Despite a plethora of studies and experiments showing the benefits of demand response, it remains a novelty product both in restructured and regulated markets. For example, the state of California set a goal of reducing its peak demand by 5 percent this summer through price-responsive demand response (DR) programs. The actual result came in at 2.2 percent. The state now is considering mandatory DR standards based on its early trials with load-management standards in the late 1970s and its long-standing success with codes and standards for promoting energy efficiency.
DR can play a vital role in the nation’s mix of electricity resources. It can allow utilities to reduce power consumption during high-cost peak-demand times, and defer building expensive new peaking capacity that would be used for a couple of hundred hours a year. In addition, DR can prevent brownouts and blackouts during emergency situations. It promotes system reliability by providing the grid operator with tools to manage demand during critical days. Coupled with advanced metering infrastructure (AMI), it can improve the level of service provided to electricity customers.
DR comes in two types: Price-responsive DR uses price to address an imbalance between the demand and supply of electricity caused by conditions in the power market, and reliability-responsive DR can be dispatched directly to meet system-reliability problems.
Several states have a long-standing tradition of implementing reliability-responsive DR through, for example, curtailable and interruptible rates and direct load control of central air conditioners. However, no state has much experience with price-responsive DR. For many years, the primary barrier to its wider adoption was the lack of cost-effective metering technologies. Rapid advances in solid-state electronics largely have eliminated this concern. The barriers that remain are related to customer willingness to adopt price-responsive DR, and the willingness of utilities and regulators to offer such programs to customers. It may be possible to overcome these barriers through a combination of innovative rate design and government standards.
Projections of the potential reduction in peak demand that can be achieved through price-responsive DR programs depend on the amount of coincident demand reduced per customer and on the number of participating customers. In addition to the potential benefits of reliability-responsive DR programs,1 price-responsive DR offers three levels of effects on power loads: technical potential, economic potential, and market potential.
• Technical potential measures the outcome if all customers used the best-available DR technology. For example, in the residential class, this is the “gateway system,” which allows homeowners automatically to manage electricity consumption at several points of end-use, including air conditioning, space and water heating and swimming-pool pumps. Across all customer classes we estimate the technical 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.
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.
Analytical issues in this area include the need to modify existing cost-benefit methodologies for evaluating demand-side programs, to develop protocols for measuring DR impacts and to implement innovative rate designs that incorporate the risks of outages and high peak-generation costs. Current efforts by utilities and commissions to develop workable dynamic rate designs and effective protocols for measuring DR impacts are steps toward solving these problems.
Additionally, regulators and utilities need to develop a consistent message on DR and find ways to better educate customers about the costs embodied in current rates. Customers also need to be informed about the benefits that could come from broad adoption of time-varying and dynamic rates, the true impacts on their electricity costs that would come from such a change and the options they have for responding. This could begin with stressing the simple message that electricity costs more during peak periods, emphasizing the fairness of time-varying rates. Many customers assume such rates would amount to rate increases when, in fact, utility revenue would not change—customers whose consumption patterns reflect below-average peak consumption would see bill reductions; those with above-average peak consumption would see increases that reflect the degree to which their peak consumption currently is receiving a subsidy from other customers.
Policy makers need to design and adopt rates and program designs that reflect the value of DR to the electricity system and to customers. Those designs must be effectively marketed to customers.
With well-designed rate designs in place, the focus would shift to overcoming the technological barriers to DR. First and foremost is the need to install AMI systems. This likely will happen in California over the next five years.
To get the most out of the AMI investment, it may be necessary to equip the customer’s home with enabling technologies such as automation that facilitates reducing demand during critical-peak times. The use of existing technologies that support customer response should be integrated into program and tariff offerings, while further development of such technologies continues.
Additionally, rates need to be designed with an understanding of the level of response that customers are capable of providing. Customers provide a significantly higher level of demand response when equipped with enabling technologies that automate the response and facilitate the control of electricity consumption at multiple end-use points. Ultimately, these enabling technologies need to be adopted on a large scale for California to approach its DR potential.
One approach being considered is the California Energy Commission’s authority to set “load management” standards. These standards originally were created in the mid-1970s to allow the commission to develop programs for reducing peak demand and reshaping utility load-duration curves. The commission is expressly authorized to consider the following load management techniques, although its authority is not limited to these three:
• Adjustments in rate structure to encourage use of electrical energy at off-peak hours or to encourage control of daily electrical load. Compliance with those adjustments in rate structure shall be subject to the approval of the Public Utilities Commission in a proceeding to change rates or service.
• End-use storage systems that store energy during off-peak periods for use during peak periods, such as thermal storage, pumped storage, and other storage systems.
• Mechanical and automatic devices and systems for the control of daily and seasonal peak loads.
The commission’s extant load-management authority may be a valuable, even necessary, policy tool for the state to bridge the gap between the current level of DR in California and its full cost-effective potential. This policy tool may be particularly effective in two areas. One is modifying the default tariff, which could be changed to a dynamic tariff that reflects the higher cost of using electricity during critical peak hours and lower cost during off-peak hours, and provides a sharply directed signal for lowering peak demand. The other is the adoption of technologies enabling customers to better respond to the opportunities created by dynamic-pricing tariffs.
California has not met its DR goals, largely due to the absence of dynamic pricing and enabling technologies. To overcome these barriers, the Energy Commission will deliberate on whether to set load-management standards.
In the late 1970s and early ’80s, the state experimented with the first generation of load-management standards and this largely was successful. The standards were useful in stimulating discussion about innovative ways of reducing peak load and deferring or eliminating the need for peaking capacity. Some of these standards, such as mandatory time-of -use rates for large customers and direct load control of central air conditioners, still are around and continue to be refined. However, the current and projected DR deficit is large and persistent, making it necessary to explore new avenues for managing it.
Given the state’s success with implementing appliance and building standards, it makes eminent sense to revisit the load-management standards. Of course, the next generation of load-management standards will differ substantially from the first generation, since much has changed in the intervening three decades. To implement a load-management standard, the commission would be required to follow a formal rulemaking process as it does with appliance and building standards.
Such standards likely will yield a substantial financial benefit to the state. Three ideas for DR standards present a compelling, though illustrative, picture of how much additional benefit would be derived by pursuing the California Energy Commission’s load-management standard-setting authority.
The first standard calls for default dynamic pricing; the second for programmable communicating thermostats (PCTs) in all residential and small commercial and industrial buildings; and the third for automatic DR software (automated DR) in medium and large commercial and industrial buildings.
These standards would focus on the two key barriers to the faster deployment of DR in the state: Lack of dynamic pricing and lack of enabling technologies. They are designed for use on a day-ahead basis but, if need be, also can be deployed on a day-of basis. From a planning perspective, both triggering strategies are important. The day-ahead strategy decreases the likelihood that emergencies will be encountered, while the day-of strategy provides a mechanism for dealing with the emergency when it does occur.
These examples enhance the role of pricing mechanisms for managing demand and supply and decrease the role of cash incentives, which are more expensive and difficult to sustain over the long haul. Additionally, the standards could be used to encourage permanent load shifting through technologies like thermal storage and pumped storage.
Rather than the current situation, in which each utility has its own system for communicating with smart thermostats and other DR-enabling technologies, a statewide standard for technologies that would implement price/emergency signal protocols also might be productive. Additionally, the load-management standards could be used as a premise to hold hearings, through which to explore the barriers that AB 1X poses to DR, and ways of addressing this issue.
To place the benefits of these standards in perspective, consider first a case in which no load-management standards are in place. In this scenario, dynamic pricing would be offered as an optional tariff by the utilities as they roll out AMI to customers.6 An optional dynamic-pricing tariff is unlikely to achieve a participation rate greater than 20 percent and probably would not be combined with enabling technologies such as a smart thermostat. Under these assumptions, dynamic pricing could achieve a reduction in system peak demand of around 3 percent, representing over $1 billion in benefits over the next 20 years.
Now consider a second case in which a dynamic-pricing standard is adopted in California, requiring utilities to offer dynamic pricing as the default rate. Under these conditions, the literature suggests 80 percent of customers are likely to stay on dynamic pricing, with the other 20 percent opting back to their old rate. Assuming these dynamic-pricing customers are not equipped with enabling technology, the peak demand reduction could increase to some 10 percent, representing benefits of nearly $6 billion. The incremental benefit of the dynamic-pricing standard would be an increase in peak demand reduction of roughly 7 percentage points and incremental benefits of around $4 billion.
If, on top of the default dynamic-pricing standard, another standard was imposed that requires the installation of PCTs in all residential dwellings, the potential benefits would rise even further. The standard could require all residential customers be equipped with PCTs that can receive price signals so their temperature setback would be adjusted by a few degrees during critical-priced periods. With this technology installed, the estimated peak reduction potential might increase incrementally by roughly 3 percentage points to around 13 percent.7 Collectively, demand response standards could be worth $9 billion.8
Finally, an automated DR standard could be included with the PCT standard and the dynamic-pricing standard. This could equip commercial and industrial customers with system-wide automation, allowing them to leverage existing energy management control systems and automatically manage lights, air conditioning, and other sources of load during peak times. With this addition, the estimated peak reduction potential could increase incrementally by roughly 2 percentage points to approximately 15 percent. The present value of the benefits could increase incrementally by around $1 billion to $9 billion (see Figure 2).
Clearly, substantial benefits can flow from implementing load-management standards. As the policy conversation proceeds, stakeholders have a chance to help California achieve even greater DR goals.
1. These projections are in addition to the current peak reductions achieved through reliability-triggered demand response.
2. Much higher responses are possible in specific facilities that have time-flexible production processes, energy storage systems and back-up generation. Since these are highly facility-specific, they have not been included in our estimate of technical potential.
3. These turbines come in sizes generally ranging from 50 MW to 100 MW.
4. In R.02-06-001, the CPUC specified a value of $85/kW-year. That value is widely accepted throughout the mainland United States. However, once the revenue stream associated with energy sales from the operation of the turbine is subtracted, a value of $52/kW-year is obtained.
5. Sam Newell and Frank Felder, “Quantifying Demand Response Benefits in PJM,” Study Report Prepared for PJM Interconnection, LLC and the Mid-Atlantic Distributed Resources Initiative (MADRI), Jan. 29, 2007.
6. As proposed by PG&E.
7. Note that this estimate assumes that these benefits will accrue over a 20-year period during which all residential customers have PCTs installed in their homes. There would be an initial period during which the PCTs would need to be rolled out to customers.
8. Note that some of the figures may not add up due to rounding.