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 would have to be updated, Baker said. FERC is proposing that grid operators use 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 would then have a slightly different set of parameters from other resources so the PJM market engine would need 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.
The other conflict would be if the wholesale system needed it to provide services at the wholesale level, and there was also a distribution system opportunity for retail services.
“These revenue-related issues about how to recover costs for more than one service would have to be reconciled,” Baker said. “FERC has precedent for ruling these kinds of multiple uses are not allowed but it could rule to allow them.”
The NOPR may or may not require system operators to optimize returns from storage services, he said. “If system operators must do it, they will need a new type of optimization engine or algorithm that does not currently exist. That will have a direct impact on implementation of the order that comes out of this process.”
Storage progress in other ISOs
While PJM and CAISO are furthest along, other system operators are already taking steps to address NOPR’s requirements, according to Jason Burwen, policy and advocacy director at the Energy Storage Association (ESA), an industry trade group.
If broad agreements come out of the FERC process, storage may play a significant role in wholesale markets by the end of 2019, he added. “But implementation will be the difficult part.”
PJM has encountered complications that have slowed progress, but its leadership created an opportunity for storage in its frequency regulation market that was an important breakthrough, Burwen noted. That is one example of how “the qualification criteria for storage to participate will be a system operator to system operator decision."
While different storage projects can serve the diverse needs of system operators, compensation for all services is not available in any of the markets, Burwen noted, creating uncertainty.
“Different storage devices have different performance capabilities which make them more or less right to provide different services and participate in different markets,” he said, “but compensation for all services is not yet available in any market.
The lack of longer term contracts for the storage projects adds to the uncertainty of the energy storage market and makes projects harder to finance, he added. That’s where NOPR can come in and create new opportunities for storage in markets where it is harder to break in.
Take the New York ISO, he said. The grid operator is aligning its planning with New York’s Reforming the Energy Vision initiative under the DER roadmap. Outside of the REV, NYISO is planning incremental changes to market access for energy storage.
It may be the furthest along on bidding parameters, has introduced state of charge parameters, and a forthcoming piece will optimize intra-hour participation for storage resources, Burwen added.
And the Midcontinent ISO, known for its more deliberate planning process, has a wide-ranging effort to integrate storage offers, focusing on allowing fast-response energy storage to enter its frequency regulation market.
ISO-New England recently released a guide that describes the characteristics and requirements of the markets it operates that now allow for storage. But the guide is not the same as a comprehensive tariff, so the FERC NOPR will be important, Burwen said.
Compared to the others, the Southwest Power Pool has farthest to go, Burwen said.
“New York, New England, and MISO all have to deal with the minimum size requirement, though New York’s effort to align with the REV may put it a little ahead of the others,” he added. “SPP has the farthest to go on all the requirements but is working on them.”
The capacity controversy
In each market, storage can provide a host of grid services, from spinning reserves to voltage control and resiliency. But providing electric capacity is “an especially attractive play for storage,” PJM’s Baker said.
On most systems, peak power demand is relatively short in duration, so the expensive thermal peaker plants that serve it go underutilized.
With its increasing affordability, storage may be able to cost-effectively displace them with the FERC NOPR rules in place.
In ISO-NE, the compensation for capacity in the 2019-2020 auction period is about $84/kW-year, said Harjeet Johal, a senior manager with international energy consultant ICF and co-author of a recent white paper on storage capacity values.
In round numbers, the cost of lithium-ion battery storage with a four-hour duration can be about $300/kW-year, he said. “The $84 is about 30% of the break-even economics for storage, just from capacity, if it is compensated the same as other capacity resources.”
But storage offers a stack of services, and a single value stream is unlikely to justify its cost, he said.
“Yet a significant portion of break-even can come from capacity, and with the cost of storage projected to drop as much as 25% to 30% in the next five years, capacity compensation can continue to be an important factor in battery economics.”
A controversial proposal in the NOPR would limit storage duration to four hours, potentially hurting its ability to rush into capacity markets, Baker and other said. But the ICF paper foresees a real opportunity for storage in capacity markets if that rule is abridged.
Most markets attribute value to storage if it meets a basic threshold of capacity that matches the four hour peak demand period, ICF’s Johal said. “Other resources, like renewables, get compensated for whatever part of the peak demand period they supply capacity, but the rule allows battery storage compensation only if it meets the entire peak.”
To solve that problem, the paper proposed a graduating scale that would value storage for every block of capacity it delivers. “There is value for every block of capacity the battery storage delivers and it should be compensated,” Johal said.
Rather than switching from full compensation for delivering four hours of capacity to none for a two-hour duration — as most markets presently do — the capacity value should vary according to what part of peak demand it addresses, he said.
“The first one-hour block of storage is the maximum value because it addresses the maximum system risk from spiking demand. The second block captures a reduced risk and the incremental value of each block of capacity continues to decrease,” he explained.
Each system can craft its own value framework based its load profile, the power quality and the underlying resource mix, Johal added.
ESA’s Burwen pointed out that when generation is used for capacity, more than half the time it is used for less than two hours relative to nameplate capacity.
“There is capacity value in assets with durations of one, two, or three hours and they can be used in a way that reduces the system’s capacity costs,” he said.
But there is some pushback to that line of thinking.
CAISO’s Klauer said storage and DERs must be regarded differently than generation because there is less certainty about their availability and managing them requires extra attention.
“The right amount of capacity for the California market has been defined as four hours of continuous output,” he insisted. “It also has to be available three days in a row and for 24 hours per month.”
Baker essentially agreed. “It depends on each market’s capacity construct,” he said. “For PJM, capacity value can be earned in any hour in which there is a need for it so the graduating scale would not work. It is up to the resource owner to bid according to that resource’s availability.”
Renewables, Johal said, faced the same dilemma until a framework was developed to support their participation in capacity markets. A similar framework can be developed for storage, he said
The road ahead
Ultimately, the rules proposed in the NOPR will need to evolve to serve each system, CAISO’s Klauer said. “Ultimately it is about what preserves the system’s reliability.”
Recent success for storage in PJM’s frequency regulation market shows “that rules allowing participation and attributing value to storage will drive its development,” Baker said.
How the markets are eventually designed to accommodate storage’s many services will determine the success of the resource, Burwen said. The NOPR a big deal, but for storage to recognize its full potential, it must have markets for all its services.