FERC Steps Up Efforts to Support Integration of Energy Storage Technologies Into Wholesale Power Markets
As momentum builds for wide-scale development and deployment of electric energy storage technologies, the Federal Energy Regulatory Commission (FERC) has been taking a fresh look at how it can facilitate the integration of energy storage resources into wholesale electric markets. Advancements in energy storage technology and the ability of these resources to improve grid reliability and efficiency have been the primary drivers of FERC’s initiatives. Until recently, the only technology widely used for energy storage was pumped storage hydro, which can only be economically developed where there is viable geography, topology and a significant discrepancy between on-peak and off-peak power costs. In 2014, pumped hydroelectric resources represented approximately 98 percent of the over 22 gigawatts of installed electric storage capacity in the U.S. However, lithium-ion electric battery resources have recently taken a larger role in ancillary services markets, and the development of other emerging storage technologies continues to advance. The Energy Storage Association reports that the energy storage market is set to develop rapidly, with an expected six gigawatts of storage capacity to be added in 2017 and over 40 gigawatts of installed storage capacity by 2022. While conventional pumped storage hydroelectric projects will continue, on a gigawatt basis, to comprise the lion’s share of U.S. storage capacity for the foreseeable future, lithium-ion batteries and flywheel technologies have steadily increased their respective market shares since 2010, and these technologies are poised for continued expansion.
Based on its long history of licensing pumped storage projects, FERC is familiar with the capabilities of electric energy storage facilities to integrate with the power grid. However, as new technologies with more diverse operating characteristics have been deployed, FERC has grappled with how to treat storage projects – should they be classified as generation, transmission, load or all of the above? Historically, FERC addressed the interconnection and sale of electricity from pumped facilities and other storage technologies, including batteries, flywheels, and compressed air resources just as it would any other generating facility. However, energy storage devices can play many different roles. They can act like a generator, selling energy, capacity and ancillary services in wholesale electricity markets. They also can function as a transmission asset, correcting transmission voltage and frequency by absorbing or releasing electricity as needed. In addition, storage resources function as load centers when they charge from the grid to purchase energy for later discharge or to reduce system load by providing demand response services.
In many ways, advancements in energy storage technologies and their deployment have outpaced the development of wholesale electric market rules that recognize the unique abilities, limitations and needs of storage resources. In the absence of a clear federal policy, transmission-owning utilities and regional transmission organizations (RTOs) have developed disparate rules governing the participation of energy storage resources in wholesale electric markets. As one RTO executive recently put it, “[We’ve] had kind of fits and starts with [storage] … but as far as having a clear policy, well, that’s never happened.”
That may change very soon. The rulemaking and policy proceedings initiated by FERC in late 2016 and early 2017 could result in clear, standardized RTO policies relating to the participation of energy storage projects in wholesale electric power markets. There is, however, some uncertainty. FERC currently lacks a quorum of commissioners necessary to issue orders in the pending rulemaking and policy proceedings described below. In addition, the President has an opportunity to fill four out of the five FERC commissioner seats and to select a new FERC chairman, which he could do by the end of the year. So far, the President has made two nominations, and, despite speculation, it is unknown who the third and fourth candidates will be or who will serve as FERC chairman. All candidates will require confirmation by the Senate, which will take a few months. Once the new commissioners and chairman are in place, FERC could decide to abandon or shelve the rulemakings described below, but doing so would ignore the need for clear rules for a growing industry. Moreover, recent FERC orders have set precedent that, in effect, implements many of the proposals set forth in the pending rulemakings, thereby making it more difficult for FERC’s new leadership to completely change course.
I. Compensating Energy Storage Projects
Among the more complicated issues now before FERC is how best to compensate providers of energy storage services. Similar to its treatment of wholesale power sellers that demonstrate that they lack market power, FERC has granted authority to owners of storage projects to sell energy and ancillary electric services at “market-based rates,” i.e., at rates established either by independently run auctions or by agreement between the seller and buyer, without regard to cost-of-service or other traditional ratemaking methodologies. However, as discussed further below, wholesale market rules require further improvements to capture the full value of energy storage services and to accommodate their unique limitations. Unlike conventional generating technologies, which can generate as long as fuel or another energy input is available, storage projects have a finite runtime before they must recharge. For example, new utility-scale lithium-ion batteries can be designed to discharge energy for four hours or more, but older systems could discharge for a shorter time.
Finite runtimes and the need to constantly recharge their facilities have presented challenges to storage project owners seeking to participate in wholesale power markets. Many regional wholesale electric market rules, which were developed with conventional generation in mind, establish minimum runtimes for entities wishing to sell energy and capacity. Owners of storage devices that participate in these markets are susceptible to penalties if their projects are unable to provide energy throughout the entire commitment period. In addition, profits and revenues of storage owners selling at market-based rates will rise and fall with the market. If wholesale electric prices are too low, storage owners might not earn enough to cover their fixed and operating costs, including the costs of power for charging.
The uncertainty of market-based rate revenues in wholesale electric markets has led some storage owners to seek cost-based compensation in exchange for providing ancillary electric transmission services, namely absorbing and discharging power to maintain electric transmission reliability. An advantage of cost-based compensation is that it provides storage device owners with a consistent rate of return that, among other things, covers the capital costs of supplying and installing their storage resources and the estimated costs to purchase energy necessary to recharge the devices. Under a cost-based approach, to the extent that they exceed estimated costs, actual costs to purchase energy to recharge a storage device are not recovered without a fuel adjustment clause or similar provision that allows for a full pass-through of actual costs. In addition, FERC has signaled that it will grant incentivized transmission rates (i.e., cost-based rates that include an adder to further compensate the owner) to storage projects that improve reliability and reduce the cost of power delivered to end-use customers.
In 2008, the developer of a large (500 MW) pumped-hydroelectric project sought FERC approval to receive an incentivized rate of return under the California Independent System Operator’s (CAISO) transmission tariff. In support of its application, the pumped storage project developer committed to cede operational control of the facility to CAISO. FERC rejected the proposal, finding that it would be inappropriate for CAISO, which is intended to be an independent RTO, to have operational control over, and receive compensation from, the storage facility. FERC expressed concern that CAISO’s independence as an RTO would be compromised if CAISO were in a position where it would be submitting bids on behalf of the storage facility into the competitive wholesale electric markets that CAISO administered.
FERC reached a different conclusion in 2010, when it determined that a collection of sodium sulfur batteries, ranging in size from 10 to 50 MW, located at various sites along the CAISO transmission grid, were wholesale transmission facilities that qualified for incentivized rate treatment. In the 2010 case, the battery project owner agreed to forego any sales into CAISO’s wholesale electric markets. Instead, the owner committed that it would follow CAISO’s directions in a manner similar to the way in which high-voltage transmission lines are operated by investor-owned utilities under the direction of CAISO. As a result, CAISO would not be in a position where it would be charging or discharging the batteries, thereby maintaining its independence.
In November 2016, FERC convened a technical conference to explore whether storage devices should receive market- or cost-based compensation. Many trade groups and utilities advocated that storage devices should be eligible for both, depending on the services that they are providing at any given moment. FERC agreed. In January 2017, FERC issued a policy statement in which it clarified that electric storage resources can receive both cost- and market-based revenues for providing separate services. To qualify, owners of storage resources will need to (1) credit any market-based rate revenues to their cost-based ratepayers, (2) use market-based rate revenues to offset and reduce their cost-based rates, or (3) otherwise ensure no double recovery of costs to the detriment of electric ratepayers.
II. Interconnection of Energy Storage Projects
Until recently, energy storage developers seeking to interconnect their projects to the transmission grid were required to rely on procedures and agreements designed for generation facilities. In many cases, this approach has worked. This result is not surprising since, for example, pumped storage hydroelectric facilities generate power much in the same way as conventional hydroelectric facilities. As a result, when FERC adopted standardized utility interconnection procedures and agreements in 2003, it did not direct utilities or RTOs and utilities to include explicit provisions for energy storage devices. FERC has since recognized that differences between generation and storage technologies require different interconnection provisions.
In 2013, FERC held technical conferences and initiated a rulemaking proceeding to revise its pro forma “small generator” interconnection procedures and agreement, which apply to the interconnection of generating facilities that do not exceed 20 MW. In response to comments from energy storage groups, FERC proposed to include energy storage devices within the definition of generation facilities eligible for interconnection service. The move was not universally applauded. CAISO commented that the revision was unnecessary, stating that storage devices were already able to interconnect to the CAISO transmission system as small generating facilities. FERC agreed but ultimately adopted its proposal, explaining that explicitly including energy storage as a small generating facility would improve transparency with regard to how its small generator interconnection procedures and agreement should be implemented.
Not all storage developers embraced FERC’s clarification. In March 2016, the Midcontinent Independent System Operator Inc. (MISO), the RTO responsible for much of the Midwestern transmission grid, filed a disputed generator interconnection agreement for an approximately 20 MW battery storage facility to be added to two existing 30 MW gas turbine generators. Known as the Harding Street Battery Storage Project, it was the first transmission grid-scale lithium-ion battery storage array located in the MISO footprint. Indianapolis Power & Light Company (IPL), which owns the Harding Street facility, protested the filing, in part, because it referred to the Harding Street battery storage facility as a “generating facility” – IPL advocated the use of a new term for storage facilities. Although the definitional debate may seem of minor consequence, it was part of a larger effort to distinguish the rights and responsibilities of owners of storage projects from those of generation project owners. IPL also sought more substantive changes to reflect the distinct operating characteristics of its storage facility and to distinguish it from a generating facility. Ultimately, however, FERC accepted the agreement based, in part, on the fact that MISO explicitly expanded the definition of “generating facility” to include storage facilities.
In its final meeting of 2016, FERC proposed similar changes to its standard interconnection rules and agreement for “large generators” with a capacity of more than 20 MW. Consistent with its 2013 revisions to the pro forma small generator interconnection procedures and agreement, FERC proposed to revise the definition of “Generating Facility” in the pro forma large generator interconnection procedures and agreement to include electric storage resources. In addition, FERC proposed to require utilities and RTOs to evaluate their methods for modeling electric storage resources for interconnection studies and to report to FERC as to why and how their existing practices are or are not sufficient.