The electric utility industry is currently undergoing the greatest period of transformation in its history. Utilities are facing new challenges, and these challenges present opportunities for them to reevaluate business processes that have remained unchanged for decades. This blog series delves into six of what we consider to be the most impactful challenges, dissects them, and hypothesizes how they will shape the future of the utility industry. This blog post focuses on the most popular customer behavior program for energy management: demand response.
This past summer, specifically during the month of June 2017, temperatures blasted the Southwest with a heatwave that led most people to crank up their air conditioning. During this time, utilities across five states, from California to Texas, broke their all-time records for peak demand. ERCOT, the Electric Reliability Council of Texas, broke its previous record three times in one afternoon on July 20th. The demand was met without issues, but ERCOT assesses its current summer reserve of 18.9% will decrease to less than 10% within a decade, a small margin if their customers’ demand is underestimated.
One method of increasing generation capacity is by building new power plants. For many decades, a utility’s business model focused on building infrastructure. The annual increase in electricity consumption was always large enough to support new investments in power generation. In this scenario, ERCOT’s utilities would likely build a natural gas plant, after considering the Clean Air Act requirements and the cost of the various types of fuels. If building new plants was the only option available to utilities, Maximilian Auffhammer, an environmental economist at the University of California, calculated it would cost U.S. utilities a total of $180 billion during the 21st century to meet rising demand peaks. This magnitude of investment is unattainable for many utilities. In today’s market, the electricity load is growing gradually, and utilities must find alternatives to combat the cost of building new power plants or utilizing expensive auxiliary generators when demand reaches peak levels.
Solutions that are financially feasible focus on energy efficiency and optimization. Energy management includes any programs or technology that enable customers to manage their electricity use to benefit themselves and the utility. One well-known method is demand response, a program in which consumers reduce consumption based on market signals. Instead of requiring a utility to manipulate supply to match demand, demand response empowers the customer to manipulate demand to match supply. Depending on the program, consumers can respond to fluctuations in price, demand charges, or critical thresholds on the electric grid. During times of peak load, high wholesale energy prices, or compromised supply situations, the utility sends signals to customers enrolled in these programs asking them to reduce their load. The utility benefits from additional control of a flexible load, and the customer enrolled in demand response benefits from monetary compensation for their flexibility.
Two markets, retail and wholesale, exist for demand response programs. The latter, often called supply-side programs, are usually offered by independent system operators (ISO) or regional transmission organizations (RTO) and allow demand response providers to bid into the wholesale electricity market alongside traditional generation plants. According to surveys from the Federal Energy Regulatory Commission (FERC), two of the top demand response programs are wholesale market programs. Emergency Response and Load as Capacity Resources account for 24% and 15% of total peak load reduction respectively. One of the leaders in capacity resource demand response, the Pennsylvania, Jersey, Maryland Power Pool (PJM) RTO, signed contracts for almost 170,000 MW of capacity in 2016, and roughly 12,500 MW of the total were demand response resources, equaling 7 percent of the peak demand. Since demand response is reducing energy during peak times when electricity costs are higher, PJM estimates its customers saved as much as $650 million in a summer month. PJM is building increased integration of demand response into its supply forecast and expects to achieve the increase without any adverse effects on service.
Demand response is not a new concept. According to a survey conducted by Utility Dive, 66 percent of utility executives said their utilities offer energy management and efficiency services to customers. According to FERC’s assessment of demand response in 2017, over 9 million customers are enrolled in incentive-based programs, a number that has remained steady in recent years. Wholesale incentive-based programs include emergency demand response and bidding as capacity reserves. On the other hand, time-based programs increased by 10% to include over 7.5 million customers. Dependent on rate structures, these programs are offered by utilities as retail market demand response. The most common rate structures are real-time pricing (hourly pricing based on the market), critical peak pricing (increased prices during peak hours), and time-of-use rates (predefined pricing for periods throughout the day). Utilities can only offer time-based rates to customers with capable meters, so a 10% increase could be correlated in part to the increase in the number of smart meters installed, approaching 43% of total meters in 2015, according to FERC.
With the addition of many smart grid initiatives across the U.S., specifically advanced metering infrastructure (AMI) meter installations, more and more customers are becoming eligible for retail programs. Specifically, residential and small commercial customers account for the largest percentage and are targeted for direct load control programs, which give utilities or third-party demand response aggregators direct access to controllable appliances. This type of control requires communication networks to send messages to the appliance controllers when certain conditions are met. These networks and other modernization efforts give demand response the opportunity to work in conjunction with variable renewable energy. In the future, air conditioners, water heaters, and electric vehicle charging stations could be cycled quickly to respond to spikes or dips from wind and solar. A study by Peak Load Management Alliance (PLMA) determined that industry professionals rate demand response as the second-best way to handle variable energy sources (38%), second only to energy storage (43%).
In addition to the opportunity for retail demand response to integrate with renewable energy, industry leaders predict supply-side demand response can provide other services to distribution grid operations. Some of the services focus on the quality of the electricity delivered, such as steady-state voltage management, phase balancing, and power quality. These goals are dependent on grid modernization technology such as sensors and automatic grid controls, as well as close communication with power generation sources.
The existence of two different markets for demand response opens the possibility of incompatible programs offered by a utility and the utility’s ISO or RTO, but many states and their Public Utility Commissions (PUC) are organizing workshops or working groups to ensure the retail and wholesale programs are complementary. Instead of the $180 billion investment in new plants mentioned at the beginning of this article, supply-side demand response providers can potentially prevent the need for new generating units, as well as improve electricity power quality. Paired with behind-the-meter demand response programs that use time-of-use (TOU) rates to flatten the load curve and that increase the adoption of renewable energy by compensating for its variability, demand response is poised to be a powerful tool in energy efficiency for the smart grid.
When utilities consider redesigning their business models or implementing new technologies and programs, they often cite regulatory obligations as one of the leading obstacles they face. In contrast, regulatory requirements have not been a concern for many demand response implementations. In January 2016, the U.S. Supreme Court upheld FERC Order 745, which ensures demand response providers in the wholesale market will be compensated for their load reduction at the same rate electricity generators are compensated. On the retail side, the California PUC mandated its utilities must enroll their residential customers in TOU rates by 2019, a trend being picked up by other utilities.
The biggest obstacle to demand response is not regulation, but customer response. Utilities must devote resources to informing their customers about how demand response works and how programs could benefit them. Before switching large numbers of customers to time-based rates, pilot programs must gauge how customers react to the new rates and if opt-out opportunities are needed. For incentive-based programs like load control, customers can be hesitant to sign up without assurances from the utilities that their air conditioners, water heaters, electric cars, etc. will be cycled in a way that provides the least disruption to their lifestyle and that they will be compensated fairly for the trade-off.
Overall, demand response builds upon the new partnership-style relationships utilities have with their customers, thanks to customer presentment programs. Furthermore, demand response programs will become increasingly effective as they continue to utilize advancing smart grid capabilities, including communication networks which we will discuss in a future post in this series. But before we dive into how communication technology is changing our electric grid, the next blog post discusses the impact of third-party vendors in the energy industry, including influential demand response providers.
About the Author
As a consultant at Red Clay Consulting, Megan Milam has comprehensive training and functional experience with Oracle Utilities Application Framework software and Oracle Utilities Lodestar software. Furthermore, her Bachelor of Science degree in electrical engineering, with an emphasis in power systems and smart grid technology, and her previous work experience at a transmission System Operator give her a technical background with a firm understanding of industry best practices and an ability to implement optimal solutions.