DEMAND RESPONSE-MOST SIMPLY DEFINED AS the decision not to consume energy in response to price and other factors-holds enormous potential to balance the power system, integrate variable-output renewable resources into the grid and increase the efficiency of the electric utility industry.
The U.S. Congress has directed development of demand response as a national policy, but take-up has been limited to date in some states, and by some utilities, in part due to current regulatory constructs.
In its "2010 Assessment of Demand Response and Advanced Metering" staff report, released in February, the Federal Energy Regulatory Commission (FERC) gave demand response a slightly new definition, redefining it as "Changes in electric use by demand-side resources from their normal consumption patterns in response to changes in the price of electricity, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized."
Program classifications have morphed and diversified over the years, too. This year's FERC report lists 14 different types of programs, from direct load control (one of the most common demand response programs offered, as far back as 1968) and interruptible load to demand bidding and buyback, time-of-use and critical peak pricing, regulation service and system peak response transmission tariff.
Program confusion can occur, making decision-making, especially in early planning and implementation of new demand response options, even more difficult. "The rapid evolution of demand response programs, rules and names increases confusion among respondents and staff alike," the FERC report notes.
OPPD adds residential curtailment to C&I
In 2009, Nebraska utilities budgeted $12 million to promote demand-side management within the state. About $6 million of that was for energy efficiency (both gas and electric), with the other half designated for load management. The Omaha Public Power District (OPPD), the twelfth-largest public power utility in the United States in terms of customers (more than 340,000 in all or parts of 13 counties in the east and southeast portions of the state), now offers several interruptible riders, which pay its customers for agreeing to provide load curtailments or activate on-site genera-tion for a limited number of times per year. These riders differ, depending upon whether the curtailment event is mandatory or voluntary, and the minimum load drop ranges from 100 kW to 500 kW.
Denise Kuehn, OPPD's manager of demand side and sustainable management, discussed some of the operational issues and challenges of implementing demand response initiatives within the utility. "When demand response is based on a direct signal, we have better control of the load changes," she explained. "We have programs where we request that the customer curtail (energy usage), and the timing fluctuates, which makes it tougher."
Commercial and industrial curtailment has been in the utility's mix for quite some time, Kuehn said. On the residential side, OPPD did some early demand response pilots in the 1990s, which got mixed reviews and didn't work optimally. Over the past two summers, the utility has piloted new residential demand response programs with much more success, and is now launching full deployment of the program. Pilots are intended to serve as learning experiences, both for the utility and for its customers, and OPPD definitely learned some technology lessons along the way.
Technology as a detractor
When asked about the IT and communication challenges of integrating demand response within the utility, Kuehn pointed to the coordination of different technologies as a definite challenge. "Technology is required to send out the signal to turn off devices, and to verify and track results. Coordinating this with different technologies can be difficult and time-consuming," she said.
In the residential pilots, as an example, the challenges became obvious fairly quickly. "We started with condensers, and found there was too great a temperature rise-our goal was a temperature rise of less than 4 degrees. So, we went to thermostats, and spent months trying to pull the data out of them. We're going back to condensers," Kuehn said.
SCE an old hand at DR
In California, the state's three investor-owned utilities were preparing to file their three-year demand response funding applications as this issue went to press, according to Mark Martinez, Southern California Edison's manager of business strategy and planning. One of the nation's largest investor-owned utilities, Southern California Edison (SCE) delivers power to nearly 14 million people in 180 cities across central, coastal and southern California, across 50,000 square miles of service territory.
SCE has been designing, developing and deploying reliability and price-responsive-based demand response retail programs for more than a quarter of a century. These programs include interruptible tariffs, direct load control, capacity-based retail products and dynamic dispatchable pricing. SCE operates one of the largest comprehensive demand response portfolios in the country, with more than 1,600 MW of available peak reduction capacity from all retail customer classes, available for reliable dispatch at times of emergency and during critical peak periods.
SCE has experienced substantial growth in its demand response portfolio since the summer of 2006, when California experienced a "one in 50" summer heat wave. In 2008, the same year that SCE increased its demand response capabilities across all customer sectors by almost 280 MW, there were again multiple price-responsive critical periods throughout the summer, as well as a transmission emergency event in November that required immediate load reductions.
The utility believes strongly in customer choice and education in order to increase demand response efficiencies. In its comments to FERC concerning the draft National Action Plan on Demand Response, which saw early circulation in 2009, SCE noted: "To achieve effective DR, as many customers as possible should be exposed to DR options and be encouraged to participate in these programs." Demand response programs, the utility said, should offer customer choice and be flexible and adaptable in order to encourage customer participation, so that customers can select the programs that best suit their particular situation. "Customer education, clear eligibility requirements and balanced incentives assist customers in selecting the most appropriate program," SCE told FERC.
And there are other challenges too, according to the IOU, the largest being the effort needed to bring price- responsive demand response to the mainstream customers. Dynamic pricing and frequent dispatching of customer-approved load reductions has not been readily adopted by customers, even those equipped with advanced metering and enabling technology. Overcoming these hurdles, SCE says, will involve education and awareness, new ideas, additional program design, system improvements and enabling technologies to facilitate customer participation. A marketing approach that combines compatible energy efficiency activities will assist, as well.
RTOs have a role, as well
Regional transmission operator PJM Interconnection LLC has also long been active in the demand response market. Andrew Ott, PJM's senior vice president, markets, shared the clear benefits of economic and capacity-based demand response to both regional grid operation and whole market operation. "The PJM capacity market has attracted nearly 13,000 MW of demand resources offered; over 9,200 MW have cleared," he said.
"There are two types of demand response: energy-based (responsive to price or environmental instruction) and capacity-based (emergency)," Ott added. "When demand response offers or responds, both types are beneficial. Having demand response come in offers more flexibility and diversity of supply. It's beneficial from both operational and market-efficiency points of view."
Ott says that more automation in demand response means it will become more predictable as an operational tool for load balancing. As a large control area, load is balanced using economic dispatch (every five minutes), synchronized reserve (16 percent of which, for PJM, is provided by demand response), and frequency control (regulation every four seconds).
Without automation, there is a gap, Ott says, in the wholesale-retail interface. "Smart grid is enabling those kinds of gaps to be jumped, but retail-wholesale coordination is still a wish."