By Darren Brady, EnerNOC, Inc.
Editor’s note: This is the second in a series of special articles on the “ins and outs” of demand response (DR). The following article is authored EnerNOC, a DR provider based in Boston, and looks at the positives of DR from a utility point of view. An earlier article on selling DR to facility managers starts on page 52.
The problem is well-known: Today’s grid infrastructure is aging and in need of significant investment, but there are increased challenges in siting, financing and operating new generation, transmission and distribution.
The question is a common one: How do we modernize the grid to meet the demands of the twenty-first century?
There is not one solution. Federal and state policy makers are recognizing the need to invest in the demand side of the equation–that is, decreasing demand (kW) and consumption (kWh) to avoid or defer the need to build supply infrastructure. The costs of raw materials, fuel and construction are increasing. Utilities are turning to demand response (DR) as an environmentally sensible and reliable resource to reduce peak demand for a targeted number of hours per year. DR is an evolving resource. It is establishing itself as a key component in today’s electrical system, and is likely to become a highly valuable resource in the future.
What is DR Today?
Historically, utilities have typically made efforts to manage electricity demand by administering energy efficiency and load management programs. Until recently, load management programs have focused on small residential customers and large industrial customers through direct load control and interruptible rates, respectively. Residential customers on direct load control programs have simple control hardware attached to a common household appliance such as an air conditioner or pool pump; interruptible customers get a telephone call when they need to shut down.
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Today’s DR programs are distinct from traditional load management programs for a variety of reasons. First, DR can target commercial, institutional and industrial (C&I) customers who can contribute significantly to peak load reductions, but have historically sat on the sidelines. While traditional load management programs either targeted a specific end-user application (e.g., air conditioning) or required a full facility shut down, the processes at C&I facilities vary widely and customers crave more customized reduction strategies. Utilities can now work with third parties who have necessary “behind the meter” expertise to develop unique curtailment strategies. Reductions can also be automated or manual depending on the sensitivity of the process and customer comfort.
Second, today’s DR programs can be considered firm resources: They are designed to be dispatched more frequently and more reliably than the load management programs of yesterday. Third party providers can aggregate DR resources within a utility’s service territory to mitigate the risk of a given customer’s non-performance during a DR event. Advances in technology allow granular two-way communication between the DR operator and the customer’s meter without the need for a full advanced metering deployment. This technology both enables the DR operator to better manage load response events and provides resource visibility to utility system operators.
Why Utilities are Choosing DR.
Utilities have increasingly adopted DR as part of their resource portfolios for the following reasons.
- DR is Cost Effective: The cost of one alternative to DR–building a peaking power plant and associated transmission infrastructure–is rising due to increased raw material and fuel costs. As DR technology becomes more advanced, it can cost-effectively defer or avoid the need to procure new supply resources.
- DR is Reliable: Advanced metering and control technology allow utilities to have visibility into the performance of individual and aggregated DR resources on a near real-time basis. Third parties can guarantee demand reductions by managing DR resources using a portfolio approach.
- Environmental Concerns are Increasing: A DR portfolio provides capacity and energy without the carbon or other emissions associated with a peaking power plant. Further, a DR program will not likely face the “NIMBY” (not in my backyard) concerns that can plague a potential new power plant.
- DR Sees Favorable Regulatory Treatment: Legislative and regulatory bodies at the state and federal levels are encouraging utilities to adopt DR. A few states have created statewide Renewable Portfolio or Energy Efficiency standards for which DR qualifies. For example, the Public Utility Commission in Colorado recently issued a ruling that requires a utility to seek DR; in Nevada utilities can earn favorable rates of return on their DR investment. The Energy Independence and Security Act of 2007 explicitly encouraged the adoption of measures like DR that reduce peak load.
- DR is Quick-To-Market: DR resources can be brought online within a matter of months; it can take years to site and build a new power plant.
- DR is a Flexible Resource: Utilities can customize DR resources to meet unique system needs. DR resources can be used to reduce peak demand within a territory, respond to a reliability event, provide ancillary services such as spinning or balancing reserves, mitigate load growth from areas subject to transmission constraints, or reduce a utility’s exposure to high wholesale or spot market energy prices.
- Customers Demand DR: As energy costs rise, many utilities are seeing their major customers asking for demand response program options as a way of mitigating their costs. DR can help to keep customer satisfaction levels high.
What is the DR Future?
DR penetration is increasing, and technology will continue to improve the capabilities and the adoption rates. Some of the following trends are emerging.
- Demand as a True Supply Alternative: Utilities are getting creative. DR is not just a reliability product used as a last line of defense to prevent a blackout; utilities are procuring more flexible DR products that can be dispatched for economic and reliability purposes. Regulated utilities are designing programs with more firm availability, sometimes up to 100 hours per year, and the option for voluntary response during non-firm hours. Utilities in deregulated markets, such as Commonwealth Edison in Chicago (PJM) and Consolidated Edison in New York (NYISO), have built upon ISO/RTO DR programs to use DR resources to address local distribution constraints.
- A Sophisticated Technology Future: As the software required to effectively manage DR resources and events becomes more advanced, utilities will be able to “turn the DR dial” instead of just “pushing the DR button.” Third party aggregators are becoming adept at crafting more nuanced and responsive portfolios that can increase the DR potential in a service territory, both in terms of capacity and availability. DR events are currently managed with a “push the button” approach–a utility with 50 MW of DR calls a three hour event and all program participants within the service territory reduce an aggregated 50 MW from the grid for three hours. But what if the utility really only needs 30 MW and they need it instead for eight hours which extends beyond the length that most business and institutions can sustain reduced consumption? DR aggregators are currently developing advanced algorithms, curtailment methodologies and portfolio creation strategies to overcome challenges created by these types of situations.
- BalancingIntermittent Resources: ISO/RTOs and utilities are starting to procure DR as an ancillary services product. Interestingly, as more intermittent resources like wind and solar come onto the system, DR can be used to balance the fluctuations inherent in these sources of power generation. Currently, for example, DR can participate in PJM’s Synchronized Reserves and Regulation Markets, and ERCOT’s Responsive Reserve and Non-Spin Markets. In addition, some utilities have purchase quick-response DR programs to meet ancillary services requirements.
- Bundling up: Lastly, DR can play an important role in utility energy efficiency and renewable energy initiatives. In some states, such as Pennsylvania and North Carolina, the opportunity is explicit: the energy delivered during DR events can count toward a utility’s Renewable Portfolio Standard requirements. In other states, the opportunity is much broader. DR programs can assist utilities in acquiring tangible environmental benefits like Renewable Energy Certificates or White Tags. DR aggregators are mining DR program data to identify and execute additional energy efficiency opportunities that can be implemented with DR technology. This approach of bundling DR, energy efficiency and the associated environmental attributes will dramatically increase the value DR provides to a utility and its C&I customers.>
Darren Brady is chief operating officer and senior vice president of EnerNOC where he leads the operations, engineering and information technology teams and supports the company’s continued efforts to expand into new markets. He holds a BA from Brown University and an MBA from UCLA. Email him at firstname.lastname@example.org.