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Wind farms have three characteristics that complicate their widespread application as an electricity resource: limited control, unpredictability and variability. Therefore the integration of wind output into bulk power electric systems is qualitatively different from that of other types of generators. The electric system operator must move other generators up or down to offset the time-varying wind fluctuations. Such movements raise the costs of fuel and maintenance for these other generators. Not only is wind power different, it is new. The operators of bulk power systems have limited experience in integrating wind output into the larger system. As a consequence, market rules that treat wind fairly—neither subsidizing nor penalizing its operation—have not yet been developed. The lack of data and analytical methods encourages wind advocates and sceptics to rely primarily on their biases and beliefs in suggesting how wind should be integrated into bulk power systems. This project helps fill this data and analysis gap. Specifically, it develops and applies a quantitative method for the integration of a wind resource into a large electric system. The method permits wind to bid its output into a short-term forward market (specifically, an hour-ahead energy market) or to appear in real time and accept only intrahour and hourly imbalance payments for the unscheduled energy it delivers to the system. Finally, the method analyses the short-term (minute-to-minute) variation in wind output to determine the regulation requirement the wind resource imposes on the electrical system. Copyright © 2002 John Wiley & Sons, Ltd.

As the US electricity industry is restructured, the generation, transmission, and system-control equipment and functions that maintain voltages within the appropriate ranges are being deintegrated. These changes in industry structure require new institutional rules and markets to plan for additional voltage-support capacity, to reserve capacity for future use, and to deploy capacity in real time to meet current and contingency conditions. These services can be obtained through engineering mandates or through markets. Whether the location-specific nature of voltage control will permit the creation of competitive markets is not yet known. Voltage control is accomplished by managing reactive power on an alternating-current power system. Reactive power can be produced and absorbed by both generation and transmission equipment. Reactive-power devices differ substantially in the magnitude and speed of response and in their capital costs. System operators, transmission owners, generators, customers, power marketers, and government regulators need to pay close attention to voltage control as they restructure the US electricity industry. When generators are required to supply excessive amounts of reactive power, their real-power production must be curtailed. These opportunity costs are not currently compensated for in most regions. Current tariffs are based on embedded costs. These embedded-cost tariffs average about $0.51/MWh, equivalent to $1.5 billion annually for the United States as a whole. Although this cost is low when compared with the cost of energy, it still aggregates to a significant amount of money. This paper explains why power systems require reactive power. It then examines the various types of generation and transmission resources used to supply reactive power and to control voltage. Finally it discusses how these resources are deployed and paid for in several reliability regions around the country.

Ancillary-service costs comprise a substantial share—as much as 25 percent—of total bulk power costs. The cost levels and the great variation in the cost of different services suggests that additional work is needed to define each service and identify how much of it is required.

The relevance of the historic rationales for energy-efficiency programs has changed: the basis for future programs will depend on electricity industry structure, environmental policies, and public perception of remaining barriers in energy service markets.

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.

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.

Trained as an engineer and employed at a national laboratory, I have been working on new forms of planning for electrical utilities. To learn how environmental groups have influenced utility company decisions, I spent a year (July 1992 through June 1993) working with the Energy Project of the Land and Water Fund of the Rockies (LAW Fund). The LAW Fund provides legal support to local environmental groups throughout the Rocky Mountain region. The LAW Fund's Energy Project focuses on the use of demand-side management programs, renewable resources, and integrated resource planning as ways for utilities to deliver desired energy services to their customers at minimal environmental cost. (Demand-side management programs are those that affect the amount and timing of customer electricity use, such as energy audits.)

Environmental groups, if they pick their issues and their turf carefully, and work closely with other interest groups, can have a profound and positive effect on electric utility planning and regulation.

The growing investment by governments and electric utilities in energy efficiency programs highlights the need for simple tools to help assess and explain the size of the potential resource. One technique that is commonly used in that effort is to characterize electricity savings in terms of avoided power plants, because it is easier for people to visualize a power plant than it is to understand an abstraction like billions of kilowatt‐hours. Unfortunately, there is no standardization around the characteristics of such power plants.In this article we define parameters for a standard avoided power plant that have physical meaning and intuitive plausibility, for use in back‐of‐the‐envelope calculations. For the prototypical plant this article settles on a 500‐megawatt existing coal plant operating at a 70% capacity factor with 7% T&D losses. Displacing such a plant for one year would save 3 billion kWh/year at the meter and reduce emissions by 3 million metric tons of CO2 per year.The proposed name for this...

The growing investment by governments and electric utilities in energy efficiency programs highlights the need for simple tools to help assess and explain the size of the potential resource. One technique that is commonly used in this effort is to characterize electricity savings in terms of avoided power plants, because it is easier for people to visualize a power plant than it is to understand an abstraction such as billions of kilowatt-hours. Unfortunately, there is no standardization around the characteristics of such power plants. In this letter we define parameters for a standard avoided power plant that have physical meaning and intuitive plausibility, for use in back-of-the-envelope calculations. For the prototypical plant this article settles on a 500 MW existing coal plant operating at a 70% capacity factor with 7% T&D losses. Displacing such a plant for one year would save 3 billion kWh/year at the meter and reduce emissions by 3 million metric tons of CO2 per year. The proposed name for this metric is the Rosenfeld, in keeping with the tradition among scientists of naming units in honor of the person most responsible for the discovery and widespread adoption of the underlying scientific principle in question—Dr Arthur H. Rosenfeld.

Debates about the appropriate economic tests to use in assessing utility demand side management (DSM) programs miss the point in failing to address the magnitude of the impacts. This analysis shows that DSM programs generally reduce electricity costs (significantly) while raising electricity prices (usually only slightly). The topics of the article include analyzing DSM impacts in utility expansion plans, the base-case utility, the surplus utility, and the deficit utility.

Electric utilities increasingly look to the demand side to supplement traditional supply resources for meeting future energy and demand growth. The process of assessing the relative costeffectiveness of demand and supply resources involves two activities: (1) selecting an integrating method, and (2) deciding how to treat the three dimensions of resources (ie, financial, economic, and reliability). This paper looks at the integrating processes used by electric utilities in their short- and long-term planning. Although some evidence on the relationship between the way resource dimensions are treated and resource selection exists, little is known about the relationship between using different integrating methods and resource selection. Since integrating methods vary from the simple to the complex with a corresponding increase in cost to a utility, the paper concludes with a research agenda that will clarify the relationships between using different integrating methods in electric utility planning and the types of resources selected

The utilities in this study — which account for about one-third of all U.S. power generation — will likely grow an additional 30% over the next ten years. Though their resource mix is changing to include more demand-side management, most are not planning to implement all the efficiency measures that would be cost-effective

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.

During the past few years, the scope and nature of resource planning at electric utilities has changed dramatically. The scope of planning has expanded to consider energy efficiency and loa management programmes as resources, the environmental costs of electricity production, and a variety of resource-selection criteria beyond electricity price. The nature of planning has expanded to include regulatory commissions, nonutility energy experts, and customers, as well as utilities themselves. Similar changes are beginning to occur at gas utilities. This paper discusses a few of the key issues related to resource planning: provision of financial incentives to utilities for successful implementation of integrated resource plans, incorporation of environmental factors in resource planning, bidding for demand and supply resources, development of guidelines for preparation and review of utilityintegrated resource plans, resource planning for gas utilities, and greater efforts by the US Department of Energy to encourage integrated resource 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.

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 unprecedented uncertainties that complicate long-term resource planning. As a consequence, many utilities emphasize small resources that can be constructed quickly. However, insufficient data and analysis exist to adequately assess this risk-reduction strategy. This paper compares the benefits of such flexible resources (including energy-efficiency and load-management programs) with their costs, relative to large, long-lead-time power plants. The program flexibility benefits computed for various examples amount to 2–20 per cent. Cost estimates from the Northwest Power Planning Council suggest that these benefits are generally not enough to justify the higher costs of small power plants. However, the benefits are more than sufficient to justify the incremental costs associated with expansion of simple-cycle combustion turbines to combined-cycle operation. Also, the benefits amply justify application of the Council's option-and-build strategy. The first stage of their strategy involves the time-consuming but inexpensive activities of siting, designing, and licensing the plant. Then, the plant can be constructed, the site can be held as an option for several years, or the plans can be terminated. This strategy permits the second stage (construction) to be timed to match changes in load growth at very little cost. Utility conservation and load-management programs can provide substantial flexibility benefits. These benefits are a consequence of the ease with which such programs can be adjusted to match load growth. Relative to construction of a single 600 MW power plant, implementing the demand-side program described here cuts electricity price by 10 per cent, 50–100 per cent more than do small, short-lead-time power plants.

A model of residential energy use was developed to simulate the period from 1970 to 2000. The model predicts annual energy use by fuel, end use, and type of housing, and also estimates annual equipment installations and ownership, equipment energy re quirements, structural heat retention, fuel expendi tures, equipment costs, and costs for improving heat retention in new and existing housing units. Thus the model provides considerable detail on residential energy uses and associated costs. These details are useful for evaluating the effects of alternative energy conservation policies, programs, and tech nologies during the next quarter century. The present version of the model handles four fuels, eight end uses, and three types of housing. Each of these 96 components of total energy use is calculated each year as a function of stocks of occupied housing units and new construction, equipment ownership by fuel and end use, heat retention of housing units, average unit energy requirements for each type of equipment, and usage factors that depend on household behavior. Simulation of energy use from 1960 to 1975 shows that the model accurately predicts historical data on aggregate energy use, energy use by fuel, energy use by end use, and market shares of ownership of equipment.

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.

The major uncertainty about energy conservation is not its importance in resolving energy problems, but the role of governments vis-a-vis the free market. During the past few years, both the overall efficiency of energy use and the number of government conservation programs increased sharply. However, the extent to which these efficiency improvements were due to government programs is unclear. A key element in the careful evaluation of these conservation programs is data. Data, particularly on energy consumption, are needed to help sort out the effects of government programs relative to market forces. However, data can serve these purposes only if they are accurate, consistent, comprehensive, accessible, and documented. This paper discusses data requirements and current data sources for careful evaluation of energy conservation programs.

Because of dramatic changes in electricity costs, prices, and consumption during the past decade, electric utilities are faced with many new opportunities on the customer side of the meter. Design, analysis, and implementation of successful conservation and load management programs, however, require additional research. This paper discusses several important research topics related to assessment of electricity-conserving technologies, impacts of utility conservation and load management programs, and the electric utility planning process.

Energy efficiencies of residential heating and cooling equipment, appliances and structures can be significantly improved by implementing known design changes and by conducting R&D programs to develop advanced systems. These design changes are likely to be cost-effective for typical American housholds. The Oak Ridge National Laboratory (ORNL) residential energy use simulation model is used to evaluate the national energy and direct economic effects of implementing the conservation programs in the proposed National Energy Plan and offering to the market advanced technologies currently being developed by private industry and the Federal government. These changes are likely to cut residential energy use by more than 63.3 × 1018 J between now and the year 2000. The present worth of the fuel bill reductions (at a real interest rate of 8%) is $26.7 billion greater than the present worth of the extra capital cost associated with improved equipment, appliances, and structures.

In 1977, heating, cooling, lighting, and other operations in residential and commercial buildings used 27 quads (1 quad = 10(15) British thermal units) of energy. This is more than one-third of the nation's total energy budget. Future trends in energy use in buildings are likely to depend strongly on fuel prices and government policies designed to save energy. Three scenarios are examined: (i) a base line in which fuel prices rise as projected by the Department of Energy; (ii) a conservation case that includes higher gas and oil prices plus the regulatory, financial incentive, and information programs authorized by the 94th Congress and proposed in the April 1977 National Energy Plan; and (iii) another conservation case that also includes new technologies (more efficient equipment, appliances, and structures). These scenarios are analyzed for changes in energy use, costs, and employment by means of detailed engineering-economic models of energy use in residential and commercial buildings developed at the Oak Ridge National Laboratory and input-output analyses developed at the University of Illinois.

An important and unresolved issue concerning home energy audit programs is the accuracy of the engineering calculations. That is, the accuracy of audit predictions of energy savings for recommended retrofit measures is generally unknown. Data available from a recent evaluation of the Bonneville Power Administration Residential Weatherization Pilot Program allow comparison and analysis of the relationships between actual electricity savings and audit estimates of likely savings. The BPA program offered free home energy audits to identify cost-effective conservation measures to reduce space and water heating electricity use. The program also offered zero-interest, deferred-payment loans for installation of measures recommended during the audit. The actual reduction in annual electricity use averaged 4130 kWh across participant households. The cost of the retrofits that yielded this saving averaged $2100. The median ratio of actual-to-estimated saving is 0.66. Thus, on average, two thirds of the expected saving is actually realized. However, there is substantial variation in this ratio. Actual electricity use increases in the second year for more than 10% of these homes. On the other hand, actual savings are more than double the audit estimates in more than 10% of the homes.

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.

The structure, inputs, validation and operation of a residential energy use model are examined with the intention of providing an analytical tool for evaluation of energy conservation option for effects on energy use and related costs.

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.

A comprehensive engineering-economic model of residential energy use (developed at ORNL) was used to evaluate the energy impacts of various energy conservation strategies. The model simulates household energy use at the national level for four fuels, six end uses, and three housing types--single family, multifamily buildings, and trailers. Several cases were run with the model to determine the impacts on energy use of each factor, in isolation, and in combination with other determinants of fuel use. Dr. Hirst concludes the following: (1) residential energy use will grow more slowly during the last quarter of the 20th century than it did during the third quarter; (2) a ''high forecast'' developed in the study is not valid because it was assumed that fuel prices will hold constant (1975), that household formation and personal income will increase rapidly, and that the 1960-1970 trend in housing choices (away from single-family) will not continue; (3) implementation of energy conservation programs to raise fuel prices can have significant energy impacts; (4) implementation of a program to increase efficiency of residential equipment by 1980, as specified in the Energy Policy and Conservation Act, can cut energy use in the year 2000 by at least 10 percent; andmore » (5) programs to improve thermal integrity of residential structures can also provide significant energy savings during the next 25 years. (MCW)« less

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%.

This paper describes the methods used and the assumptions made in developing a regional data base for each of the nine U.S. census, divisions. The data are used to provide regional input to a comprehensive engineering-economic computer model to simulate energy use in the residential sector from 1970 to 2000. These regional models provide an analytical tool with which conservation policies, technologies, and strategies can be evaluated for their effects on residential energy use, fuel expenditures, and capital costs.

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.

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.