by Jeff St. John
July 10, 2020

This is the fourth installment in our five-part series on the major trends in enabling grid-edge distributed energy resources to play a fully integrated role in the power grid system. This installment focuses on the transmission-distribution grid interface, and examines how decades-old models for distribution grid-connected assets to participate in wholesale energy markets are being transformed to allow the full array of modern DER capabilities to bear — and the challenges that remain. 

Click here to read our previous entries on the challenges of integrating distributed energy resources on the grid; smart inverters as grid control agents; and breaking new ground for non-wires alternatives.


Back in 2018, the Federal Energy Regulatory Commission issued Order 841, a groundbreaking effort to open interstate transmission grid markets to energy storage systems. Part of FERC’s mandate to the country’s regional transmission organizations (RTOs) and independent system operators (ISOs) included finding ways to allow aggregated, distribution-grid-connected storage — and eventually, a whole panoply of DERs — to be included in their new market structures.

But the path to DER-wholesale market integration has been complicated. Soon after issuing Order 841, FERC broke off the DER-specific portions of it into a separate proceeding, RM18-9, which still hasn’t officially launched. Meanwhile, ISO and RTO compliance with Order 841 has been hounded by the technical and legal challenges of finding ways for batteries to compete against power plants on something approximating a level playing field.

Aggregating multiple types of DERs with very different operating characteristics further confuses the situation. Some DER capabilities, such as demand response for grid capacity, have already been participating in wholesale markets for decades, albeit under rules and market constructs that vary from ISO to ISO, state to state, and utility to utility. Others, like fast-responding grid regulation or spinning reserves from solar smart inverters, aggregated batteries or flexible loads, remain in pilot project stage. 

Still, Order 841-based market opportunities are starting to lead to action. ISO New England’s rules for battery aggregations have opened up markets for storage players such as Sunrun and Engie. FERC’s recent approval of New York grid operator NYISO’s “dual participation” system paves the way for batteries to compete in both retail and wholesale markets later this year. And California has a growing roster of DERs playing wholesale market roles, if not in quite the way that state grid operator CAISO may have expected.

“We don’t necessarily have meaningful volume now in the markets,” said Elta Kolo, grid edge research content lead at Wood Mackenzie. Getting the market rules right for Order 841 compliance “will set the foundation for integrating energy storage” and provide guidance for how to extend those rules to DERs at large. But, she said, “We’re still in the implementation phase.” 

Technical challenges of coordinating cross-grid operations 

Significant technical challenges lie in the way of enlisting behind-the-meter and distribution-connected assets, said Ajit Renjit, senior project manager at the Electric Power Research Institute (EPRI). “ISOs now have to manage not only a 500-megawatt coal plant but [also] thousands of residential DERs,” which comes with some big problems. 

First of all, “the electrons that are produced by the DER have to move through the distribution infrastructure,” he said. That requires a new level of coordination between utilities and wholesale market operators to ensure that distribution grids aren’t destabilized by what DERs are doing in response to ISO signals, or conversely, that a failure in distribution capacity isn’t preventing them from meeting the transmission grid’s needs. 

Secondly, to prove that wholesale market participants are responding to dispatch signals and providing the services they’ve promised, “ISOs have always metered and monitored the systems,” he said. But “the communications that needs to be deployed [are] significant, and the cost is high.” Alternate methods to the direct communications links between ISOs and generators need to be developed. 

EPRI has launched a U.S. Energy Department-funded research project called ENGAGE, aimed at defining and developing the complete suite of technologies and integrations needed to solve these problems. Those include devising communications protocols, control schemes, and measurement and verification systems that can operate at both the individual DER and aggregator level. 

A few pilot projects are testing a full suite of technical solutions to these problems. One such pilot — involving New York utility Con Edison, NYISO, U.K.-based technology provider Smarter Grid Solutions and Shell New Energies-owned microgrid developer GI Energy — is seeking to determine whether privately owned batteries can support utility grid needs and earn money in wholesale markets at other times to bolster their cost-effectiveness. 

So far, the 1-megawatt batteries connected to the distribution grid have shown they’re capable of responding to utility and NYISO dispatches as planned. “NYISO tested several energy services, dual participation and a communications option for the DER program expected to go live late next year,” Con Ed spokesperson Allan Drury said in an email. 

Smarter Grid Solutions operates the system that coordinates Con Ed and NYISO’s interaction with the batteries. That includes taking day-ahead schedules for when each party has access to the battery and receiving NYISO’s commands every 6 seconds, said Stuart McMahon, SGS senior smart grid engineer. 

This real-time connection allows batteries to ply their instantaneous response capabilities into multiple grid services markets, including more lucrative frequency regulation and 30-minute and 10-minute spinning reserves, Drury said. At the same time, “if there’s an emergency on the grid, Con Edison has the power to override that NYISO 6-second basepoint and issue their own discharge command" using the same SCADA interface its distribution grid operators use. 

SGS also developed a “novel approach” for replacing the point-to-point cyber-secure communications NYISO uses to send commands to market participants like power plants with a “multipoint communications system,” which allows dispatches to be shared between multiple assets at once, he said. 

“That’s important for a distributed energy resource management system,” or DERMS — a core concept for allowing grid operators to communicate with DER aggregators that can “communicate to multiple devices, with different manufacturers and different protocols.” Many utility DERMS efforts are aimed not only at managing DERs on their own grids but also allowing them to serve wholesale market needs.

Projects like these are proving that the technology to integrate DERs into wholesale markets can work. But whether or not they’re allowed to — and whether or not the benefits of doing so outweigh the costs — may be more important questions. 

Getting the economics right (or wrong)

“Beyond the technology challenge, there is a regulatory challenge as well,” said EPRI's Renjit. A big one is the issue of the “double-counting” rules that prohibit DERs from simultaneously serving retail and wholesale markets. Beyond the potential for DERs to be asked to perform mutually exclusive tasks, serving both retail and wholesale masters could allow DERs to leverage retail program revenue to undercut wholesale market competitors. 

Another barrier is picking the communications and metering options that can balance the goals of keeping costs down and providing the appropriate level of certainty to wholesale market operators as to whether DERs are actually providing the services they’re being paid for.

“For a residential inverter, why would I pay for a revenue-grade meter, or for an aggregator to provide the telemetry on a two-second scale?” Renjit asked. Devising methods to accurately “baseline” energy consumption for resources that get paid to reduce energy use, such as demand response, opens up further measurement complications.

California's grid operator, CAISO, is an illustration of challenges that can arise if the costs of participation in DER-wholesale market integration are not managed properly.

Since 2017, CAISO has allowed aggregated DERs into its markets, including batteries, solar systems and demand response, under its Distributed Energy Resources Provider (DERP) tariff.  But to date, CAISO’s DERP tariff provisions haven’t enlisted any active participants. That’s most likely because the way it’s structured has made it far less attractive than the other opportunities for DER aggregations in California, such as the Demand Response Auction Mechanism pilot program or utility-run Proxy Demand Resource programs, according to pro-DER group Advanced Energy Economy.

In a 2019 paper, AEE noted that “DERP’s 24/7 settlement requirement precludes potential participants from taking advantage of opportunities outside the wholesale markets,” a problem that NYISO’s dual-participation model has avoided. Even worse, “under DERP, energy storage systems must pay twice for the energy they use to charge their systems, once at the retail rate and again at the wholesale rate. Furthermore, DERP requires the installation of detailed and expensive telemetry in each individual DER, undermining the financial case for aggregating hundreds or thousands of small assets into a portfolio.” 

Legal challenges: Past, present and future

FERC has delayed its efforts on broader DER integration until the ISOs and RTOs it regulates have come up with solutions to energy storage aggregation under Order 841 that could help provide workable solutions to quandaries like these.

Beyond managing technical issues, ISO and RTO implementation plans have had to pass muster with stakeholders including large-scale power plant operators, which have resisted previous incursions into wholesale markets by competing resources. A generator industry group’s challenge to FERC’s authority to regulate demand response went all the way to the U.S. Supreme Court before being decided in FERC’s favor in 2016. 

To date, the biggest challenge to Order 841 has come not from generators, however, but from groups representing utilities and state regulators. Last year, these groups raised a court challenge to FERC’s decision to deny their request for rehearing the order on the grounds that it improperly extends federal authority over state energy policy. 

A three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit heard oral arguments on the case in May, and a decision is expected in the coming months. So far, energy storage and DER advocates are hopeful the court will uphold Order 841, given previous decisions such as the Supreme Court’s ruling on demand response. 

“FERC has jurisdiction to regulate the participation of distributed energy resources in the wholesale market,” Jeff Dennis, AEE’s managing director and general counsel, said in an interview. At the same time, Order 841 makes it clear that “states retain their full authority through interconnection agreements and other means to retain the reliability of the distribution system.” 

AEE is eagerly awaiting FERC action on the broader DER integration issues in RM18-9, Dennis said. “DERs are uniquely valuable in that they can provide services across both retail and wholesale markets. Making sure they can provide both, and not be forced to pick one or the other, is an important issue.”