Electricity Markets: Consumers Could Benefit from Demand Programs, but Challenges Remain
Published: 2004-08-13T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: 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).
section_title: What GAO Found
paragraphs: 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.

section_title: Letter
paragraphs: 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.
subsections: section_title: Background
subsections: section_title: Demand and Supply in Regional Electricity Systems Must Be Continually Balanced and Adjusted
paragraphs: 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.
section_title: Federal Restructuring of the Electricity Sector Has Expanded the Role of Competition and Markets, but States Remain Divided on Market Development
paragraphs: 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. 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.
section_title: Both FERC and DOE Believe That Demand- Response Programs Could Address a Number of Problems
paragraphs: 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.
section_title: The Federal Government and General Services Administration Are Large Electricity Users
paragraphs: 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. 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.
section_title: Market-Based and Reliability Programs Allow Demand to Respond to Changing Prices and Supply Shortages but Are in Limited Use
paragraphs: 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.
subsections: section_title: Market-Based Programs Transmit Information about Changing Prices, Allowing Customers to Adjust Demand, but Use Is Limited
paragraphs: 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.
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 (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.
section_title: Reliability Programs Allow Grid Operators to Reduce Demand in Response to Supply Shortages, but Use Is Limited
paragraphs: 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.
section_title: Some GSA Facilities Are Registered to Participate in Market-Based and Reliability Programs
paragraphs: 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.
section_title: Demand-Response Programs Have Saved Millions of Dollars and Can Improve the Reliability of the Electricity System
paragraphs: 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.
subsections: section_title: Market-Based Programs Have Saved Millions of Dollars and Have the Potential for Even Greater Savings
paragraphs: 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.
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.
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.
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.
section_title: Demand-Response Programs Can Improve the Reliability of the Electricity System, Reducing the Incidence of Costly Blackouts
paragraphs: 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. 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.
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. 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.
section_title: Opportunities Exist for GSA to Benefit Further from Demand-Response Programs
paragraphs: 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.
section_title: Multiple Barriers Make It Difficult to Introduce and Expand Demand- Response Programs
paragraphs: 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.
subsections: section_title: State Regulations Promoting the Widespread Use of Fixed, Average Prices Impede the Development of Demand-Response Programs and Efficient Wholesale Markets
paragraphs: 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. 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.
section_title: Lack of Some Equipment at Customers’ Locations Limits Use of Demand-Response Programs
paragraphs: 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.
section_title: Customers’ Limited Awareness of Demand- Response Programs and Their Potential Benefits Hinders Program Introduction and Expansion
paragraphs: 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.
section_title: Several Outside Factors Have Also Served to Limit the Benefits of Participating in Available Demand- Response Programs in Recent Years
paragraphs: 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.
section_title: GSA’s Participation in Demand-Response Programs Has Been Limited
paragraphs: 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.
section_title: Certain Programs Show How Barriers Were Overcome and Provide Lessons on How to Cultivate New Programs
paragraphs: 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.
subsections: section_title: Two Programs Illustrate How to Overcome Barriers
paragraphs: 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.
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.
section_title: Successful Demand- Response Programs Offer Three Important Lessons for Nurturing Further Programs
paragraphs: 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,  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.
section_title: Conclusion
paragraphs: 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.
section_title: Recommendations for Executive Action
paragraphs: 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.
section_title: Agency Comments and Our Evaluation
paragraphs: 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 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.
section_title: Scope and Methodology
paragraphs: 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 , the Department of  Energy, and the General Services Administration ) 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 ), 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.
section_title: Selected Experts Interviewed
paragraphs: 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.
section_title: Comments from the Federal Energy Regulatory Commission
paragraphs: The following are GAO’s comments on the Federal Energy Regulatory  Commission’s letter dated July 7, 2004.
subsections: section_title: GAO Comments
paragraphs: 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.
section_title: Comments from the General Services Administration
section_title: GAO Contacts and Staff Acknowledgments
subsections: section_title: GAO Contacts
section_title: Staff Acknowledgments
paragraphs: In addition to the individuals named above, Mary Acosta, Dennis Carroll,  Randy Jones, Jon Ludwigson, Paul Pansini, Frank Rusco, Anne Stevens,  Barbara Timmerman made key contributions to this report. Important  contributions were also made by Kim Wheeler-Raheb and Carol Herrnstadt  Shulman.
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