I have been asked to provide for you a review of the demand side management activity in Virginia as it relates to incumbent regulated utilities.
Demand side management, or DSM, activities attempt to change the consumption patterns of electricity. There are two primary types of DSM: conservation and load management.
Conservation efforts are aimed at reducing energy usage and, hence, conserving natural resources and reducing pollution since less power needs to be generated. Examples include programs that promote energy- efficient lighting or weatherization.
Load management programs shift energy usage away from the daily peak, or heavy usage time, to the off-peak hours. Therefore, load management programs may not reduce energy usage or conserve natural resources. The value of load management programs is the more efficient use of the electric system and a reduction in the need for additional generating capacity. Examples include energy storage systems or water heater control programs.
Historically, long-range planning was a critical component in the successful operation of an electric utility. Each utility's obligation to serve the customers in its franchised service territory required that adequate generating capacity be available to meet the forecasted customer demand levels. Because of the lead times necessary to get environmental and regulatory approvals and then construct transmission lines or generating units, a planning horizon of fifteen to twenty years was common.
In the I 980s a new type of forecasting methodology was introduced known as Integrated Resource Plans, or IRPs. The basic function of an IRP is to estimate the change in demand over the forecast period, to project adjustments to that demand the utility may bring about through the use of DSM, and to show how the remaining level of demand is expected to be met with capacity additions, transmission additions or purchased power.
The distinguishing feature of IRPs is the integration of demand side resources (conservation and load management) with supply side resources (generating units and purchased power) for meeting future needs. Prior plans only looked to the supply side for a solution. Electric utilities have been required to file IRPs with the SCC since the mid-I 980s.
The examination and promotion of DSM reached a peak nationwide in the late I 980s and early I 990s. In March 1992, the State Corporation Commission issued an order in an investigation of DSM programs for both electric and gas utilities (Case No. PUE900070).
In that order, the Commission stated "cost effective [DSM] programs are essential components of the balanced resource portfolio that utilities must achieve to provide energy to Virginia customers at fair and reasonable rates." It further stated that "while we are encouraged about the role conservation can play in our future, we must move cautiously in an attempt to avoid promoting uneconomic programs, or those that are primarily designed to promote growth of load or market share without serving the public interest. Conservation at any cost is inappropriate
The Commission's encouragement of DSM, but insistence on cost effectiveness, set the tone for related policy decisions.
The Commission's approach was conservative. There was a concern that some DSM programs, particularly conservation programs, would create winners and losers. Each DSM program has a cost that must be compared to the benefits that can be derived from the program.
For instance, with a conservation program that provides rebates for energy efficient lighting, a customer could decide to participate if he calculated that his energy usage would decline enough to cover the total cost of the lighting less the rebate. However, the cost to the utility of the rebate may exceed the savings to the system. The cost of the rebate is passed on to all customers, therefore the non-participating customers are, in effect, subsidizing the participating customers.
Load management programs are often easier to cost justify. For instance, a utility may have a program in which it offers large users a rate reduction credit for the ability to curtail service to that customer at a time of high demand. By interrupting service, the utility is able to avoid purchasing expensive emergency power. These savings are a benefit to all customers that should offset the rate credit.
At the Commissions' direction a task force was formed to develop a methodology for calculating the costs and benefits of a DSM program. The task force was composed of a variety of parties, including utilities, environmental groups and consumer representatives.
The regulated nature of a utility required that an evaluation of DSM programs be broader than the type of analysis a private firm would perform in evaluating capital investment decisions. This broader framework includes an analysis of costs and benefits to parties other than the utility. For instance, the impact of a DSM program on participating utility customers and on non-participating customers are two perspectives of importance, as just discussed.
In its March 1992 order, the Commission clearly stated that it would not attempt to quantify environmental benefits in the cost/benefit analysis of DSM programs.
The Commission considers environmental factors from a qualitative standpoint in a variety of decisions, such as certification cases for new generating capacity or transmission line construction. In addition, the cost of compliance with existing state and federal environmental laws was already included in the overall cost of service.
It was the environmental costs that were external to the existing process that the Commission declared would not to be considered. Not only would the calculation of these costs be controversial and complex, the Commission stated it did not have the statutory authority to quantify such costs.
The task force recommended to the Commission a series of cost/benefit tests that could be performed on DSM programs to determine their impact from several perspectives. The Commission endorsed the cost/benefit tests recommended by the task force.
We saw a surge of DSM activity in Virginia in the mid 1990s. The programs approved were, for the most part, experimental programs. They included financing for energy efficiency measures, standby generation, curtailable service, water heater wrap programs, low income weatherization, field testing for new technologies, promotion of high efficiency heating and cooling systems, and a variety of other measures.
A critical factor in the cost/benefit tests is the costs a utility may be able to avoid through the use of DSM by reducing the need for additional transmission, distribution or generation facilities. A single program proposed by a utility did not necessarily have to prove cost effective, but the total package of DSM programs of a utility did have to be cost effective. Without this flexibility many conservation programs would never have been approved.
In recent years, there has been a significant reduction in DSM activity in Virginia and elsewhere, including states that were much more aggressive in the promotion of DSM.
To give you an idea of the declining emphasis on DSM, let me use Virginia Power as an example. In its 1993 Integrated Resource Plan filed with the Commission, Virginia Power projected that by the year 2005 its approximately 20 DSM programs would reduce its summer peak demand by 963 megawatts. In its 1996 IRP some programs had been dropped; the projected DSM reduction for 2005 was 224 megawatts. In last year's IRP, Virginia Power had about four DSM programs remaining and projected a reduction in 2005 of 74 megawatts.
The decline in DSM activity is a result of several factors. One is the restructuring of the electric industry and the move toward competition for the provision of energy. Competitive pressures lead to a focus on cost minimization to the detriment of some DSM programs.
I mentioned before that historically utilities would plan their systems 15 to 20 years in advance. This helped in the justification of DSM programs that often have a long payback period. As we have moved closer to a competitive generation market, the planning horizon of utilities has become much shorter. With competitive generation, Integrated Resource Planning becomes less feasible since new generation will not necessarily be added by the utility.
Another blow to the chances of success for DSM programs was the advent of new, energy efficient and relatively low-cost gas-fired turbines that became the capacity of choice. Since the justification of a DSM program was dependent upon the costs that could be avoided, the availability of these low-cost turbines made it harder for DSM to compete.
Now we are approaching 2002, when generation will become competitive. For a regulated utility in the future, a cost/benefit analysis of a DSM program will be dependent upon the transmission and distribution costs that can be avoided. There may be some programs for distribution utilities that can pass such a test, but fewer than in the past.