California’s Renewables Portfolio Standard (RPS) requires that, by 2020, all utilities in the state use renewables to generate at least 33 percent of the electricity provided to retail customers. Reaching this RPS target will also play a key role in determining whether or not California will meet its ambitious greenhouse gas emission reduction targets. Many other states are in similar situations: Currently California is one of 29 states (plus the District of Columbia and two U.S. territories) (1) that have RPS targets, and another eight States and two more U.S. territories (2) have adopted renewables portfolio goals (see Figure 1).
Achieving these goals will require a number of states to rely much more heavily on electricity generated by intermittent wind and solar resources. In California, wind and solar generation are expected to provide virtually all of the additional renewable energy needed to achieve the state’s RPS target (see Figure 2).
In order to maintain the stability of the electricity grid, supply and demand must be in balance at all times. Wind and solar generation, however, tend to be intermittent. As a result, heavier reliance on wind and solar generation will make it harder to maintain the stability of the grid from moment to moment. This will increase the need for the “ancillary” services (3) and load following services grid operators use to maintain the stability of the grid, and avoid the supply and demand imbalances that, in a worst-case scenario, could lead to load shedding, brownouts, and/or blackouts.
The need for these services used to manage the effect of variable renewable generation on grid stability is the “renewables integration” challenge.
Ancillary and load following services are typically provided by quick start fossil-fueled power plants. (4) However, California may not have enough of these resources to meet the additional need created by its increased reliance on wind and solar, due largely to a state environmental policy requiring the retrofitting or retirement of 17,000 MW of “once through cooling” fossil-fueled power plant capacity by 2017.
The potential retirement of that much capacity is a serious issue because those units already account for more than 36 percent of the capacity available to meet forecasted peak demand during the summer of 2012. (5) And, adding new back-up generation capacity would be costly.
However, demand response (DR) programs that are capable of quickly adjusting the amount of electricity customers use, might be able to provide some of the required ancillary and load following services – perhaps at a lower cost than quick start fossil-fueled power plants.
Therefore, at the request of California’s statewide Demand Response Measurement & Evaluation Committee (DRMEC), (6) Navigant prepared a white paper that gives policymakers and non-technical stakeholders a basic understanding of the potential for using the DR programs of California’s three investor-owned utilities (IOUs) to help integrate the additional wind and solar generation California will need to achieve its 33 percent RPS target. (7)
A survey completed as part of the study found other regions of the country have already begun using DR to provide ancillary services (see Table 1).
The ability of each California IOU DR program to provide these services was evaluated by comparing each program’s characteristics to the technical standards that CAISO tariffs require for each ancillary service:
- Advance Notice of Deployment (“Notice”): The minimum amount of time that must elapse between the receipt of notice of deployment from the CAISO, and the receipt of a dispatch signal.
- Speed of Response to Control Signal (“Speed”): The maximum amount of time that can elapse between the receipt of a dispatch signal from the CAISO, and the provision of the product/service.
- Duration of Response (“Duration”): The minimum amount of time for which the resource must be able to provide the product/service each time that resource is dispatched.
- Frequency of Response (“Frequency”): The frequency with which a particular resource will be dispatched to provide that product/service.
- Range of Permissible Deviation (“Reliability”): The maximum permitted deviation between the amount of that product/service a resource was scheduled to deliver, and the amount of that product/service the resource actually delivered (i.e., an uninstructed deviation).
That evaluation demonstrated that a number of IOU DR programs might be able to provide these services, if they were modified in several ways. The most important changes would be:
- increasing the number of times and frequency with which the DR program could be “dispatched” (i.e., used to adjust customer demand for electricity);
- providing less or no advance notice that the program will be dispatched;
- using telemetry for real-time communications, load metering, and load control; and,
- automating the changes in customer load in response to control signals
Making these changes would substantially improve the ability of those DR programs to contribute to the integration of wind and solar energy (see Figure 3).
The white paper also identified the attributes new types of DR programs would need to provide each of these services.
The adoption of these types of DR programs would not only facilitate but perhaps reduce the cost of integrating the wind and solar energy needed to meet California’s 33 percent RPS by 2020. If other states needing to rely more heavily on wind and solar to achieve their renewables portfolio standards and goals also adopted these types of DR programs, it would move the nation closer to a cleaner energy future.
Bruce W. Perlstein, Dr. Perlstein has over 25 years’ experience consulting on energy- and financial risk- related strategy, management, policy, and valuation related issues. His clients have included: dozens of electric power, oil, and gas industry companies; financial services firms and investment banks; multilateral agencies, including the World Bank; and governments in the U.S., Canada, Europe, Latin America and East Asia.
Since 2003, his power industry work has focused on: integrated resource planning; renewable power project evaluations and renewable energy integration; designing and evaluating the impacts and cost effectiveness of dynamic pricing and Smart Grid-enabled energy efficiency and demand response resources; greenhouse gas emission policies and allowance markets; and valuations of energy-related derivatives and complex financial securities; and expert testimony. Earlier in his career, Dr. Perlstein served as a Senior Vice President (Enterprise Risk Management) at the world’s largest insurance brokerage firm, a Director or Principal at several of the world’s largest accounting, management, and economics consulting firms, a Director in the Corporate Development department of one of the country’s largest broadcasting networks, and Vice President (Strategic Planning) at one of the largest U.S. banks.
Dr. Perlstein has taught at Columbia University’s Graduate School of Public & International Affairs and Northeastern University, and lectured at M.I.T. and Brandeis University. He holds a Ph.D. in Economics and Politics from Brandeis University and an Sc.M. in Finance and Applied Economics from M.I.T.’s Sloan School of Management.
Source: www.dsireusa.org, accessed in June 2012.
Source: April 29, 2011 Joint IOU Submission to CPUC, 2010 Long-Term Procurement Plan System Analysis Preliminary Results, in California Public Utilities (CPUC) Rulemaking 10-05-006.
Ibid, Figure 4-5: p. 4-14.
Ibid, Figure 5-4 and Figure 5-5: p. 5-7 and p. 5-9.
1) Puerto Rico and the Northern Mariana Islands.
2) Guam and the U.S. Virgin Islands.
3) Ancillary services include: non-synchronized, non-spinning reserves; synchronized spinning reserves; and regulation “up” and “down” energy.
4) That is not necessarily the case in systems with a lot of hydropower capacity.
5) As of mid-March 2012, the California ISO forecasted a 46,352 MW summer peak in 2012 under typical (“1-in-2”) weather conditions. See: CAISO, 2012 Summer Loads and Resources Assessment (March 15, 2012): p.2.
6) The DRMEC consists of representatives of the state’s three investor-owned utilities (IOUS) – Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E) – plus the California Energy Commission (CEC), and the California Public Utility Commission (CEC).
7) Navigant Consulting, Potential Role of Demand Response Programs in Maintaining Grid Stability and Integrating Variable Renewable Energy under California’s 33 Percent Renewables Portfolio Standard (July 18, 2012). Available at http://www.calmac.org/publications/7-18-12_Final_White_Paper_on_Use_of_DR_for_Renewable_Energy_Integration.pdf