Regulatory incentives move customer-side solutions forward.
At face value, few would argue the benefits of demand-response (DR) programs. During tight supply and demand conditions, electricity users can reduce energy use for the short term in response to a price signal or a reliability trigger from their utility system operator, load-serving entity, regional transmission organization/independent system operator (RTO/ISO) or other DR provider by lowering their power consumption. As a result, peak prices are reduced and stabilized, grid reliability is enhanced, and the need to build additional costly generation, transmission and distribution facilities is forestalled. A 2007 study by The Brattle Group showed that even a 5% drop in peak demand in the United States would yield a $3 billion annual savings in generation, transmission and distribution costs.
Though it appears to be an obvious win for all involved, the Federal Energy Regulatory Commission (FERC) stated in a 2009 assessment that current DR programs tap less than a quarter of the total market potential. One primary roadblock to expanding DR programs on a large scale is the regulatory policies currently in place, on both a federal and state level, and the way these policies govern the wholesale and retail markets.
Under traditional regulatory policies, utilities have earned revenue based on the volume of energy delivered to customers. If electricity consumption decreases during peak periods due to DR initiatives and is not shifted to off-peak hours, utilities can lose revenue. Traditional regulation also dictates that investor-owned utilities earn returns on capital invested in generation, transmission and distribution facilities. Utilities, therefore, have a strong financial incentive to focus on investing in supply-side assets rather than demand-side.
A Federal View of Demand Response
To better clarify the problem, the FERC conducted a nationwide survey to analyze DR participation. The commission presented the results in its August 2006 report “Assessment of Demand Response and Advanced Metering” and has followed with annual updates.
In its sixth-annual report, published in November 2011, the commission shared its latest findings:
DR potential in organized markets operated by the Electric Reliability Council of Texas (ERCOT), RTOs and ISOs increased by more than 16% since 2009
Demand responded to peak load emergency conditions in ERCOT and the RTO and ISO organized markets
Federal and state regulators and others continue to focus on DR, taking actions to remove barriers to wholesale DR and develop policies to address smart grid.
In addition, the FERC determined that there is a clear need for better DR measurement. Along those lines, the North American Energy Standards Board has been developing standards for the measurement and verification of demand reductions by DR resources at the wholesale and retail levels. At issue is how to estimate effectively a customer's baseline electricity use. At the wholesale level, participants in DR programs measure their reductions by comparing actual meter readings against the customer baseline (what the metered load would have been without the reduction in demand). The RTOs and ISOs use various baseline methods to estimate consumption without DR. Efforts are underway at both state and industry levels to standardize baseline estimates.
The FERC noted that another significant regulatory issue currently being addressed in state rate cases is how to recover the cost for investment in the devices, controls and software needed to implement DR. Federal stimulus funds injected $4.5 billion in initial smart grid and DR investments, but acquiring additional funds will need to be worked out through regulatory policies.
Demand Response vs. Bulk Power Generation on the Regional ISO Level
The FERC affirmed the importance of DR in wholesale energy markets when it issued Order No. 719 in October 2008. The order made changes in the way RTOs or ISOs operate in the wholesale market and outlined requirements:
Accept bids from DR resources in their markets for certain ancillary services, on a basis comparable to other resources
Eliminate, during a system emergency, a charge to a buyer in the energy market for taking less electricity in the real-time market than purchased in the day-ahead market
Accept bids from aggregators of DR from retail customers of utilities that distributed more than 4 million MWh in the previous fiscal year but not accept bids from those that distributed less than 4 million MWh
Modify their market rules, as necessary, to allow the market-clearing price during periods of operating-reserve shortage to reach a level that rebalances supply and demand to maintain reliability while providing sufficient provisions for mitigating market power.
In its March 15, 2011, final rule, the FERC removed compensation barriers for DR resources participating in wholesale energy markets. Now when a DR resource participates in an organized wholesale energy market administered by a RTO or ISO, that DR resource must be compensated at the market price for energy, referred to as the locational marginal price (LMP). LMP, the same market rate paid to generation resources, will be paid to DR resources when it meets the cost-effectiveness threshold. This threshold will consider DR's impact on remaining loads to prevent customers who are not engaged in DR activities from incurring a greater cost for electricity.
“This shows that demand response is equivalent to generation and supply-side resources, and thus deserves equal compensation in wholesale energy markets,” said Dan Delurey with the Demand Response and Smart Grid Coalition.
Delurey explained that one issue connected with DR is whether it can be a reliable resource in an energy portfolio assembled by an RTO or utility. He noted that the FERC ruling confirmed that DR resources could be counted as reliable.
Paul Murphy, chair of the ISO/RTO Council, added that ISO capacity markets that allow DR make it possible for “demand response to be counted upon in a way that wasn't possible before to displace the need for new generation and new transmission facilities.” The ISO/RTO Council consists of the 10 ISOs and RTOs in North America that provide wholesale electricity to two-thirds of electricity consumers in the United States and half of Canada's population.
Stu Bresler, vice president of market operations and demand resources at PJM Interconnection, said that the reliability of the grid must be maintained and that DR has the ability to assist with that. “We need to incorporate the necessary analysis so that if the unforeseen happens, we still have a reliable system,” said Bresler. “We don't know exactly how much DR will be available years into the future, but we plan on the basis of what has already been committed to the system.”
Demand Response at the Retail Market/State Level
Though DR is important on the wholesale level, the FERC's “National Assessment of Demand Response Potential” report stated that demand could be reduced significantly if retail customers were on time-based rates. The industry has shown a keen interest in this potential as evidenced by the 15 smart grid and DR pilot projects launched since the mid-1990s. Thus far, only a small number of state utilities have implemented time-based rates and tariffs.
Those states that have time-based rates have peak-time rebates in which customers earn rebates by reducing energy use from a baseline during peak times for a specified time period. California is one of the few states that has a critical peak pricing tariff for commercial and industrial customers as a default rate in which customers must opt out. The Maryland Public Service Commission rejected Baltimore Gas & Electric's proposal for critical peak pricing rates and approved only peak-time rebates in the utility's smart grid plans.
Scott Hempling, executive director of the National Regulatory Research Institute, explained why retail customers have not embraced DR on a widespread scale.
“A disconnect exists between wholesale and retail markets, with retail prices usually set at average cost while wholesale prices reflect market competition, though the effectiveness of that competition is often in dispute,” Hempling stated in his 2010 report “Demand Response and Aggregators of Retail Customers: Legal, Economic and Jurisdictional Issues.” “The result is that retail customers are prevented from responding to wholesale price changes at the time those changes occur.
“There is significant opportunity for increased demand response if retail customers were on time-based rates,” Hempling said. “The costs of operating electric systems vary based on a number of factors, including time-of-day and season. In organized markets, wholesale prices may change significantly from hour to hour, or in even shorter time increments. However, most customers are on fixed retail rates that do not reflect variations in electricity costs. Instead, rates are based on average costs over a year. Customers who do not see time-based rates do not lower their demand when these prices are high.”
To help drive DR forward, federal and state regulators are working together on issues and policies as part of the National Association of Regulatory Utility Commissioners/FERC Collaborative on Smart Response. Phyllis Reha, vice chair at the Minnesota Public Utilities Commission, represents state public utility commissions in the collaboration. Minnesota ranks third among states in terms of the amount of DR it has implemented, behind only California and Texas.
State Regulatory Models for Demand Response
“Demand response is primarily a state issue,” said Reha. “Each state has its own regulatory policies in place so the issue is different for each state.”
The Environmental Protection Agency (EPA) categorized these models in its 2007 report “Aligning Utility Incentives with Investment in Energy Efficiency.” The EPA defines three primary categories of regulatory approaches to DR: program cost recovery, performance incentives and lost margin recovery. The EPA report explained how various cost recovery and performance incentives work:
- Program cost recovery
A utility can recover prudently incurred DR investment costs on a dollar-for-dollar basis through a rider or customer surcharge. Cost recovery alone, however, will not address the lost margin revenue the utility will face due to reduced energy sales. Also, cost recovery does not factor in opportunity costs that DR investments displace supply-side investments for which a utility can earn a profit.
- Targets, incentives and penalties
Regulatory commissions in some states have set DR targets for utilities with both rewards and penalties based on performance measured against those targets. For example, a utility may face a penalty for failing to achieve at least 70% of the target, receive a pro-rated percentage of the incentive for achieving 70% to 110% of the target, and receive an additional reward for achieving more than 110% of the target.
- Shared savings
The utility receives a percentage share of the energy savings from a DR investment. The savings are generally calculated as the avoided costs of an additional supply-side resource minus the DR investment. Incentives are given for achieving targets, and penalties are incurred for failing to hit the targets. This method encourages cost management because excessive spending reduces the incentives available.
- Rate of return
A utility will accumulate costs associated with DR investments as regulatory assets and can recover those costs in the utility's next rate case. This puts DR on equal footing with supply-side investments. A few states have implemented rate-of-return adders in which DR investments earn a higher rate of return than traditional supply-side investments.
- Avoided cost
The utility would be compensated for demonstrated demand-side savings by receiving a percentage of the utility's avoided supply costs. Duke Energy has proposed this approach with its Save-a-Watt program, but the model has not received final approval.
The EPA report does not address lost margin recovery mechanisms such as decoupling (an arrangement in which utility company profitability is no longer tied directly to kilowatt-hour sales) because “a properly designed performance incentive mechanism can indirectly address recovery of lost margin revenue, eliminating a disincentive and creating a balanced regulatory platform that will properly incent utilities to evaluate DR investments.”
Reha used her own state of Minnesota as an example of how these models might work in one state. “We have dollar-for-dollar cost recovery under our conservation improvement program,” Reha said. “We provide incentives to utilities for meeting certain savings requirements. We have tried lost revenue recovery mechanisms that have not been very successful because the numbers were growing so high that the cost-benefit analysis indicated that it was not working. Then we came up with a program cost recovery approach that had been measured as energy efficient and we added incentives to it.
“We also look at demand response in our integrated resource planning that includes our regional power agencies,” Reha said. “It requires that both our supply side and demand response be considered together. We've tried some pilot programs that look at dynamic pricing rates for customers. Minnesota is a traditionally regulated state, and these dynamic pricing options are better suited to those states that have already been restructured. Minnesota allows a rate of return for utility investments in demand response and that rate of return is determined through a regular rate case.”
A state's regulatory policies regarding DR also can be shaped by that state's ratepayer advocate and EnerNOC' senior vice president Gregg Dixon notes that state ratepayer advocates have differing views on the subject. (EnerNOC provides DR products to utilities, grid operators and commercial/industrial customers.) “If the advocates want to see low cost in the short term, then they typically aren't going to be supportive of renewables or technologies that might be perceived as having a higher short-term expense,” Dixon said. “Some advocates say they want decoupling because they don't believe utilities are the most efficient way to spend ratepayer dollars on energy efficiency and they want a third party to do it. You see states like Vermont, Hawaii and Maine where they have set up entities to remove administration of efficiency programs from utilities. Many states are taking a ‘wait-and-see’ approach while California tends to be very progressive in this regard. Everyone else learns lessons from whether they sink or swim with their initiatives.”
Currently, state regulators are looking at the hot-button issue of retail aggregation. “Now that the FERC is requiring integration of and full payment for DR through Orders 719 and 745, retail aggregators want to play a significant role,” Dixon said. “They want to act on behalf of large electricity customers to aggregate operational flexibility, monetize it and share in that new revenue stream. As you might imagine, this creates all kinds of healthy competition between third parties, utilities and customers themselves.”
Jeff Davis, a Missouri Public Service commissioner, said the situation begs the question of whether or not a customer should be able to sell its excess electricity to an aggregator and back into the market. “Traditionally, a utility would sell any excess capacity and then the ratepayers would get a portion of the compensation,” Davis said. “Then you get into resource planning where you must prevent double bidding into the market in which two entities are counting on the same resources or where those involved are saying that there is more or less demand than is really available. Regulators are struggling to come up with answers.
“Every state has a different regulatory framework,” Davis said. “On the East Coast, you have a capacity market and a lot of states that are deregulated. In the Midwest, everyone is still operating under traditional rate-of-return regulation. Missouri regulatory policy only allows utilities to sell electricity. We have an aluminum smelting company in our state that has a 98% load factor, so its electricity rate is 3.5 cents per kilowatt. Should they be able to sell the power on the market like a lot of companies did when Enron was at work 10 years ago? My understanding is that a lot of aluminum smelters in the Northwest shut down their plants, sold their electricity for a pile of money and moved to Brazil. If companies are getting a low interruptible rate from their utility, should they be able to market that electricity to an aggregator company and keep the profits? If so, are other ratepayers having to contribute to those large industrial customers selling electricity?”
Reha explained that the primary concern of state regulators is how much DR-related programs are going to cost and who is going to pay those costs. “We are very protective of our jurisdictions,” Reha said.
Bresler said that once the proper regulatory framework is in place, the future looks bright for DR playing a strong role in the retail and wholesale markets. “We do need to leverage these technologies to enable retail customers to take better control of their costs and to improve the communication between the wholesale market operator, like PJM, and the market participants and aggregators of retail customers,” Bresler said. “Like anything else, it will be an evolution.”
Status of State-Provided Energy-Efficiency Incentive Mechanisms
|State||Financial incentives for energy efficiency||State||Financial incentives for energy efficiency|
|District of Columbia||1||1||North Carolina||2||2|
Source: Database of State Incentives for Renewables and Efficiency (www.dsireusa.org).
The Brattle Group | www.brattle.com
EnerNoc | www.enernoc.com
National Association of Regulatory Utility Commissioners