In advance of the Obama administration’s stimulus package, FERC, ISO New England and the Midwest Independent System Operator released separate reports recommending expansions of Demand Response Programs.

The Federal Energy Regulatory Commission (FERC), ISO New England, Inc. (ISO-NE) and the Midwest Independent System Operator (MISO) recently released separate reports assessing developments in Demand Response (DR) programs and making recommendations aimed toward expanding the programs. The reports present a mixed score card on DR overall. The viability of such programs to date, however, and the Obama administration’s focus on such programs signal likely DR and smart-grid advances.

In a January 8, 2009, speech on the economy, President-Elect Obama indicated the importance he attaches to developing smart grid systems as part of his overall economic stimulus package when he announced that he would “build a new smart grid that will save us money, protect our power sources from blackout or attack, and deliver clean, alternative forms of energy to every corner of our nation.”

Indeed, House Ways and Means Committee Chairman Charlie Rangel (D-N.Y.) and House Appropriations Committee Chairman David Obey (D-Wis.) released outlines for their stimulus proposals yesterday, kicking off the debate. The proposal includes $32 billion to transform the nation’s energy transmission, distribution and production systems with $11 billion for research and development for a reliable, efficient electric grid, including pilot projects and federal matching funds for the Smart Grid Investment Program (established in the Energy, Independence and Security Act of 2007). The matching program would reimburse up to 20 percent for investments in smart grid technologies. The initial proposal also includes $2 billion for energy efficiency and renewable energy research, development and deployment activities.

Because most electricity consumers are billed on a per kilowatt-hour volume basis under a flat retail rate structure, most consumers lack clear “real-time” price signals (and the necessary smart metering and related technology) to reduce their usage during peak hours or to shift consumption to less expensive periods. DR programs are designed to help reduce inefficiency in power production and consumption, avoid unnecessary investment in transmission and generation capacity, and lessen some of the adverse environmental consequences posed by running fossil-fueled power plants, including the production of greenhouse gases. DR programs furthermore will play a role in managing load growth and transmission congestion, thus ensuring short-term capacity availability and increased grid reliability. Ultimately, DR programs will progress hand-in-hand with the development and deployment of smart-grid and metering technologies.

FERC 2008 Assessment of Demand Response and Advanced Metering

In December 2008, FERC released its 2008 Assessment of Demand Response and Advanced Metering, as required by Section 1252(e)(3) of the Energy Policy Act of 2005. Based on its survey, FERC observed significant gains in advanced metering penetration, DR program participation, and state and federal regulatory activity designed to promote DR programs and to reduce barriers to their implementation, including retail metering and pricing structures. Departing FERC Chairman Joseph T. Kelliher stated, “It is good to see the numbers behind the progress we know is being made on these demand response and advanced metering fronts,” noting that FERC is “making demand response a priority.” FERC Commissioner Jon Wellinghoff highlighted the importance of DR in smart grid technologies: “demand response,” he said, “is clearly the ‘killer application’ for the smart grid.”

In its report, FERC found that the ratio of advanced meters—which are necessary to allow load-serving entities (LSEs) to create dynamic pricing systems to allow for more accurate price signals to consumers—to installed meters has grown in the United States to about 4.7 percent in 2008, with higher gains among cooperative utilities. FERC also determined that many more utilities offered real-time pricing in 2008 than in 2006, and that about 8 percent of U.S. customers now participate in a DR program. These gains translate to an increase of about 3,400 megawatts (MW) of potential DR response resource contribution since 2006; such contribution now amounts to almost 41,000 MW, about 6 percent of U.S. peak demand. The mid-Atlantic, midwestern and southeastern U.S. regions currently make the largest DR contributions to the national power system.

FERC noted the initiatives of several states to advance DR through legislation and utility regulation, often as part of programs designed to reduce overall electricity use. Some individual states, for instance, have adopted peak pricing rates for their customers. FERC also found that some multi-state groups have adopted coordinated programs primarily composed of education, research and development. Some utilities have expanded voluntarily their DR programs to address peak load growth and the costs of new power generation. In another development, third-party aggregators have formed to provide services to customers traditionally unable to participate in DR programs.

To promote wholesale power market DR, moreover, FERC has removed several barriers to DR participation in wholesale markets. FERC’s Order No. 719, issued in October 2008, obligates Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) to identify and address barriers to comparable treatment of wholesale DR resources in ancillary services markets, allows DR aggregators in certain circumstances to bid DR for retail customers directly into the energy market, and modifies other market rules. These rule modifications should allow the market-clearing price to equalize supply and demand, including DR in the mix, when shortages occur in operating reserves.

FERC noted that certain states and the Federal government have eliminated some barriers to DR, such as “decoupling” utility revenue and variations in retail power sales volume. FERC found, however, that significant obstacles remain to the more widespread adoption of DR, such as the lack of time-based billing rates for many customers, restrictions on access to meter data, impediments to assessing load reductions accurately, high costs of implementing DR programs during economic downturns and the absence of enough kinds of suitable DR programs to meet the needs of prospective DR providers.

FERC made a number of recommendations in its report. These include aligning retail DR programs and time-based rates with the design of wholesale markets, eliminating obstacles to equivalent participation by DR resources in wholesale power markets, supporting efforts of third parties to verify and track DR, and studying how to tie together efficiently DR, energy efficiency and smart-grid programs.

The report also notes that Congress has tasked FERC under Section 529 of the Energy Independence and Security Act of 2007 to make a “National Assessment of Demand Response,” due by June 17, 2009, which estimates DR potential in five- and 10-year time horizons. In addition, under Section 573, based on stakeholder input, FERC must create a National Action Plan on Demand Response, due one year later, that identifies the needs for technical assistance, education, regulatory provisions and model contracts, for customers, states, utilities and DR providers. Six months thereafter, FERC and the U.S. Department of Energy must submit to Congress a proposal for executing the plan.

ISO-NE Forward Capacity Auction Results Filing

On December 23, 2008, ISO-NE submitted to FERC its Forward Capacity Auction Results Filing, which presents the results of its second Forward Capacity Auction (FCA-2). The Forward Capacity Auction is a competitive process by which supply and demand resources bid to provide capacity to meet New England’s anticipated future electricity needs using a descending clock auction that determines both the market clearing prices and capacity suppliers for each zone. This auction was held on December 8 to 10, 2008, for the June 1, 2010, through May 31, 2012, Capacity Commitment Period. In its report, ISO-NE concluded that the Forward Capacity Market (FCM) effectively supplies reliable capacity for the region and drew attention to the significant gains made in attracting Demand Resources to FCA-2. It noted that 2,900 MW of Demand Resources cleared the auction, an increase of 400 MW from the first FCA, which ISO-NE held in February 2008 for the 2010-11 Capacity Commitment Period. Gordon van Welie, President and CEO of ISO-NE, recently stated, “The initial auction results are clear evidence of this market’s ability to attract the demand- and supply-side resources needed throughout New England.”

Overall, by the concluding eighth bidding round, FCA-2 reached a minimum price of $3.60/kW-month with 4,755 MW of excess supply resulting. Because of the excess capacity offered, ISO-NE announced that it will prorate the Capacity Clearing Price, resulting in the purchase of 37,282 MW of capacity at $3.119/kW-month. Interestingly, as a result of the FCA-2, a single Capacity Zone emerged for the entire New England region.

Several days before releasing the report, ISO-NE stated to FERC in Docket No. ERO3-345 that participation in its DR programs increased by 38 percent in the year ending October 1, 2008. “New England as a region is at the forefront of demand resource development due in large part to the region’s newly established forward capacity market,” the report announced. ISO-NE asserted that “ready-to-respond” DR assets increased from 2,213 assets totaling 1,417.3 MW of DR to 3,019 assets providing 1,951.1 MW. The Connecticut load zone exhibited the highest load response (769 MW of ready-to-respond assets)—a 39 percent share. Maine offered 472.7 MW of load response, constituting a 24 percent share and northeastern Massachusetts, 230.7 MW, reflecting a 12 percent share.

ISO-NE also reported in Docket No. ERO3-345 that across all eight load zones, payment for 1 MW of DR interruption averaged $144/MW-hour (MWh) (April to September 2008), ranging from $122.84/MWh in Rhode Island to $162.95/MWh in Maine. ISO-NE also assessed the impact of DR on wholesale pricing, determining that real-time locational marginal prices declined by 31 cents/MWh for the first three months of the reporting period and by 27 cents/MWh during the second half. Maine experienced the largest average locational marginal price decrease ($1.66/MWh during the first three months of the period studied).

Once the 2010-11 capacity commitment period begins, two of ISO-NE’s five DR programs will expire: namely, the real-time and day-ahead response programs. ISO-NE announced that it is in the process of discussing with stakeholders the future of its price-response programs.

MISO Fostering Economic Demand Response Report

On December 20, 2008, MISO released its report entitled Fostering Economic Demand Response in the Midwest ISO. The report found that the MISO can attain significantly higher levels of DR over the next 20 years. Such gains could result from falling costs, such as for implementing both advanced metering infrastructures and “behind the meter” enabling technologies, e.g., programmable communicating thermostats, as well as from state and Federal policies that may promote price-based DR. After estimating the possible DR gains for the region, the report concluded “that the current resource base could be nearly doubled through aggressive DR policies over the next 20 years” from an estimated 6 percent to a maximum achievable potential of 11 percent by 2027.

The authors of the report, the Brattle Group, determined that the best way to align the price of electricity with the cost of producing and transmitting it is to send varying price signals to consumers that correspond to the fluctuating cost of electricity. The authors are not optimistic that states will implement dynamic pricing in the near term because transitioning to a new pricing system may upset the economic positions of existing market participants, expose certain retail customers to volatile prices, and require the widespread near-term deployment and use of smart meters that can provide interval data and two-way communication with market participants. The report, however, concludes that RTO/ISOs could create DR systems at the wholesale level, primarily through software/hardware measures that can allow consumers to respond dynamically to spot energy prices. This, they conclude, could make markets more competitive, efficient and dependable.

The MISO report presents a two-year plan to allow curtailment service providers (CSPs), i.e., aggregators, to participate in the market as a stopgap measure before implementation of economic DR. Such a timeline is necessary since economic DR incorporating dynamic pricing can only work if DR is integrated into the RTO’s market software and the DR resources can perform all the tasks necessary to set prices accurately. The plan also establishes ways of calculating customer baseline load (CBL) so that RTOs can incorporate verifiable DR “negawatts” (negative MWs) into their scheduling and transmission systems.

Currently, according to MISO, market participants allegedly can game the system by such means as overstating customer loads and receiving compensation for load reductions that never took place, temporarily increasing loads and then making repeated curtailments to exclude subsequent days from baseline measurements, or excluding low-usage days from baseline calculations. MISO’s report acknowledges that the baseline definition is a salient issue hindering market design for DR and that related measurement and verification (M&V) measures may create significant transaction costs. MISO will consider modifying its rate system and business practices to enable a “supply curve” model that would assist CSPs entering the market. Implementing such a system, the report argues, will require MISO to develop a sound CBL methodology and M&V protocols. Finally, the report advocates that MISO explore the benefits of DR with state commissions and utilities, and that it work together with them to phase-in dynamic rates.

The timeline presented in the report for adopting a supply curves model that factors in CSP participation anticipates that MISO will need six months to work with its stakeholders to design its CBL approach and M&V protocols, and four months to modify its business rules and coordinate them into its settlement software. Over the next two years, the report concludes, MISO also will need to assess whether it should create a new electronic interface to accommodate demand response resource (DRR) submissions. In addition, it will need to study whether its existing interface sufficiently incorporates all of the qualities of DRRs and determine if DRR should set real-time market prices. Furthermore, the report noted that in addition to working with state commissions and utilities to discuss the benefits of DR and how to implement dynamic retail rates, MISO also will need to explore the effects of economic DR on anticipating demand, planning capacity and influencing resource costs.

The report also noted that MISO has substantially less economic DR than other RTOs. PJM Interconnection and the California Independent System Operator currently lead RTOs in DR enrollment, although ISO New England and the New York ISO have significant participation in their DR programs.