Utilities are leaving no stone unturned in their search for ways to save electricity. Federal incentives will support new technologies and projects, but can those incentives overcome structural...
California: Mandating Demand Response
California’s load-management experience argues for formal DR standards
potential at 25 percent of peak demand. 2
• Economic potential measures what would happen if all customers used a cost-effective combination of technologies rather than the best available technologies. This produces an estimate of the economic potential for demand reduction through DR programs of approximately 12 percent.
• Market potential measures what would happen if a cost-effective combination of technologies is accepted by a lesser number of customers in the market. It differs from economic potential, which assumes all customers accept dynamic pricing. Our estimate of the current market potential for price responsive DR is approximately 5 percent.
The Value of 5 Percent
If California were to achieve a 5 percent peak-demand reduction, several benefits would be realized.
• Reduction in needed peaking-generation capacity: This most significant, long-run benefit consists of the sum of avoided capacity and energy costs;
• Avoided-energy cost associated with the reduced peak load; and
• Reduction in required transmission and distribution capacity.
A 5 percent reduction in California peak demand of approximately 61,000 MW amounts to 3,050 MW of avoided peak demand. The amount of peaking capacity needed to meet this peak demand can be computed by allowing for a reserve margin of 15 percent and line losses of 8 percent. This totals 3,800 MW or roughly the output of 50 combustion turbines. 3 A conservative value of the avoided cost of generation capacity is $52/kW a year. 4 Thus, the total value of avoided generation capacity costs would be roughly $200 million a year.
Using the relationship observed between capacity and energy benefits in a recent DR study for five mid-Atlantic states, the annual value of avoided energy costs is estimated at around $20 million. 5
In addition, transmission and distribution capacity needs would be reduced. While these are system-specific and depend on the coincidence between system and local-area peaks, they are unlikely to be zero. A conservative estimate of 10 percent savings in generation capacity and energy costs derives an estimate of roughly $20 million per year for savings in T&D costs.
Adding up these three components yields long-run benefits of demand response of $240 million per year ( see Figure 1 ). Over a 20-year time horizon, the present value of DR benefits could reach $3 billion.
In conversations with two dozen stakeholders, the Brattle Group identified 14 barriers to price-responsive DR. These 14 barriers to DR can be aggregated into two broad problem areas: A lack of dynamic pricing and a lack of enabling technologies (see Table 1) .
Most of the barriers are related to rate-design issues and specifically to a lack of dynamic pricing. These barriers include policy issues, such as the need to deal with constraints created by the rate freeze in place for a large percentage of residential use as required by Assembly Bill (AB) 1X and the need to ensure that default rates reflect the traditional rate-design objective of cost-based pricing. Solving these issues may require policy attention to address the tension between promoting economic efficiency and fairness and maintaining the current AB 1X subsidies.