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Operating reserves are the front lines in the defense of electric systems against major generation and transmission outages. Operating reserves are provided by generating units that can increase their output rapidly to restore the system to generation/load balance after a major disturbance occurs. We examine the functions of and the requirements for operating reserves, and the data and analysis that support minimum-operating-reserve requirements. We obtained data on the number and severity of generator outages for three large US electrical systems, including a power pool, a regional reliability council, and a utility. These data show a range of 15 to 40 major (>500 MW) outages a year for systems ranging in size from 20 000 to 48 000 MW of peak demand. Finally, we discuss several emerging issues related to the underlying technical support for minimum reserve requirements, alternative ways to pay for these reserves, the data needed to support the analysis of these requirements, and the mix of functions that are currently included within operating reserves.

Estimates of transition costs for U.S. investor-owned electric utilities range from $20 to $500 billion. These potential losses are a consequence of the above-market book values for some utility-owned power plants and long-term power-purchase contracts, as well as deferred income taxes, regulatory assets, and public-policy programs. Because of the wide range of estimates and the potentially large dollar amounts involved, state and federal regulators need a clear understanding of the methods used to calculate these estimates. In addition, they may want simple methods that they can use to check the reasonableness of the estimates that utilities and other parties present in regulatory proceedings. This paper explains various methods to calculate transition costs. Top-down methods, because they use the utility as the unit of analysis, are simple to apply and to understand. However, their aggregate nature makes it difficult to determine what specific assets and liabilities affect their estimates. Bottom-up methods use the individual asset (e.g. power plant) or liability (e.g. power-purchase contract) as the unit of analysis. These methods have substantial data and computational requirements.

This paper discusses the potential financial consequences, or transition costs, of transforming electricity generation from a regulated to a competitive market in the US. Industry-wide estimates suggest potential monetary losses could exceed $100 billion as a result of the move to competition. The paper discusses the most prominent strategies suggested to address these potential losses. For each strategy, the paper identifies the parties most likely to bear the financial consequences. Most strategies do nothing to reduce the total costs to society, but instead shift costs from one set of economic actors to another. The exceptions are those strategies that result in economic-efficiency gains, which can then be used to offset the transition costs. Most of the strategies examined require the cooperation of several parties, including regulators, to be implemented successfully.

During the past several years, more and more electric utilities have been running demand-side management (DSM) programmes. These programmes improve the efficiency with which customers use electricity and affect the timing of that use (eg to shift it away from high-cost times). Utilities run such programmes for two primary reasons. One is to improve customer service. The second is to acquire resources that, just like power plants, can meet customer energy service needs. DSM programmes often are less expensive and environmentally cleaner than power plants. By 1994, US utility DSM programmes had cut potential summer peak demand by 7% and annual electricity use by 2%. We examine the economics of DSM in the late 1990s, reviewing current estimates of avoided supply costs and the cost of conserved electricity for DSM programmes. We review the environmental effects of electricity production and the environmental benefits of DSM programmes. Finally, we consider alternative electric industry structures and how DSM can operate within these alternatives.

Today's typical vertically integrated utility sells electricity and associated services as a bundled product. These ancillary services support and make possible the provision of the basic services of generating capacity, energy supply, and power delivery. These ancillary services include the following: management of generating units; reserve generating capacity to follow variations in customer loads, to provide capacity and energy when generating units or transmission lines suddenly fail, to maintain electric-system stability, and to provide local area security; transmission-system monitoring and control; replacement of real power and energy losses; reactive-power management and voltage regulation; transmission reserves; repair and maintenance of the transmission network; metering, billing, and communications; and assurance of appropriate levels of power quality.

This paper discusses competition in the electricity industry and how it might affect utility DSM programs. The roles that state regulatory commissions could play to affect retail competition and DSM programs are examined. Commissions could set exit or reentry fees for customers who want to buy electricity from an entity other than the local utility. Or they could ‘tax’ the use of the local distribution system to discourage uneconomic wheeling and to pay for DSM programs. The effects of DSM programs on retail electricity prices and how utilities might redesign their DSM programs for a more competitive environment are considered. In the future, utility DSM programs may 1. (1) focus more on customer service and less on system-resource benefits, 2. (2) emphasize capacity reductions more and energy savings less as utilities seek to minimize the lost revenues associated with DSM, 3. (3) become more cost-effective as utilities identify better ways to deliver DSM services at lower cost, and 4. (4) involve fewer inter- and intraclass transfers as utilities increasingly have individual customers pay for their own DSM services. While DSM programs in the future may be different from what they are today, they will continue to be important to utilities as powerful marketing tools and to society because of their environmental and economic-productivity benefits.

In principle, current regulation of investor-owned electric utilities is simple: the more electricity a utility sells, the more money it makes for its stockholders. This link between sales and earnings encourages utilities to sell more electricity, whether or not such increased sales benefit customers. For the same reason, utilities often find it difficult to conduct even the most cost-effective energy-efficiency programs: these programs reduce sales, and reduced sales cut earnings. Although the theoretical underpinnings of this problem have been carefully explained, little quantitative analysis exists to identify the magnitude of the problem. This paper provides that quantitative analysis for a Rocky Mountain utility. It shows that a utility that runs modest energy-efficiency programs will find its return on equity cut by almost 100 basis points. Sensitivity analyses confirm that this earnings loss will occur under a wide range of sizes and load factors of energy-efficiency programs, retail price levels and structures, and short-run marginal costs. Shareholder losses are greatest for utilities that run ambitious programs and for which the difference between retail electricity price and average fuel cost is high. This erosion of earnings occurs even though utility customers may receive substantial benefits from these energy-efficiency programs because rapid load growth accelerates the need to build new and often expensive generating capacity.

The number, scope, effects, and costs of electric-utility demand-side management (DSM) programs are growing rapidly in the United States. Utilities, their regulators, and energy policy makers need reliable information on the costs and performance of these programs to make informed decisions. In particular, information is needed on the ability of these programs to cost-effectively provide energy and capacity resources that are alternatives to power plants. We discuss a new handbook that addresses the need for additional and better information in two ways. First, the handbook (and this paper) contain discussions of the key concepts associated with DSM-program types, participation, energy and load effects, and costs. Second, the handbook offers definitions and a sample reporting form for utility DSM programs. The primary purpose in developing these definitions and this form is to encourage consistency in the collection and reporting of data on DSM programs.

We argue that it is more appropriate to compare demand-side management (DSM) programs, rather than DSM technologies, with supply resources in electric utility integrated planning. To accomplish this, DSM technologies must be identified and screened for appropriateness in a given service territory. Then, the technologies must be converted into DSM programs and screened again for cost-effectiveness. The discussion of important features of this process in this paper is illustrated by the experiences of U.S. electric utilities. We conclude that not enough is known about 1. (1) mechanisms for effectively converting DSM technologies into DSM programs and 2. (2) the trade-offs between DSM program costs incurred by utilities and customer-participation rates.

Energy efficiency in the USA improved dramatically between 1973–1986. During the past two years, however, efficiency has stagnated. This is unfortunate because improving efficiency saves money for energy consumers, boosts economic productivity, reduces oil imports, and improves environmental quality. This paper discusses ways for the US Department of Energy to further improve US energy efficiency during the 1990s. Such efforts include: make a national commitment to energy efficiency; strengthen the Federal Energy Management Program; update programmes aimed at State and local governments; increase energy-efficiency research; work with utilities and State regulatory commissions to implement least-cost planning; strengthen energy-efficiency standards, and collect more data on energy-use and its determinants.

This paper deals with the most significant accomplishments of recent projects sponsored by the U.S. Department of Energy's Least-Cost Utility Planning Program. This overview, with its accompanying bibliography, is designed to make the resources of these projects, completed in 1989, widely accessible to utility planners and regulators. The most significant contributions of the projects relate to three areas: 1. (1) DSM technology assessments and database development, 2. (2) assessments of current planning methods and future policy directions, and 3. (3) consensus building and the development of organizational structures to support least-cost planning.

Least-cost utility planning is a new way for utilities and state regulatory commissions to assess consistently a variety of demand and supply resources that cost-effectively meet customer energy-service needs. This new planning paradigm 1. (a) explicitly includes conservation and load-management programs as energy and capacity resources; 2. (b) includes consideration of environmental and social factors, as well as of direct economic costs; 3. (c) involves public participation; and 4. (d) includes careful analysis of the uncertainties and risks posed by different resource portfolios and by external factors. The relative paucity of data on demand-side resources, particularly when compared to the information available on supply resources, poses a significant barrier to integrating these options into utility resource plans. In this study, we briefly compare the data and assumptions available on supply resources with those available on demand-side resources. We then discuss the types of data that are needed to assess existing patterns and trends in electricity use (baseline data), the costs and performance of demand-side technologies, and the effects of demand-side programs. Our analysis suggests that evaluation of program effects is the area with the greatest need for additional attention.

Restructuring the US electricity industry has become the nation's central energy issue for the 1990s. Restructuring proposals focus on more competitive market structures for generation and the integration of transmission within those structures. The proposed move to more competitive generation markets will expose utility costs that are above those experienced by alternative suppliers. Debate about these above-market, or transition, costs (e.g., their size, who will pay for them and how) has played a prominent role in restructuring proceedings. This paper presents results from a project to assess systematically strategies to address transition costs that will be exposed by restructuring the electricity industry.

More U.S. utilities are running more and larger demand-side management (DSM) programs . Assessing the cost-effectiveness of these programs raises difficult questions for utilities and their regulators . In particular , should these programs aim to minimize the total cost of providing electric-energy services or should they minimize the price of electricity? Most of the debates about the appropriate economic tests to use in assessing utility programs do not address the magnitude of the impacts . As a result , questions remain about the relationships among utility DSM programs and acquisition of supply resources and the effects of these choices on electricity prices and costs. This study offers quantitative estimates on the tradeoffs between total costs and electricity prices. A dynamic model is used to assess the effects of energy-efficiency programs on utility revenues, total resource costs , electricity prices, and electricity consumption for the period 1990 to 2010. These DSM programs are assessed under alternative scenarios for three utilities: a "base" that is typical of U.S. utilities; a "surplus" utility that has excess capacity, few planned retirements, and slow growth in fossil-fuel prices and incomes; and a "deficit" utility that has little excess capacity, many planned retirements, and rapid growth in fossil-fuel prices and incomes. Model results show that DSM programs generally reduce electricity costs and increase electricity prices. However, the percentage reduction in costs is usually greater

Twenty-four US electric utilities were surveyed concerning their operating environments, organizational characteristics, and the mix of resources selected for their integrated resource plans. This article describes the responding utilities in terms of a number of important characteristics, identifies relationships between these characteristics and utility resource mix, and offers recommendations for ways to ensure that cost-effective Demand-Side Management (DSM) programs are fully considered by utilities. Key findings include the following: (1) utilities that include greater amounts of DSM in their plans will not need new capacity as soon as will other utilities; (2) utilities that attribute substantial importance to collaborative planning with non-utility interests emphasize DSM more than utilities that do not favour collaboration as highly; and (3) utilities that attribute greater importance to cost when choosing options for the integrated plan select less DSM than do other utilities, while those that ascribe greater importance to environmental concerns select more DSM.

Electric utilities face a variety of uncertainties that complicate their long-term resource planning and acquisition. Many utilities deal with these uncertainties by pursuing flexible strategies that allow changes to be made incrementally with little difficulty and at low cost. Thus, utilities today avoid construction of large, baseload power plants because of their long construction times and high capital costs. On the other hand, utilities view combustion turbines as flexible because they have small unit sizes, take only a few years to build, are inexpensive, and can later be converted to combined-cycle units (to increase capacity and improve performance). Energy-efficiency and load-management programs, because of their inherently small unit size and opportunities to adjust participation over time, are attractive for the same reasons.

The Bonneville Power Administration operated an interim Residential Weatherization Program during 1982 and 1983 throughout the Pacific Northwest. The program offered free home energy audits and financial incentives to help pay for installation of recommended retrofit measures in electrically heated homes. Almost 104,000 homes were retrofit during the two years the program operated at a cost to BPA of almost $160 million. This study analyzes actual electricity savings for about 1000 homes that participated in the BPA program in 1982 or 1983. The data for each household include electric utility bills for one year before and one year after retrofit; daily temperature data for weather stations near these households; energy audit reports and postinstallation inspection forms; and information on household demographics, structure characteristics, and heating fuels from surveys conducted in Fall 1983 and June 1984. The major factors related to actual household electricity savings after retrofit are: preretrofit electricity use, audit estimate of electricity saving for measures installed, changes in electricity prices, and changes in primary or supplemental heating fuels (especially shifts to and from wood). Together, these factors explain no more than half the variation across households in actual savings.

This paper reviews trends in residential energy use and commercial energy use for the 1950–1975 period. Historical data on energy use by type of fuel—electricity, gas, oil, other—are presented for both sectors. These energy use data are compared with data on the determinants of energy use for each sector: population, per capita income, fuel prices, economic output from the service sectors, commercial building floorspace. These historical data show marked differences between the 1950–1972 and 1972–1975 periods. From 1950 to 1972, energy use in both sectors grew steadily and rapidly. Since 1972, however, energy use growth has been almost static and unstable. The data show, in a general way, the influence of changes in fuel prices and economic activity on energy use.

The Hood River Conservation Project (HRCP) was a major residential retrofit demonstration project. The project was intended to install as many cost-effective retrofit measures in all electrically heated homes in Hood River, OR, USA. To achieve 100% participation, HRCP offered a package of ‘super’ retrofit measures and paid for installation of these measures. Almost all (91%) of the eligible households participated, in stark contrast to the much lower participation levels achieved in other residential conservation programmes. Also, unlike other programmes, HRCP attracted larger fractions of traditionally hard-to-reach groups: low-income households; occupants of multifamily units; and renters. The key factors leading to this phenomenal success include: the offer of free retrofits; determination on the part of staff to enlist every eligible household; the use of community-based marketing approaches; and reliance on extensive word-of-mouth among Hood River residents.

CONN SAVE is a non-profit consortium of electric and gas utilities in Connecticut, established to deliver services mandated by the federal Residential Conservation Service. This article describes a quantitative evaluation of the programme which involved collection of several types of data from CONN SAVE, fuel suppliers and households. Data from home energy audits and on-site home interviews were analysed in terms of conservation potentials as of Spring 1981. Potential for space-heating energy saving was roughly 15% greater in participant homes than in control homes and for water heating energy saving was slightly larger for control homes. Participant homes installed many more retrofit measures than control households and, as a consequence, were expected to cut their annual energy costs by 2–3 times as much as the control households - 18 MBtu vs 7 MBtu ($160 vs $60). Hence, the CONN SAVE audit was effective in stimulating additional retrofit action on the part of participants.

This paper describes a detailed quantitative evaluation of the Residential Weatherization Pilot Program, operated by the Bonneville Power Administration from 1980 through 1982. The program provided free energy audits to more than 6000 electrically-heated homes and gave zero-interest loans to weatherize almost 4000 of these audited homes. The total cost of the program was almost $8 million. Using actual electricity consumption records for program participants and nonparticipants, we calculated the energy-saving effect of the pilot program in several ways and always reached the same conclusion. Households that received an audit and weatherization loan reduced their annual electricity consumption by about 3500 kWh relative to what they would have done without the program: this 3500 kWh is the saving that can be directly attributed to the program. Using a simple net present worth approach, we computed program benefits and costs for participating households, the BPA power system, and the Pacific Northwest region as a whole. Under a wide range of assumptions concerning discount rate, years until the weatherization loan is repaid, program energy saving, and BPA's marginal cost of power, the program is economically attractive from all three perspectives.

This paper evaluates the impact of the US National Energy Plan on energy demand in US commercial and residential buildings. Following a brief historical review of energy use patterns in US buildings, estimates are presented of how the National Energy Plan would affect the sector in terms of fuel expenditures and investment in energy using equipment and structures. The analysis is based on economic-engineering models of energy demand which are currently being used by the US Department of Energy to evaluate conservation programmes. The demand models incorporate behavioural as well as technological determinants and are sufficiently disaggregated to allow consideration of individual components of the National Energy Plan.

Evaluation efforts of utilities with active home energy audit programs were reviewed to provide insights into the operations and effectiveness of existing utility home energy audit programs. About half the utilities contacted had little or no evaluation activity. Of those with evaluation activity, most conducted only informal evaluations for in-house use. A few utilities had conducted fully documented formal evaluations. On the basis mainly of written reports received from the utilities, findings about customer response to programs are summarized. The topics discussed include: determinants of program participation rates, use of financing, attitudes toward programs, actions taken, characteristics of participants and energy savings due to programs.

This paper describes the contents and analyzes the results of detailed engineering audits performed at 41 institutions owned by the State of Minnesota. These institutions include community colleges, state universities, office buildings, hospitals, and Department of Transportation regional facilities. The audits covered 270 buildings and include 2010 individual energy conservation recommendations. Implementing all these suggestions would cut energy use by 71 MBtu/ft 2 -audited, equivalent to at least 32% of baseline energy use at these institutions. The cost to implement all these measures is $1.90/ft 2 with an average payback period of less than 8 yr (using 1978 fuel prices). Implementing only those items that pay back in less than 5 yr would save 47 MBtu/ft 2 -audited at a cost of 29c/ft 2 . The cost-effectiveness of different measures is a strong function of the type of measure. HVAC, power plant, and lighting measures tend to have short payback periods of about 3 yr. Envelope measures, on the other hand, have long payback periods, with an average of 23 yr.

This article evaluates the energy savings and direct economic benefits of introducing heat pump and solar water heaters to the US residential market and the effects of a tax credit for solar installations. Energy savings are estimated for ten regions of the USA, as well as for the country as a whole, over the period 1977–2000. Changes in annual fuel bills and capital costs for water heaters are also computed. The results suggest that heat pump water heaters are likely to offer much larger benefits than solar heaters, even with tax credits. This is because heat pumps provide the same electricity savings (about 50%), but at a much lower capital cost.

The 26 local Community Action Agencies in Minnesota administer a federal programme to audit and retrofit homes occupied by low-income households. This programme aims to improve the thermal performance of these homes and so reduce the economic hardship faced by these households because of high and rising fuel prices. A key question concerns the actual energy savings that can be attributed to the programme. The work reported here involved collection and analysis of fuel consumption records from low-income households throughout Minnesota. Data were obtained from 59 households that had received weatherization services and from 37 households that were eligible for assistance but had not yet been weatherized. Comparisons of fuel consumption across the two groups for the 1976–1977 and 1977–1978 winters showed that the average saving due to weatherization was 13% of total household energy use. Based on fuel prices that prevailed in 1979, the cost of weatherization is likely to be repaid with lower fuel bills in 3–4 years.

This article analyses existing knowledge of consumer response to conservation incentives for energy efficiency. It criticizes the treatment of incentive effects in existing energy demand models and reviews the literature on three questions that have been given insufficient attention in formal analyses of energy demand: How does the size of an incentive affect energy users' responses? Are different types of incentives (eg, rebates, loans, grants) perceived differently even when they have the same economic value? What non-financial features of financial incentive programmes influence their effectiveness? Finally, it discusses approaches to resolving such questions.

Household energy use patterns and retail energy price trends for electicity, gas, oil and coal, and gasoline are examined for the period 1950–74. The major results of this examination are listed below. 1. 1. Households directly use about one-third of the Nation's total energy: 22% in their homes and 13% in their autiomobiles. In 1974, American households spent $70 billion on the 25 QBtu of fuel they consumed directly. 2. 2. The Consumer Price Indices for fuels showed sizable changes between 1950 and 1974. Electricity prices (“real prices, not “nominal” prices) declined 27% between 1950 and 1970 and then climbed 9% between 1970 and 1974. Gas prices increased 9% during the 1950s, declined 15% during the 1960s, and rose 4% between 1970 and 1974. Oil and coal prices remained nearly constant between 1950 and 1965; between 1965 and 1972 prices declined 5%; since then prices increased more then 50%. Gasoline prices remained nearly constant between 1950 and 1965; the next seven years saw a 14% decline followed by a 26% increase between 1972 and 1974. 3. 3. The energy price changes proposed by President Ford in January 1975 would, if implemented, increase the Comsumer Price Index by about 1.3% due to direct impacts and another 0.9% due to indirect impacts—a total increase of 2.2%.

The behavioral response (e.g. changes in indoor temperatures, attention to window and door openings) to residential technical efficiency improvements (e.g. attic insulation, storm windows) is an important and largely unresolved issue. Although there is considerable discussion concerning the extent to which households take back some of the energy savings due to technical efficiency improvements in increased comfort, there is almost no empirical evidence on the subject. Detailed electricity billing data (from mid-1981 to mid-1983) were analyzed for 79 households that received financial assistance from the Bonneville Power Administration to retrofit their homes in mid-1982. The mean retrofit expenditure in these homes was $1900; the mean reduction in annual electricity use was 4700 kWh, of which 83% was due to reductions in space heating electricity use. Analysis of the electricity billing data suggests that these households increased their indoor temperature settings after retrofit by almost 1 °F on average. This temperature increase led to an estimated average loss of almost 600 kWh of electricity saving. In other words, roughly 10% of the energy saving due to retrofit was taken back in terms of increased comfort. These results concerning changes in indoor temperatures should be viewed cautiously because of limitations in the analytical method and the large variation across households.

Oak Ridge Associated Universities (ORAU) staff conducted energy audits at 48 hospitals in four states between 1978 and 1980. The energy audits show an average potential energy saving of almost 100 kBtu/ ft 2 (1.1 GJ/m 2 ), a 20% reduction. The variation among hospitals is large; the range is from 6% to 49% of baseline energy use. The cost to implement all these conservation practices and measures is quite low, only 25 ¢/ft 2 ($2.65/m 2 ), which implies an average payback period of only one year. Analysis of the audit results shows that the potential energy saving increases with baseline energy use and decreases with fuel price. This suggests that large energy savings will be found at hospitals that are particularly energy-intensive and that have low fuel prices.

The authors examine three residential energy conservation programmes under study and development by the US government. These programmes include setting appliance efficiency targets, developing new thermal standards for housing, retrofitting existing houses to improve thermal performance and a stronger energy conservation programme. The programmes are compared using a model developed for the FEA and ERDA which projects consumption up to the year 2000. The major conclusion is that the programmes can save both energy for the USA and money for individual households.

We identify behavioral questions that arise with 4 kinds of policy interventions for energy efficiency in buildings: information, incentives, standards, and technological research and development. A general strategy is described for answering such questions by using 6 analytical methods: formal models, analysis of existing data, surveys, ethnographic methods, small-scale experimentation, and evaluation research. We evaluate each method for addressing each behavioral question in policy analyses.

Energy conservation involves the substitution of intelligence, prudence, maintenance, and better equipment for scarce, insecure, and costly energy. These substitutions improve efficiency of energy use and thereby enhance economic productivity. The benefits of conservation are clear, but the proper role for government is hotly debated. Although the normal workings of the market system are doing much to stimulate cost-effective conservation actions, several barriers to conservation still exist. Government programmes are needed to help overcome these barriers. Present US Department of Energy conservation programmes could reduce annual energy use by 2.7 quads in 1985 and by 13 quads in 2000. The present worth of the estimated cumulative oil saving over 20 years is $50 billion, in addition to the savings realized by energy consumers themselves.

Many electric utilities throughout the U.S. prepare and publish integrated resource plans. These long-term plans seek to develop the best mix of demand and supply options to meet customer needs for electric-energy services. Puget Power, a medium-sized utility in western Washington, recently completed its first integrated resource plan. Puget Power's plan is based largely on analyses conducted with two different planning models. These analyses suggest that differences in load growth are likely to have only a modest effect on electricity prices during the next two decades. The plan also suggests that energy conservation and power purchases are likely to be the most important resources during the next decade or so. Combined-cycle combustion turbines and electricity from small power producers may also be important. Long leadtime, capital-intensive facilities such as coal plants are not attractive under the assumptions used here.

This paper examines the effects of government regulatory, incentive and research programs on residential energy use and household economics during the 1977–2000 period. The basis for these evaluations is a detailed engineering-economic model of residential energy use developed at ORNL. Results of these analyses suggest that future trends in residential energy use are subject to considerable control. Estimates of energy use in the year 2000 vary by 50%. A judicious combination of government regulations (appliance efficiency standards, thermal standards for construction of new residences), incentives for weatherization of existing homes and research and development to produce new technologies can yield a future in which residential energy use in the year 2000 is at roughly the present level. Such a combined program can also provide large economic benefits to households: the reduction in the present worth (at a real interest rate of 8%) of fuel bills between now and 2000 could exceed the extra costs of more efficient equipment and structures by $60 billion.

The Electric Power Research Institute sponsored a two-day workshop, ‘Measuring the Effects of Utility Conservation Programs’, in February 1982. The workshop featured 10 presentations by electric utility analysts on several subjects related to evaluation of utility residential energy conservation programmes. This paper summarizes the major themes and findings of the workshops. The workshop papers are published in the Proceedings, available from EPRI.

The Energy Information Administration recently published data they collected from the National Interim Energy Consumption Survey (NIECS). NIECS includes detailed information on 4081 individual households: demographic characteristics, energy-related features of the structure, heating equipment and appliances therein, recent conservation actions taken by the household, and fuel consumption and costs for the April 1978–March 1979 one-year period. This data set provides a new and valuable resource for analysis. We summarized and analysed the NIECS data on household energy consumption — total energy use, electricity use, and use of the primary space heating fuel. The regression equations constructed explain roughly half the variation in energy use among households. These equations contain 10 or fewer independent variables, the most important of which are fuel price, year house was built, floor area, and heating degree days.

Between 1973 and 1980, U.S. energy use grew at an average annual rate that was only one-tenth the pre-embargo rate. This dramatic change in energy growth was caused by a combination of rapidly rising fuel prices, slower economic growth, occasional shortages of fuels, and government and utility conservation programs. This paper examines the post-embargo period in terms of energy use in each of the major sectors: residential and commercial buildings, transportation, and industry. The analysis deals with two issues: what changes occurred in energy use during this period relative to pre-embargo trends and why these changes occurred. Energy use in 1980 (76 quads) was about 20 quads lower than pre-embargo trends would suggest. About half of this reduction was due to slower growth in economic activity. The remainder was due to improvements in energy efficiency, spurred primarily by rising fuel prices and also by government and utility conservation programs. The 1980 increase in overall energy efficiency (10 quads) was due primarily to technical efficiency improvements and secondarily to operational changes.

The Bonneville Power Administration operated a residential weatherization pilot programme from 1980 to 1982. The programme provided free home energy audits to more than 7000 electrically heated homes in the Pacific Northwest and gave zero-interest loans to weatherize over 4000 of these homes. The total cost of the programme was $11 million. This paper describes several mehtods used to estimate the net energy-saving effect of the BPA programme (ie the electricity saving that could be directly attributed to the programme). The simplest method ivolves estimation of weather adjusted annual electricity consumption for each household. The second approach uses this weather adjusted consumption as the dependent variable in a pooled time-series cross-section regression model of electricity use. The third approach involves estimation of qualitative choice models of the decisions to retrofit and to participate in the BPA programme. Results from these models are used to define Mills ratio terms that are then used as explanatory variables in the regression model of the second approach. The range in estimated programme saving, given the diversity of analytical methods used, is surprisingly small — 3100–3300 kWh/year per average programme participant.

An electric utility can determine the value of demand-side programs (conservation and load management) in its service territory by following a procedure that involves several steps. The first three are general in nature: 1. (1) identify potential markets and end-use technologies to serve these markets, 2. (2) estimate technical potential, 3. (3) estimate cost-effective potential. The other eight are program-specific: 4. (4) develop program options that deliver end-use improvements to customers, 5. (5) estimate program participation, energy-use effects, and costs over time, 6. (6) project electricity use with and without the program, 7. (7) analyze program economics (benefits and costs), 8. (8) test the concept, 9. (9) implement a pilot program, 10. (10) implement a full-scale (systemwide) program, 11. (11) evaluate the program.

The Minnesota Energy Agency and the Department of Administration sponsored workshops for boiler operators in 1979. The workshops, attended by engineers from state-owned facilities and from private buisnesses, dealt with improvements to fuel/air ratios for large gas and oil-fired boilers. The process and costs of developing and running these workshops are documented. Two different surveys of workshop attendees were conducted, one directly after the workshops and the second two months later. The first survey asked attendees about their reactions to the course (instructor, manual, and visuals) and their intentions to make the fuel/air ratio changes that were discussed during the workshops. The responses were remarkably positive, with 82% of the attendees rating the probability of making these changes as either excellent or good. The followup telephone survey sought to determine how many attendees had actually made these changes in the two months following the workshops. Again, the results were quite positive: 79% of the respondents said that they had made the adjustments to some or all of their boilers. Altogether 60% of the boilers operated by these respondents had been adjusted. If these responses accurately reflect the changes made because of the workshops, then the State of Minnesota saved $88,000 in fuel bills during 1979. This is three times the cost of running the two March workshops (including the value of the attendees' time). This suggests that this workshop—and by implication, others like it—are an effective use of State resources.

A detailed computer model is developed to calculate energy flows and electricity uses for residential refrigerators. The model is used to evaluate the energy and associated initial cost impacts of alternative designs to reduce refrigerator energy use. Implementing all the changes considered, except for elimination of the frost-free feature, would cut electricity use 52% and increase purchase price only 19%.

The 1978 National Energy Conservation Policy Act established the federal Residential Conservation Service (RCS). The programme is operated by electric and gas utilities, which are required to offer their residential customers low-cost, on-site home energy audits. These inspections are intended to identify cost-effective ways to cut space heating, air conditioning and water heating energy use. But the RCS has been controversial since its inception. Most consumer and environmental groups, many state governments and some utilities think the programme saves energy and serves important social purposes. Yet many utilities and the present federal administration think the programme is expensive and ineffective. Several congressional hearings have been held during the past few years to decide whether the programme should be continued, modified or terminated. The author, Eric Hirst, testified at one such hearing, held by the Subcommittee on Energy Conservation and Power, US House of Representatives in September 1985. This is an edited version of his written statement.

An assessment of program benefits and costs for the Bonneville Power Administration (BPA) Residential Weatherization Pilot program is presented. The assessment is based on a detailed empirical evaluation of the program, and enough data was collected from both program participants and nonparticipants to analyze the actual energy savings that could be attributed to the BPA program. This information was also used to compute the Net Present Worth (NPW) of the program from the perspectives of the program participants, the BPA power system, and the Pacific Northwest region as a whole. 17 references, 1 figure, 2 tables.

Many electric utilities offer their residential customers substantial financial incentives (low-interest loans or rebates) to install energy-efficient equipment and building retrofit measures (Stern, Berry, and Hirst 1985). For example, the Tennessee Valley Authority gave zero-interest loans to almost 500,000 households between 1977 and 1985; these loans average almost $1000 each for installation of retrofit measures (TVA 1985). Pacific Gas and Electric Company spent almost $100 million on administrative and debt service costs for its residential retrofit loan program, in which about 500,000 households participated (California PLC 1984).

As competition in the US electricity industry grows, utilities (and others) worry more about the increases in electricity prices that demand-side management (DSM) programs often cause. Therefore, several utilities have reduced the scope of their DSM programs or focused these programs more on customer service and less on improving energy efficiency. This study uses the Oak Ridge Financial Model (ORFIN) to calculate the rate impacts of DSM. These simulations suggest that DSM programs, although they reduce electric bills, often increase electricity prices. However, utilities can run DSM programs that cut prices. Reducing DSM-program costs, focusing programs on those areas where large transmission and distribution investments can be deferred, timing DSM programs to match avoided costs, and shifting more of the utility's fixed costs to the monthly customer charge will cut DSM-induced price increases.