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Report to the Chairman, Committee on Governmental Affairs, U.S. Senate:
July 2004:
ELECTRICITY MARKETS:
Consumers Could Benefit from Demand Programs, but Challenges Remain:
GAO-04-844:
GAO Highlights:
Highlights of GAO-04-844, a report to the Chairman, Committee on
Governmental Affairs, U.S. Senate:
Why GAO Did This Study:
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).
What GAO Found:
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.
What GAO Recommends:
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.
[End of section]
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:
Appendixes:
Appendix I: Scope and Methodology:
Appendix II: Selected Experts Interviewed:
Appendix III: Comments from the Federal Energy Regulatory Commission:
GAO Comments:
Appendix IV: Comments from the General Services Administration:
Appendix V: GAO Contacts and Staff Acknowledgments:
GAO Contacts:
Staff Acknowledgments:
Tables:
Table 1: Studies of the Benefits of Existing Market-Based Pricing
Programs for Regions and Specific Programs:
Table 2: Studies of Potential Benefits of Demand-Response:
Figures:
Figure 1: Illustration of Variations in Market-Based Pricing Systems:
Figure 2: Gulf Power's Energy Control System for Residential
Participants in GoodCents Select:
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:
Letter July 30, 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 well-
functioning 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 demand-response 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 demand-
response 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.[Footnote 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 self-regulated by
an elected board.
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 demand-response 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.[Footnote 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:
market-based 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.
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-of-use 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:
[See PDF for image]
[End of figure]
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; mid-peak, 6:00 a.m. to noon and 6:00 p.m. to 10:00 p.m; peak,
noon to 6:00 p.m.). The highest prices are established for periods such
as the peak when demand and cost of supply are generally highest, based
on historical cost and consumption information, and are designed to
encourage consumers to reduce demand during those periods. We examined
two time-of-use programs, one traditional program in California and a
variation on that type of program in Florida. One industrial consumer
operating a refrigerated warehouse, and participating in a traditional
time of use program, explained how he adjusts his operations in
response to these rates. By refrigerating some products at lower than
normal temperatures during the night when prices are lower, he can turn
the refrigeration equipment off during the middle of the day to avoid
the higher daytime prices without temperatures rising above acceptable
levels. While these responses can be useful, experts told us,
traditional time-of-use prices are unable to reflect unforeseen events,
such as increased demand because of extreme heat or a sudden supply
shortage, which may occur if a power plant is unexpectedly shut down.
To modify time-of-use rates to accommodate these possibilities, the
Florida program we reviewed operates a variation on time-of-use rates
in a voluntary program for about 3,200 residential customers. Gulf
Power presets prices for three periods per day (peak, off-peak, and
mid-peak). However, with some advance notification, an additional price
preset at a much higher level (called the critical peak price) can be
put into effect at any time when supplies are tight or demand is high;
however, this higher price cannot be in effect for more than 88 hours
per year. An innovative control system, provided by the utility,
enables customers to program the system to shut off as many as four
electrical devices in response to preset price periods and notifies
participants if the critical peak pricing period is in effect. The
critical peak price was not used in 2003, but in 2002 the utility put
the additional price into effect on 11 occasions for a total of 12
hours.
With respect to real-time pricing, prices generally vary for each hour
of each day and are more closely linked to variations in the actual
hourly cost of supply than time-of-use rates. There are several
different ways of implementing real-time pricing programs. For example:
* Niagara Mohawk in New York State allows some of its large customers
to participate in a program that prices electricity on an hourly basis,
based on a forecast done the day before consumption is to occur (with
about 140 customers and accounting for about 8 percent of total
electricity sales).
* Georgia Power, a regulated utility, offers a voluntary real-time
pricing program (with 1,600 customers and about 5,000
megawatts[Footnote 3] (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 Web-based 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. They are not penalized if they do not
bid; however, they are penalized if their bid is accepted and they fail
to provide the agreed-upon reduction. The New York grid operator told
us demand bidding was a relatively small resource for reducing demand,
accounting for 1,500 MWhs, for which 24 participants were paid $100,000
or more in 2002. One participant told us that they were willing to bid
when prices reach certain high levels, but they were reluctant to do so
if prices were low because reducing demand generally reduced their
production or otherwise hindered their business operations.
For demand-bidding programs to operate, the program operator must
develop an estimate of participant demand for all hours of the year--
called a baseline. According to experts, because individual consumer
demand varies seasonally, in response to the economy, and for other
reasons, it is often difficult to develop a baseline that accurately
estimates demand. Further, because most of these customers have not
agreed to purchase the electricity that they are offering to sell, some
experts have questioned whether this lack of clear ownership of the
electricity raises questions over property rights and opens the
programs to manipulation.
Overall, the use of market-based pricing is relatively limited,
generally affecting only certain types of customers and some areas and
accounting for a small share of overall demand, with most customers
still paying prices that are not market-based. Time-of-use pricing
programs are available from many utilities, but participation is
generally limited to some commercial and industrial customers. However,
in some parts of the country some customers have been required to pay
time-of-use rates. For example, the California Public Utility
Commission requires large customers of the state's public utilities to
be on time-of-use pricing plans. Real-time pricing programs are
available in only a few locations, and the number of customers enrolled
in these programs is generally small. With regard to demand bidding,
these programs are relatively new and available only in a few
locations. Even where they are available, active participation has been
limited to times when wholesale prices are high.
Reliability Programs Allow Grid Operators to Reduce Demand in Response
to Supply Shortages, but Use Is Limited:
Reliability-driven programs allow the grid operator or utility to call
on participating customers to reduce demand during periods of tight
supply by shutting down equipment or by generating their own
electricity. Grid operators and utilities activate these programs to
avoid widespread blackouts during periods of extremely high demand or
when a power plant or transmission line is shut down unexpectedly.
Although enrollment in 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, demand-response 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: "The Economics of Real-Time and Time-of-Use
Pricing for Residential Consumers," King, June 2001;
Results/ conclusions: Pacific Gas and Electric has operated a time-of-
use program since 1982, with about 85,000 participants as of 2001.
Consumers have reduced their electricity usage during peak periods by
18%. As of the early 1990s, 80% of participants were saving $240 per
year through the program, or about $16 million per year. The utility
has also benefited from the shift in demand to off-peak.
Study title, author, date: "Evaluation of the Energy-Smart Pricing
Plan: Final Report," Summit Blue Consulting for Community Energy
Cooperative, Mar. 2004;
Results/conclusions: Community Energy Cooperative of Chicago's demand-
response program had 750 participating residential customers,
representing a wide variety of neighborhoods and types of homes, in
2003, its first year of operation. Under day-ahead pricing, these
customers saved an average of 19.6% on their energy bills, or more
than $10 per month in 2003, for modestly cutting back on consumption
during approximately 30 hours of peak demand during the summer months.
Study title, author, date: "Industrial Response to Electricity Real-
Time Prices: Short Run and Long Run," Schwarz, et al., Oct. 2002;
Results/conclusions: Real-time pricing by Duke Power in the Carolinas
induced demand reductions of about 70 MW, or approximately 8% of
consumption during four summer months of peak demand. This translates
into long-term savings of about $2.7 million per year for the 110
industrial customers who participated during the period 1994 to 1999.
Study title, author, date: "Customer Response to Electricity Prices:
Information to Support Wholesale Price Forecasting and Market
Analysis," Braithwait for EPRI, Nov. 2001;
Results/conclusions: Georgia Power's real-time pricing program, with
about 1700 participants representing about 5,000 MW of demand, can
count on a demand reduction of at least 750 MW when capacity is
constrained and wholesale markets are tight. On a few days in summer
1999, Georgia Power's real-time prices reached levels as much as twice
as high as those seen in previous years. Prices were moderately high
on several days and spiked to an extremely high level on a few days.
The very large industrial customers on hour-ahead rates reduced their
purchases by about 30% from their normal rate on the moderately high-
priced days and by nearly 60% during the two high-cost, capacity-
constrained episodes.
Study title, author, date: "Analysis for 2002 GoodCents Select Program
Critical Calls," Gulf Power, May 2003;
Results/conclusions: Customers participating in Gulf Power's critical
peak pricing program in 2002 on average consumed 50 percent less
electricity during "critical periods"- -when price was higher--than
did a similar group of nonparticipating consumers. Participants also
paid 11 percent less in total electricity bills because their total
electricity expenditures rose slower than the similar group of
nonparticipants.
Study title, author, date: "Demand Responsiveness in Electricity
Markets," Lafferty, et al. for FERC, Jan. 2001;
Results/conclusions: Residential customers in the Wisconsin Public
Service Corporation's peak-load pricing program who faced a peak price
that was double the off-peak price reduced their consumption during
summer peak periods by about 12%, while those facing a peak price that
was 8 times the off- peak price reduced their consumption by 15% to
20% during summer peak periods. At peak hours during heat waves,
consumption was reduced by 31% relative to nonpeak noncritical days.
Study title, author, date: "Responsive Demand: The Opportunity in
California," McKinsey and Company, Mar. 2002;
Results/conclusions: From July 1999 through August 2000, San Diego Gas
and Electric Company charged residential customers electricity prices
based on regional wholesale market prices. During this period, it
provided customers with the electricity wholesale price index on their
monthly statements. In June-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%.
Study title, author, date: "New York Independent System Operator
(NYISO) Price-Responsive Load Program Evaluation: Final Report," Neenan
Associates, Jan. 2002;
Results/conclusions: The NYISO's demand bidding program provided over
25 MW of load reduction when summer peak prices were the highest in
2001. The program's scheduled load reductions are estimated to have
reduced market prices by 0.3% to 0.9%. Total collateral benefits from
reducing market prices are estimated to be $1.5 million in 2001. The
program is expected to reduce the frequency of system emergencies and
lessen the need for reliability programs.
Study title, author, date: "Framing Paper #1: Price-Responsive Load
(PRL) Programs," Goldman for NEDRI, Mar. 2002;
Results/conclusions: The New England Independent System Operator's,
New England Demand-response Initiative (NEDRI) was used on six
occasions in 2001 when prices frequently reached $1,000/MWh providing
an average demand reduction of 17 MW.
Source: GAO.
[End of table]
As the table shows, these estimates of actual savings include savings
to individual utilities and their customers as well as regional
savings. For example:
* Individual programs operated by utilities located across the United
States have seen reductions in demand of between 5 percent and 60
percent during high-priced hours, resulting in millions of dollars in
customer savings and/or cost reductions. For example, according to a
study of a long-running time-of-use program in California, in the early
1990s 80 percent of participants were saving $240 per year (or about
$16 million per year in total for all participants) by cutting back on
their consumption during the hours of peak demand. According to another
study, Georgia Power staff could plan on participants reducing about
750 MW of power during high-priced hours, and they have seen reductions
in peak demand of up to 17 percent on critical days. These savings
reduce the amount of costly peak-generation equipment necessary, they
said, and the program passes these savings along to its customers.
* Regional programs operating in the Northeast (New York and New
England) have witnessed significant reductions in demand, which
resulted in (1) millions of dollars in participant savings through
price reductions and direct payments and (2) price reductions for
nonparticipants amounting to millions of dollars more per year. For
example, according to one study, the New York grid operator's demand
bidding program reduced electricity prices by $1.5 million in summer
2001.
Our discussions with individual participants also highlighted specific
savings for them resulting from the availability and use of demand-
response programs. For example:
* According to a manager at a rural textile mill participating in
Georgia Power's real-time pricing program, the mill reduced its
purchases from the utility by increasing the output of an on-site
generator during periods of high prices, for a savings of about $1
million per year. These savings allowed his mill to remain competitive
while many others in the United States had shut down production and
moved to other countries, in part because electricity prices were too
high.
* In California, according to the manager at a three-building
commercial office complex that participates in market-based and
reliability programs, the complex reduced its total electricity costs
by 17 percent in 2003. To achieve these savings, the facility used
advanced energy controls that allowed building operators to raise or
lower building temperature and lighting, as well as a thermal storage
cooling system that allowed it to chill water at night and use it
during the day to cool the building and thereby avoid using air-
conditioning during times when prices were high.
* One residential participant in Gulf Power's critical peak pricing
program significantly reduced his demand during the most costly hours
and saved nearly $600 per year, or more than a third of his annual
power costs, by shifting many activities from the most costly hours to
off-peak hours.
As table 2 shows, retrospective studies of past crises in the West and
other parts of the country that have experienced significant market
problems estimate that these programs could have saved potentially
billions of dollars had they been available and used in these areas.
One study examined the electricity crisis of 2000 to 2001 in the West
and estimated that, had market-based pricing been in place, the high
prices seen in California during 2000 might have been reduced by 12
percent--resulting in a $2.5 billion reduction in the state's
electricity costs. Similarly, experts have prospectively estimated that
the widespread implementation of these programs could result in
significant reductions in electricity costs. For example, three
separate studies concluded that widespread implementation of demand-
response programs could result in savings ranging from $5 billion to
$15 billion, depending on the extent of participation and the costs of
implementation.
Table 2: Studies of Potential Benefits of Demand-Response:
Retrospective:
Study title, author, date: "The Financial and Physical Insurance
Benefits of Price-Responsive Demand," Hirst, May 2002;
Results/conclusions: Retrospective: If hourly pricing had been in place
for 20% of California's retail electricity demand in 1999 and there had
been a moderate amount of price responsiveness, the state's electricity
costs would have been 4%, or $220 million lower. In 2000, electricity
prices were almost four times higher and also much more volatile than
in 1999. Hourly pricing for 20% of retail demand in 2000 would have
saved consumers about $2.5 billion or 12 percent of the statewide power
bill.
Study title, author, date: "Getting Out of the Dark: Market-based
pricing could prevent future crises," Faruqui, et al., fall 2001;
Results/conclusions: Retrospective: In California, during the energy
crisis in summer 2000, if demand-response to hourly market-based retail
prices had been in place, Californians could have reduced their peak
demand by 193 MW, thereby reducing prices from peak hourly levels of
$750 per MWh to $517 per MWh. For the summer season as a whole, energy
costs would have been reduced on high-priced days by $81 million.
Study title, author, date: "Mitigating Price Spikes in Wholesale
Markets through Market-Based Pricing in Retail Markets," Caves, Eakin
and Faruqui, Apr. 2000;
Results/conclusions: Retrospective: In late July 1999 in the Midwest,
wholesale electricity prices spiked to $10,000 per MWh. If only 10% of
the retail demand for electricity had faced real-time pricing and there
had been a moderate amount of price responsiveness, electricity prices
would have risen to only about $2,700, 73% percent less than the price
actually observed. Having just a small fraction of industry demand
facing real-time prices would significantly dampen price spikes.
Prospective:
Study title, author, date: Power System Economics: Designing Markets
for Electricity, Stoft, 2002;
Results/conclusions: Retrospective: Evaluating power markets broadly,
the net benefits of demand with real- time pricing would be about 2
percent of the total spent on electricity. For the United States in
2003, that would amount to about $4.5 billion. This long-term estimate
assumes that customers shift consumption from peak to 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.
Study title, author, date: "Economic Assessment of RTO Policy," ICF
Consulting for FERC, Feb. 2002;
Results/conclusions: Retrospective: The potential benefits for U.S.
electricity customers from adopting real- time pricing, with
conservative assumptions about customers' magnitude of response and
their ability for distributed generation, are estimated to be $7.5
billion annually, compared with the status quo by 2010, the first year
the effects would be fully in place.
Study title, author, date: "White Paper: The Benefits of Demand-Side
Management and Dynamic Pricing Programs," McKinsey and Company, May
2001;
Results/conclusions: Retrospective: U.S. electricity customers could
potentially realize benefits of $10 billion to $15 billion per year if
they all participated in demand-response programs and, on average,
shifted 5 percent to 8 percent of their consumption from peak to off-
peak periods and curtailed consumption by another 4 percent to 7
percent. The switch to demand-response programs would avoid 250
peaking power plants at 125 MW each to handle peak demand, for a total
of 31,250 MW of peak capacity (or $16 billion to build plants used to
handle peak demand). Also avoided would be 680 billion cubic feet of
natural gas usage and 31,000 tons of nitrous oxide pollution per year.
Study title, author, date: "The Western States Power Crisis:
Imperatives and Opportunities," EPRI White Paper, June 2001;
Results/conclusions: Retrospective: If adopted everywhere in the
United States, demand-response programs could reduce demand for
electricity by 45,000 MW or about 6 percent of forecasted peak
baseline usage. In California, demand-response could reduce demand by
8.7% and offset the need for new capacity by eliminating 57% of the
forecasted load growth during the next several years.
Study title, author, date: "The Choice Not to Buy: Energy Savings and
Policy Alternatives for Demand Response," Braithwait and Faruqui, Mar.
2001;
Results/conclusions: Retrospective: 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.
Study title, author, date: "The Feasibility of Implementing Dynamic
Pricing," California Energy Commission, Oct. 2003;
Results/conclusions: Retrospective: 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.
[End of table]
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 seldom-used 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.[Footnote 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
demand-response 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 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 market-based 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 high-priced 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.[Footnote 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 demand during times when electricity is scarce and costly, as
individual customers choose not to purchase increasingly expensive
supplies. This mechanism is especially useful when demand is slowly
approaching the total available supply and customers have some advanced
warning that electricity is becoming more costly. For example, higher
real-time prices seen by retail customers would reflect, generally
within 1 hour, a power plant or transmission line's unavailability.
Seeing these prices, customers tend to reduce demand and hence the
amount of electricity that must be generated from power plants during
the next hour. This lower level of demand, in turn, makes it easier for
the grid operator to add enough supplies to meet demand and perhaps
reduces the cost of doing so. However, these programs may not be able
to meet sudden needs or provide sufficient and predictable demand
reductions to maintain reliability.
Second, reliability-driven programs provide additional flexibility by
allowing grid operators to either increase supply or reduce demand to
avoid blackouts or other disruptions. These types of mechanisms are
especially useful in obtaining known amounts of demand reduction
relatively quickly and sustaining demand reduction over some
predictable period of time. For example, one expert told us that this
type of program would be very useful if a large power plant had to
suddenly shut down for safety reasons, and the grid operator found that
available alternative supply sources were very costly or insufficient
to meet their quantity and location needs. In this case, the grid
operator might be able to maintain reliability at a lower cost by
interrupting electricity service to interruptible customers for a short
period of time, an interruption for which they would be paid. By this
planned and compensated interruption of service for a few customers,
utilities and other service providers are able to avoid unplanned
service interruptions--or blackouts--for a much greater number of
customers. For example:
* During California's energy crisis of 2000 and 2001, experts found
that utility programs that could interrupt service were instrumental in
avoiding blackouts on at least five occasions.[Footnote 6]
* 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.[Footnote 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 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 demand-response 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.[Footnote 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 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.[Footnote 9]
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 demand-
response 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 demand-
response 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
electricity-consuming 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
demand-response 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 high-priced 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
demand-response 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 demand-response was available.
GSA's Participation in Demand-Response Programs Has Been Limited:
According to GSA officials, participation in demand-response programs
has been limited for the following reasons:
* GSA lacks specific guidance on how to participate. While GSA provides
guidance regarding participation in reliability-driven programs,
information regarding market-based pricing programs is limited. For
example, a regional energy manager we spoke with was not generally
familiar with market-based pricing programs and thought that backup
generation was required to participate. Another regional energy manager
told us that he relied on information provided by the local utility and
grid operator to provide the information he used to make decisions on
whether to participate in these programs.
* Federal agency tenants have little incentive to reduce their
consumption. According to GSA officials, current leases require a fixed
monthly payment from federal agency tenants, which does not provide a
way to share any savings from demand reduction efforts or to pass on
the higher costs to agencies creating higher demand during high cost
periods. Therefore, tenants do not have incentives to seek
opportunities for the electricity savings that could be realized from
participation in demand-response programs.
In addition, the need to reduce demand has been limited in recent
years. As with other customers, GSA officials have not seen high
electricity prices because of such factors as moderate weather.
Consequently, GSA officials told us that they have had difficulty
maintaining interest in reliability-based programs among their clients
or in recruiting new ones.
Certain Programs Show How Barriers Were Overcome and Provide Lessons on
How to Cultivate New Programs:
Certain demand-response programs that we reviewed illustrate how the
barriers we identified were overcome and also point out three broader
lessons on how to cultivate new programs.
Two Programs Illustrate How to Overcome Barriers:
To overcome regulatory barriers, Gulf Power, a regulated utility in the
panhandle of Florida, introduced its GoodCents Select market-based
pricing program by receiving regulatory approval to offer it as a
voluntary program. The utility demonstrated to state regulators that
its program could offer benefits such as lower overall electricity
costs and additional services to participants without raising prices
for or otherwise harming nonparticipants. In general, state regulators
told us that they review the impact of programs on the electricity
rates of nonparticipants, which is referred to as the rate impact test.
This test compares the avoided costs, including costs to construct
power plants and transmission lines as well as costs to operate and
maintain new facilities, with the costs of operating the program. In
the case of the demand-response program that we reviewed, they approved
the program proposed by the utility because of its benefits for both
participants and nonparticipants.
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-of-day 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.
Figure 2: Gulf Power's Energy Control System for Residential
Participants in GoodCents Select:
[See PDF for image]
[End of figure]
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,[Footnote 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 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:
* 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.
* In reporting to Congress, the Chairman should identify the options
that may have potentially large benefits and are cost-effective for
achieving consumer response, as well as statutory or other impediments
to putting these options into practice.
* Because the development of demand-response programs depends upon
there being markets where these services can be sold, the Chairman
should encourage, where reasonable, equal consideration of supply and
demand when approving or changing market designs.
In implementing these recommendations, it is important that the
Commission continue working with system operators, regional entities,
and interested state commissions, and market participants to develop
compatible regional market rules and policies regarding demand-
response. FERC should use these outreach efforts to identify regions of
the country where demand-response programs are most urgently needed and
where grid operators, state regulatory officials, and market
participants are amenable to the collaborative introduction of
regionwide demand-response programs. As part of its efforts, FERC
should also engage the Department of Energy in its examination of
demand-response options and involve the department in its outreach
efforts, thus leveraging its expertise in identifying cost-effective
technologies and its relationships with state, industry, and consumer
groups.
Because demand-response programs offer potential financial benefits to
the federal government and to demonstrate the federal government's
commitment to improving the functioning of electricity markets, we
recommend that, for locations where the General Services Administration
has significant energy consumption, its Administrator take the
following four actions:
* Require regional energy managers to identify what demand-response
programs are available to them, require building operators to determine
whether they could actively participate in the programs, and quantify
the benefits of that participation.
* Develop guidance that clearly articulates to the regional offices
that participation in demand-response programs should be considered as
part of the energy decisions that they make.
* Require (1) guidance on specific measures that building operators can
take to respond to market-based programs, similar to the guidance that
they provide for responding to emergencies and (2) training on
evaluating how to maximize benefits from participation in these
programs.
* Clarify the incentives for participation by defining how the GSA, its
building operators, and its federal agency tenants will share the
benefits and risks of participating in these programs through its
leases.
Agency Comments and Our Evaluation:
We provided FERC and GSA a draft of our report for review and comment.
The Chairman of FERC endorsed our conclusions regarding the importance
of demand-response to competitive energy markets and to electricity
system reliability. The Chairman also generally agreed with the
report's recommendations. In response to one recommendation, the
Chairman agreed to consider conditioning market-based rate authority on
the presence of sufficient demand-response, but noted FERC uncertainty
as to whether it can require such a condition or that such conditioning
would be workable, given current policy that separates wholesale and
retail functions. Our recommendation, however, has a precedent in a
similar state jurisdictional issue--that of the construction of new
power plants. In this instance, FERC approved a mechanism, commonly
known as "capacity markets," that created an additional market for
power plants and serves as a signal for when they are needed. In the
same way, our recommendation, if properly implemented, could create
such a market for demand-response as well as serve as a complementary
signal for new capacity. FERC also provided several general and
clarifying comments or suggestions that we incorporated as appropriate
or address in appendix III.
GSA agreed with the report's conclusions regarding the importance of
demand-response to an efficient and reliable electricity industry. GSA
also stated that it agreed with the majority of our recommendations,
but it expressed some concern about one of them. Overall, its comments
focused on concerns about risk, especially in the form of financial
penalties that GSA may incur through participation in demand-response
programs. GSA also commented on the broad risks regarding price
stability and power reliability that pervade the transition from
regulated to restructured electricity markets. As such, GSA expressed
concern about the fourth recommendation for GSA to define how benefits
from successful demand-response 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 [Hyperlink, 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,
Signed by:
Jim Wells,
Director, Natural Resources and Environment:
[End of section]
Appendixes:
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:
* In California, we examined programs operated by one large electricity
provider and several programs operated by others. We examined two
programs operated by Southern California Edison: time-of-use rates for
large customers, interruptible rates for large customers, and and
direct interruptions to the operation of specific electrical devices,
such as air conditioners at customers' homes and/or businesses. In
addition, we discussed a range of programs operated by the state grid
operator (the California Independent System Operator [ISO]), and the
state created in response to the electricity crisis in 2000 and 2001.
We interviewed officials at Southern California Edison, the state
public utility commission, the California ISO, the California Energy
Commission, California Power Authority, and Pacific Gas and Electric.
In addition, we met with four customers that participated in programs
operated by Southern California Edison.
* In New York State, we examined programs operated by one large
electricity provider and by the state grid operator. We examined a
real-time 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 participants who
reduce demand when reliability is at risk. We also examined a
reliability program (called the Special Case Resources) that requires
participants to sign agreements in advance to reduce demand whenever
requested and pays them for doing so. In our report, we combine our
discussion of these two reliability programs. We also interviewed staff
from Niagara Mohawk, the New York ISO, the New York State Energy
Research and Development Authority, the New York Public Service
Commission, and a consultant who annually reviews the performance of
programs run by the New York ISO. In addition, we met with four
customers that participate in programs operated by the New York ISO
and/or Niagara Mohawk.
* In Georgia, we examined a real-time pricing program operated by
Georgia Power, a regulated utility. We also interviewed staff at
Georgia Power, the Georgia Department of Natural Resources--
Environmental Protection Division, and the Georgia Public Service
Commission. In addition, we met with two customers that have
participated in the Georgia Power program.
* In Florida, we examined a critical peak-pricing program (GoodCents
Select) operated by Gulf Power, a regulated utility. We also
interviewed staff at Gulf Power, the Florida Office of the Public
Counsel, the Florida Energy Office, and the Florida Public Service
Commission. In addition, we met with one residential participant in the
program.
To determine GSA's participation in demand-response programs, we
interviewed GSA staff located in the headquarters' Energy Center of
Expertise and in GSA's 11 regional offices and obtained information
about electricity consumption at about 1,400 facilities where GSA pays
for electricity. In addition, we obtained information about demand-
response activities at 53 large GSA buildings. These buildings incurred
the highest electricity expenses of the about 1,400 GSA-operated
buildings nationwide and represented about 40 percent of the agency's
total electricity expenses in 2003. We obtained information on
participation and the benefits of demand-response programs for a 5-year
period--1999 through 2003. To estimate the potential benefits of GSA's
more widespread and active participation in demand-response programs,
we used information on GSA's participation and benefits from the 53
large buildings for 1999 through 2003 to estimate the potential
benefits to large GSA-controlled buildings for 2004 through 2008.
Specifically, we based our estimate of possible future GSA savings from
demand-response programs on historical data on savings by GSA buildings
participating in demand-response, the degree to which these 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.
[End of section]
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.
[End of table]
[End of section]
Appendix III: Comments from the Federal Energy Regulatory Commission:
FEDERAL ENERGY REGULATORY COMMISSION:
WASHINGTON, DC 20426:
OFFICE OF THE CHAIRMAN:
July 7, 2004:
Mr. Jim Wells:
Director, Natural Resources and Environment:
United States General Accounting Office:
Room 2962:
441 G Street, N.W.:
Washington, D.C. 20548:
Re: GAO Report Entitled Electricity Markets: Consumers Could Benefit
from Demand Programs, But Challenges Remain:
Dear Mr. Wells:
Thank you for your June 18, 2004 letter enclosing your draft report,
Electricity Markets: Consumers Could Benefit from Demand Programs, But
Challenges Remain. I congratulate you on this effort and appreciate the
opportunity to comment.
I endorse and support GAO's conclusions that demand response would help
competitive energy markets function better and enhance the reliability
of the electric system. These goals underlie the Commission's own
activities in developing and fostering demand response in wholesale
electric markets. As this Commission has stated repeatedly, we cannot
have a fully competitive and robust wholesale electric market unless
customers have the ability to see and respond to electricity prices by
modifying their demand for electricity.
Before I comment on the specific content within the draft report, I
would like to offer three overall observations. First, the report
correctly focuses on three main barriers to the introduction of demand
response programs: (1) 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. The Commission recognizes these three
barriers and has acted within our jurisdiction - wholesale electric
markets --to lower or remove these barriers. Ultimately, however, these
barriers were historically created and are today sustained at the state
level, so the solution to these barriers lies in the states with retail
electric regulators and policymakers. Our Strategic Plan commits to
"work with states to support robust programs for customer demand-side
participation in energy markets." The commission has been working to
enhance and broaden wholesale electric markets, to improve market
transparency and participation to create more effective energy and
capacity prices that give clear signals that serve both the demand and
supply side. Where we see barriers in wholesale markets, we will work
within our jurisdiction and authority to remove them.
Second, I generally support the report's recommendations to: (a)
consider the presence or absence of demand-response programs as a
factor in the approval of wholesale market designs, (b) identify demand
response options in future reports to Congress, and (c) to encourage,
where reasonable, equal consideration of supply and demand when
approving or changing market design. I will ensure that the Commission
continues its outreach and collaboration efforts with all parties on
demand response (and its enabler, distributed generation), and our
staff will continue their close cooperation with the Department of
Energy on demand response and distributed generation issues. Examples
of our close working relationship with the Department of Energy have
included the joint sponsorship of the New England Demand Response
Initiative stakeholder process and our current coordinated support of
the International Energy Agency's Demand Response Resources project.
Third, we will consider your recommendation to condition a seller's
market-based rate authority on having sufficient demand response
capability. We do take market structure into account when granting
market-based rate authority and approving market power mitigation
policies. As a practical matter, it may not be possible to condition
market-based rate authority of wholesale sellers on actions taken by
their retail affiliates given current policy that separates wholesale
merchant and retail functions. A wholesale seller cannot necessarily
influence the policies of its retail affiliate, nor the state's retail
regulations under which it operates - but we can certainly encourage
state regulators to recognize the relationship between demand response
and market power mitigation. It is unclear whether we can require
wholesale suppliers to be subject to the existence of demand response
programs as a condition of market-based rate authority in wholesale
markets.
In addition to these overall comments in support of the report, I have
several general and detailed comments on the contents of the report.
These are discussed below.
General Comments:
First, while the authors of the report recognize and understand the
fundamental role of state policy and regulation in encouraging demand
response, a clearer exposition of the role of federal and state
regulation would strengthen the report. It would be helpful to include
a brief review, early in the report, of federal and state regulation
and relative jurisdictions as they relate to demand response. In
addition, references to regulation throughout the report should clearly
identify the responsible party (i.e., state versus federal). Without
these clarifications, readers of the report may not fully comprehend
that the success of demand response requires actions by both federal
and state regulators, not just the federal government. This point
would also be strengthened if your report offers recommendations
targeted towards state policymakers to highlight the need for strong
state impact on the success or failure of demand response and wholesale
market price levels, regardless of whether the state's retail customers
are served in a traditionally regulated or retail competitive
environment.
Second, I disagree with the inference throughout the report that demand
response is limited. For example, page 4, in "Results in Brief', states
that, "Two types of demand-response programs are in limited use," and
that, "Although reliability programs are more widely available than
market based pricing programs, their use is limited." The report is
correct that the amount of load currently participating in demand
response programs is a small portion of peak load in most regions of
the country. Nevertheless, the report leaves a negative impression
about the potential of demand response and does not adequately
highlight successes and recent significant improvements. New York is an
example of a successful implementation of demand response --the amount
of demand response in NYISO's reliability-driven demand response is
nearly equal to NYISO's typical 1,800 MW operating reserve, and the
amount of demand response in NY is about 5% of peak system load. The
most important lesson from New York is that the development of this
level of demand response required the joint cooperation and support of
multiple parties, i.e., NYISO, market participants, NYPSC and FERC - a
model for how demand response could be developed nationwide.
Third, in its criticism of the implementation of demand bidding
programs, the draft report laments that demand bidding program
participation is limited to high price periods (2ND full paragraph on
page 17. "Even where they are available, active participation has been
limited to times when wholesale prices are high."). This criticism is
misplaced. This Commission recognizes that demand bidding programs
provide the most benefit to the market and to participating customers
when prices are high. During periods of low prices, the value to price-
responsiveness to the market is low, and it is not profitable for
customers to reduce demand and potentially modify or curtail production
processes. Customers and LSEs will participate when it is "worth their
while." Experience has shown that when prices are high, participation
increases.
Fourth, the report does not adequately characterize the value and
importance of existing ISO emergency programs that obligate load
reductions through agreements and contracts. On page 19, the report
categorizes all emergency programs as "voluntary reduction programs."
The report only briefly mentions the signed agreements in NYISO's
Special Case Resources (SCR) program that obligate participants to
reduce demand when notified. The SCR program has proven to be an
important program for reliability and reserves in New York, and the
report downplays its importance within the NYISO and their value in
other regions. The Commission supports these programs because they
provide a guaranteed payment to customers willing to respond when
asked, and can lead to greater customer interest and participation in
other programs. I recommend that this section place greater emphasis on
these programs, and recognize the similarity of these contractual
programs to interruptible programs.
Fifth, I strongly agree with the report's concern on page 36 that low
prices and oversupply "could imperil demand-response programs," and
that in the West during the crisis of 2000 and 2001 "because programs
are difficult to start up, particularly during a crisis, little
additional demand response was available." This "boom-bust" problem
affects both demand response programs and the availability of peaking
supply units, so the Commission has been pursuing various policies to
improve resource adequacy, provide incentives for infrastructure
development, and enhance revenue and price stability. To address this
problem as it relates to demand response, this Commission has
encouraged and approved policies that provide capacity value for demand
response and recognize the value of demand response as a callable
resource option. Unfortunately, the report does not provide a targeted
recommendation to resolve the "boom-bust" problem. The report's
recommendation to solve this fundamental problem and others is to
recommend that FERC require demand response before it accepts various
market designs. We would welcome any specific thoughts from the
report's authors to address this long-term resource adequacy problem,
particularly in areas without ISOs or RTOs operating a competitive,
organized wholesale electric market.
Finally, while the report focuses on actions and policies that the
Commission and the General Service Administration can undertake, it
overlooks the potential role of other federal agencies. In particular,
the Department of Energy (DOE) can play an important and critical role
in developing the potential of demand response in the United States.
DOE's ongoing responsibilities to develop nationwide energy policy,
fund energy research and development, and provide energy education can
be utilized to foster greater demand response and awareness of demand
response as a crucial resource. While the DOE has been active in
promoting demand response, DOE could play an even larger role, and the
GAO may have helpful recommendations for DOE's role and
responsibilities with respect to demand response.
On a matter of detail, on pages 3 and 11, the report states, "as part
of a broader effort to develop consistent rules for regional markets,
FERC proposed an effort to encourage demand response in wholesale
markets." It is not clear which Commission effort is being described.
Our attempts to implement Standard Market Design did include demand
response as a core characteristic, as does its successor, the Wholesale
Market Platform. FERC continues to advocate an open wholesale platform
for demand and supply resource to compete on an equal basis, and
encourage states to "plug in" retail demand into this platform.
Thank you again for the valuable insights in your report.
Best regards,
Signed by:
Pat Wood, III:
Chairman
The following are GAO's comments on the Federal Energy Regulatory
Commission's letter dated July 7, 2004.
GAO Comments:
1 .We agree with FERC that the divided jurisdiction over electricity
markets poses a challenge for implementing demand-response. We have
already mentioned this divided jurisdiction in the opening pages of our
report and discussed it in greater detail in the background section.
GAO, which works for Congress to evaluate federal agencies and
recommend changes at those agencies, cannot make "recommendations" to
state commissions. We agree, however, that state commissions are
important to the success of demand-response. Toward that end, our
recommendation states that FERC should work with state commissions to
develop complementary policies regarding specific demand-response
programs. Accordingly, we made no changes to our report for this
comment.
2. We agree with FERC that demand-response programs have been
implemented in some markets, such as the NYISO, as we discuss in our
report. These programs provide examples of the importance and success
of demand-response, particularly with regard to reliability. However,
we continue to believe that the amount of load actively participating
in such programs is "limited" when compared with peak load in most
regions, as FERC notes. Our finding that demand-response programs are
in limited use, when viewed from a regional or countrywide perspective,
is not meant to leave a negative impression, as described by FERC,
regarding the potential of demand-response. In fact, the second
objective of our report discusses its overall benefits at some length
and finds that it shows substantial potential. Our point in identifying
the limited extent of demand-response is meant to clarify that in many
parts of the country additional efforts are needed to assure that
sufficient demand-response exists in all markets overseen by FERC. As
such, we made no changes to our report.
3. The sentence referred to in this comment was not intended to
criticize the implementation of demand bidding. Rather, we are
clarifying the limited extent of demand bidding, which so far has been
relevant only when prices reach very high levels, as FERC observes. We
agree that demand bidding is meant to provide relief when prices are
high. However, we also note that program operators expressed concern
that there was little demand bidding in some markets even when prices
were at levels where many customers would benefit from reducing 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 demand-
response, 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 also
engage the Department of Energy's expertise in identifying cost-
effective 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.
[End of section]
Appendix IV: Comments from the General Services Administration:
GSA:
GSA Administrator:
July 15, 2004:
The Honorable David M. Walker:
Comptroller General of the United States:
General Accounting Office:
Washington, DC 20548:
Dear Mr. Walker:
The General Services Administration (GSA) appreciates this opportunity
to submit agency comments on the U.S. General Accounting Office (GAO)
"Draft Report to the Chairman, Senate Committee on Governmental
Affairs, U.S. Senate, Electricity Markets: Consumers Could Benefit
through Demand Programs, But Challenges Remain," GAO-04-844 (Draft
Report).
GSA agrees with the majority of the recommendations and recognizes that
the recommendations provide GSA with an ideal opportunity to advise and
assist other Federal Agencies in implementing a more thorough demand
response program across the Nation.
Specific comments on the Report and the Report's recommendations are
enclosed. Questions regarding the Draft Report may be directed to Mr.
Mark Ewing, Energy Subject Matter Expert, at (202) 708-9296 or mark.
ewing@gsa.gov.
Sincerely,
Signed by:
Stephen A. Perry:
Administrator:
Enclosure:
General Services Administration:
Public Buildings Service:
Energy Center of Expertise:
Response to:
Proposed Report: Electricity Markets: Consumers Could Benefit through
Demand Programs (GAO-04-844):
Participation in market-based demand response programs.
The Draft Report outlines various electricity demand response programs,
generally described as either reliability or market-based. The Draft
Report makes a specific case for increased participation in these
programs by all retail customers, including GSA. In general, GSA agrees
with the Report's conclusion that effective demand response is
beneficial to the efficient and reliable functioning of the electricity
industry. It is important to note that GSAs participation in
reliability and market-based demand response programs may require
significant investment and may pose financial risks to GSA in terms of
penalties. Despite these challenges, GSA is cautiously increasing
participation in market-based programs in order to maximize potential
savings. The Draft Report states that, "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 [sic] to lead by example." What the Report does
not state is that by participating in market-based demand response
programs, such as real-time pricing, GSA exposes itself to
significantly greater risk should we not be able to reduce demand. The
Draft Report quantifies the potential savings resulting from greater
participation as $12 to $114 million, but it does not quantify
potential penalties. Using the real-time pricing example above, if a
GSA building was incapable of reducing demand according to price
signals, GSA would incur significantly higher utility costs
immediately. GSA would also face the dilemma of operating in excess of
appropriations during the term of a given fiscal year. Exposing GSA to
such potentially volatile market prices, when extrapolated to cover
GSA's inventory nationwide, may present more risk than the budget
planning process can accommodate.
Participation in reliability-driven demand response programs.
The Draft Report states, "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."
While regulation of the electricity industry did not provide for well-
functioning electricity markets, regulation did provide better price
stability and power reliability than what currently exists. As states
evolve toward a deregulated marketplace, many utilities are attempting
to avoid stranded costs related to an efficient and reliable grid to
better position their companies for competition. As a result, the grid
is suffering in terms of both efficiency and reliability. Increasingly,
retail consumers are not only paying more for electricity, but are also
asked to pay the cost for electric reliability by investing in
equipment that allows a building to change its electric consumption
patterns, i.e., demand response. This investment requires careful
planning so that investments are realized in the appropriate markets.
Unfortunately, deregulation by states is not proceeding in any kind of
predictable pace or general order. Often, consumer groups stop laws at
the last minute or rules are changed within short time periods of three
years or less. Given these constraints, combined with the limits of the
Federal budget process, an accurate long-term strategy cannot be
developed to permit widespread participation in response programs
nationwide. While GSA has made progress, efforts are often focused
specifically toward three states where the investment is considered to
have the most predictable return on investment. Finally, it is not
clear in the broadest sense whether or not this investment burden by
retail customers, like GSA, is the most efficient process for
correcting electricity industry problems.
Specific to the recommendations of the draft report, GSA offers the
following comments:
Recommendation 1 - last line add "potential" before the word
"benefits."
Recommendation 2 - GSA concurs:
Recommendation 3 - GSA concurs:
Recommendation 4 - GSA does not concur as it would not be practical for
GSA to share savings with tenants for successful demand response
participation as GSA assumes the rate/price/cost risk associated with
electric costs during the core, on-peak hours of the day when it sets
it rental rate. While GSA can offer incentives for its operations and
maintenance contracts and GSA building managers can be rated based on
energy performance, including demand response performance, it is not
practical to share short-term savings with tenants in the form of
interim rate reductions. However, informal tenant awareness events and
the incorporation of tenant performance features into the lease can and
do provide non-financial and quantifiable incentives to participants in
GSA's demand response programs. Finally, if GSA were to offer tenants
financial incentives to participate in demand response programs, they
would include sharing penalties as well as savings, which could
compromise customer satisfaction.
[End of section]
Appendix V: GAO Contacts and Staff Acknowledgments:
GAO Contacts:
Jim Wells (202) 512-3841 Dan Haas (202) 512-9828:
Staff Acknowledgments:
In addition to the individuals named above, Mary Acosta, Dennis
Carroll, Randy Jones, Jon Ludwigson, Paul Pansini, Frank Rusco, Anne
Stevens, Barbara Timmerman made key contributions to this report.
Important contributions were also made by Kim Wheeler-Raheb and Carol
Herrnstadt Shulman.
(360321):
FOOTNOTES
[1] In some instances, state public utility commissions have allowed
the use of time-of-use rates, or other time-differentiated pricing, but
these cases are limited.
[2] U.S. General Services Administration, Summary Report of Real
Property Owned by the United States Throughout the World (Washington,
D.C.: June 2001). We have reported that the governmentwide real
property data that GSA compiles--often referred to as the worldwide
inventory--have been unreliable and of limited usefulness. However,
these data provide the only available indication of the size and
characteristics of the federal real property inventory. For more
information, see U.S. General Accounting Office, Federal Real Property:
Better Governmentwide Data Needed for Strategic Decisionmaking, GAO-02-
342 (Washington, D.C.: Apr. 16, 2002).
[3] A watt is a measure of electrical power, or work. A kilowatt (KW)
is 1,000 watts. A megawatt (MW) is 1,000,000 watts. One megawatt is
equal to the demand of about 750 homes. A kilowatt used for 1 hour is
equal to 1 kilowatt-hour (KWh). A megawatt used for 1 hour is equal to
1 megawatt-hour (MWh).
[4] According to industry data (Platts PowerDAT), from 1998 through
2003, power plants in the United States with a total generating
capacity of between 84,000 MW and 134,000 MW operated 10% or less of
the time. In 2003, these seldom used plants accounted for about 14% of
the total installed capacity in the United States.
[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).
[6] Goldman, et al., estimated that demand-response during this period
avoided between 50 and 160 hours of rolling blackouts ("California
Customer Load Reductions during the Electricity Crisis: Did They Help
to Keep the Lights On?" LBL [May 2002]).
[7] In addition to these savings, the utility reduced its hedging costs
by $3.9 million, and all customers together saved $20 to $40 million
from the lowered likelihood of blackouts.
[8] U.S. General Accounting Office, Lessons Learned from Electricity
Restructuring: Transition to Competitive Markets Underway, but Full
Benefits Will Take Time and Effort to Achieve, GAO-03-271 (Washington,
D.C.: Dec. 17, 2002). As noted earlier, only a small amount of demand,
in total, may be needed to deliver the benefits of demand-response.
Only a few customers need to be responsive to varying prices for there
to be "adequate" levels of demand-response in markets. Customers would
be free to choose between (1) paying varying prices, with varying
monthly bills, and (2) paying slightly more, on average, in order to be
guaranteed flat monthly prices reflecting the average cost of serving
them over a longer period of time. Customers willing to respond to
varying prices would not pay for a "flat price" guarantee.
[9] Because NERC establishes technical and operational standards,
including the need to maintain certain levels of reserves, it may also
be necessary to change rules to allow demand-response options to be
counted in measuring whether grids are being operated reliably.
[10] One 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.
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