Demand Response and the FERC Standard Market Design NOPR
FERC recognizes the important role that demand response plays in keeping a market in balance. References to demand response appear throughout the Standard Market Design NOPR, which encourages demand resource participation in energy and ancillary services markets on an equal footing with generation resources.
Nonetheless, the NOPR provides little detail on how demand response will be achieved. Retail customers are the source of demand response, but retail service comes under the regulatory jurisdiction of the states rather than FERC. Consequently, FERC has little direct ability to increase demand participation. Instead, FERC hopes to establish the wholesale market infrastructure that will facilitate the development of demand response programs by load-serving entities (LSEs).
Demand Response, Locational Marginal Pricing, and Centralized Markets
In the proposed Standard Market Design (SMD), the key elements that would encourage demand response are locational marginal pricing (LMP) and the establishment of centralized day-ahead and real-time markets for energy, ancillary services, and transmission services. LMP and centralized markets provide efficient wholesale price signals to which LSEs and customers might respond if retail market designs allow such response. Over the longer term, LMP and centralized markets will lead to more efficient investment in generation, transmission and demand response technology, resulting in lower costs and ultimately lower prices to consumers.
LMP will allow demand response to play a role in relieving transmission constraints, both in the short and the long term, by communicating the cost of electricity service to customers. Locational marginal prices are the only prices that are consistent with efficient system dispatch, and they are the only prices that induce self-interested loads to consume efficient quantities of power and profit-maximizing generators to produce efficient quantities of power.
Demand Response and Day-Ahead Scheduling of Transmission Services
The proposed SMD calls for a transmission usage charge that is the combination of marginal congestion costs and (possibly) marginal losses. Customers will be able to establish limits on the price they will pay for scheduled transmission in a given hour. If the congestion costs and marginal losses exceed the customer-specified limit, then the customer would not have transmission scheduled. Likewise, transmission customers will be able to submit multi-hour (but same day) block bids which indicate the maximum price they are willing to pay for the entire multi-hour period. If the total of the hourly transmission usage prices over the period exceeds the customer-specified maximum price for that period, the entire bid would be rejected and the transaction would not be scheduled. FERC is seeking comment on whether this concept should be extended to allow transmission scheduling for multiple days. FERC believes the multiple-days option might be a desirable feature for customers with congestion revenue rights.
Demand Response and Energy Markets
FERC proposes that the Independent Transmission Provider (ITP) operate both a day-ahead and a real-time energy market. The day-ahead energy market will be a voluntary, bid-based, security-constrained market. Generators and customers would be free to engage in bilateral transactions and they would not be required to trade in the day-ahead market. Market participants would need to provide the ITP with day-ahead notice of their bilateral transactions so that the ITP could arrange transmission service to support these transactions.
Day-ahead markets allow buyers and sellers to observe market-clearing prices. If prices are being determined in a predictable manner, buyers and sellers can undertake additional actions appropriate to changing expectations of high or low prices. The ability of market participants to react to day-ahead prices improves the liquidity of the markets, encourages efficient use of resources, and decreases the price volatility of both the day-ahead and the real-time markets.
FERC believes that allowing demand to bid into day-ahead markets will be less costly than programs where end-users receive greater than market-based payments in order to reduce demand. FERC, however, stops short of requiring that the pro forma transmission tariff include market-based demand response programs..
Demand Response and Ancillary Services Markets
The NOPR identifies three ancillary services (regulation and frequency response, operating reserves—spinning, and operating reserves—supplemental) that might conceivably be provided by loads. The markets for these ancillary services would be operated by ITPs, though transmission customers might self-provide these services or obtain them through bilateral contracts. These markets would be bid-based and open to all potential providers, with the objective of procuring the ancillary services at the lowest cost. Any generation capacity and any demand-side resource that meet the technical requirements of an ancillary service would be allowed to offer a bid to provide the service. As a practical matter, many loads would be able to provide operating reserves—supplemental, but few or none would be able to provide the other ancillary services.
Demand Response and Long-Term Resource Adequacy 1
The proposal's requirement for long-term resource adequacy allows demand resources to count as capacity. It is not clear from the NOPR exactly how the capacity provided by demand resources might be measured. Allowing demand response to satisfy the long-term resource requirement reduces the bias toward using new generation for meeting regional needs. The long-term Resource Adequacy Requirement also allows FERC to assert some regulatory authority over demand response, while “recognizing that supply planning and retail demand response are the states’ responsibility.”
Demand Response and Market Power Mitigation 2
FERC cites the lack of price-responsive demand and the concentration of generation in transmission-constrained load pockets as the key structural flaws inhibiting competition. Two general approaches can be taken to address such flaws. One approach is to identify and remove the structural barriers causing these flaws. The second is to try to reduce the undesired market inhibitions by direct market intervention. Increasing demand response is one approach that addresses structural barriers in electricity markets. Imposing price mitigation measures is an approach that involves intervention.
FERC seems to be of two minds regarding the relative roles of demand response and market power mitigation. In the summary press release announcing the NOPR, FERC recognizes that the “strong role of demand response will limit supplier market power by holding peak energy prices in check, while SMD’s strong market monitoring and mitigation measures will detect, prevent or correct market power abuses.” Likewise in this press release, FERC claims that “greater demand response and increased transparency will make it easier for individual players to monitor and respond to each other’s behavior. Market monitoring and market power mitigation will serve as regulatory backstops to protect customers.” However, in the NOPR itself, FERC states a much more direct role for mitigation, contending that “the market power mitigation needs to compensate for the lack of price-responsive demand in the market.”
FERC recognizes the essential role that demand response plays in well-functioning electricity markets. While the NOPR does not have a section devoted specifically to demand response, the topic arises throughout the document.
LMP conveys accurate price signals to market participants, including customers who are the ultimate source of demand response. Voluntary centralized markets, particularly for day-ahead energy and ancillary services, will greatly facilitate demand resource participation.
Supplier market power can be effectively checked by demand response. The proposed SMD envisions longer-term functioning markets with demand and supply responses being the market-based solutions to market power. Market power monitoring and mitigation would be secondary backstops. In the short-term, however, the NOPR describes a more activist mitigation process to compensate for the lack of demand response.
FERC recognizes that demand response programs are the states’ responsibility. The Commission's proposal strives to establish the market infrastructure to allow demand response, but does not design or mandate demand response programs themselves. As a result, there remain many practical issues regarding demand response, most notably the challenge of accurately measuring and compensating load response. Regulatory jurisdictional issues also remain major obstacles to coordinated incorporation of demand response into wholesale electricity markets.
1 See the accompanying brief entitled “The Resource Adequacy Requirement of FERC’s Proposed Standard Market Design.”
2 See the accompanying brief entitled “Market Monitoring and Market Power Mitigation in FERC’s Proposed Standard Market Design.”