Demand Response & Reliability: Following The Fed Model
May 1, 2003
By Dr. William M. Smith, Joel C. Gilbert, and Paul C. Meagher
Regional demand resource banks, based on the Federal Reserve Bank system, would make for greater use of customer demand response mechanisms while ensuring long-term resource adequacy.
Demand response is the only resource available to electricity markets that is not plagued by long lead times, severe regulatory scrutiny, and environmental concerns.
In a perfect world, retail prices would moderate electricity markets, and a fair amount of demand response would happen naturally. However, as the 2001 California power crisis demonstrated, regulatory and political bodies are sometimes unwilling to allow price to do its job. This unwillingness has two outcomes:
- Very little liquidity is induced into the market for approaches like demand trading (negawatts for megawatts).
- In an infrastructure that has few viable physical storage mechanisms, preventing price from performing will lead to boom/bust cycles in reliability.
But just how do we ensure long-term resource adequacy, especially if demand grows? Plain common sense would seem to imply that any member of the electricity value chain today should seek demand response as a mechanism for competitive differentiation, price-risk mitigation, and reliability enhancement. However, the uncertainty and intermittence in demand response valuation devastate the business case for widespread inclusion in electricity markets at this time. And, given that there is currently little to no financial incentive to even maintain the market's current inventory of demand response mechanisms, and the regional ISO/RTO rules are going to find a new home for only a portion of them, it seems almost certain this critical infrastructure resource will atrophy while the profit motivation for the development of new resources continues to suffer.
Market forces generally are not considered adequate to ensure reliability in critical infrastructures because the communication of price opportunities might not have sufficient advance timing to provide adequate resources in response. As a result, criteria, such as some level of reserves, generally have been used to preclude worst-case scenarios. However, adequate reserve margins are questionable future prospects.
The long-run benefits of customer demand response participation are clear, but market uncertainty is a real problem. Forecasts for a cooler than normal summers and adequate regional supplies spawn disinterest and encourage energy companies to go "naked." Then, when prices spike, few customers are engaged, and the valuation seems obvious. The next summer, when everyone is ready to take advantage of these price spikes, there may be none.
This boom-bust cycle is not a surprise, but customers want some level of annual benefit assurance to stay involved in demand response. This can be accomplished through regulation and free markets.
The regulatory answer, a familiar one, uses the traditional least-cost planning model to determine avoided costs in the long run and the benefits of customer participation. A free market solution involves a risk-taking body that understands the long-run value proposition for customer demand response and underwrites the acquisition and coordination of this resource in anticipation of a rightful future reward (the long-term market signal).
Regional Demand Response Resource Banks
This sets the stage for regional demand response resource banks. Liquidity in our currency is maintained by the Federal Reserve Bank system. Reserves are a natural model for any resource that has extreme variation in time-based need. Because the reserves must be reasonably close to where they are needed, we suggest a set of regional resource banks, following a similar model to the way wholesale markets are now being organized (e.g., RTOs).
These resource banks would be places where customers could deposit their existing demand response capabilities (in exchange for periodic interest payments, plus performance-based use transaction fees). These could also be places where customers (or their agents who would construct resources at their locations) could borrow money to invest in additional demand response resources, similar to the way customers finance their homes and business investments. The bank would arrange for an independent audit of these resources (much like the combination of building inspectors and property appraisers) and would retain the rights to use these resources for regional electricity markets, consistent with a set of approved operational guidelines.
Once the resources were proven deposits, their capabilities could be made available to all market counterparties: ISO/RTO organizations, retailers, generators, and even other customers (perhaps facing undesirable real-time prices). These counterparties could all purchase capabilities from these banks and sign aggregate call options against these resources with assurance that the capabilities would perform and were financially firm. The bank also would assure all market counterparties that the demand response resources were not being sold beyond their proven capabilities-in other words, no gaming permitted.
Buyers from this bank would naturally have quite varied interests. Some might want only the reliability-enhancement, near-real-time resource benefits. Others might want capa- city and energy cost avoidance benefits, and still others might want to shift energy patterns from one part of the day to another.
Some of these concepts are complementary, some not. There will be times when a customer's demand trading capabilities can be bought by multiple parties in a month, or even on any one day. Some customers will have precedent relationships due to bilateral agreements for their resource, and times when their resource is open to see a bid from anyone in the market. And some customers will want to exercise their options themselves, while some would naturally wish to designate others as their agents.
The bank concept permits all of this commercial transaction flexibility while assuring all counterparties that the customer's demand trades are fungible, reliable, and exercised with appropriate compensation to all those involved in the transactions. The source of funds into the bank could come from energy counterparties who want to invest (and thereby share in the reward derived by the bank), as well as from pure financial interests. Customers would be free to shop as often as they want, or stay with the incumbent energy provider, while keeping their resource on deposit for all parties.
The acquisition of the customer capabilities would come from customers who want to place their resources on deposit, as well as from third party intermediaries (similar in concept to curtailment service providers). Technology-enabling partners (controls, distributed generation, etc.) could also look to the bank for commercial loans to invest the resulting capabilities into the reserve system.
As in all commercial banking terms, there would be a limit to the level of investment based upon the intrinsic value of the resource. If the commercial terms were fundamentally in line with any given level of investment, and the customer were deemed a prudent investment candidate, the bank would underwrite the appropriate portion of the investment.
The full extent of this business proposition is significant because demand response is an alternative to supply along a time domain continuum similar to the supply-side options. At one end of the time-vlaue continuum, investments could be made into energy efficiency as opposed to generation itself; third-party energy services companies have made a business of doing so with customers. Seasonal energy management alternatives could follow the same model, once again providing a value signal based upon displaced or avoided energy costs. In both cases, the customer and the free market agent have a clear and repeatable value proposition, since the savings do appear each and every year.
On the other hand, demand response valuation for day-ahead and day-of markets can, for years, have so little value that no commercial terms are viable. While the value in a year with significant price spikes can be impressive, the uncertain nature of that result is likely to discourage both the customer, and certainly the free-market counterparty, from continued involvement.
ISO/RTO organizations can offer capacity payments to encourage such activity, but that mechanism is not widespread. The recent FERC SMD suggests that the capacity payment model is less desirable than open-market structures. Therefore, the concept of a commercially underwritten resource bank may well prove to be a viable candidate solution.
A simplified conceptual diagram appears above.
The electricity market may one day be so robust that commercial banks in demand response will be as common as banks are today in monetary markets. However, to get this market going on stable footing, some level of exclusive aggregation seems necessary at the moment. Putting all of the resource into one regional bank for an area presents the best chance for aggregate value and liquidity. Once the strategy is proven to work, further granularity is likely to evolve.
The establishment of these banks and the associated audited valuation will permit customers and third-party entrepreneurs to confidently offer customers more options. These options will include the traditional third-party shared energy savings, performance contracts, and a host of other creative energy options we see today. The mechanisms would be similar to the way local and regional banks do business. However, unlike traditional bankers, this bank would understand the wholesale power market and its nuances. As a result, the division of the bank that offered structured products could design commercial interfaces to the energy retailers, generators, ISO/RTO organizations, or other entities the bank determined were rightful market counterparties.
The bank also would be a natural neutral third party to market participants to develop the required resources and to act as the public price transparency agent and arbiter of fair terms. ISO/RTOs would no longer have to worry about the acquisition of this resource. They would have to consider only how the resource best interacts with their responsibilities. Energy companies could contract with the bank to cover any resource requirements, and even regional generating companies might purchase seasonal call agreements with the bank as an alternative to agreements with other generating companies.
In the hopes of expediting the transition to functional competitive electricity markets, we encourage FERC to incorporate whatever facilitating mechanisms it feels comfortable with into the SMD to enable market-driven solutions to moderate the electricity supply/demand balance. Such mechanisms would certainly provide opportunities for concepts like regional demand response resource banks to play a valuable role in these markets, by helping ensure long-term resource adequacy. These banks would do so by providing financial storage by way of appropriate demand response investments for an electricity system that has no good physical storage capability.
Dr. William M. Smith is manager of Market-Driven Demand Response at EPRI. Contact him at 650-855-2415. Joel C. Gilbert is CEO of Apogee Interactive, and Paul C. Meagher is sector technical manager at EPRI Worldwide.
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