By John Moore, Director, Sustainable FERC Project, Climate & Clean Energy Program, NRDC
If federal regulators do the right thing, electricity customers across the Midwest may soon be able to earn money while boosting grid reliability and clean energy. Earlier this year, the Federal Energy Regulatory Commission (FERC) floated the idea of opening up markets for “demand response.” Today, many states, mostly in the Midwest, prohibit their electricity customers from directly providing demand response into FERC-regulated regional power markets through what are known as third-party “aggregators.” These bans raise power costs, create barriers to renewables integration, and increase reliance on dirty peaker power plants. For these reasons, the Sustainable FERC Project and other public interest organizations support the removal of these barriers as soon as possible.
Demand response works best in FERC-regulated markets
Demand response, or DR, refers to voluntary customer reductions in power consumption, typically occurring when the power grid is near its capacity limits (and prices are often highest). DR is one class of increasingly popular “distributed energy resources,” or DERs, which also include rooftop solar, electric vehicles, heat pumps, and other customer-controlled equipment and actions. DERs contrast with large power plants which have one purpose—to generate electricity.
A relatively crude form of demand response has been occurring periodically this year in California and New York. Extraordinarily hot weather, coupled with the daily drop-off in solar power at dusk, spurred utilities and the state to ask customers to reduce energy consumption during high-demand periods, typically by using less air conditioning or avoiding electric car charging.
But we shouldn’t count on people conserving energy when asked to keep our power grid running. A better way is to let customers, like you and me, sell our demand response commitments in FERC-regulated power markets. DR has been successfully used for years in this way in the Middle Atlantic region, where the grid operator PJM relies heavily on demand response to help control the level of energy consumption during stressful peak demand times.
For example, in October 2019, PJM deployed over 700 megawatts of demand response during an extreme heat event. Demand response currently comprises 5.5 % of PJM’s total power supply (9,500 MWs), about two-thirds of which can respond in less than a half-hour. Because this DR is backed by contracts and commitments, grid planners can rely on it and save money by building fewer power plants. Demand response in PJM also provides grid reliability services to help fine-tune the grid’s operation.
Aggregators maximize the value of demand response
One reason why DR is so effective in PJM is because of the presence of commercial “aggregators” of demand response. These companies are the crucial link between electricity customers and FERC-regulated regional power markets like PJM. Aggregators take on all of the obligations and responsibilities of selling power—or in this case, demand response—into the PJM markets, obligations that you and I, and most other smaller electricity customers, cannot legally perform (and probably would not want to do even if we could). They take care of the large financial commitments, the complex market interface software, extensive system monitoring capabilities, and other obligations on behalf of many thousands of individual customers.
In the electrified world of the future, aggregators of energy services will be vital to harnessing the power of millions of homes, buildings, cars, and other grid-connected resources. Whether working independently or through utilities, aggregators have the economies of scale necessary to collect and manage customer-owned resources.
FERC knows this because over the last several years it has opened power markets to distributed energy resources, such as for electricity storage in 2018 and most recently with most other DERs in 2020. While those rules authorized the aggregation of DERs, FERC has allowed an outdated decade-long exemption specific to demand response to remain in place. In a nutshell, that rule allows states to prohibit the aggregation of demand response, instead giving utilities complete control over DR.
FERC’s rule allowing states to ban aggregators of demand response is the last vestige of a line of earlier FERC orders, predating many of the technological changes transforming the grid and empowering consumers. At present, 14 states have adopted this FERC-authorized ban on aggregators, plus an unknown number of other regulatory authorities, mostly in the Midwest.
States’ worries are misplaced
Why do states want to ban aggregators of demand response? The ‘official’ reasons don’t check out. States and their regulated utilities worry that aggregators will interfere with predicable utility forecasts of customer electricity demand. (This is less of a concern in most of the states in PJM, which enjoy some degree of retail electricity competition and where most utilities no longer own power plants.) As we explain in our comments to FERC on this issue, this worry doesn’t really hold water. Utilities are experts in planning for multiple uncertainties across many fronts, including for example the impacts of rooftop solar/net metering, energy efficiency, power plant fuel costs, economic growth, weather, and technology, to name a few.
Some states also worry that it will be hard for them to regulate aggregators. The easy response is that regulation is the very essence of the purpose of state commissions, and new programs or policies should not be rejected simply because they require the creation of additional standards and oversight.
Another concern might be utility profits. Before demand response, utilities built “peaker plants” that run on just a few of the highest power demand days each year. Since many utilities in the Midwest and elsewhere earn a guaranteed return on their investments, courtesy of you and me, they like building as many expensive power plants as they can. Demand response threatens to replace some of those big investments with lower-cost energy conservation so it’s no surprise that utilities worked to convince their regulators to preserve their monopoly over it.
However, commissions can work through any legitimate rate impacts from loss of sales—such ratemaking is after all a core purpose of energy regulators in most of the Midwest. The broader public interest concern of state regulators should be on ensuring that utilities invest prudently considering all factors, including the impacts of demand response on utility sales.
In the meantime, utility-sponsored demand response in the Midwest has barely grown in the last decade—again, not surprising since it can compete with utilities’ power plants. Aggregators, on the other hand, have a strong business reason to grow demand response at a time when automation and control technology makes it easier than ever to manage the resource.
The benefits of advanced, cost-effective demand response are numerous—from lowering the price of power and rates, to avoiding the construction of large new power plants, strengthening grid resilience in extreme weather conditions, and increasing the responsiveness and system flexibility to integrate high levels of wind and solar renewable energy resources into the grid. However, considering the mixed incentives of opt-out states, DR has little chance to unleash its full potential. Given DR’s clear and well-documented benefits, and FERC’s clear legal authority to regulate wholesale demand response, there is no sound policy reason for states to continue to ban aggregators.
FERC should act to open its markets to aggregators of demand response, which will be good for customers, clean energy, and grid reliability and resilience.
This article has been sourced from NRDC and can be accessed here