A silver bullet? Inside FERC’s landmark energy storage rulemaking
Energy storage is having an identity crisis in wholesale markets, and federal regulators are trying to fix it.
The question is simple: how do you define energy storage? For system operators, the answer is varied since storage can be categorized as generation, load or both.
To solve the conundrum, the Federal Energy Regulatory Commission opened a rulemaking for the nation’s six grid operators in order to make a place for energy storage in the markets.
As storage becomes cost-effective it can provide a litany of grid services and help alleviate concerns over the intermittency of renewable energy.
With that in mind, FERC opened a proceeding with a Notice of Proposed Rulemaking that will amend its regulations to “to remove barriers to the participation of electric storage resources and distributed energy resource (DER) aggregations in the capacity, energy, and ancillary service markets.”
Wholesale electric markets were not designed to consider energy storage, but the FERC proceeding “might solve that problem,” Shayle Kann, senior vice president at GTM Research said at at a recent storage summit.
“The rules may not create the economic case,” he said. “But the potential is there to open the markets.”
The new tariffs must accomplish two things, according to the NOPR.
First, they must establish market rules that recognize “the physical and operational characteristics of electric storage resources” and allow them to participate in the wholesale electricity markets.
Second, they must define what a DER aggregator is as a wholesale electricity market participant and establish rules for each aggregator to participate based on “the physical and operational characteristics” of its DER aggregation.
In the NOPR, distributed energy resources are defined as “source or sink of power that is located on the distribution system, any subsystem thereof, or behind a customer meter.” Those include storage resources, distributed generation and electric vehicles.
That definition is comprehensive, as is the rulemaking, and stakeholders across the board welcomed FERC’s long-term goal of integrating DERs and storage. While some markets are more advanced, others have foundational work to be done on integrating storage into their market operations.
The NOPR is expected to help both, insiders said, but leaves some important questions open about how energy storage can provide capacity, and will likely need to be tailored to meet regional grid needs.
PJM’s take on NOPR
FERC directed the six U.S. regional system operators to draft reports on their progress with storage rules and DER aggregators in the respective marketplaces.
System officials applauded the holistic approach FERC is taking with the NOPR, saying that it was “step forward” in a process about getting past “the piecemeal modifications of the last five years to a uniform holistic participation model,” PJM Senior Analyst Scott Baker told Utility Dive.
In PJM’s case, the grid operator already worked through many of the comments from FERC on their submissions of participation models and requirements, bidding parameters and minimum size requirements for DERS.
For the most part, PJM’s rules on storage eligibility for its capacity, energy and ancillary service markets are in place, except for a minor language change.
“Everyone agrees inverters are synchronized to the grid and inverter-based resources, including storage, can provide synchronized reserves. This is simply cleaning up the language,” Baker said.
But PJM’s bidding parameters will require more work because its dispatch parameters have to be updated, Barker said. For now, the grid operator uses parameters such as minimum charge rate, maximum charge rate, state of charge, and energy duration when dispatching the resource.
“If the storage bid is for a maximum duration of two hours, we wouldn’t clear it for a need for three hours,” Baker said. “Storage has a slightly different set of parameters from other resources so the PJM market engine has to be updated. It will take time but it is doable.”
PJM will also be working to refine rules on compensation that ensure storage in wholesale markets are delivered wholesale rates for power delivered. But the size of a device, set forth by the NOPR, could cause issues among system operators, Baker said. PJM is well-versed in handling storage resources as small as 100 kW, which the NOPR has required. But systems unfamiliar with demand response or DER could “see strain on their interconnection and market clearing procedures.
How CAISO plans to tackle the NOPR
California’s aggressive emissions reduction policies, renewables mandates storage mandate forced the state’s grid operator to move faster than others, said Peter Klauer, smart grid manager at the California Independent System Operator (CAISO).
For CAISO, the NOPR embodies efforts over the last several years to resolve oversupply of renewables and ramping issues sparked by the state’s goal to hit 50% renewables by 2030, he added.
That makes the challenges presented by the NOPR different for California. The state is already meeting its system needs through the Western Energy Imbalance Market as well as storage, Klauer said.
“My role is to make sure storage has equal footing and a pathway to market participation and can compete side-by-side with other generation in our markets,” Klauer said. With more than 5,000 MW of energy storage in its connection queue, the operator already laid out bidding parameters for the four storage resources in utility pilot programs.
While bidding parameters are not a problem, the challenge of managing a storage device as as small as 100 kW alarms Klauer.
“The 100 kW minimum size is a real challenge for a system operator because it is so much smaller than what we typically work with,” Klauer said. “It is a rounding error in our other system operations … Scalability is a big factor for a wholesale market and it will be more important now that FERC has approved our plan for bringing DER aggregations in.”
Another CAISO quibble with the NOPR guidelines comes from state-of-charge requirements. The operator’s experience in working with different types of storage gives Klauer reason to insist that FERC provide leeway in rules for maintaining a device’s state of charge.
“[CAISO] has two regulation products, a regulation up and a regulation down,” he said. “We don’t ensure symmetry or neutrality. Instead we have a provision of maintaining the resource at a 50% state of charge, whatever type of storage it is.”
Because CAISO is already dealing with storage resources on its system, it has rules in place that guarantee the energy those devices consume and deliver is bought and sold at the wholesale price, Klauer said.
Because CAISO is already dealing with storage resources on its system, it has rules in place that guarantee the energy from those storage devices is bought and sold at the wholesale price, Klauer said. The hurdle there will from electric vehicle participation.
“The challenge will be when energy is for or from an EV battery or aggregations of EVs,” he said. “When it is sold back, it is a wholesale transaction, but when it is used by the vehicle, it is retail consumption. And the charge and discharge may take place days apart.”
Coordinating between system operators, storage providers, and the distribution utilities is another challenge, Klauer said. The storage’s multiple stacked applications raise questions about the value streams that come from the wholesale markets and values from the distribution system level.
Multiple value streams require rules to avoid two kinds of market complications, he said. One is if the system operator wants to use the storage for transmission services while the storage owner commits it for generation services.