The Federal Energy Regulatory Commission's Order 841 aims to reduce barriers to the deployment of energy storage in wholesale power markets.

It lays the foundation for the energy storage market to grow by as much as five fold to 50 GW over the next decade. But at least half of that potential growth would depend on the development of state, not federal, policies to support energy storage, according to a new report by The Brattle Group.

FERC's order has been hailed as a landmark in the development of energy storage markets. It directs the operators of wholesale power markets — regional transmission organizations (RTOs) and independent system operators (ISOs) — to remove barriers that could keep storage resources from realizing their full value.

The Brattle report and the FERC order also coincide with the release of the 2017 U.S. Energy Storage Monitor by GTM Research and the Energy Storage Association, which found 100 MWh of grid connected storage deployed in fourth-quarter 2017. GTM expects the U.S. energy storage market will almost double in 2018 alone, with more than 1,000 MWh of storage deployed this year.

And the groundwork laid by FERC Order 841 “will further encourage energy storage deployment throughout 2018 and beyond as the industry builds toward a goal of realizing 35 GW by 2025,” Energy Storage Association CEO Kelly Speakes-Backman said in a statement.

According to the Brattle report, at least half of the 50 GW energy storage market it forecasts unfolding over the next decade could come from opening up the wholesale power markets to energy storage. But the greater part of the potential growth has to come from energy storage applications that serve the transmission and distribution sectors, which are largely beyond FERC’s jurisdiction.

A necessary and important step

“The FERC order is a necessary and important step, but it is a first step,” Judy Chang, principal and director at The Brattle Group, told Utility Dive. To really capture the opportunity up and down the value stream, “we really do need states to look at how they integrate storage on the distribution system,” she said.

Order 841 directs RTOs and ISOs to take steps in that direction by requiring that market operators ensure that participating resources are eligible to provide all the capacity, energy and ancillary service they are capable of providing and executing those transactions at locational marginal prices.

Under the FERC order, RTOs and ISOs must also draw up rules that recognize the physical and operational characteristics of storage, establish a minimum size requirement for energy storage that does not exceed 100 kW, and allow storage to de-rate capacity to meet minimum run-time requirements.

In addition to directing grid operators to remove barriers to energy storage, Order 841 gives RTOs and ISOs the flexibility to adapt rules to meet their particular needs and requirements. For instance, grid operations can set their minimum run-time requirements for storage, establish bidding requirements for storage, set the rules for managing the state of charge of storage devices, and determine if storage can sell ancillary services without participating in the energy market.

At a recent storage summit in London, Nancy Bowler, a FERC branch chief, said the order is technology agnostic and defines storage as a resource capable of receiving energy from the grid and storing it to be injected back into the grid later. Those resources, she said, could be on the transmission system, that is, the wholesale market, but they could also be on the distribution system or behind-the-meter (BTM).

But Order 841 does not force grid operators to change technical requirements or compensation mechanisms for existing products, introduce new products, or exempt energy storage resources from performance requirements.

As the Brattle report notes, Order 841 also does not address state or retail level challenges or reduce barriers that would allow for energy storage to capture distribution level or customer benefits. That underscores the important role state participation will play in the development of energy storage.

“Order 841 will have a significant effect, but the greater and wider effect will come from state policies,” Chang said.

State policy initiatives

About half a dozen states have already taken steps to incorporate energy storage into their energy sectors. California has set a mandate that calls for the state’s utilities to install 1,325 MW of storage by 2020. Massachusetts has a 200 MWh by 2020 goal. Oregon has a 5 MW by 2020 goal per utility. New York is working on an energy storage target even as the state’s governor has already proposed a 1,500 MW by 2030 target. And Arizona and Nevada have both passed legislation that calls for the states’ regulators to investigate energy storage targets.

And, as Brattle notes, even more states, including Colorado, Illinois, Indiana, Minnesota, Missouri, New Mexico, Ohio and Vermont have active proceedings that involve energy storage policies.

Many states are already redesigning retail rates to address the unintended consequences of rooftop solar incentives, such as net metering, by adding demand charges or time-of-use rates. Avoidance of demand charges, in fact, could be one of the primary business cases for BTM storage for commercial and industrial customers in the U.S., according to the Brattle report. That correlation has already been seen in countries like Australia, Spain and the U.K. that have removed feed-in tariffs for rooftop solar and seen accelerated development of BTM solar-plus-storage installations.

But, as Brattle's Chang points out, incentives have to be very carefully considered and implemented. If BTM storage is being used to reduce peak demand to avoid or reduce demand charges or to mollify the effect of time-of-use rates, that can be good for customers, but not necessarily contribute a lot to the system, she said.

The rooftop solar-driven demand charges stem from state regulator concerns that the loss of volumetric payments from rooftop solar customers is making it difficult to cover the costs of operating the grid. BTM storage can be used to avoid or diminish such demand charges, but if the incentives are not properly designed, they can perpetuate the problem.

According to Chang, “we actually are seeing this in Ontario,” which has a very large demand-based global adjustment charge designed to make up costs not recovered through the wholesale market charges. “If one customer does not pay for it, someone else will,” she said.

Valuing incentives

“You need some standards or best practices on how to value these incentives so policymakers can think about benefits, not just to the customer, but to the system as a whole,” Chang said. “These nitty gritty details really matter.”

Those details will be important. Order 841 is designed to open wholesale markets to energy storage and to optimize the value of storage by allowing storage devices to capture multiple revenue streams, for instance energy payments as well as payments for ancillary services. But Brattle says wider access to wholesale markets alone would not be enough to reach the 50 GW mark its report lays out.

Brattle conducted simulations of the Electric Reliability Council of Texas market that show the capacity value of storage declines with market penetration. This can create an advantage for first movers and has already been seen in the PJM Interconnection, which had to cap the amount of energy storage it could absorb for its fast response frequency response market.

FERC Order 841 is going to “kick start the market, and it will unlock quite a bit of opportunities,” Chang said. “But we are also saying it is important for states to consider these issues more carefully. They have a big role to play.”