the day and year. 

Typically, demand rises through the day and reaches its highest point—

called the peak—in late afternoon. In some parts of the country, average 

hourly demand can be up to twice as high during late afternoon as it is 

during the middle of the night, when it is the lowest. In addition to the daily 

variation in demand, electricity demand varies seasonally, mainly because 

air conditioning accounts for a large share of overall electricity usage in 

many parts of the country during the summer. In some cases, peak usage 

can be nearly twice as high during the summer as it is in the winter. 

Regardless of when electricity is used, the electricity network must have 

sufficient generating capacity to meet the highest levels of demand to avoid 

blackouts. A variety of power plants, ranging from “baseload” plants 

designed to operate nearly all the time to “peakers” that generally operate 

only a few hours per day in the summer, are used to meet demand through 

the day and year. Baseload plants are generally the most costly to build, but 

they generally have the lowest costs for generating electricity on an hourly 

basis. In contrast, peakers are much less costly to build but much more 

costly to operate. 

The use of costly power plants that are seldom used results in higher 

electricity prices. In general, grid operators maximize the amount supplied 

by the baseload plants. However, as demand rises through the day and 

through the year, they must use plants that are more costly to operate. 

Because of this need to use more costly plants, the differences in the 

overall costs of meeting hour-to-hour demand are sometimes quite large. 

For example, the average cost of generation can rise tenfold from when 

demand is at its lowest at night to when it is at its highest in the late 

afternoon. Although the cost of generating electricity during peaks can be 

quite high, these periods are generally short and account for only a small 

percentage of the hours during a year. According to one expert, although 

the 100 highest priced hours of the year account for only about 1 percent of 

the hours in a year, they can account for 10 to 20 percent of the total 

electricity expenditures for the year. Regardless of how often or how long 

demand reaches its highest levels, power plants must be built to meet at 

least this level of demand to avoid blackouts. Because the cost of building 

and operating these seldom-used plants must be recovered through higher 

electricity prices, the need to build and use them adds directly to these 

prices. 
Page 9 GAO-04-844 Electricity Markets

Federal Restructuring of the 

Electricity Sector Has 

Expanded the Role of 

Competition and Markets, 

but States Remain Divided 

on Market Development

A combination of federal, state, and local governments, as well as a private 

entity oversee aspects of the electric industry. The federal government, 

through FERC, oversees the interstate transmission of electricity and the 

operation of wholesale markets—competitive markets in which power is 

bought and sold by utilities and other re-sellers. FERC has the statutory 

responsibility to assure that prices in these markets are “just and 

reasonable.” As noted, FERC has historically done this by approving rates 

to recover justifiable costs and providing for a regulated rate of return. 

FERC now seeks to meet its statutory obligation by establishing and 

maintaining competitive markets, believing that competitive markets will 

produce prices that are just and reasonable. 

As part of this oversight, FERC has changed a number of rules to allow, for 

instance, new suppliers to enter competitive wholesale markets by granting 

them “market-based rate authority.” In essence, this authority permits 

suppliers to sell electricity in these markets at market-based prices. In 

contrast, FERC does not currently limit access of large buyers—including 

those who resell to retail buyers. To further competition, FERC also 

approves the creation of new regional entities to operate the electricity 

grid. In addition to overseeing the daily balancing of supply and demand, 

some of these grid operators also operate wholesale markets for electricity. 

States, through their public utility commissions or equivalent, oversee 

retail markets—markets directly serving customers. In this regulatory role, 

state commissions have historically approved utility plans for power 

plants, transmission lines, and other capital investments needed to supply 

electricity; they have also set rates to recover these costs and provide the 

utility with an approved profit margin. Under this arrangement, regulated 

electricity prices have historically been set as a single price, generally an 

average of the costs of serving a wide customer class, such as residential 

customers.1

 Thus most of today’s electricity system is a hybrid—

competition setting wholesale prices and regulation largely setting retail 

prices. In addition, neither FERC nor the states generally have jurisdiction 

over electricity entities owned by cities, such as the Los Angeles 

Department of Water and Power, or utilities owned by their customers, 

such as rural electric cooperatives and local public utility districts; these 

entities account for about 25 percent of the wholesale market and are selfregulated by an elected board. 

1

In some instances, state public utility commissions have allowed the use of time-of-use 

rates, or other time-differentiated pricing, but these cases are limited.
Page 10 GAO-04-844 Electricity Markets

In addition to involvement by federal and state agencies, a private 

membership organization made up of large electricity providers in the 

United States—the North American Electric Reliability Council (NERC)—

establishes technical and operational standards to maintain the reliable 

operation of the electricity networks. However, membership in NERC and 

adherence to its standards are currently voluntary, and it cannot penalize 

nonmembers who do not adhere to these standards. Among other NERC 

standards, utilities must maintain specific amounts of power in reserve in 

the event that demand rises to a higher level than expected or supply is 

interrupted, such as when a power plant has to shut down unexpectedly. 

In addition to FERC’s direct regulatory oversight, the federal government 

influences the electricity sector through the Department of Energy (DOE). 

Broadly, DOE formulates national energy policy, funding research and 

development on various energy-related technologies (e.g., energy-efficient 

air conditioners and refrigerators and other appliances); setting some 

standards for energy efficiency; analyzing energy issues; and disseminating 

information about energy issues to the states, industry, and the public. 

More specifically, DOE established the Office of Electric Transmission and 

Distribution in August 2003 “to lead a national effort to help modernize and 

expand America’s electric delivery system to ensure a more reliable and 

robust electricity supply.” This office worked jointly with FERC and the 

Canadian government to investigate the causes of the August 14, 2003, 

blackout in the northeastern United States and parts of Canada. 

Both FERC and DOE 

Believe That DemandResponse Programs Could 

Address a Number of 

Problems

Over the past 20 years, experts have begun to recognize the potential 

advantages of allowing customers to see and respond to market conditions. 

Historically, grid operators have maintained reliable operations by 

increasing or decreasing the amount of electricity supplied that was needed 

to meet changes in demand. However, industry experts have long said that 

allowing customers to change their demand in response to ongoing 

changes in prices or limitations in supply may offer cost and operating 

advantages over relying solely upon changes in supply. Further, these 

experts generally believe that only a small amount of demand, in total, may 

be needed to bring about these advantages. 

In this regard, FERC and DOE have said that demand-response is an 

important part of well-functioning electricity markets but is largely missing 

from today’s markets. In 2001 FERC staff concluded that demand-response 

could reduce market power, reduce price spikes, and reduce electricity 

bills, among other things. Over the past several years FERC has identified 
Page 11 GAO-04-844 Electricity Markets

problems with some wholesale markets, such as periodic price spikes and 

efforts by some electricity suppliers to manipulate prices. Further, FERC 

has said that the absence of demand-response can worsen price spikes and 

allow suppliers to manipulate prices, both of which produce prices that are 

higher than its estimate of competitive prices. For example, in its 2002 

proposed market design, FERC stated that if customers are allowed to 

respond to high prices, then price volatility and the ability of sellers to 

manipulate prices could be reduced. FERC has determined that several 

electricity sellers in the West manipulated prices during periods when 

supplies were scarce and that customers did not reduce demand in 

response to these high prices. Over the past several years, FERC has 

approved proposals by grid operators in New York State, New England, and 

California to incorporate demand-response into the wholesale markets 

they operate, but these efforts are unique to each grid operator and have 

not yet attracted significant participation. As part of a broader effort, 

referred to as Standard Market Design, to develop consistent rules for 

regional markets to promote more efficient and reliable electricity markets, 

FERC proposed a limited effort to encourage consistent demand-response 

in wholesale markets. However, this effort to implement demand-response 

was delayed because of resistance to certain aspects of the broad effort. 

In 2000, a DOE team studying a series of electric power outages in the U.S. 

found that the ability of customers to manage their demand in response to 

market prices was key to ensuring reliable electric service and the efficient 

functioning of competitive electric markets. More recently, DOE’s Office of 

Electric Transmission and Distribution believes that demand-response 

could help resolve price and reliability problems and plans a demandresponse initiative as part of its strategy to help modernize the grid. 

Further, DOE’s Federal Energy Management Program has promoted 

awareness of demand-response programs, pointing out opportunities for 

electricity users to receive payment for reducing use during specific 

periods of time.
Page 12 GAO-04-844 Electricity Markets

The Federal Government 

and General Services 

Administration Are Large 

Electricity Users

The federal government is a large owner and user of commercial and other 

building space. As of September 30, 2000, the federal government owned 

about 3 billion square feet of office space and leased about an additional 

350 million square feet.2

 While the Department of Defense is the largest 

user of building space (accounting for about two-thirds of the total owned 

building space), the General Services Administration (GSA) is the principal 

landlord for the federal government, operating buildings totaling about 330 

million square feet and leasing the space to federal agency tenants; it owns 

about 55 percent of this space and leases the remaining space from private 

building owners. Nationally, GSA pays the energy bills for about 200 million 

square feet of office space, including about $210 million for electricity used 

at its buildings. Almost half of this total was spent for electricity consumed 

in four states—California, Maryland, New York, and Texas—and the 

District of Columbia. 

Market-Based and 

Reliability Programs 

Allow Demand to 

Respond to Changing 

Prices and Supply 

Shortages but Are in 

Limited Use

Two types of programs enable customers to respond to price variations or 

to supply shortages that may compromise reliable grid operations: marketbased pricing and reliability-driven programs. Market-based pricing 

programs provide customers with information on prices that vary during 

the day based on the actual cost of supplying electricity so that customers 

can voluntarily reduce their use of electricity when prices are high. Overall, 

market-based programs are in relatively limited use with a small share of 

overall demand subject to market-based prices. Reliability-driven programs 

allow grid operators and utilities to avoid widespread blackouts when 

electricity supplies are tight by calling on participating customers to reduce 

demand. While reliability programs are more widely available, active 

participation remains somewhat limited. GSA reported that many of its 

larger facilities are currently registered to participate in both market-based 

pricing and reliability-driven programs across the country.

2

U.S. General Services Administration, Summary Report of Real Property Owned by the 

United States Throughout the World (Washington, D.C.: June 2001). We have reported that 

the governmentwide real property data that GSA compiles—often referred to as the 

worldwide inventory—have been unreliable and of limited usefulness. However, these data 

provide the only available indication of the size and characteristics of the federal real 

property inventory. For more information, see U.S. General Accounting Office, Federal Real 

Property: Better Governmentwide Data Needed for Strategic Decisionmaking, GAO-02-342

(Washington, D.C.: Apr. 16, 2002).
Page 13 GAO-04-844 Electricity Markets

Market-Based Programs 

Transmit Information about 

Changing Prices, Allowing 

Customers to Adjust 

Demand, but Use Is Limited 

Market-based pricing programs provide customers with prices that follow 

changes in electricity production costs throughout the day. We identified 

three general types of market-based pricing programs: time-of-use pricing, 

real-time pricing, and demand bidding. Two of these programs---time-ofuse and real-time pricing—provide customers with retail prices that reflect 

the changes in the cost of electricity throughout the day, as shown in figure 

1. A variation of time-of-use pricing, referred to as critical peak pricing, is 

also shown in figure 1. The third type of program, referred to as demand 

bidding, allows customers to sell back into wholesale markets electricity 

that they otherwise would have consumed. The prices offered by these 

programs differ sharply from the flat average prices that most customers 

face. Market-based prices can rise significantly when demand is high or 

supplies are short. As a result, they provide customers with incentives to 

reduce consumption during periods of peak demand when prices are 

highest. 
Page 14 GAO-04-844 Electricity Markets

Figure 1: Illustration of Variations in Market-Based Pricing Systems 

Critical peak Flat average prices

costs

Costs Critical peak prices

0.0

5.0

10.0

15.0

20.0

25.0

30.0

0.0

5.0

10.0

15.0

20.0

25.0

30.0

Cents per kilowatt hour

Off-peak

 12 a.m.

Off-peak

Mid-peak

 11 p.m.

 6 a.m.

Mid-peak

 6 p.m.

 Peak

12 p.m.

5.0

10.0

15.0

20.0

RTP hourly prices

Costs

Flat average prices

Cents per kilowatt hour

Off-peak

 12 a.m.

Off-peak

 11 p.m.

Mid-peak

 6 a.m.

Mid-peak

 6 p.m.

 Peak

12 p.m.

0.0

Real-time

prices

Average costs

for each time

block based

on historical 

use patterns 

and forecasts of 

costs and 

usage. Critical 

peak prices 

preset at a 

significantly 

higher level to 

reflect when 

costs are higher 

than normal.

Based on 

actual cost of 

electricity for 

each hour for 

each day.

One day or 1 

hour ahead of 

actual 

consumption.

Seasonally, 

such as the 

beginning of 

summer. 

Prices vary for set time blocks during the day, except when

critical peak prices apply. Critical peak prices can be put into

effect at any time but generally have a preset maximum

number of hours per year.

Price varies hourly, and hourly prices vary each day.

Price plan How prices are How prices vary during the day

determined

When prices

change

Time-of-use 

and time-ofuse prices 

with critical 

peak pricing

Source: GAO.
Page 15 GAO-04-844 Electricity Markets

With time-of-use pricing, different preestablished prices are in effect for 

predetermined parts of the day (e.g., off-peak, 11:00 p.m. to 6:00 a.m.; midpeak, 6:00 a.m. to noon and 6:00 p.m. to 10:00 p.m.; peak, noon to 6:00 p.m.). 

The highest prices are established for periods such as the peak when 

demand and cost of supply are generally highest, based on historical cost 

and consumption information, and are designed to encourage consumers 

to reduce demand during those periods. We examined two time-of-use 

programs, one traditional program in California and a variation on that type 

of program in Florida. One industrial consumer operating a refrigerated 

warehouse, and participating in a traditional time of use program, 

explained how he adjusts his operations in response to these rates. By 

refrigerating some products at lower than normal temperatures during the 

night when prices are lower, he can turn the refrigeration equipment off 

during the middle of the day to avoid the higher daytime prices without 

temperatures rising above acceptable levels. While these responses can be 

useful, experts told us, traditional time-of-use prices are unable to reflect 

unforeseen events, such as increased demand because of extreme heat or a 

sudden supply shortage, which may occur if a power plant is unexpectedly 

shut down.

To modify time-of-use rates to accommodate these possibilities, the Florida 

program we reviewed operates a variation on time-of-use rates in a 

voluntary program for about 3,200 residential customers. Gulf Power 

presets prices for three periods per day (peak, off-peak, and mid-peak). 

However, with some advance notification, an additional price preset at a 

much higher level (called the critical peak price) can be put into effect at 

any time when supplies are tight or demand is high; however, this higher 

price cannot be in effect for more than 88 hours per year. An innovative 

control system, provided by the utility, enables customers to program the 

system to shut off as many as four electrical devices in response to preset 

price periods and notifies participants if the critical peak pricing period is 

in effect. The critical peak price was not used in 2003, but in 2002 the utility 

put the additional price into effect on 11 occasions for a total of 12 hours. 

With respect to real-time pricing, prices generally vary for each hour of 

each day and are more closely linked to variations in the actual hourly cost 

of supply than time-of-use rates. There are several different ways of 

implementing real-time pricing programs. For example:

• Niagara Mohawk in New York State allows some of its large customers 

to participate in a program that prices electricity on an hourly basis, 

based on a forecast done the day before consumption is to occur (with 
Page 16 GAO-04-844 Electricity Markets

about 140 customers and accounting for about 8 percent of total 

electricity sales).

• Georgia Power, a regulated utility, offers a voluntary real-time pricing 

program (with 1,600 customers and about 5,000 megawatts3

 (MW) of 

demand) that sets hourly prices 1 hour or 1 day before electricity use, at 

the choice of the participant. Under this program, participants are only 

allowed to pay real-time prices for the new electricity demand added 

since joining the program while paying their regulated rate on the rest of 

their demand. Officials told us that the program was designed this way 

to assure that customers participating in this program continued to pay 

for their share of the utility’s existing network of power plants and 

transmission lines—like the rest of the utility’s customers. Over time, a 

growing business could have a large portion of its demand priced as part 

of the real-time rate, which is generally lower than the regulated rate. As 

a result, competitors in the same business can have different electricity 

costs, a feature that recently has made the program highly sought after 

by customers. Indeed, some customers that had not experienced growth 

sought regulatory and/or court-ordered changes to increase the amount 

of their demand eligible for pricing under the real-time rate. According 

to one participating customer, he actively monitor prices through a Webbased system several times per day, monitors his demand, and reduces 

his demand if prices exceeded predetermined levels. 

The third type of market-based pricing, referred to as demand-bidding 

programs, allows consumers to compete with traditional electricity 

suppliers, such as power plant owners and power marketers, in wholesale 

markets. While the other two types represent retail pricing efforts, demand 

bidding is a wholesale market effort. These programs, generally established 

by the grid operator or the local utility, enable mostly large customers to 

react to changing wholesale prices by offering bids to supply their large 

blocks of potential demand to the grid operator as if they were a power 

plant supplying electricity. We examined one such program operated by the 

New York grid operator, the New York ISO, and approved by FERC. In this 

program, customers who voluntarily sign up can bid amounts of demand 

reduction that they are willing to provide at prices that they determine. 

3

A watt is a measure of electrical power, or work. A kilowatt (KW) is 1,000 watts. A 

megawatt (MW) is 1,000,000 watts. One megawatt is equal to the demand of about 750 

homes. A kilowatt used for 1 hour is equal to 1 kilowatt-hour (KWh). A megawatt used for 1 

hour is equal to 1 megawatt-hour (MWh). 
Page 17 GAO-04-844 Electricity Markets

They are not penalized if they do not bid; however, they are penalized if 

their bid is accepted and they fail to provide the agreed-upon reduction. 

The New York grid operator told us demand bidding was a relatively small 

resource for reducing demand, accounting for 1,500 MWhs, for which 24 

participants were paid $100,000 or more in 2002. One participant told us 

that they were willing to bid when prices reach certain high levels, but they 

were reluctant to do so if prices were low because reducing demand 

generally reduced their production or otherwise hindered their business 

operations. 

For demand-bidding programs to operate, the program operator must 

develop an estimate of participant demand for all hours of the year—called 

a baseline. According to experts, because individual consumer demand 

varies seasonally, in response to the economy, and for other reasons, it is 

often difficult to develop a baseline that accurately estimates demand. 

Further, because most of these customers have not agreed to purchase the 

electricity that they are offering to sell, some experts have questioned 

whether this lack of clear ownership of the electricity raises questions over 

property rights and opens the programs to manipulation. 

Overall, the use of market-based pricing is relatively limited, generally 

affecting only certain types of customers and some areas and accounting 

for a small share of overall demand, with most customers still paying prices 

that are not market-based. Time-of-use pricing programs are available from 

many utilities, but participation is generally limited to some commercial 

and industrial customers. However, in some parts of the country some 

customers have been required to pay time-of-use rates. For example, the 

California Public Utility Commission requires large customers of the state’s 

public utilities to be on time-of-use pricing plans. Real-time pricing 

programs are available in only a few locations, and the number of 

customers enrolled in these programs is generally small. With regard to 

demand bidding, these programs are relatively new and available only in a 

few locations. Even where they are available, active participation has been 

limited to times when wholesale prices are high. 

Reliability Programs Allow 

Grid Operators to Reduce 

Demand in Response to 

Supply Shortages, but Use Is 

Limited 

Reliability-driven programs allow the grid operator or utility to call on 

participating customers to reduce demand during periods of tight supply by 

shutting down equipment or by generating their own electricity. Grid 

operators and utilities activate these programs to avoid widespread 

blackouts during periods of extremely high demand or when a power plant 

or transmission line is shut down unexpectedly. Although enrollment in 
Page 18 GAO-04-844 Electricity Markets

these programs is typically voluntary, the contractual agreements may 

entail financial penalties if a participant does not reduce demand as 

required by the program. We identified three types of reliability-driven 

programs: interruptible rates, direct demand control, and voluntary 

demand reduction. Some programs, such as interruptible rates, are 

targeted at large users such as commercial and industrial customers, while 

others, such as direct demand control, include residential customers.

Interruptible rate programs provide participants with a discount on 

electricity prices during all hours in exchange for the right of the grid 

operator or utility to interrupt electricity supplies if needed. Typically, the 

grid operator or utility requests that the participant reduce demand by 

some preestablished amount. Under the terms of these agreements, 

interruptions are generally limited to a certain number of hours per year, 

and the customer is provided with advance notice that service will be 

interrupted. Although enrollment in these programs is generally voluntary, 

the participant can face significant financial penalties if it fails to reduce 

demand when directed to do so, such as paying market prices for 

electricity that they consume but had agreed to interrupt. 

These programs are appropriate for customers that can curtail 

consumption for short periods with minimal impact on their overall 

operations. For example, an official with one commercial participant that 

operated cold storage facilities also participating in an interruptible rate 

program told us that his operation could reduce consumption within 30 

minutes of a call for interruption by turning off refrigeration units and 

turning down air conditioning and lighting. He said his operation could 

sustain a shutdown for as long as 6 hours without a problem. These 

programs are not appropriate for all consumers, however. Because of 

supply shortages in some areas, such as California, some programs have 

been used more frequently, and some customers realized that they should 

not participate. For example, when Southern California Edison needed to 

call on its participants frequently during the electricity crisis in 2000 and 

2001, it realized that some customers, such as hospitals and other facilities, 

should not have signed up for the programs. Many of these entities were 

unable to comply with requests to reduce demand and faced financial 

penalties, which were later waived. Because of this experience, the 

company said that they now more actively limit participation and routinely 

examine whether participants can reduce demand to the level that they 

agree.
Page 19 GAO-04-844 Electricity Markets

Direct demand control programs compensate customers financially if the 

customers allow the utility or grid operator to remotely interrupt electricity 

use by one or more electrical devices, such as air conditioners. In some 

cases, electricity may be interrupted for an hour or more, in other cases, 

the operator may “cycle” the equipment, shutting it down for several short 

periods. Generally, these programs rely on a switch installed on the air 

conditioner or other device that the utility or grid operator can remotely 

activate. By controlling a large number of small devices, the utility can 

ensure that, at any given time, some of these devices are turned off, thus 

significantly reducing the peak demand. For example, Southern California 

Edison operates several demand-response programs and has developed 

infrastructure to support them including 250,000 remotely activated 

switches on electrical equipment. In total, in 2003 the company had about 

20 years of experience with a program that has provided about 600 to 800 

MW of potential reduction in peak demand. 

Finally, voluntary reduction programs are geared to large commercial and 

industrial customers that must meet certain requirements, such as a 

minimum amount of demand reduction, to participate. In one program, the 

New York grid operator notifies participants when it needs to reduce 

system demand, allowing the participant to decide how much, if any, it 

wants to reduce consumption from an agreed-upon baseline level. 

Customers are paid for any actual reduction below the baseline level. 

Overall, these programs provide more flexibility for customers than 

interruptible programs because there is no penalty if the consumer is 

unable to reduce its demand. However, financial benefits can accrue only if 

the consumer is called on to reduce demand and actually reduces its 

consumption. In another program, participants have signed agreements 

with the New York grid operator that pay them for their willingness to 

reduce demand. These agreements are voluntary to enter into, but commit 

participants to reduce demand when asked, or face financial penalties. As a 

result of these agreements, the grid operator is able to achieve substantial 

reductions in demand with 2 hours notice. These programs also require 

communication links between the utility and customers, as well as 

advanced meters so that the utility can verify and measure the consumer’s 

actual response.

Customers told us that they reduce demand if their business situation and 

market prices warrant a reduction. For example, one manufacturer shuts 

down some processes to reduce demand and shifts workers to other tasks 

in the factory. In some cases, the manufacturer can compensate for the lost 

production by increasing output during normal work hours or during nights 
Page 20 GAO-04-844 Electricity Markets

and weekends. However, if the factory were operating at full capacity—

three shifts per day, 7 days per week—the manufacturer would need to 

consider whether the value of lost production exceeded the expected 

compensation from the grid operator. Two participants told us that certain 

provisions of labor contracts limited their ability to shift work to night 

hours, or limited the profitability of doing so, because night hours required 

the payment of higher wages to employees.

Reliability-driven programs are more widely available than market-based 

pricing programs, but participation remains somewhat limited. Many 

utilities offer interruptible rate programs to large commercial and 

industrial customers. While offered for many years, these programs were 

generally used to provide lower prices for some selected customers, but 

electricity was rarely interrupted. As a result, program operators told us 

that some customers on these types of programs, such as hospitals and 

schools, would not be able to reduce demand if directed to do so, limiting 

the effectiveness of some of these programs. Direct demand control 

programs have been offered by utilities for many years. Many customers, 

including residential customers, currently participate in them, allowing 

their air conditioners, pool pumps or other devices to be remotely turned 

off. Voluntary reduction programs are relatively new and only available in a 

few locations. Although these programs may not be activated often, 

officials in California and New York State told us that the interruptible and 

voluntary demand reduction programs helped their states enhance 

reliability in recent years, providing the grid operator with an additional 

tool to avoid blackouts and other disruptions.

Some GSA Facilities Are 

Registered to Participate in 

Market-Based and 

Reliability Programs

Of the 53 GSA facilities we reviewed, 33 facilities in six states and the 

District of Columbia are registered to participate in either market-based 

pricing or reliability-driven programs, or both, according to GSA officials. 

These officials told us that the programs that they are signed up for are 

generally voluntary—they provide financial benefits when the buildings are 

able to reduce demand but do not include penalties if they do not respond 

to price changes or requests to reduce demand. Of the buildings that 

participate in a program, 21 facilities are registered for market-based 

programs such as time-of-use and real-time pricing, 7 for reliability-driven 

programs, and 5 are registered for both types.
Page 21 GAO-04-844 Electricity Markets

Demand-Response 

Programs Have Saved 

Millions of Dollars and 

Can Improve the 

Reliability of the 

Electricity System

Demand-response programs have saved millions of dollars and could save 

billions of dollars more, as well as enhance reliability in both regulated and 

competitive markets, according to the literature we reviewed and experts 

we spoke with. For example, one market-based program in California 

saved $16 million per year and one estimate of the potential benefit of 

demand-response was as high as $10 to 15 billion. These actual and 

potential savings occur when consumers can respond to fluctuations in 

electricity prices, permitting markets to function more efficiently. In 

addition to improving the operation of electricity markets, demandresponse can enhance the reliability of the electricity system if participants 

reduce their demand in response to higher prices, and they provide an 

additional tool to manage emergencies such as supply shortages or 

potential blackouts.

Market-Based Programs 

Have Saved Millions of 

Dollars and Have the 

Potential for Even Greater 

Savings 

Over the past 25 years, many electricity market studies have reported on 

demand-response programs. Recent studies have reported that several 

programs have saved millions of dollars and demand-response could save 

billions of dollars if widely implemented in the future. These studies 

generally fall into two categories: (1) studies of actual benefits from 

programs already available and (2) studies identifying benefits that could 

be obtained if such programs had been available to ameliorate previous 

crises or potential future benefits of widespread implementation. 

As shown in table 1, a number of studies of market-based pricing programs 

demonstrate that these programs have reduced demand and resulted in 

millions of dollars in customer savings. 
Page 22 GAO-04-844 Electricity Markets

Table 1: Studies of the Benefits of Existing Market-Based Pricing Programs for Regions and Specific Programs

Source: GAO.

Study title, author, date Results/conclusions

“The Economics of Real-Time and 

Time-of-Use Pricing for 

Residential Consumers,” King, 

June 2001

Pacific Gas and Electric has operated a time-of-use program since 1982, with about 85,000 

participants as of 2001. Consumers have reduced their electricity usage during peak periods by 

18%. As of the early 1990s, 80% of participants were saving $240 per year through the program, or 

about $16 million per year. The utility has also benefited from the shift in demand to off-peak. 

"Evaluation of the Energy-Smart 

Pricing Plan: Final Report," 

Summit Blue Consulting for 

Community Energy Cooperative, 

Mar. 2004

Community Energy Cooperative of Chicago’s demand-response program had 750 participating 

residential customers, representing a wide variety of neighborhoods and types of homes, in 2003, its 

first year of operation. Under day-ahead pricing, these customers saved an average of 19.6% on 

their energy bills, or more than $10 per month in 2003, for modestly cutting back on consumption 

during approximately 30 hours of peak demand during the summer months.

“Industrial Response to Electricity 

Real-Time Prices: Short Run and 

Long Run,” Schwarz, et al., Oct. 

2002

Real-time pricing by Duke Power in the Carolinas induced demand reductions of about 70 MW, or 

approximately 8% of consumption during four summer months of peak demand. This translates into 

long-term savings of about $2.7 million per year for the 110 industrial customers who participated 

during the period 1994 to 1999. 

“Customer Response to Electricity 

Prices: Information to Support 

Wholesale Price Forecasting and 

Market Analysis,” Braithwait for 

EPRI, Nov. 2001

Georgia Power’s real-time pricing program, with about 1700 participants representing about 5,000 

MW of demand, can count on a demand reduction of at least 750 MW when capacity is constrained 

and wholesale markets are tight. On a few days in summer 1999, Georgia Power’s real-time prices 

reached levels as much as twice as high as those seen in previous years. Prices were moderately 

high on several days and spiked to an extremely high level on a few days. The very large industrial 

customers on hour-ahead rates reduced their purchases by about 30% from their normal rate on the 

moderately high-priced days and by nearly 60% during the two high-cost, capacity-constrained 

episodes. 

“Analysis for 2002 GoodCents 

Select Program Critical Calls,” Gulf 

Power, May 2003

Customers participating in Gulf Power’s critical peak pricing program in 2002 on average consumed 

50 percent less electricity during "critical periods"—when price was higher—than did a similar group 

of nonparticipating consumers. Participants also paid 11 percent less in total electricity bills because 

their total electricity expenditures rose slower than the similar group of nonparticipants. 

“Demand Responsiveness in 

Electricity Markets,” Lafferty, et al. 

for FERC, Jan. 2001

Residential customers in the Wisconsin Public Service Corporation’s peak-load pricing program who 

faced a peak price that was double the off-peak price reduced their consumption during summer 

peak periods by about 12%, while those facing a peak price that was 8 times the off-peak price 

reduced their consumption by 15% to 20% during summer peak periods. At peak hours during heat 

waves, consumption was reduced by 31% relative to nonpeak noncritical days. 

“Responsive Demand: The 

Opportunity in California,” 

McKinsey and Company, Mar. 

2002. 

From July 1999 through August 2000, San Diego Gas and Electric Company charged residential 

customers electricity prices based on regional wholesale market prices. During this period, it 

provided customers with the electricity wholesale price index on their monthly statements. In JuneAugust 2000, there was an unprecedented run-up in California wholesale electricity prices. As a 

result, the average customer’s bill increased by 240% during these 3 months, compared with the 

same period in 1999. In response, during this period in 2000, customers reduced their usage by 5%.

“New York Independent System 

Operator (NYISO) PriceResponsive Load Program 

Evaluation: Final Report,” Neenan 

Associates, Jan. 2002

The NYISO’s demand bidding program provided over 25 MW of load reduction when summer peak 

prices were the highest in 2001. The program’s scheduled load reductions are estimated to have 

reduced market prices by 0.3% to 0.9%. Total collateral benefits from reducing market prices are 

estimated to be $1.5 million in 2001. The program is expected to reduce the frequency of system 

emergencies and lessen the need for reliability programs. 

“Framing Paper #1: PriceResponsive Load (PRL) 

Programs,” Goldman for NEDRI, 

Mar. 2002

The New England Independent System Operator’s, New England Demand-response Initiative 

(NEDRI) was used on six occasions in 2001 when prices frequently reached $1,000/MWh providing 

an average demand reduction of 17 MW.
Page 23 GAO-04-844 Electricity Markets

As the table shows, these estimates of actual savings include savings to 

individual utilities and their customers as well as regional savings. For 

example:

• Individual programs operated by utilities located across the United 

States have seen reductions in demand of between 5 percent and 60 

percent during high-priced hours, resulting in millions of dollars in 

customer savings and/or cost reductions. For example, according to a 

study of a long-running time-of-use program in California, in the early 

1990s 80 percent of participants were saving $240 per year (or about $16 

million per year in total for all participants) by cutting back on their 

consumption during the hours of peak demand. According to another 

study, Georgia Power staff could plan on participants reducing about 

750 MW of power during high-priced hours, and they have seen 

reductions in peak demand of up to 17 percent on critical days. These 

savings reduce the amount of costly peak-generation equipment 

necessary, they said, and the program passes these savings along to its 

customers. 

• Regional programs operating in the Northeast (New York and New 

England) have witnessed significant reductions in demand, which 

resulted in (1) millions of dollars in participant savings through price 

reductions and direct payments and (2) price reductions for 

nonparticipants amounting to millions of dollars more per year. For 

example, according to one study, the New York grid operator’s demand 

bidding program reduced electricity prices by $1.5 million in summer 

2001.

Our discussions with individual participants also highlighted specific 

savings for them resulting from the availability and use of demandresponse programs. For example:

• According to a manager at a rural textile mill participating in Georgia 

Power’s real-time pricing program, the mill reduced its purchases from 

the utility by increasing the output of an on-site generator during 

periods of high prices, for a savings of about $1 million per year. These 

savings allowed his mill to remain competitive while many others in the 

United States had shut down production and moved to other countries, 

in part because electricity prices were too high. 

• In California, according to the manager at a three-building commercial 

office complex that participates in market-based and reliability 
Page 24 GAO-04-844 Electricity Markets

programs, the complex reduced its total electricity costs by 17 percent 

in 2003. To achieve these savings, the facility used advanced energy 

controls that allowed building operators to raise or lower building 

temperature and lighting, as well as a thermal storage cooling system 

that allowed it to chill water at night and use it during the day to cool the 

building and thereby avoid using air-conditioning during times when 

prices were high.

• One residential participant in Gulf Power’s critical peak pricing program 

significantly reduced his demand during the most costly hours and 

saved nearly $600 per year, or more than a third of his annual power 

costs, by shifting many activities from the most costly hours to off-peak 

hours. 

As table 2 shows, retrospective studies of past crises in the West and other 

parts of the country that have experienced significant market problems 

estimate that these programs could have saved potentially billions of 

dollars had they been available and used in these areas. One study 

examined the electricity crisis of 2000 to 2001 in the West and estimated 

that, had market-based pricing been in place, the high prices seen in 

California during 2000 might have been reduced by 12 percent—resulting in 

a $2.5 billion reduction in the state’s electricity costs. Similarly, experts 

have prospectively estimated that the widespread implementation of these 

programs could result in significant reductions in electricity costs. For 

example, three separate studies concluded that widespread 

implementation of demand-response programs could result in savings 

ranging from $5 billion to $15 billion, depending on the extent of 

participation and the costs of implementation. 
Page 25 GAO-04-844 Electricity Markets

Table 2: Studies of Potential Benefits of Demand-Response 

Source: GAO.

Study title, author, date Results/conclusions

Retrospective

“The Financial and Physical 

Insurance Benefits of PriceResponsive Demand,” Hirst, May 

2002

If hourly pricing had been in place for 20% of California’s retail electricity demand in 1999 and there 

had been a moderate amount of price responsiveness, the state’s electricity costs would have been 

4%, or $220 million lower. In 2000, electricity prices were almost four times higher and also much 

more volatile than in 1999. Hourly pricing for 20% of retail demand in 2000 would have saved 

consumers about $2.5 billion or 12 percent of the statewide power bill.

“Getting Out of the Dark: Marketbased pricing could prevent future 

crises,” Faruqui, et al., fall 2001

In California, during the energy crisis in summer 2000, if demand-response to hourly market-based 

retail prices had been in place, Californians could have reduced their peak demand by 193 MW, 

thereby reducing prices from peak hourly levels of $750 per MWh to $517 per MWh. For the 

summer season as a whole, energy costs would have been reduced on high-priced days by $81 

million.

“Mitigating Price Spikes in 

Wholesale Markets through 

Market-Based Pricing in Retail 

Markets,” Caves, Eakin and 

Faruqui, Apr. 2000

In late July 1999 in the Midwest, wholesale electricity prices spiked to $10,000 per MWh. If only 

10% of the retail demand for electricity had faced real-time pricing and there had been a moderate 

amount of price responsiveness, electricity prices would have risen to only about $2,700, 73% 

percent less than the price actually observed. Having just a small fraction of industry demand facing 

real-time prices would significantly dampen price spikes. 

Prospective

Power System Economics: 

Designing Markets for Electricity, 

Stoft, 2002

Evaluating power markets broadly, the net benefits of demand with real-time pricing would be about 

2 percent of the total spent on electricity. For the United States in 2003, that would amount to about 

$4.5 billion. This long-term estimate assumes that customers shift consumption from peak to offpeak periods, but that total consumption does not change. The estimate does not include potential 

benefits that accrue as a result of avoided blackouts or other service disruptions.

“Economic Assessment of RTO 

Policy,” ICF Consulting for FERC, 

Feb. 2002

The potential benefits for U.S. electricity customers from adopting real-time pricing, with 

conservative assumptions about customers’ magnitude of response and their ability for distributed 

generation, are estimated to be $7.5 billion annually, compared with the status quo by 2010, the first 

year the effects would be fully in place. 

“White Paper: The Benefits of 

Demand-Side Management and 

Dynamic Pricing Programs,” 

McKinsey and Company, May 2001

U.S. electricity customers could potentially realize benefits of $10 billion to $15 billion per year if 

they all participated in demand-response programs and, on average, shifted 5 percent to 8 percent 

of their consumption from peak to off-peak periods and curtailed consumption by another 4 percent 

to 7 percent. The switch to demand-response programs would avoid 250 peaking power plants at 

125 MW each to handle peak demand, for a total of 31,250 MW of peak capacity (or $16 billion to 

build plants used to handle peak demand). Also avoided would be 680 billion cubic feet of natural 

gas usage and 31,000 tons of nitrous oxide pollution per year.

“The Western States Power Crisis: 

Imperatives and Opportunities,” 

EPRI White Paper, June 2001

If adopted everywhere in the United States, demand-response programs could reduce demand for 

electricity by 45,000 MW or about 6 percent of forecasted peak baseline usage. In California, 

demand-response could reduce demand by 8.7% and offset the need for new capacity by 

eliminating 57% of the forecasted load growth during the next several years.

“The Choice Not to Buy: Energy 

Savings and Policy Alternatives for 

Demand Response,” Braithwait 

and Faruqui, Mar. 2001

Based on demand-response data from existing utility real-time pricing programs and actual 

California data for summer 2000, customer response to hourly market-based retail prices could 

generate demand reductions of 1,000 to 2,000 MW, reduce summer peak demand, retail prices by 

6% to 19%, and produce energy cost savings ranging from $0.3 to $1.2 billion in California alone.

“The Feasibility of Implementing 

Dynamic Pricing,” California 

Energy Commission, Oct. 2003

California could reduce its peak energy demand by 5% to 24% within a decade by implementing 

dynamic pricing and installing advanced real-time meters for all nonagricultural energy customers. 
Page 26 GAO-04-844 Electricity Markets

In achieving these savings, demand-response programs promote greater 

efficiency in supplying electricity in two ways. First, they encourage 

greater reliance on more efficient plants producing electricity at a lower 

cost and correspondingly less reliance on the plants used to handle peak 

demand, producing electricity at a much higher cost. This increased 

reliance on more efficient power plants provides the immediate benefit of 

lowering the average cost of supplying electricity, according to the studies 

we examined. This lower average cost of supply is likely to reduce 

electricity prices for consumers in either regulated or restructured 

markets. Furthermore, the use of more efficient power plants results in less 

use of natural gas and other fuels, potentially lowering the prices of these 

fuels during parts of the year. In addition, by reducing the use of seldomused peaking power plants, the industry will need to build and maintain 

fewer of them overall, which will improve the overall efficiency of the 

industry. Since 1,000 MW of peaking power plants currently cost about $300 

million to build, avoiding their construction can substantially reduce the 

amount of money the industry must commit to these little used plants.4

Second, such programs reduce the incidence of price spikes caused either 

by market conditions or by market manipulation. As part of its 2002 

proposed market design, FERC determined that the absence of demandresponse can result in periodic high prices in wholesale markets, exceeding 

the prices it would expect from competitive markets. Experts believe that 

these spikes are worsened, or in some cases may be caused, because 

consumer demand is determined in isolation from wholesale market 

conditions. Price spikes caused by natural changes in market conditions 

can be worsened by the lack of demand-response. For example, in late July 

1999 the wholesale price of electricity reached the unprecedented level of 

about $10,000 per MWh for a few transactions in the Midwest, instead of 

the usual summer day price of $30 to $50 per MWh. While FERC 

determined that hot weather led to high demand, it noted that the 

exceedingly high wholesale prices occurred principally because high 

wholesale prices were not passed through to retail customers. 

Consequently, customers did not face high retail prices—thus they received 

no signal that supply costs were extraordinarily high—and did not cut 

consumption, which would have reduced wholesale prices. Similarly, price 

4

According to industry data (Platts PowerDAT), from 1998 through 2003, power plants in the 

United States with a total generating capacity of between 84,000 MW and 134,000 MW 

operated 10% or less of the time. In 2003, these seldom used plants accounted for about 14% 

of the total installed capacity in the United States. 
Page 27 GAO-04-844 Electricity Markets

spikes caused by market manipulation, such as when a pivotal supplier 

withholds supplies in order to raise prices, can also be lessened if some 

consumers are able to see prices increase and reduce demand. Following 

the western electricity crisis, FERC determined some suppliers were able 

to increase wholesale prices by withholding supplies, contributing to a 

dramatic increase in electricity prices in California and other states. To 

limit the ability of producers to use their market power to raise prices and 

as a substitute for needed demand-response, FERC has approved various 

ways to control prices including price caps—collectively referred to as 

market power mitigation—but recognizes that these rules are imperfect 

solutions. Despite the presence of market power mitigation efforts, FERC 

has said that without demand-response prices can still exceed competitive 

levels. On the other hand, according to FERC officials, if there were 

sufficient demand-response in today’s markets, the commission could 

significantly reduce its reliance on market power mitigation rules because 

markets would be more competitive. Whether high prices are caused by 

natural market events or market manipulation, experts believe that 

demand-response programs can serve to lessen the severity of price 

increases, if properly designed and implemented. Furthermore, experts 

believe that the ability to rely on more efficient plants and the ability to 

reduce price spikes, taken together, could significantly reduce market 

prices. For example, one expert estimated that a 5 percent reduction in 

peak demand could reduce prices by 50 percent.

In addition to immediate benefits, better aligning prices with costs offers 

long-range benefits because it provides the correct incentives for 

investments in energy efficiency and conservation or for other investments 

that allow consumers to reduce or avoid consuming energy during the most 

costly hours. These investments include thermostats to alter building 

temperatures during high-priced hours and equipment such as more 

efficient air conditioners or equipment that allows consumers to shift their 

demand from peak to off-peak, such as thermal or other energy storage 

devices. When electricity customers have more incentives to invest in such 

equipment, manufacturers of this equipment also have added incentive to 

develop and sell it. These improved incentives could result in the 

availability and use of more efficient energy-using equipment with 

substantial long-term benefits for consumers and society. 

Demand-response may also result in environmental benefits in two key 

ways: reduced overall electricity supplied and reduced use of power plants 

with high pollution rates. First, to the extent that participants in marketbased pricing programs reduce their consumption of electricity during 
Page 28 GAO-04-844 Electricity Markets

peak hours and do not increase their consumption during other hours, the 

amount of electricity supplied may be reduced in total. In such a scenario, 

emissions of air pollutants are reduced. Second, in some cases, participants 

in market-based pricing programs may reduce their demand during highpriced peak hours, but increase their demand during low-priced, off-peak 

hours. These participants allow the suppliers, or grid operators, to avoid 

using peakers to meet demand but increase the use of another power plant. 

Since there are regional variations in markets and power plants, depending 

on the area of the country, this shift may result in the use of power plants 

that are more or less polluting than the avoided peaking plants. Such 

offsetting effects make it difficult to determine the net environmental 

effect. Also complicating the determination of the potential environmental 

benefit, some demand-response participants may rely on backup 

generators to supply electricity periodically. Overall, experts we met with 

noted that there may be net environmental benefits from these programs, 

but the amount of the potential benefits was uncertain and was likely to 

vary by region. 

Demand-Response 

Programs Can Improve the 

Reliability of the Electricity 

System, Reducing the 

Incidence of Costly 

Blackouts 

Demand-response programs can lessen the likelihood of blackouts and 

other disruptions with their consequent financial losses, according to the 

literature we reviewed. An Electric Power Research Institute study of a 

“typical” year’s power outages and associated losses estimated that the 

annual cost of outages to some key sectors (industrial and information 

technology) of the U.S. economy ranges from $104 billion to $164 billion. In 

California—the state with the highest costs for outages—the costs range 

from $12 billion to $18 billion.5

 Similarly, the August 14, 2003, blackout 

affected millions of people across eight northeastern and midwestern 

states, as well as areas in Canada, and lasted for several days in some areas. 

The U.S.-Canada Power System Outage Taskforce estimated that the 

blackout cost between $6 billion and $12 billion in lost goods and services. 

Demand-response programs enhance reliability in two important ways: (1) 

market-based pricing tends to reduce demand as prices rise and (2) 

reliability-driven programs provide grid operators an additional tool to 

manage the last minute balancing of supply and demand needed to avoid 

blackouts. First, market-based pricing programs tend to reduce overall 

5

“The Cost of Power Disturbances to Industrial and Digital Economy Companies,” 

Consortium for Electric Infrastructure to Support a Digital Society, EPRI and the Electricity 

Innovation Institute (June 2001).
Page 29 GAO-04-844 Electricity Markets

demand during times when electricity is scarce and costly, as individual 

customers choose not to purchase increasingly expensive supplies. This 

mechanism is especially useful when demand is slowly approaching the 

total available supply and customers have some advanced warning that 

electricity is becoming more costly. For example, higher real-time prices 

seen by retail customers would reflect, generally within 1 hour, a power 

plant or transmission line’s unavailability. Seeing these prices, customers 

tend to reduce demand and hence the amount of electricity that must be 

generated from power plants during the next hour. This lower level of 

demand, in turn, makes it easier for the grid operator to add enough 

supplies to meet demand and perhaps reduces the cost of doing so. 

However, these programs may not be able to meet sudden needs or provide 

sufficient and predictable demand reductions to maintain reliability. 

Second, reliability-driven programs provide additional flexibility by 

allowing grid operators to either increase supply or reduce demand to 

avoid blackouts or other disruptions. These types of mechanisms are 

especially useful in obtaining known amounts of demand reduction 

relatively quickly and sustaining demand reduction over some predictable 

period of time. For example, one expert told us that this type of program 

would be very useful if a large power plant had to suddenly shut down for 

safety reasons, and the grid operator found that available alternative supply 

sources were very costly or insufficient to meet their quantity and location 

needs. In this case, the grid operator might be able to maintain reliability at 

a lower cost by interrupting electricity service to interruptible customers 

for a short period of time, an interruption for which they would be paid. By 

this planned and compensated interruption of service for a few customers, 

utilities and other service providers are able to avoid unplanned service 

interruptions—or blackouts—for a much greater number of customers. For 

example: 

• During California’s energy crisis of 2000 and 2001, experts found that 

utility programs that could interrupt service were instrumental in 

avoiding blackouts on at least five occasions.6

6

Goldman, et al., estimated that demand-response during this period avoided between 50 

and 160 hours of rolling blackouts (“California Customer Load Reductions during the 

Electricity Crisis: Did They Help to Keep the Lights On?” LBL [May 2002]). 
Page 30 GAO-04-844 Electricity Markets

• During a heat wave in 2001, one reliability program in New York State 

reduced electricity use by 425 MW on four occasions, or about 3 percent 

of total consumption, and achieved estimated benefits of about $13 

million in reduced market prices.7

 In order to achieve these savings, the 

program paid selected customers $4.2 million to forgo consumption. 

More recently, grid operators used demand-response capabilities to aid 

in the recovery from the 2003 Northeast blackout, interrupting 

participants in order to speed a return to normal electricity service for 

the state’s grid. 

However, because some of these reliability-based demand-response 

programs provide for periodic payments to participants, but are used 

infrequently, they can be costly to maintain and difficult to justify during 

years when they are not needed. Nonetheless, according to experts, these 

programs are very important for maintaining reliability during times when 

electricity supplies are inadequate or demand is higher than expected. 

Further, several experts and program operators noted that these programs 

are difficult and time consuming to start up when a crisis is expected, and it 

is better to have them in place before a crisis. 

Opportunities Exist for GSA 

to Benefit Further from 

Demand-Response 

Programs 

GSA has achieved some financial benefits from its limited participation in 

demand-response programs. Of the 53 buildings with the largest electricity 

expenses that we reviewed, 33 reported participating in a demand-response 

program, and 13 of these reported savings ranging from 0.1 percent to 10.8 

percent, for a total of $1.9 million from 1999 through 2003. About 72 

percent of these benefits were from facilities participating in market-based 

pricing programs, 9 percent from facilities participating in reliability-driven 

programs, and 19 percent from facilities participating in both types of 

programs. However, while we received some estimates from GSA about its 

participation in market-based programs, total savings may be higher. Some 

building operators did not quantify the benefits of these programs and 

many building operators did not actively participate, even though their 

buildings were enrolled in them. For example, while large GSA buildings in 

California are registered for the time-of-use rate, as California requires, 

GSA staff told us that some building managers do not actively monitor 

price changes or take steps to adjust demand to respond to changing 

prices. As a result, some GSA buildings do not realize the additional 

7

In addition to these savings, the utility reduced its hedging costs by $3.9 million, and all 

customers together saved $20 to $40 million from the lowered likelihood of blackouts. 
Page 31 GAO-04-844 Electricity Markets

savings that could result from reducing demand when prices are highest. In 

contrast, GSA building managers at facilities in Illinois that are enrolled in 

reliability-driven programs have actively participated by reducing their 

electricity demand, at the utility’s request, in exchange for payment. 

We estimate that GSA might be able to achieve substantial savings if it 

participated more actively in demand-response programs. Based on savings 

actually achieved from demand-response programs by 13 large GSA 

buildings (over 100,000 square feet in size) from 1999 through 2003, the 

median savings potentially achievable for these 13 buildings over the 5-year 

period, 2004 through 2008, is $6.9 million and ranges from $1.4 million to 

$13.6 million, depending on how actively the buildings participate, weather 

conditions, and other factors, and assuming that at least time-of-use 

programs are available. If the other 40 GSA buildings of this size were to 

participate in demand-response programs that provided similar savings 

over this period, the median additional savings are estimated to be $20.5 

million with a range of $4 million to $40 million. If all 419 GSA-managed 

buildings over 100,000 square feet in size were to participate in demandresponse programs that provided similar savings over this period, we 

estimated median GSA savings of $58.2 million with a range of $12 to $114 

million, according to our analysis.

Multiple Barriers Make 

It Difficult to Introduce 

and Expand DemandResponse Programs

Demand-response programs face three main barriers to their introduction 

and expansion: (1) regulations that shield customers from short-term price 

fluctuations, (2) the absence of needed equipment installed at customers’ 

sites, and (3) customers’ limited awareness of programs and their potential 

benefits. In addition, several external factors, such as moderate weather, 

have kept prices low in recent years in many parts of the country, thereby 

limiting the financial incentives for participation. Lack of specific guidance 

to the tenants in GSA buildings regarding participation and the tenants’ 

lack of incentive to reduce consumption have also limited GSA’s 

involvement in these programs.
Page 32 GAO-04-844 Electricity Markets

State Regulations 

Promoting the Widespread 

Use of Fixed, Average Prices 

Impede the Development of 

Demand-Response 

Programs and Efficient 

Wholesale Markets

Whether subject to traditional regulation or restructured markets, the costs 

of supplying electricity are generally not reflected in the prices that 

consumers see in the retail markets where they buy electricity. Instead, 

these prices are generally prescribed by state law or regulation as a single 

average price for all purchases made over an extended period.8

 Seeing no 

variation in retail prices, customers lack the information and the incentive 

to respond to the actual variation in supply conditions throughout the day 

and from season to season. This lack of consumer response becomes 

particularly important during periods of high demand for electricity, when 

the actual costs of its production are the highest, but customers remain 

unaware of the higher costs and thus have no incentive to reduce their 

demand. In turn, since consumers do not reduce their demand, they can 

unknowingly drive up the price for electricity in wholesale markets as their 

suppliers purchase electricity to meet their demand. This impact on 

wholesale prices ultimately increases the cost to consumers over time and 

may result in energy and/or financial crises similar to those experienced in 

the West. In short, the presence of such traditional retail pricing acts as an 

impediment to both the introduction and expansion of demand-response 

programs and to the efficient operation of wholesale markets.

Because retail prices remain subject to regulatory control in most cases, 

the introduction of market-based pricing arrangements that reflect the 

underlying costs of supply may not be possible without regulatory changes. 

In retail markets that remain subject to traditional regulation, local utilities 

cannot offer new pricing arrangements without first obtaining state 

approval. According to state utility commission staff, approval often 

requires demonstrating that the introduction of new pricing arrangements 

will benefit the participants while causing no price increases for 

nonparticipants. In restructured retail markets, competitive suppliers may 

be able to offer new arrangements that reflect costs without first obtaining 

regulatory approval, but the availability of flat average prices—as required 

8

U.S. General Accounting Office, Lessons Learned from Electricity Restructuring: 

Transition to Competitive Markets Underway, but Full Benefits Will Take Time and Effort 

to Achieve, GAO-03-271 (Washington, D.C.: Dec. 17, 2002). As noted earlier, only a small 

amount of demand, in total, may be needed to deliver the benefits of demand-response. Only 

a few customers need to be responsive to varying prices for there to be “adequate” levels of 

demand-response in markets. Customers would be free to choose between (1) paying 

varying prices, with varying monthly bills, and (2) paying slightly more, on average, in order 

to be guaranteed flat monthly prices reflecting the average cost of serving them over a 

longer period of time. Customers willing to respond to varying prices would not pay for a 

"flat price" guarantee. 
Page 33 GAO-04-844 Electricity Markets

by regulation or law—may continue to present a barrier to consumers 

switching to these rates. In addition, whether in regulated or restructured 

markets, because demand-response programs can reduce total electricity 

consumption—upon which owners and operators of the transmission 

system are paid—it may also be necessary to change how these entities are 

compensated. 

Similarly, the introduction of reliability-driven programs may not be 

possible without regulatory and other actions by federal, state, and other 

entities. In general, reliability-driven programs are developed in a broader, 

regional context, where their success depends upon their integration with 

the flow of electricity throughout a region. Because electricity grids have 

become highly regional, with supply and demand in one part of the grid 

instantaneously affecting the grid across a wide geographic area, it is 

important for grid operators fully understand supply and demand 

conditions within these regional grids and to have sufficient authority to 

maintain reliability. Since introducing restructuring to wholesale electricity 

markets, FERC has approved the formation of eight grid operators across 

the United States that have different levels of authority and a variety of 

rules. Therefore, the effectiveness of reliability-based programs depends on 

the amount of the grid the operators control and the extent to which the 

operator’s rules differ from the rules in a neighboring jurisdiction. As part 

of the changes needed to introduce reliability programs, it may not be 

possible to introduce several types without creating markets for them. For 

example, it may be necessary to make changes to allow companies to 

aggregate small individual demand-responses, such as residential air 

conditioners and water heaters, and provide a way to then sell the 

aggregated demand as a substitute for supply to the grid operator. To 

implement these changes, industry experts believe that FERC may need to 

change the rules used by grid operators so they can allow the creation of 

appropriate markets.9

 

9

Because NERC establishes technical and operational standards, including the need to 

maintain certain levels of reserves, it may also be necessary to change rules to allow 

demand-response options to be counted in measuring whether grids are being operated 

reliably. 
Page 34 GAO-04-844 Electricity Markets

Lack of Some Equipment at 

Customers’ Locations Limits 

Use of Demand-Response 

Programs 

Most customers currently lack the necessary equipment—meters, 

communication devices, and special tools—for participating in demandresponse programs. Although the needed technologies are commercially 

available, they are not present at most customers’ homes and businesses. 

For example, the meters installed in most homes and businesses measure 

only total consumption, which is generally measured on a monthly basis for 

billing purposes. However, most demand-response programs require 

meters that are capable of measuring when electricity is consumed. These 

types of meters generally cost between $100 and $1000, according to 

experts we spoke with. Additionally, experts and program operators told us 

that the way in which some buildings are metered is inadequate to support 

effective participation in demand-response. For example, regulators, 

program operators, and others in New York State told us that the building 

code did not require that commercial and residential buildings be metered 

individually. They explained that in New York City, which has many large 

residential and commercial buildings, or multibuilding complexes, some of 

which may comprise hundreds to thousands of individual users, a single 

meter measures consumption. As a result, individual customers do not pay 

for the electricity that they consume; instead, they pay for a share of the 

total electricity consumed. In these circumstances, even if an appropriate 

meter were installed to replace the existing meter, individual customers 

would have only limited incentive to reduce their consumption, since the 

benefits of any individual reduction would be shared among all the other 

customers.

Most customers also do not have appropriate communications equipment 

for demand-response programs. Because most customers’ electricity rates 

change infrequently, it has not been necessary to design or implement 

specific communications for this purpose. However, with most demandresponse programs, more timely communication is important. According to 

operators of programs that we reviewed, they relied on some combination 

of e-mail, pagers, and telephones to provide timely communication. 

Finally, some demand-response programs may require other equipment. 

For example, in market-based and reliability programs that allow the retail 

energy provider or grid operator to interrupt specific pieces of electricityconsuming equipment, participants need installed switches on their 

electrical equipment that can be activated remotely. Installing these 

technologies can be costly and raises questions about who should pay for 

them and how best to install them. Historically, local utilities paid for and 

installed the meters, recovering this cost through electricity rates over 

several years. However, because of uncertainties about the future of retail 
Page 35 GAO-04-844 Electricity Markets

restructuring and of the ability to recover these costs in competitive 

markets, utilities have been reluctant to pay for metering equipment unless 

cost recovery is guaranteed, which some regulators have been reluctant to 

do. Several experts told us that costs could be significantly reduced if the 

equipment were purchased and installed on a widespread basis. However, 

since not all customers participate in demand-response programs, it is not 

clear that such widespread installations are economical, even in light of the 

potential for reduced costs.

Customers’ Limited 

Awareness of DemandResponse Programs and 

Their Potential Benefits 

Hinders Program 

Introduction and Expansion 

In areas where demand-response programs are available, some customers 

are unaware of them or do not know how they could benefit from 

participation. For example, despite the widespread availability of demandresponse programs in New York State, and of extensive outreach, many 

customers in New York State remain unaware of them, according to 

experts we spoke with. In a survey conducted for the operator of two 

programs in New York State, program operators learned that about half of 

the eligible customers it believed were well-informed about electricity 

matters were unaware of the demand-response programs. However, the 

same study found that the customers that were aware of the programs were 

highly likely to participate in them.

In some cases, the simultaneous availability of and solicitation for multiple 

programs can confuse potential participants. For example, California state 

officials told us that, in response to the 2000 and 2001 electricity crisis, 

many new programs were created in addition to a number of existing 

programs. According to one utility we spoke with, customers found it 

difficult to sort through the multiple options and were also were confused 

by utility program complexities due to multiple programs and/or changing 

policies and requirements. 

According to program operators and industry experts, customers often do 

not know the specific sources of their own demand (such as various 

production processes and air-conditioning), when their demand is the 

highest, and what options exist to reduce their demand without 

significantly affecting their commercial operations or household comfort. 

For example, customers participating in the Georgia Power real-time 

pricing program told us that the utility staff was indispensable in initially 

informing them about the existence of the program, about quantifying the 

potential savings, and in identifying ways to reduce demand during highpriced hours. 
Page 36 GAO-04-844 Electricity Markets

Several Outside Factors 

Have Also Served to Limit 

the Benefits of Participating 

in Available DemandResponse Programs in 

Recent Years

Several factors have also reduced the incentive to participate in demandresponse programs over the past several years. These include (1) moderate 

weather across most of the country over the past couple of years that has 

limited overall and peak demand; (2) a slow national economy, which has 

limited overall demand; and (3) many new power plants in some parts of 

the country have increased supply and lowered costs in those areas. 

Consequently, prices have moved downward overall. However, experts 

note that these types of programs may be urgently needed when supplies 

are limited and prices are high. 

According to participants that we met with, they hoped to benefit from 

their ability to reduce demand when prices were high and, in some cases, 

increase demand when prices were low. Participants told us that although 

they signed up for demand-response programs, they often would not 

actively participate unless prices were high enough to offset the costs of 

shutting down. Some businesses said they may not continue to participate 

unless they could demonstrate the financial benefits of doing so on a 

regular basis to senior managers, either through higher prices or through 

some ongoing payment for their willingness to reduce demand if needed. 

Recognizing this problem, program operators, grid operators, and others 

said that the persistence of low prices could imperil demand-response 

programs. For example, in the parts of the West where prices have 

historically been generally low, there was only limited demand-response 

capability outside of California. However, this capability became urgently 

needed during the crisis of 2000 and 2001. Because these programs are 

difficult to start up, particularly during a crisis, little additional demandresponse was available. 

GSA’s Participation in 

Demand-Response 

Programs Has Been Limited

According to GSA officials, participation in demand-response programs has 

been limited for the following reasons: 

• GSA lacks specific guidance on how to participate. While GSA provides 

guidance regarding participation in reliability-driven programs, 

information regarding market-based pricing programs is limited. For 

example, a regional energy manager we spoke with was not generally 

familiar with market-based pricing programs and thought that backup 

generation was required to participate. Another regional energy 

manager told us that he relied on information provided by the local 

utility and grid operator to provide the information he used to make 

decisions on whether to participate in these programs. 
Page 37 GAO-04-844 Electricity Markets

• Federal agency tenants have little incentive to reduce their 

consumption. According to GSA officials, current leases require a fixed 

monthly payment from federal agency tenants, which does not provide a 

way to share any savings from demand reduction efforts or to pass on 

the higher costs to agencies creating higher demand during high cost 

periods. Therefore, tenants do not have incentives to seek opportunities 

for the electricity savings that could be realized from participation in 

demand-response programs.

In addition, the need to reduce demand has been limited in recent years. As 

with other customers, GSA officials have not seen high electricity prices 

because of such factors as moderate weather. Consequently, GSA officials 

told us that they have had difficulty maintaining interest in reliability-based 

programs among their clients or in recruiting new ones.

Certain Programs 

Show How Barriers 

Were Overcome and 

Provide Lessons on 

How to Cultivate New 

Programs 

Certain demand-response programs that we reviewed illustrate how the 

barriers we identified were overcome and also point out three broader 

lessons on how to cultivate new programs. 

Two Programs Illustrate 

How to Overcome Barriers

To overcome regulatory barriers, Gulf Power, a regulated utility in the 

panhandle of Florida, introduced its GoodCents Select market-based 

pricing program by receiving regulatory approval to offer it as a voluntary 

program. The utility demonstrated to state regulators that its program 

could offer benefits such as lower overall electricity costs and additional 

services to participants without raising prices for or otherwise harming 

nonparticipants. In general, state regulators told us that they review the 

impact of programs on the electricity rates of nonparticipants, which is 

referred to as the rate impact test. This test compares the avoided costs, 

including costs to construct power plants and transmission lines as well as 

costs to operate and maintain new facilities, with the costs of operating the 

program. In the case of the demand-response program that we reviewed, 

they approved the program proposed by the utility because of its benefits 

for both participants and nonparticipants. 
Page 38 GAO-04-844 Electricity Markets

Gulf Power also overcame the barrier of inadequate equipment by installing 

an innovative package of new technologies, including a computerized 

controller, called a “gateway” that integrates the metering, communication, 

and switches to control demand. Figure 2 illustrates this system. The 

programmable thermostat receives and displays information about the 

current electricity price period (e.g., peak prices) and allows customers to 

preprogram demand reductions for up to four appliances based on time-ofday or in response to changes in prices, or both. The switches are 

automatically triggered if the preprogrammed criteria are met such as if 

high critical peak prices are in effect. For example, customers can choose 

to shut off the heat pump, air conditioner, pool pump, or hot water heater if 

prices reach a certain point or other events occur. By automating demand 

reduction, this program allows customers to avoid consuming costly 

electricity, even if they are not actually present to monitor or turn off the 

equipment. However, this system also allows the consumer to override the 

preset programming if desired; for example to operate the air-conditioning 

if they are home during the day. The data on electricity usage is sent 

periodically via an integrated telephone line. Utility officials noted that 

installing meters and related equipment for their programs costs, on 

average, $600 to $700 per customer. In addition, because Gulf Power was 

able to demonstrate to regulators that the program provided benefits to 

nonparticipants, it was possible to have some of the cost of the equipment 

paid for by a state mechanism used to fund energy efficiency and other 

similar programs. The cost-sharing required participants to pay 60 percent 

and all ratepayers to pay 40 percent of the costs. These technologies had 

the added benefit of making participation easy, a consideration that was 

important to customers. 
Page 39 GAO-04-844 Electricity Markets

Figure 2: Gulf Power's Energy Control System for Residential Participants in GoodCents Select

The grid operator (Gulf Power) sends a 

(1) radio paging signal (VHF signal) to 

participant's homes with price when a 

critical peak event is called. Information 

is received by a (2) computerized 

controller and radio receiver above the 

electric meter called a "gateway." The 

gateway integrates metering and 

communication and contains the data 

on prices for hourly time-of-use periods, 

for critical peak periods, and tracks the 

amount of energy used in each period. 

The gateway communicates with the 

programmable thermostat (located 

inside the house) via the power line 

carrier (sending data over power lines in 

the house).

The (3) programmable thermostat 

receives and displays current 

information on electricity prices and 

allows customers to preprogram 

demand reductions for up to four 

appliances — where switches are 

automatically triggered if prices rise 

above a certain level or at preset times 

of the day. Customers can choose to 

shut off the (4) HVAC/heat pump, (5) hot 

water heater, and the (6) pool pump. 

The thermostat communicates with 

these appliances using a power line 

carrier. In addition, the system allows 

the customer to override the preset 

programming if desired by pushing a 

button on the thermostat.

(1) Grid operator

Power line carrier

Power line carrier

Source: GAO analysis and illustration based on Gulf Power information; photos (2) and (3) Gulf Power.

(2) Gateway

(3) Programmable thermostat

(4) HVAC/heat pump

(4) HVAC/heat pump

(5) Hot water heater

(6) Pool pump
Page 40 GAO-04-844 Electricity Markets

Gulf Power also overcame the barrier of limited customer awareness 

through advertising and providing additional services that customers 

valued, such as whole house surge suppression and power outage 

notification, for a fee of $4.95 per month. This charge also enables the 

utility to recoup some of its expenses. Gulf Power utilized mass marketing 

techniques to make consumers aware of the program and to provide basic 

information about the advantages available to participants. Further, the 

utility provided a detailed information package to interested customers and 

actively followed up with telephone and other contacts. Utility officials told 

us that customers require substantial education about the program’s 

benefits, its basic features, and its ease of access to make the program 

successful. Residential customers, according to these officials, must be 

convinced that they will not be worse off financially and that they can 

achieve savings without substantially reducing their quality of life. In 

addition to the services provided by the innovative package of metering 

and other technologies, participants also received other services that they 

valued as part of their participation. 

In New York State, the grid operator overcame barriers to establish both a 

market-based pricing program and a reliability-driven program primarily 

targeting commercial and industrial customers. In the summer of 2000, grid 

operators, utilities, and others expected supply shortages and quickly 

established these new programs to address these shortages. 

The New York grid operator overcame the regulatory barriers by 

convincing the state regulators and FERC to make changes needed to 

establish the programs. These included the creation of an electronic 

trading marketplace so participants could offer their demand reductions to 

the grid operator at a certain price. State regulatory officials told us that 

they and FERC were open to considering the regulatory changes because 

there were no other options for quickly adding new power. 

The New York grid operator overcame the barrier of inadequate equipment 

by identifying a state-funded entity to share the cost of installing the 

needed equipment. The program received financial support from the New 

York State Energy Research and Development Authority for installing 

needed equipment such as meters that can measure hourly consumption. 

This organization was allowed to provide as much as 70 percent of the cost 

of the meters, but it generally paid about 40 to 45 percent of the costs. The 

grid operator told us that the availability of this money made the customer’s 

decision to participate easier because costs were lower. The ISO also 

developed an automated telephone notification system, introduced in 2003, 
Page 41 GAO-04-844 Electricity Markets

to replace the previous nonautomated process, which was described as 

time-consuming and inefficient. New York grid operators used the new 

system for the first time in August 2003 in conjunction with the blackout. 

The grid operator overcame the barrier of inadequate customer awareness 

by starting the program during a time when supply shortages were 

expected and by widely publicizing the program’s availability and its 

potential benefits. The grid operator provided brochures and other sources 

of information that identified the growing threat posed by the tight 

electricity supplies, the benefits of participating in the program, the role of 

participants, and the rules under which the program operated. In addition, 

state officials hosted a series of workshops that boosted awareness of the 

program and the need for demand-response. Enrollment in the program has 

grown substantially from its inception; in 2002 there were about 1,700 

participants accounting for about 1,500 MW of demand. Industrial 

customers have also formed a trade association that has helped identify 

ways to improve the program. 

Successful DemandResponse Programs Offer 

Three Important Lessons for 

Nurturing Further Programs

The demand-response programs that we reviewed offer important lessons 

for such programs to succeed. First, programs with sufficient incentives 

make customers’ participation worthwhile. For example, Gulf Power’s 

market-based pricing program provides a more than sevenfold difference 

between the lowest and the highest prices, depending on the time of day 

and season. Exposure to this great a difference in prices and the savings 

that result from adjusting demand accordingly provide a strong incentive 

for participation. In contrast, Puget Sound Energy began a somewhat 

similar program that was ultimately unsuccessful because the price 

differences with the regulated program were only about 20 percent 

different—too small to induce customers to change their consumption,10

according to studies we reviewed.

Second, programs are more likely to succeed if state regulators and market 

participants are receptive to the potential benefits of demand-response 

programs in their areas. In both Florida and New York State, certain market 

factors made demand-response especially appealing. In Florida, Gulf 

Power’s customer base is predominantly residential and prone to sharp 

variation in daily and seasonal demand because of air-conditioning. In 

10One study calculated that, if an average customer shifted all usage out of expensive 

periods and into the economy period, savings would amount to only $4.65 per month.
Page 42 GAO-04-844 Electricity Markets

presenting their case to state regulators, utility officials, demonstrated that 

the avoided costs of adding new capacity were greater than the costs of 

introducing a market-based pricing program. Similarly, in New York State, 

state officials recognized the potential for supply shortages, the difficulty 

of adding new capacity, and the benefits of developing a reliability-driven 

program as an alternative. 

Third, to achieve these benefits and increase the chances of success, the 

design of programs should consider appropriate outreach, the introduction 

of necessary equipment, and the ease with which customers can 

participate. The programs discussed here have demonstrated that these 

factors are also critical to success. 

Conclusion The goal of restructuring the electricity industry is to increase the amount 

of competition in wholesale and retail electricity markets. While wholesale 

market prices are now largely determined by supply and demand in those 

markets, retail demand does not generally respond to market conditions 

because of key barriers discussed in this report, especially the presence of 

flat, average prices generally set by states. These prices serve to insulate 

consumers from market conditions and prevent them from potentially 

choosing to reduce demand when prices are rising dramatically or when 

grid reliability is a concern. As such, retail consumers—as was the case in 

California—can unknowingly drive up wholesale market prices because 

they continue to consume as much as or more electricity than normal even 

when demand could exceed available supplies. Thus, this hybrid system—

competition setting wholesale prices and regulation setting retail prices—

results in electricity markets that do not work as well as they could. 

This hybrid system also makes it difficult for FERC to assure the public 

that wholesale prices are “just and reasonable.” While electricity markets 

are subject to divided jurisdiction, it is clear that these markets remain 

operationally joined; actions in one market affect the other. FERC has 

previously determined that actions in retail markets, particularly when 

consumers do not respond to market conditions, can cause prices in 

wholesale markets to exceed competitive levels. Such outcomes are not 

desirable or consistent with FERC’s responsibility for wholesale prices. 

Thus, FERC may have to take additional steps—within its jurisdictional 

boundaries—to ensure that competitive wholesale markets are not, 

unknowingly or unnecessarily, harmed by retail buyers. 
Page 43 GAO-04-844 Electricity Markets

It is clear that connecting wholesale and retail markets through demand 

response would help competitive electricity markets function better and 

enhance the reliability of the electric system, thus potentially delivering 

large benefits to consumers. Overcoming existing barriers will not be easy, 

however. Capturing these benefits will require leadership, collaboration, 

and action on the part of FERC, interested state regulatory commissions, 

and market participants in order to develop electricity markets that are 

truly competitive. Without these efforts to incorporate demand-response in 

today’s markets, prices will be higher than they could be, the incidence of 

price spikes caused by either market conditions or by market manipulation 

will be greater, and industry will have less incentive for energy efficiency 

and other innovations, among other things. 

To date, GSA has benefited from participation in demand-response 

programs, but clearly could do more. As a large customer with buildings 

located across the country, GSA is uniquely situated to benefit from 

demand-response programs and to provide a benefit to local electricity 

markets. While it has signed up for some programs, GSA could participate 

more actively by adjusting its energy consumption in response to prices 

and/or emergencies when asked—without compromising the operation of 

its buildings or tenants. To the extent that GSA does so, it could further 

reduce its annual electricity spending, possibly benefit the broader 

electricity market, and provide an opportunity for the federal government 

to lead by example. 

Recommendations for 

Executive Action

We recommend that the Chairman of the Federal Energy Regulatory 

Commission take the following three actions:

• Because the lack of demand-response can result in wholesale prices that 

are not consistent with competitive outcomes and may not be “just and 

reasonable,” we recommend that the Chairman consider the presence or 

absence of demand-response programs when: (1) determining whether 

to approve new market designs or approve changes to existing market 

designs, (2) considering whether to grant market-based rate authority, 

and (3) determining whether to allow some buyers to participate in 

wholesale markets. As part of this process, FERC should consider its 

authority to use this information in making decisions on these matters. 

If there is inadequate demand responsiveness and FERC determines 

that it has authority, it should not approve these designs, authorities, or 

participation until such time as there is some combination of price 

and/or reliability based demand-response to assure that prices will be 
Page 44 GAO-04-844 Electricity Markets

just and reasonable. If FERC determines that its authority is not 

sufficient to take such action, it should seek this authority from 

Congress.

• In reporting to Congress, the Chairman should identify the options that 

may have potentially large benefits and are cost-effective for achieving 

consumer response, as well as statutory or other impediments to putting 

these options into practice. 

• Because the development of demand-response programs depends upon 

there being markets where these services can be sold, the Chairman 

should encourage, where reasonable, equal consideration of supply and 

demand when approving or changing market designs.

In implementing these recommendations, it is important that the 

Commission continue working with system operators, regional entities, 

and interested state commissions, and market participants to develop 

compatible regional market rules and policies regarding demand-response. 

FERC should use these outreach efforts to identify regions of the country 

where demand-response programs are most urgently needed and where 

grid operators, state regulatory officials, and market participants are 

amenable to the collaborative introduction of regionwide demand-response 

programs. As part of its efforts, FERC should also engage the Department 

of Energy in its examination of demand-response options and involve the 

department in its outreach efforts, thus leveraging its expertise in 

identifying cost-effective technologies and its relationships with state, 

industry, and consumer groups. 

Because demand-response programs offer potential financial benefits to 

the federal government and to demonstrate the federal government’s 

commitment to improving the functioning of electricity markets, we 

recommend that, for locations where the General Services Administration 

has significant energy consumption, its Administrator take the following 

four actions: 

• Require regional energy managers to identify what demand-response 

programs are available to them, require building operators to determine 

whether they could actively participate in the programs, and quantify 

the benefits of that participation.
Page 45 GAO-04-844 Electricity Markets

• Develop guidance that clearly articulates to the regional offices that 

participation in demand-response programs should be considered as 

part of the energy decisions that they make.

• Require (1) guidance on specific measures that building operators can 

take to respond to market-based programs, similar to the guidance that 

they provide for responding to emergencies and (2) training on 

evaluating how to maximize benefits from participation in these 

programs.

• Clarify the incentives for participation by defining how the GSA, its 

building operators, and its federal agency tenants will share the benefits 

and risks of participating in these programs through its leases.

Agency Comments and 

Our Evaluation 

We provided FERC and GSA a draft of our report for review and comment. 

The Chairman of FERC endorsed our conclusions regarding the 

importance of demand-response to competitive energy markets and to 

electricity system reliability. The Chairman also generally agreed with the 

report’s recommendations. In response to one recommendation, the 

Chairman agreed to consider conditioning market-based rate authority on 

the presence of sufficient demand-response, but noted FERC uncertainty 

as to whether it can require such a condition or that such conditioning 

would be workable, given current policy that separates wholesale and 

retail functions. Our recommendation, however, has a precedent in a 

similar state jurisdictional issue—that of the construction of new power 

plants. In this instance, FERC approved a mechanism, commonly known as 

“capacity markets,” that created an additional market for power plants and 

serves as a signal for when they are needed. In the same way, our 

recommendation, if properly implemented, could create such a market for 

demand-response as well as serve as a complementary signal for new 

capacity. FERC also provided several general and clarifying comments or 

suggestions that we incorporated as appropriate or address in appendix III.

GSA agreed with the report’s conclusions regarding the importance of 

demand-response to an efficient and reliable electricity industry. GSA also 

stated that it agreed with the majority of our recommendations, but it 

expressed some concern about one of them. Overall, its comments focused 

on concerns about risk, especially in the form of financial penalties that 

GSA may incur through participation in demand-response programs. GSA 

also commented on the broad risks regarding price stability and power 

reliability that pervade the transition from regulated to restructured 
Page 46 GAO-04-844 Electricity Markets

electricity markets. As such, GSA expressed concern about the fourth 

recommendation for GSA to define how benefits from successful demandresponse participation will be shared with tenants. With this broad concern 

regarding risk to GSA in mind, GSA expressed the view that such sharing 

would not be practical because the agency would bear the risk while 

tenants reaped the rewards and because the savings to be shared are of a 

short-term nature. We revised the recommendation to reflect GSA’s 

concern by adding that risk should be shared between the agency and its 

tenants. As revised, we believe the recommendation provides sufficient 

flexibility for GSA to develop practical approaches for sharing financial 

incentives as well as penalties with its tenants to encourage participation in 

demand-response programs. However, we note that as the electricity 

market places greater emphasis on competition, consumers such as GSA 

and the federal agencies that it serves will face greater price volatility. 

Consequently, efforts to manage this greater price volatility by developing 

demand-response capabilities will be an important element in managing 

GSA’s operating costs. 

As agreed with your office, unless you publicly announce the contents of 

this report earlier, we plan no further distribution until 30 days from the 

report date. At that time, we will send copies to other appropriate 

congressional committees; the Chairman of FERC; the Administrator of the 

General Services Administration; and other interested parties. We also will 

make copies available to others upon request. In addition, the report will be 

available at no charge on the GAO Web site at http://www.gao.gov.

If you or your staff have any questions about this report, please contact me 

at (202) 512- 3841. Key contributors to this report are listed in appendix V.

Sincerely yours, 

Jim Wells

Director, Natural Resources

and Environment
Page 47 GAO-04-844 Electricity Markets

Appendix I

Scope and Methodology ApApenednxidexiIs

To assess demand-response programs, their benefits, barriers to expansion, 

ways to overcome barriers, and the federal government’s participation, we 

conducted an extensive review of the literature; analyzed industry and 

participant data on the performance of the programs, where such data was 

available to us; and conducted interviews with state and federal officials (in 

the Federal Energy Regulatory Commission [FERC], the Department of 

Energy, and the General Services Administration [GSA]) and the Edison 

Electric Institute, a trade association representing large electricity 

providers. 

To provide insights on the operation and experience of several current 

programs, we also examined programs in four states in greater detail: two 

in states with restructured retail markets (California and New York State) 

and two in states with traditionally regulated retail markets (Georgia and 

Florida). We selected these programs because they have operated for 

several years and experts consider them innovative and successful models. 

In particular, we examined the following programs: 

• In California, we examined programs operated by one large electricity 

provider and several programs operated by others. We examined two 

programs operated by Southern California Edison: time-of-use rates for 

large customers, interruptible rates for large customers, and and direct 

interruptions to the operation of specific electrical devices, such as air 

conditioners at customers’ homes and/or businesses. In addition, we 

discussed a range of programs operated by the state grid operator (the 

California Independent System Operator [ISO]), and the state created in 

response to the electricity crisis in 2000 and 2001. We interviewed 

officials at Southern California Edison, the state public utility 

commission, the California ISO, the California Energy Commission, 

California Power Authority, and Pacific Gas and Electric. In addition, we 

met with four customers that participated in programs operated by 

Southern California Edison. 

• In New York State, we examined programs operated by one large 

electricity provider and by the state grid operator. We examined a realtime pricing program implemented by Niagara Mohawk that provides 

day-ahead hourly prices against which actual consumption is billed. We 

also examined programs operated by the state grid operator (New York 

ISO)—one market-based pricing program and two reliability programs. 

We examined the New York ISO demand-bidding program (called the 

Day-Ahead Demand-Response Program). We examined one reliability 

program (called the Emergency Demand-Response Program) that pays 
Appendix I

Scope and Methodology

Page 48 GAO-04-844 Electricity Markets

participants who reduce demand when reliability is at risk. We also 

examined a reliability program (called the Special Case Resources) that 

requires participants to sign agreements in advance to reduce demand 

whenever requested and pays them for doing so. In our report, we 

combine our discussion of these two reliability programs. We also 

interviewed staff from Niagara Mohawk, the New York ISO, the New 

York State Energy Research and Development Authority, the New York 

Public Service Commission, and a consultant who annually reviews the 

performance of programs run by the New York ISO. In addition, we met 

with four customers that participate in programs operated by the New 

York ISO and/or Niagara Mohawk. 

• In Georgia, we examined a real-time pricing program operated by 

Georgia Power, a regulated utility. We also interviewed staff at Georgia 

Power, the Georgia Department of Natural Resources—Environmental 

Protection Division, and the Georgia Public Service Commission. In 

addition, we met with two customers that have participated in the 

Georgia Power program. 

• In Florida, we examined a critical peak-pricing program (GoodCents 

Select) operated by Gulf Power, a regulated utility. We also interviewed 

staff at Gulf Power, the Florida Office of the Public Counsel, the Florida 

Energy Office, and the Florida Public Service Commission. In addition, 

we met with one residential participant in the program. 

To determine GSA’s participation in demand-response programs, we 

interviewed GSA staff located in the headquarters’ Energy Center of 

Expertise and in GSA’s 11 regional offices and obtained information about 

electricity consumption at about 1,400 facilities where GSA pays for 

electricity. In addition, we obtained information about demand-response 

activities at 53 large GSA buildings. These buildings incurred the highest 

electricity expenses of the about 1,400 GSA-operated buildings nationwide 

and represented about 40 percent of the agency’s total electricity expenses 

in 2003. We obtained information on participation and the benefits of 

demand-response programs for a 5-year period—1999 through 2003. To 

estimate the potential benefits of GSA’s more widespread and active 

participation in demand-response programs, we used information on GSA’s 

participation and benefits from the 53 large buildings for 1999 through 2003 

to estimate the potential benefits to large GSA-controlled buildings for 2004 

through 2008. Specifically, we based our estimate of possible future GSA 

savings from demand-response programs on historical data on savings by 

GSA buildings participating in demand-response, the degree to which these 
Appendix I

Scope and Methodology

Page 49 GAO-04-844 Electricity Markets

buildings participated, and weather conditions, which we obtained from 

GSA and other sources. To account for variations in the factors affecting 

benefits, a Monte Carlo simulation was performed. In this simulation, 

values were randomly drawn 1,500 times from probability distributions 

characterizing possible values for participation rates, degree of 

participation, and weather conditions. The simulation resulted in forecasts 

of possible future savings from demand-response program participation by 

GSA. 

In developing our report we also met with 20 experts, who have extensive 

experience with demand-response programs. These individuals are listed in 

appendix II.

We conducted our work from March 2003 through July 2004 in accordance 

with generally accepted government auditing standards.
Page 50 GAO-04-844 Electricity Markets

Appendix II

Selected Experts Interviewed ApendxiI

This appendix lists the 20 experts we interviewed on the issues 

surrounding demand-response programs. Their listing here does not 

indicate their agreement with the results of our work. 

1. Severin Borenstein, University of California-Berkeley

2. Steve Braithwait, Christensen Associates

3. Richard Cowart, Regulatory Assistance Project

4. Larry DeWitt, Pace University School of Law

5. Ahmed Faruqui, Charles River Associates

6. Steve George, Charles River Associates

7. Joel Gilbert, Apogee Interactive

8. Charles Goldman, Lawrence Berkeley National Laboratory

9. Eric Hirst, Consulting in Electric-Industry Restructuring

10. Jerry Jackson, Jerry Jackson Associates Ltd.

11. Lynne Kiesling, Northwestern University

12. Chris King, E Meter Corporation

13. Roger Levy, Levy Associates

14. Amory Lovins, Rocky Mountain Institute

15. Bernie Neenan, Neenan Associates

16. Michael O’Sheasy, Christensen Associates

17. Steven Rosenstock, Edison Electric Institute

18. Larry Ruff, Charles River Associates

19. Vernon Smith, George Mason University

20. William Smith, Electric Power Research Institute
Page 51 GAO-04-844 Electricity Markets

Appendix III

Comments from the Federal Energy 

Regulatory Commission ApendxiI

Note: GAO comments 

supplementing those in 

the report text appear 

at the end of this 

appendix.
Appendix III

Comments from the Federal Energy 

Regulatory Commission

Page 52 GAO-04-844 Electricity Markets

See comment 1.
Appendix III

Comments from the Federal Energy 

Regulatory Commission

Page 53 GAO-04-844 Electricity Markets

See comment 2.

See comment 3.

Now on p. 17.
Appendix III

Comments from the Federal Energy 

Regulatory Commission

Page 54 GAO-04-844 Electricity Markets

See comment 4.

See comment 5.

See comment 6.
Appendix III

Comments from the Federal Energy 

Regulatory Commission

Page 55 GAO-04-844 Electricity Markets
Appendix III

Comments from the Federal Energy 

Regulatory Commission

Page 56 GAO-04-844 Electricity Markets

The following are GAO’s comments on the Federal Energy Regulatory 

Commission’s letter dated July 7, 2004.

GAO Comments 1. We agree with FERC that the divided jurisdiction over electricity 

markets poses a challenge for implementing demand-response. We 

have already mentioned this divided jurisdiction in the opening pages 

of our report and discussed it in greater detail in the background 

section. GAO, which works for Congress to evaluate federal agencies 

and recommend changes at those agencies, cannot make 

“recommendations” to state commissions. We agree, however, that 

state commissions are important to the success of demand-response. 

Toward that end, our recommendation states that FERC should work 

with state commissions to develop complementary policies regarding 

specific demand-response programs. Accordingly, we made no changes 

to our report for this comment. 

2. We agree with FERC that demand-response programs have been 

implemented in some markets, such as the NYISO, as we discuss in our 

report. These programs provide examples of the importance and 

success of demand-response, particularly with regard to reliability. 

However, we continue to believe that the amount of load actively 

participating in such programs is "limited" when compared with peak 

load in most regions, as FERC notes. Our finding that demand-response 

programs are in limited use, when viewed from a regional or 

countrywide perspective, is not meant to leave a negative impression, 

as described by FERC, regarding the potential of demand-response. In 

fact, the second objective of our report discusses its overall benefits at 

some length and finds that it shows substantial potential. Our point in 

identifying the limited extent of demand-response is meant to clarify 

that in many parts of the country additional efforts are needed to assure 

that sufficient demand-response exists in all markets overseen by 

FERC. As such, we made no changes to our report.

3. The sentence referred to in this comment was not intended to criticize 

the implementation of demand bidding. Rather, we are clarifying the 

limited extent of demand bidding, which so far has been relevant only 

when prices reach very high levels, as FERC observes. We agree that 

demand bidding is meant to provide relief when prices are high. 

However, we also note that program operators expressed concern that 

there was little demand bidding in some markets even when prices 

were at levels where many customers would benefit from reducing 
Appendix III

Comments from the Federal Energy 

Regulatory Commission

Page 57 GAO-04-844 Electricity Markets

demand. These programs are generally subscribed to by customers 

with large demand, such as manufacturing. They are complex insofar as 

customers must develop baselines to reflect their expected 

consumption for all hours of the year, as we discuss in the report. We 

made no changes in response to this comment.

4. Our report intended to reflect the value and importance of voluntary 

and contractual ISO emergency programs. For both types of emergency 

programs, we noted that enrollment is typically voluntary. However, 

customers participating in contractual programs sign agreements that 

might entail financial penalties if a participant does not reduce demand 

as required by the program. We agree with FERC that these programs 

within the NYISO are important. In responding to our fourth objective, 

we discussed the reasons for the success of these programs, citing 

them as examples that might be applied in other areas. For these 

reasons, no changes in response to this comment were included in our 

report. 

5. As FERC considers our recommendation to condition the granting of 

market-based rate authority upon the presence of sufficient demandresponse, we are hopeful FERC will regard our recommendation as 

another way to dampen the ill effects of the “boom-bust” cycle. In this 

respect, we see our recommendation as a way help create a market for 

demand-response, which should benefit the development of these 

programs. In our view, the currently low electricity prices offer a 

perhaps short-lived opportunity to develop demand-response resources 

that may be urgently needed if demand intensifies in response to a 

stronger economy, weather events, fuel price increases, supply 

interruptions, or other events. With respect to actions to address 

resource adequacy, FERC may be in the position to limit the activities 

of energy sellers who are unwilling to develop or acquire adequate 

demand-response, even in markets without an organized ISO or RTO. It 

may be able to exercise this leverage when key participants in these 

markets seek FERC approval for market-based rate authority or for 

purchases from markets overseen by FERC. In view of these 

observations, we made no changes to our report. 

6. While our report did not elaborate on DOE’s potential role in detail, we 

recognized its importance. In our report, we discuss DOE’s role in 

formulating national energy policy, researching technologies, and 

disseminating information to the public, among other things. In 

addition, in our recommendations to FERC, we suggested FERC should 
Appendix III

Comments from the Federal Energy 

Regulatory Commission

Page 58 GAO-04-844 Electricity Markets

also engage the Department of Energy’s expertise in identifying costeffective technologies and information dissemination capabilities, thus 

leveraging DOE’s technology expertise and its relationships with state, 

industry, and consumer groups. As such, we did not add additional 

information in response to this comment.
Page 59 GAO-04-844 Electricity Markets

Appendix IV

Comments from the General Services 

Administration ApendxiIV
Appendix IV

Comments from the General Services 

Administration

Page 60 GAO-04-844 Electricity Markets
Appendix IV

Comments from the General Services 

Administration

Page 61 GAO-04-844 Electricity Markets
Page 62 GAO-04-844 Electricity Markets

Appendix V

GAO Contacts and Staff Acknowledgments ApendxiV

GAO Contacts Jim Wells (202) 512-3841

Dan Haas (202) 512-9828

Staff 

Acknowledgments

In addition to the individuals named above, Mary Acosta, Dennis Carroll, 

Randy Jones, Jon Ludwigson, Paul Pansini, Frank Rusco, Anne Stevens, 

Barbara Timmerman made key contributions to this report. Important 

contributions were also made by Kim Wheeler-Raheb and Carol Herrnstadt 

Shulman.

(360321)
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GAO

Permit No. GI00