Utility, DR Provider Alliances: Meeting Regulatory Requirements, Reducing Costs and Driving System Reliability

By Janette Kessler Dudley, ConsumerPowerline

Many utilities have received mandates from public utilities commissions (PUCs), state legislatures or other regulatory bodies requiring that a certain percentage of peak load be met by demand response and energy efficiency programs within a certain timeframe. For example, in Maryland, utilities must achieve a 15 percent reduction of 2007 peak load by 2015 through demand response and energy efficiency measures. In part, these mandates stem from the recognition that reducing the demand side of the equation can be more reliable and cost-effective than increasing the supply side.

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Many states are also mandating that, by a date certain, a specified percentage of the state’s electricity be sourced from renewable resources. For example, in the recently enacted Massachusetts Green Communities Act, 15 percent of load must be met by renewable energy by 2020. Because many types of renewable energy (including wind and solar) are intermittent, this increased share of renewable energy will require an increase in the amount of 10 minute and 30 minute reserves procured by a utility or regional transmission organization (RTO). Demand response providers can assist utilities in meeting these regulatory obligations.

In addition to helping utilities meet their regulatory obligations, demand response providers can also be a powerful tool for a utility in addressing rising electricity costs. In the face of rapid load growth, it is more cost-effective to procure demand response as a capacity resource than it is to build a new peaking power plant. In addition, economic demand response programs can help moderate prices during shortage conditions. When the need for power spikes unexpectedly, without demand response, utilities need to bring the most expensive power plants on-line. As a result of the scarcity, prices often spike at these critical times, and these higher prices are then passed through to the ratepayers. Alternatively, demand response resources can reduce the peak load resulting in a moderation of peak prices.

Finally, utilities around the country are increasingly turning to demand response to address reliability concerns. Demand response is particularly valuable in ensuring reliability for several reasons:

  • Local problems in a transmission or distribution system can be addressed with targeted load-shedding;
  • Lead times for the implementation of demand response resources are often significantly less than other resource types, including generation and transmission infrastructure, and can therefore be utilized to quickly respond to reliability problems; and,
  • Many load resources can provide operating reserves that respond in 10 minutes or less, thereby providing grid stability until other generation resources can be brought on-line.

Because of its high quality, lower start-up cost, lower cost of operation and rapid time-to-market, demand response can be used to effectively address regulatory requirements, rising electricity prices and reliability problems.

Meeting Regulatory Requirements

There are at least 25 state PUCs or regulatory bodies that have passed or are currently holding proceedings on utilizing energy efficiency measures and demand response in meeting current and future demand growth. Most of these have a specific target per year and an overall deadline. Many utilities have little or no demand response experience. The sales and marketing, registration, metering, monitoring and deployment of customers participating in demand response programs can be extremely time-consuming and a distraction from the utility’s core business of electricity supply and distribution. As a result, many utilities have chosen to partner with demand response providers, such as ConsumerPowerline, to help meet these regulatory requirements.

Some demand response providers have years of experience in multiple electricity markets in all phases of the customer relationship. These companies also have sophisticated engineering teams and software platforms with which to meter, monitor, provide settlement to and deploy demand response customers. Rather than re-inventing these platforms internally, it is often faster and far more cost-effective for utilities to partner with demand response providers. In addition, most demand response providers are willing to guarantee the performance of their resources, thereby reducing the operational and reliability risk to the utility. Instead of the utility enrolling dozens of small to medium commercial and industrial loads, and having to monitor each of those customers, the utility can enter into a contract with a demand response provider for a certain amount of MW to be provided under pre-contracted conditions. For example, a utility might contract with a provider to deliver 50 MW, for up to 40 summer peak hours, over a five-year period. In the event that the provider does not meet a certain percentage of its required obligation, it would lose some of its posted financial assurance, thereby further reducing the utility’s risk.

In addition to meeting regulatory requirements for energy efficiency and demand response targets, many state PUCs and legislatures are mandating that a certain percentage of the state’s peak electric demand be met by renewable energy. This obviously has positive impacts on the environment, but can create reliability concerns for a utility due to the intermittent nature of many renewable energy resources. For example, in the Electric Reliability Council of Texas (ERCOT) there are nearly 5,519 MW of wind generation and more under development (according to a May 16, 2008 release). In January 2008, ERCOT increased the amount of responsive reserve service that it procures in order to maintain reliability. Of this, 1,150 MW can be provided by load resources (LaaR) that can respond in 10 minutes or less when called by ERCOT. To illustrate the importance of these load resources, on February 26, 2008 (the same day that Florida suffered a blackout), a significant amount of wind and conventional generation that was expected to be on-line was unavailable. At the same time, the demand for electricity was significantly higher than forecasted. As a result, ERCOT invoked its EECP (Emergency Electric Curtailment Plan) Step 2 emergency procedure and called 1,150 MW of LaaR resources. Within 12 minutes, 1,200 MW came off the grid. This was over 100 percent of the amount that had been procured for that hour. A blackout–or rolling blackouts–was thereby avoided. (See Figure 1.)

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Cost Effectively Meeting Rapid Load Growth

Adding new peaking generation to a utility’s capacity resources can cost $600 to $800/kW in upfront capital costs. The annualized capacity cost, including: a reserve margin gross-up of 12 percent, transmission losses of 8 percent, a 9 percent discount rate, and a 30-year life would be approximately $82/kW/year. Alternatively, demand response resources can be acquired for as little as $60/kW/year (depending on the notice period and the number of deployment hours). And, because the load is being reduced at the source of the demand, transmission and distribution losses and reserve margins are eliminated. Clearly demand response provides a cost-effective alternative to new peaking capacity. In addition, a single demand response provider can add at least 10 MW of demand response capacity per month or 120 MW in a year. As a result, utilities and PUCs throughout North America are turning to these resources to address supply-demand gaps in a timely and cost-effective manner. For example, The Public Service Company of Colorado determined that it needed 360 MW of new capacity by summer 2009 in order to meet expected demand growth. The Public Service proposed to provide this capacity through a combination of new combustion turbine units (at a cost of approximately $700/kW), as well as purchased capacity. The Public Utilities Commission, however, directed the Public Service to acquire the additional 123 MW through demand side management programs to the greatest extent possible.

In its order, the Commission stated,”[A] new third-party aggregation DR program, can be used to offset a portion of the anticipated imported electric energy and capacity needed to meet the peak loads and reserve margins, and that it may be less costly than short-term power purchases. We direct the Public Service to fully utilize existing DSM capabilities and expand existing programs with the goal of eliminating as much as feasible of the 123 MW of projected purchase power for the summer 2009.”

Further, even voluntary demand response can help save utilities and ratepayers millions, in addition to the programs described above. Those who operate the grid will pay every power plant that comes on-line, in a high-load hour, as much as the last power plant on-line will ask in order to run. These extra costs are assessed to ratepayers. When ratepayers (electricity consumers) voluntarily shed-load at these times electricity prices stabilize. It is, therefore, also in consumers’ best interests to turn extra load off, even on a moment’s notice, if they are advised to do so. A demand response firm will often offer the utility, gratis, the means to effectively communicate with its consumers, in real-time, adding real value for many more hours each year, to what is already a valuable product.

There are many benefits of a multi-faceted demand side management approach including permanent efficiency reductions, peak load management, and demand response, which are illustrated in Figure 2.

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Addressing Reliability Concerns

Demand response providers are also a valuable resource to utilities in addressing reliability concerns. In 2007, Central Vermont Public Service looked at several alternatives to enhance both grid and transmission system reliability throughout Central Vermont, and determined that a demand response program could provide significant relief to the electricity supply system in an efficient, cost-effective and environmentally responsible manner. It contracted with ConsumerPowerline to provide a turnkey demand response program for 25 MW.

Through the program, transmission operator Vermont Electric Power Co. can call upon demand response assets in the targeted Central Vermont territory, with 30 minutes notification, to curtail load in emergency conditions.

ConsumerPowerline will work with medium to large electricity customers in the Coolidge Connector affected portion of the Central Vermont Public Service area to evaluate electricity consumption and provide curtailment recommendations and plans that will not impact a customer’s core operations. The turnkey program includes enrollment, participation, reporting and payments.

Demand response providers can offer turnkey demand response products to utilities that respond like peaking units, but are less expensive, faster to market and can often respond in 10 minutes or less. As a result, demand response can be a powerful tool for utilities that need to meet regulatory requirements for peak load reductions, increased capacity from renewables, or simply to meet supply-demand gaps in a rapid, cost-effective manner. Finally, demand response providers can help address reliability concerns with a reliability-based demand response program, creating a winning situation for utilities, ratepayers and demand response providers.

Editor’s note: This is the second part of a Consumer Powerline series on DR. The first article was published in the August issue.

Janette Kessler Dudley is vice president of market development for ConsumerPowerline, a full service strategic energy asset management firm and a provider of demand response solutions. Dudley holds a BS from the University of California at Davis and an MBA from the Wharton School. She has 20 years experience in the electricity, telecommunications, and community development fields, including finance, M&A and market development.

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The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at Jennifer.Runyon@ClarionEvents.com.

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