DERs AND WHOLESALE MARKETS: Leveling the Playing Field—Or Creating a New One?

This blog is the fourth in a series on the relationship between distributed energy resources or “DERs” and the transmission system.

Achieving a truly modern grid that can reliably and affordably integrate high penetrations of renewable energy like wind and solar will require policy changes to reflect and incorporate DERs into regional load forecasting and transmission system planning. It will also require making wholesale energy market rules fair so that DERs (and other clean energy resources) to can compete with fossil fuel and nuclear power plants in the supply of energy, flexibility and other grid services.

To date, the design of wholesale energy markets—centralized energy, capacity and ancillary service markets in regions managed by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs)—has been slow to catch up with the exploding emergence of wind and solar power and, more recently, DERs like energy efficiency, demand response (compensating customers for altering energy use at specific times), rooftop solar generation, electric vehicles and other energy storage options. Although traditionally dominated by coal, nuclear and natural gas-powered participants, wholesale markets are meant to be fuel and technology neutral and allow participation by any resources that are technically able to provide the energy, capacity or other grid services that the markets facilitate.

What are wholesale markets and how do they work?

The term “energy markets” can be used to mean a lot of different things. In the traditional monopolistic utility context, the only available market prospect was a bilateral construct –a series of opportunities for power plants to sell their output to utilities, usually via a utility competitive procurement process and a long-term power purchase agreement. Utilities also often developed their own power supply outside of the market context—and still do—in order to satisfy the electricity demands of their residential, commercial and industrial customers.

But the emergence of energy and reserves sharing across utility footprints, followed by the development of RTOs and ISOs, has changed the equation. Now, utilities in some regions have become the buyers in centralized, competitive wholesale markets (for energy, capacity and ancillary services) that offer an alternative to traditional bilateral transactions in the region.

Wholesale energy markets are centralized markets in which independent power plant owners bid to supply megawatt-hours of energy (driven by coal, natural gas single and combined cycle, wind and solar power plants, and in a few cases, DERs). Wholesale buyers like utilities submit desired purchase quantities to satisfy predicted energy demand. All of the RTO and ISO regions operate day-ahead and real-time energy markets—matching offered supply with demand both the day before the energy is need and in real-time to make up for day-ahead discrepancies. Regional system operators manage the market process and “clear” or accept the power plants’ supply bids starting from the lowest priced bids to the highest bid necessary to satisfy market demand. All of the power plants that clear the market receive the same price, known as the locational marginal price (LMP), for their energy. LMP is the marginal cost (the cost it would take to produce the next megawatt-hour of energy above the total amount cleared) at a given point on the grid at a given time.

Wholesale capacity markets were designed to ensure resource adequacy—a sufficient power supply to reliably serve demand one to three years in the future. The market intends to send forward price signals that encourage both maintenance of economically-efficient existing power plants and the construction of new ones (which may take a few years) as necessary to satisfy predicted future demand. Some DERs qualify to participate in forward capacity markets. Capacity markets operate similarly to energy markets.

Finally, wholesale ancillary service markets are markets used to more competitively supply services in addition to actual energy, necessary to keep the grid running on a day-to-day basis, as well as during an unexpected outage by a power plant or transmission line. For example, frequency regulation is a market-based service that helps to balance electricity supply and demand minute by minute. Synchronized or spinning reserves is another market-based service that is provided by power plants able to start up and provide power as quickly as five minutes after asked, and that exist to respond in the case of an unexpected supply outage.

Although there are nuances within and across regions, power suppliers and the markets’ operators typically optimize their supply bids so that if their resources can provide more than one of energy, capacity and/or ancillary services at the same time, the services they end up providing represent the most cost-effective combination.

(For more detail on how markets work, look here and here. PJM and other RTOs also have good training available on their specific markets.)

What’s the role of DERs in wholesale markets?

Traditionally, the wholesale market suppliers were fossil fuel and nuclear power plants. As the amount of wind and solar power has increased on the grid and technology has spurred DERs like energy efficiency and demand response, market rules have evolved to allow participation by these usually clean resources—more accurately, in some of the markets, some of the time, and for some of the resources. Utility-scale wind and solar power owners can bid their resources into wholesale energy markets and to a limited degree, capacity markets. Similarly, owners of energy storage (like batteries) are in theory able to bid into some energy, capacity and certain ancillary service and capacity markets. 

But in practice, the rules that regulate market participation have not caught up with the reality of our evolving resource mix. Some market rules simply do not address the possibility of DER participation. In these cases, suppliers of DERs are at best left to fit their round pegs into square holes in terms of qualifying their resources to compete. At worst, they are simply barred from market participation. For example, until recently all DERs that participated in NYISO’s markets had to qualify as demand response.

In other cases, determinations about the resource characteristics that markets should value are centered on an outdated view of our power generation fleet and how to achieve a cost-effective and reliable resource mix. For example, PJM, the system operator for the region that covers 13 Mid-Atlantic States and the District of Columbia, operates day-ahead and real-time energy and ancillary service markets, as well as a full three-year forward capacity market. As energy market prices continue to drop, mostly because of cheap natural gas, PJM is concerned that existing generators will not recover sufficient revenues to stay in the market. PJM recently changed its capacity market rules to allow only resources that will be available to provide power at any and all times—effectively, fossil-fueled and nuclear power plants – to qualify for participation.

Ostensibly, variable resources like wind and solar power could bid into the capacity market with other resources that collectively satisfy the universal availability requirement, but too many barriers exist to allow this to work in practice. (We are challenging these rules in court). The vast majority of zero-fuel cost and zero-carbon resources like utility-scale wind and solar power, and DERs like energy efficiency, demand response and rooftop solar, which can provide some capacity but not all day, every day, cannot participate in PJM’s modified capacity market. Consequently, consumers will pay more for fossil fuel and nuclear plants to provide unnecessary duplicative capacity, while missing out on the full value of the ignored resources.

Reforming these existing markets is critical, but will only take us so far down the path toward integrating a future resource mix that’s dominated by renewable energy. We are seeing signs of acknowledgment of the changing resource mix reality by the grid operators in the Mid-Atlantic (PJM), New England (ISO-NE) and New York (NYISO), which are each proposing ways to address public policy impacts (largely, increasing amounts of renewables) on their wholesale markets. The reality that the electric grid willbe comprised of majority renewable power in the not-so-distant future and the potential that technology has unleashed in the DER space requires serious rethinking about the services that wholesale markets provide.

In light of significant penetrations of wind and solar power, the grid operators in the Midwest (MISO) and California (CAISO) have led the way in developing market-based products that provide some sort of flexibility service necessary to complement wind and solar power production by addressing the variable characteristics of these resources. Many DERs have the technical capabilities to provide these services (and the market rules allow their participation). More work remains to be done in considering products that value the flexibility and resiliency attributes available from DERs’ unique traits.

What policy changes are needed?

DER participation in existing and future wholesale markets will grow exponentially with these policy changes:

1. The agency that oversees interstate transmission—the Federal Energy Regulatory Commission (FERC)—should review existing wholesale energy, capacity and ancillary services markets and the extent to which DERs face barriers to participation in those markets even though they are technically capable of providing services. (The agency recently issued a survey and collected comments that examine these issues for energy storage, specifically—a good model.) FERC should propose reforms to remove identified barriers.

2. FERC should consider whether the existing suite of required ancillary services remain the right or complete set of grid services necessary to facilitate a clean, affordable, and reliable electric system dominated by variable energy resources like wind and solar power. FERC should consider proposing reforms that either require the provision of new market-based grid services or at least consideration of whether certain new services are necessary on a region-by-region basis.

3. States should reconsider laws and regulations that ban the aggregation of DERs for purposes of participating in wholesale markets (or otherwise). These laws protect utility interests at the cost of consumers. Reform can balance the needs of utilities while providing opportunities for the cost and environmental efficiencies related to DER participation in wholesale markets.

Two additional points are worth noting. First, these recommendations are made in the context of ongoing tensions between state policy choices and wholesale capacity markets more generally—as most notably evidenced in the recent U.S. Supreme Court decision in Hughes v. Talen Energy Marketing (our take here and here, and if you want to get really specific, read this). Although these tensions have been limited mostly to big wind farms and natural gas plants and not DERs, current challenges to market design in the Mid-Atlantic  and New York show that potential implications of policy-market conflicts do not spare DERs. Although a topic for another day, our recommendations   also must be considered in the context of these emerging and important jurisdictional questions.

Second, policy changes alone will be insufficient. Operational awareness and coordination between wholesale market operators and distribution system market operators and utilities will be critical for DERs to participate in either or both of wholesale and distribution level markets and programs. RTOs and ISOs should engage directly with utilities and state utility commissions to identify and begin to address these issues (an excellent distillation of these issues here). The U.S. Department of Energy could facilitate engagement as part of its grid modernization effort, through a FERC working group with the National Association of Regulatory Utility Commissioners and the North American Electric Reliability Corporation or by other means.

The content & opinions in this article are the author’s and do not necessarily represent the views of AltEnergyMag

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