Electricity Markets: Consumers Could Benefit from Demand
Programs, but Challenges Remain (13-AUG-04, GAO-04-844).
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 black- out 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 demand-response 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).
-------------------------Indexing Terms-------------------------
REPORTNUM: GAO-04-844
ACCNO: A11111
TITLE: Electricity Markets: Consumers Could Benefit from Demand
Programs, but Challenges Remain
DATE: 08/13/2004
SUBJECT: Electric energy
Energy demand
Energy industry
Energy marketing
Price regulation
Prices and pricing
Program evaluation
Strategic planning
State law
Consumer education
California
Florida
Georgia
New York
******************************************************************
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** may not resemble those in the printed version. **
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GAO-04-844
United States Government Accountability Office
GAO Report to the Chairman, Committee on Governmental Affairs, U.S. Senate
August 2004
ELECTRICITY MARKETS
Consumers Could Benefit from Demand Programs, but Challenges Remain
a
GAO-04-844
Highlights of GAO-04-844, a report to the Chairman, Committee on
Government Affairs, U.S. Senate
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.
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 [email protected].
August 2004
ELECTRICITY MARKETS
Consumers Could Benefit from Demand Programs, but Challenges Remain
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.
Contents
Letter
Results in Brief
Background
Market-Based and Reliability Programs Allow Demand to Respond
to Changing Prices and Supply Shortages but Are in Limited Use
Demand-Response Programs Have Saved Millions of Dollars and Can Improve
the Reliability of the Electricity System Multiple Barriers Make It
Difficult to Introduce and Expand Demand-Response Programs Certain
Programs Show How Barriers Were Overcome and Provide
Lessons on How to Cultivate New Programs Conclusion Recommendations for
Executive Action Agency Comments and Our Evaluation
1 4 7
12
21
31
37 42 43 45
Appendixes Appendix I: Appendix II: Appendix III:
Appendix IV: Appendix V: Scope and Methodology
Selected Experts Interviewed
Comments from the Federal Energy Regulatory Commission
GAO Comments
Comments from the General Services Administration GAO Contacts and Staff
Acknowledgments
GAO Contacts
Staff Acknowledgments
47 50
51 56
59
62 62 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
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
This is a work of the U.S. government and is not subject to copyright
protection in the United States. It may be reproduced and distributed in
its entirety without further permission from GAO. However, because this
work may contain copyrighted images or other material, permission from the
copyright holder may be necessary if you wish to reproduce this material
separately.
A
United States Government Accountability Office Washington, D.C. 20548
August 13, 2004
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
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
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
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
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
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.
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.
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.
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.
1In 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.
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 Demand-Response 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
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.
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.
2U.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).
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.
Figure 1: Illustration of Variations in Market-Based Pricing Systems
Source: GAO.
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:
o 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
about 140 customers and accounting for about 8 percent of total
electricity sales).
o 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.
3A 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).
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 Reliability-driven programs allow the grid
operator or utility to call on Grid Operators to Reduce participating
customers to reduce demand during periods of tight supply by Demand in
Response to shutting down equipment or by generating their own
electricity. Grid
operators and utilities activate these programs to avoid widespreadSupply
Shortages, but Use Is blackouts during periods of extremely high demand or
when a power plant Limited or transmission line is shut down unexpectedly.
Although enrollment in
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.
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
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.
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.
Table 1: Studies of the Benefits of Existing Market-Based Pricing Programs for
Regions and Specific Programs
Study title, author, date Results/conclusions
"The Economics of Real-Time and Pacific Gas and Electric has operated a
time-of-use program since 1982, with about 85,000 Time-of-Use Pricing for
participants as of 2001. Consumers have reduced their electricity usage
during peak periods by Residential Consumers," King, 18%. As of the early
1990s, 80% of participants were saving $240 per year through the program,
or June 2001 about $16 million per year. The utility has also benefited
from the shift in demand to off-peak.
"Evaluation of the Energy-Smart Community Energy Cooperative of Chicago's
demand-response program had 750 participating Pricing Plan: Final Report,"
residential customers, representing a wide variety of neighborhoods and
types of homes, in 2003, its Summit Blue Consulting for first year of
operation. Under day-ahead pricing, these customers saved an average of
19.6% on Community Energy Cooperative, their energy bills, or more than
$10 per month in 2003, for modestly cutting back on consumption Mar. 2004
during approximately 30 hours of peak demand during the summer months.
"Industrial Response to Electricity Real-time pricing by Duke Power in the
Carolinas induced demand reductions of about 70 MW, or Real-Time Prices:
Short Run and approximately 8% of consumption during four summer months of
peak demand. This translates into Long Run," Schwarz, et al., Oct.
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 Georgia Power's real-time pricing
program, with about 1700 participants representing about 5,000 Prices:
Information to Support MW of demand, can count on a demand reduction of at
least 750 MW when capacity is constrained Wholesale Price Forecasting and
and wholesale markets are tight. On a few days in summer 1999, Georgia
Power's real-time prices Market Analysis," Braithwait for reached levels
as much as twice as high as those seen in previous years. Prices were
moderately EPRI, Nov. 2001 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 Customers participating in Gulf Power's
critical peak pricing program in 2002 on average consumed Select Program
Critical Calls," Gulf 50 percent less electricity during "critical
periods"-when price was higher-than did a similar group Power, May 2003 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 Residential customers in the Wisconsin Public
Service Corporation's peak-load pricing program who Electricity Markets,"
Lafferty, et al. faced a peak price that was double the off-peak price
reduced their consumption during summer for FERC, Jan. 2001 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 From July 1999 through August 2000, San Diego Gas
and Electric Company charged residential Opportunity in California,"
customers electricity prices based on regional wholesale market prices.
During this period, it McKinsey and Company, Mar. provided customers with
the electricity wholesale price index on their monthly statements. In
June2002. August 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 The NYISO's demand bidding program provided
over 25 MW of load reduction when summer peak Operator (NYISO)
Price-prices were the highest in 2001. The program's scheduled load
reductions are estimated to have Responsive Load Program reduced market
prices by 0.3% to 0.9%. Total collateral benefits from reducing market
prices are Evaluation: Final Report," Neenan estimated to be $1.5 million
in 2001. The program is expected to reduce the frequency of system
Associates, Jan. 2002 emergencies and lessen the need for reliability
programs.
"Framing Paper #1: Price-The New England Independent System Operator's,
New England Demand-response Initiative
Responsive Load (PRL) (NEDRI) was used on six occasions in 2001 when
prices frequently reached $1,000/MWh providing
Programs," Goldman for NEDRI, an average demand reduction of 17 MW.
Mar. 2002
Source: GAO.
As the table shows, these estimates of actual savings include savings to
individual utilities and their customers as well as regional savings. For
example:
o 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.
o 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:
o 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.
o In California, according to the manager at a three-building commercial
office complex that participates in market-based and reliability
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.
o 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.
Table 2: Studies of Potential Benefits of Demand-Response
Study title, author, date Results/conclusions Retrospective
"The Financial and Physical If hourly pricing had been in place for 20% of
California's retail electricity demand in 1999 and there Insurance
Benefits of Price-had been a moderate amount of price responsiveness, the
state's electricity costs would have been Responsive Demand," Hirst, May
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: Market-In California, during the energy crisis
in summer 2000, if demand-response to hourly market-based based pricing
could prevent future retail prices had been in place, Californians could
have reduced their peak demand by 193 MW, crises," Faruqui, et al., fall
2001 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 In late July 1999 in the Midwest, wholesale
electricity prices spiked to $10,000 per MWh. If only Wholesale Markets
through 10% of the retail demand for electricity had faced real-time
pricing and there had been a moderate Market-Based Pricing in Retail
amount of price responsiveness, electricity prices would have risen to
only about $2,700, 73% Markets," Caves, Eakin and percent less than the
price actually observed. Having just a small fraction of industry demand
facing Faruqui, Apr. 2000 real-time prices would significantly dampen
price spikes.
Prospective
Power System Economics: Evaluating power markets broadly, the net benefits
of demand with real-time pricing would be about Designing Markets for
Electricity, 2 percent of the total spent on electricity. For the United
States in 2003, that would amount to about Stoft, 2002 $4.5 billion. This
long-term estimate assumes that customers shift consumption from peak to
off
peak 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 The potential benefits for U.S. electricity
customers from adopting real-time pricing, with Policy," ICF Consulting
for FERC, conservative assumptions about customers' magnitude of response
and their ability for distributed Feb. 2002 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 U.S. electricity customers could potentially
realize benefits of $10 billion to $15 billion per year if Demand-Side
Management and they all participated in demand-response programs and, on
average, shifted 5 percent to 8 percent Dynamic Pricing Programs," of
their consumption from peak to off-peak periods and curtailed consumption
by another 4 percent McKinsey and Company, May 2001 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: If adopted everywhere in the United
States, demand-response programs could reduce demand for Imperatives and
Opportunities," electricity by 45,000 MW or about 6 percent of forecasted
peak baseline usage. In California, EPRI White Paper, June 2001
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.
Source: GAO.
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
4According 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.
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
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).
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:
o 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
6Goldman, 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]).
o 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
7In 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.
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 Demand-Response
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.
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
8U.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.
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
9Because 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.
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
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 Demand-Response 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.
Several Outside Factors Have Also Served to Limit the Benefits of
Participating in Available Demand-Response 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:
o 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.
o 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 Certain demand-response programs that we reviewed
illustrate how the
barriers we identified were overcome and also point out three broaderShow
How Barriers lessons on how to cultivate new programs. Were Overcome and
Provide 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.
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.
Source: GAO analysis and illustration based on Gulf Power information;
photos (2) and (3) Gulf Power.
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,
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 Demand-Response 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.
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.
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:
o 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
just and reasonable. If FERC determines that its authority is not
sufficient to take such action, it should seek this authority from
Congress.
o 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.
o 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:
o 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.
o 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.
o 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.
o 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
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
Appendix I
Scope and Methodology
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:
o 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.
o 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
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.
o 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.
o 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
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.
Appendix II
Selected Experts Interviewed
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
Appendix III
Comments from the Federal Energy Regulatory Commission
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
See comment 1.
Appendix III
Comments from the Federal Energy
Regulatory Commission
See comment 2.
Now on p. 17. See comment 3.
Appendix III
Comments from the Federal Energy
Regulatory Commission
See comment 4.
See comment 5.
See comment 6.
Appendix III
Comments from the Federal Energy
Regulatory Commission
Appendix III
Comments from the Federal Energy
Regulatory Commission
The following are GAO's comments on the Federal Energy Regulatory
Commission's letter dated July 7, 2004.
GAO Comments 1.
2.
3.
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.
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.
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
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
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.
Appendix IV
Comments from the General Services Administration
Appendix IV
Comments from the General Services
Administration
Appendix IV
Comments from the General Services
Administration
Appendix V
GAO Contacts and Staff Acknowledgments
GAO Contacts Jim Wells (202) 512-3841 Dan Haas (202) 512-9828
Staff Acknowledgments
(360321)
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.
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