The Federal Energy Regulatory Commission last week unanimously approved an order that could prove to be a landmark in the development of energy storage.
FERC’s order “opens the floodgates for storage participation” in wholesale power markets, Ravi Manghani, director of energy storage at GTM Research, said.
Order 841 directs operators of wholesale markets — Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) — to come up with market rules for energy storage to participate in the wholesale energy, capacity and ancillary services markets that recognize the physical and operational characteristics of the resource.
A level playing field
“The rules will codify mechanisms that will establish a level playing field that, ideally, is relatively comparable across regions,” Daniel Finn-Foley, senior energy storage analyst at GTM Research, told Utility Dive.
FERC specifies that those rules must:
- Ensure that a storage resource can provide all the services it is technically capable of providing,
- Ensure that an energy storage resource can be dispatched and can set market clearing prices as both a buyer and a seller,
- Account for the physical and operational characteristics of storage resources through bidding parameters or other means,
- Establish a minimum size for participation in RTO/ISO markets that does not exceed 100 kW, and
- Specify that the sale of electricity from the RTO/ISO markets to a storage resource that the resource resells must be at the wholesale locational marginal price.
FERC gave RTOs and ISOs nine months to file tariffs that comply with the order and another year to implement those tariff provisions.
Finn-Foley called the FERC rules “a starting point” for the development of energy storage projects in wholesale markets. “It is as if the industry has had one hand tied behind its back,” Finn-Foley said.
Growth through fiat
Much of the growth in energy storage to date has come about through regulatory fiat, such as California’s mandate to use storage to fill the capacity gap left by the Aliso Canyon methane leaks.
Aliso Canyon proved energy storage can provide capacity, Finn-Foley said, and with the right market design it could provide capacity services in other markets, as well. He cited research by GTM that shows energy storage will be competitive with new build gas-fired peakers in five to 10 years. But that can’t happen unless the right market mechanisms are in place, he noted.
“It will take guts from the industry to really dive in” to the wholesale markets, Finn-Foley said. One of the challenges, he noted, is that most investors like contracted revenue streams. It is easier to sign a contract when a project is backed by a state mandate, but Finn-Foley said a lot of projects in wholesale markets will not be contracted. Energy storage can already perform a lot of functions, including power price arbitrage, spinning reserves and capacity. “It is up to the industry to figure out how to weave all those together; we already have the fabric,” he said.
It is notable that the FERC order could allow storage to compete head-to-head against traditional resources such as peaking plants. “It is nice to see it come in as a market mechanism and not as a mandate,” Maria Robinson, director of wholesale markets at Advanced Energy Economy, a business advocacy group, told Utility Dive. “I would imagine this will allow energy storage companies to find new ways to compete,” she said. “Ultimately, it is all about scaling.”
Opening wholesale markets to energy storage could encourage a variety of utility-scale storage projects, which could in turn spur further price declines as development accelerates.
“We are pretty excited,” Kiran Kumaraswamy, market applications director at Fluence Energy, told Utility Dive. Fluence is an energy storage services company formed earlier this year by AES and Siemens. FERC’s order will bring more megawatts into the market, but the fact of the matter is that there was already a lot happening, he said.
States ahead of FERC
California and New York, which both have single state ISOs, have either implemented rules for energy storage or are in the process of doing so, and states like Massachusetts and Oregon have issued energy storage targets.
In part, those states are ahead of FERC because the rulemaking for Order 841 was issued in November 2016 and then the process was delayed because FERC lacked a quorum until August 2017. “FERC’s order puts the ball back in the RTOs’ court again,” Kumaraswamy said.
“Calif was the role model,” Kumaraswamy told Utility Dive. “They have a great model already, and it was widely discussed in the FERC process.” Where the work needs to be done, he said, is in the Midcontinent ISO and the Southwest Power Pool.
“A lot will depend on the implementation by RTOs, Kumaraswamy said. “That is where the rubber meets the road. We hope to stay closely engaged in the process.”
California, in fact, just took the next step in the evolution of its energy storage market by implementing rules to govern multi-use applications, also known as revenue stacking.
Kumaraswamy said those rules could benefit the 100 MW, 400 MWh storage project Fluence announced earlier this year in Long Beach, Calif. The project could provide flexible peaking, as well as some ancillary services, he said.
Kumaraswamy said energy storage is moving on to “that next dimension” where it can replace gas peakers. He said that and the potential to combine storage with solar power are two of the main opportunities Fluence is pursuing.
In a larger context, the interaction of wholesale rules, which fall under FERC’s federal jurisdiction, and state rules could be the key to developing the full value of energy storage.
“I think barriers at the state and retail level — such as batteries on the distribution system or behind customer meters — face unique barriers that are distinct and in addition to the barriers at the wholesale level now addressed by the FERC order,” Johannes Pfeifenberger, a principal at The Brattle Group, told Utility Dive.
Pfeifenberger cited a paper Brattle did on energy storage in the Electric Reliability Council of Texas (ERCOT) market that showed the wholesale market accounted for about 60% of the benefits with the deferral of transmission and distribution costs and avoided distribution outages accounting for the rest. The transmission aspects are under both federal and state jurisdiction.
The study found that using wholesale market benefits alone, only about 1,000 MW (3,000 MWh) of storage in ERCOT would be cost effective. But if distribution benefits are included, the market could support as much as 5,000 MW (15,000 MWh) of energy storage. The reason, Pfeifenberger said, is that energy storage projects could quickly saturate the market for ancillary services such as frequency regulation. The key is being able to access different value streams, he told Utility Dive.
A similar effect occurs in the capacity market, Pfeifenberger said. In the ERCOT report, Brattle found that 1,000 MW of storage has a capacity value of about 1,000 MW, but 5,000 MW of storage has a capacity value of only 3,100 MW and 8,000 MW of storage only has a capacity value of about 4,000 MW. The value of storage starts to decline after it begins to reach the limits of its duration, Pfeifenberger said. The same decline does not happen for generating plants that can generally be dispatched for as long as they are needed.
He said that underscores the benefits of being able to get revenues from both the wholesale and the distribution markets. “What California has done works hand in glove with what FERC has done,” Pfeifenberger said.
California’s ISO, like New York State’s, is now in the midst of reviewing its rules for energy storage. But even in a storage friendly environment like California, it is useful to have FERC pushing the issue. “Wholesale markets are designed with stakeholder input, and that can get in the way of new technologies,” Pfeifenberger said. “Owners of incumbent resource don’t necessarily invite new technologies to compete.”