FERC Steps Up Efforts to Support Integration of Energy Storage Technologies Into Wholesale Power Markets

by Orrick, Herrington & Sutcliffe LLP
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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.[1] 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.[2] 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.”[3]

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.[4] 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.[5] 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.[6] 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.[7]

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.[8]

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.[9] 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.

FERC also proposed to allow generator owners with excess transmission capacity on their interconnection facilities to install energy storage devices on the same site as their existing generating facilities and to use the same interconnection facilities for the generation and storage facilities. FERC further proposed to allow interconnection customers to install more generating or storage capacity than the MW limit of their interconnection service. However, under both of these proposals, the simultaneous combined output of the generation and storage facilities may not exceed the interconnection service capacity previously granted to the generator owner, unless the generator owner submits a request to increase its interconnection service capacity and pays for any necessary upgrades to the transmission system. For example, the owner of a 50 MW solar project with 60 MW of interconnection service could install a 30 MW or larger storage facility, provided that the simultaneous combined output of the solar and storage facilities did not exceed 60 MW. Similarly, the owner of a 30 MW battery storage project might elect to obtain interconnection service for only 22 MW because, although the storage facility is technically capable of discharging as much as 30 MW over a 30-minute period, the owner might elect to reduce output to 22 MW per hour, which it could discharge over a longer time period and thereby satisfy minimum runtime requirements to sell energy and capacity into wholesale markets.

In response to its interconnection proposals, FERC received over 60 sets of public comments from utilities, RTOs and trade groups, including many renewable generation and energy storage groups. Those comments generally support FERC’s proposals, with suggested revisions to address differences among RTO interconnection procedures. As discussed above, at present FERC lacks a quorum of commissioners necessary to issue a final rule. Accordingly, assuming that the incoming chairman does not decide to shelve or abandon the rulemaking proceeding, it still may be several months before FERC issues a final rule in this proceeding.

III. Participation of Energy Storage Technologies in Wholesale Electricity Markets

Modernizing utility and RTO interconnection rules to accommodate the unique requirements of energy storage projects is just the first step toward broader participation of storage in wholesale electric markets. Until recently, FERC has largely refrained from establishing minimum participation opportunities and requirements for energy storage projects in wholesale markets. RTOs and utilities have, in turn, developed inconsistent rules that, in some cases, preclude energy storage developers from participating in wholesale electric markets or from receiving full compensation for the value they can provide.

One area in which FERC has acted is in the provision of ancillary electric services, i.e., services purchased by electric utilities to maintain the reliability of their transmission systems. Frequency regulation (or frequency response) is an ancillary wholesale electric market service whereby a resource injects or absorbs power from the transmission system in order to maintain grid stability. In 2011, FERC directed RTOs to implement a compensation model that rewarded fast-responding frequency response resources.[10] Two years later, FERC directed RTOs to consider the speed and accuracy of resources providing regulation and frequency response services in determining its regulation reserve requirements.[11] Unlike most conventional generation, storage devices such as batteries, flywheels and compressed air resources can discharge electricity almost immediately following an automated request from the system operator, thereby providing more value to the integrated transmission system. As a result, FERC’s decisions to favor faster and more accurate resources were a win for the energy storage industry.

Outside of the ancillary services markets, there is little uniformity among RTOs as to the degree to which storage devices are permitted to participate in wholesale electric markets. In the MISO and New York Independent System Operator (NYISO) markets, storage resources are eligible to provide frequency regulation service. In addition, if their facilities are capable of providing energy for at least four contiguous hours each day, storage resource owners can register their facilities as “use limited resources” in MISO or “energy limited resources” in NYISO and sell energy and capacity into the respective wholesale markets. In addition, MISO and PJM allow storage resources to register and participate in markets as generation resources, provided that they can meet certain performance and eligibility criteria. All of the FERC-regulated RTOs permit storage resources to participate as demand response, shifting power demand away from peak periods.

CAISO has been a leader among the RTOs with respect to integration of storage resources in wholesale electric markets. CAISO’s successes are due in large part to a state mandate for California’s three investor-owned utilities to procure a total of 1,325 MW of energy storage capacity by 2024.[12] CAISO’s market rules do not explicitly distinguish among resource types, but, in order to participate in CAISO markets, resources must have a minimum capacity of 0.5 MW, or 0.1 MW if participating as demand response, and they must provide this capacity for a minimum of 30 minutes in the real-time market, or 60 minutes in the day-ahead market. If an energy storage project can satisfy these eligibility requirements, it can participate in CAISO’s energy and ancillary service markets as generators, “Non-Generator Resources,” pumped-storage hydroelectric or demand response resources, or as part of an aggregation of distributed energy resources. Non-Generator Resources are defined under the CAISO tariff as “[r]esources that operate as either Generation or Load and that … are … constrained by a [MW hour] limit to (1) generate Energy, (2) curtail the consumption of Energy in the case of demand response, or (3) consume Energy.”[13]

As mentioned above, minimum runtime requirements have raised barriers to entry for energy storage devices seeking to participate in some wholesale markets. In the Southwest Power Pool, storage resources can participate in energy, regulation and contingency reserve markets if they are able to sustain a constant output for at least 60 minutes. Similarly, PJM requires resources participating in its reserve markets to respond to dispatch instructions within 10 minutes and to maintain a constant level of output or curtailment for at least 30 minutes. However, many storage resources are unable to sustain an output for 60 or even 30 minutes unless they significantly reduce their rate of discharge to a lower level, leading some storage owners to participate in a narrower subset of market products, including ancillary services and demand response.

IV. Removing Barriers to Entry to Wholesale Electric Markets

In 2016, FERC revisited energy storage, this time to address barriers to entry in wholesale electric markets other than ancillary services. In April 2016, FERC issued data requests requiring each jurisdictional RTO to provide information related to market rules that might affect the participation of storage resources in wholesale markets. Informed by comments received in this proceeding, FERC issued a notice of proposed rulemaking on November 17, 2016, proposing broad reforms to remove barriers to the participation of energy storage projects, as well as aggregated distributed energy resources, in wholesale electric markets.[14]

As an initial step, FERC proposed to direct RTOs to add definitions to their tariffs for “Energy Storage Resources.” As proposed, an Energy Storage Resource would be defined broadly as “a resource capable of receiving electric energy from the grid and storing it for later injection of electricity back to the grid regardless of where the resource is located on the electrical system.” In addition, FERC proposed to direct RTOs to revise their market participation models – the framework by which an RTO operates its wholesale markets – to accommodate the participation of energy storage resources in all wholesale electric markets while recognizing their unique physical and operational characteristics. As proposed, the participation models must satisfy each of the following requirements:

  1. energy storage resources must be eligible under the RTO’s tariffs to provide all capacity, energy, and ancillary services that they are technically capable of providing;

  2. RTO bidding parameters must reflect and account for physical and operational characteristics of energy storage resources;

  3. energy storage resources must be able to be dispatched and set wholesale market clearing prices as both a wholesale seller and a wholesale buyer;

  4. the minimum size requirement for energy storage resources must not exceed 100 kW; and

  5. the price for what FERC characterizes as wholesale sale of energy to an energy storage resource that the resource stores and subsequently resells back into electric markets must be the locational marginal price paid to generators, i.e., the marginal cost of supplying, at least cost, the next increment of electric demand at a specific location on the transmission system.

Under FERC’s proposal, the qualifying criteria for energy storage resources must not limit participation to any particular type of electric storage resource or other technology. The qualifying criteria also must ensure that the RTO is able to dispatch storage resources in a way that recognizes their physical constraints and optimizes their benefits to wholesale markets.

FERC also proposed to direct RTOs to provide opportunities for energy storage resources to provide any wholesale energy, capacity and ancillary services that they are technically capable of providing, and to require RTOs to establish bidding parameters that consider the resource’s state of charge, upper charge limit, lower charge limit, maximum energy charge rate and maximum energy discharge rate. These bidding parameters are intended to ensure that RTOs are able to efficiently and effectively dispatch energy storage resources. Taken together, these proposed requirements would greatly expand opportunities for energy storage resources to participate in wholesale electric markets.

In February 2017, industry groups and other stakeholders filed public comments that were generally supportive of FERC’s wholesale market participation proposals. Assuming FERC’s new leadership does not abandon this initiative, it may be many months before FERC issues a final rule, but FERC has already put many of its proposals into action. On February 1, 2017, FERC issued an order granting in part a complaint filed by IPL alleging that MISO’s tariff is discriminatory because it does not allow energy storage projects, such as the Harding Street project, to offer all of the services that they are technically capable of providing in MISO’s wholesale electric markets.[15] FERC agreed and directed MISO to revise its participation model and its tariff to “accommodate the unique features of energy storage technologies” and to allow energy storage resources to offer any wholesale electric service that they are technically capable of providing.[16]

V. Ongoing Efforts and Open Questions

Looking ahead, FERC will need to address interconnection and market participation issues relating to the combined use of generation and storage resources. IPL’s Harding Street Battery Storage Project provides an example of how traditional combustion turbines are incorporating storage resources, and other gas-fired generation developers are following suit, but storage also offers obvious benefits to renewable generators. By their nature, intermittent technologies such as solar and wind projects rely on the availability of their fuel source to generate electricity. As a result, they are able to generate electricity only when the sun is shining or the wind is blowing. In addition, depending on their contractual arrangements, renewable projects can be curtailed when prices become sufficiently negative to overcome production tax credits and other production-based incentives. By combining storage with generators, intermittent resource owners can ride through periods of curtailment by using production to charge their batteries for later discharge when there is great demand or higher prices. The ongoing rulemaking proceedings on generator interconnection and market participation could address questions related to the development and use of combined generation and storage facilities.

The combination of energy storage and power generation also raises regulatory issues outside the context of generator interconnection or participation in wholesale markets. For example, many owners of small renewable energy resources choose to certify their projects as qualifying small power production facilities under the Public Utilities Regulatory Policy Act of 1978 (PURPA). Under PURPA, qualifying facilities have federally-guaranteed rights to interconnect with and to sell power to their interconnected utilities at favorable “avoided cost” based rates. In addition, most qualifying facilities are exempted from utility-type regulation under Federal Power Act and the Public Utility Holding Company Act of 2005. But eligibility requirements for qualifying facility certification and associated regulatory exemptions largely turn on the fuel source and the power production capacity of the qualifying facility. Adding an energy storage device to a qualifying facility could increase the overall facility capacity and raise questions about the source of energy used to recharge the storage device. For example, does a 75 MW wind project with 10 MW of storage exceed the 80 MW capacity limit for wind qualifying facilities? How will FERC account for grid-supplied storage energy, given the PURPA requirement that the wind qualifying facility use only renewable resources for its energy input? FERC will face these and related issues as storage combined with renewables becomes more commonplace.

On another front, changes may be required to the reliability standards and defined terms administered by the North American Electric Reliability Corporation (NERC), which develops and enforces mandatory reliability standards for users, owners and operators of the bulk electric system. In its proposed rulemaking on wholesale market participation, FERC acknowledged that certain definitions in NERC’s glossary of terms, including the definition of frequency response, were developed for generating facilities and required revision to properly address the unique characteristics of storage technologies. Accordingly, FERC sought comment on whether and to what extent NERC-defined terms and reliability standards may create barriers to participation of electric storage resources or other non-synchronous technologies in wholesale electric markets. If FERC determines that it is necessary to adopt changes to NERC reliability standards or terminology to reflect the use of storage technologies, the proposed changes will need to be addressed through a NERC stakeholder process and submitted to FERC for public comment and review.

VI. Conclusion

FERC’s recent initiatives suggest that it might address many questions related to energy storage interconnection and wholesale market participation by late 2017 or early 2018. However, it is unclear how the RTOs and their stakeholders will respond. FERC gives RTOs broad discretion in how they manage their respective wholesale markets, and FERC will approve deviations from its pro forma tariff if an RTO can demonstrate that its alternative tariff provisions are consistent with or superior to the pro forma tariff provisions established by FERC.

In addition, there is an overarching question as to the role of FERC leadership. The change in administration will result in the appointment of four new commissioners, including a new chairman. New FERC leadership could abandon or deviate from the policies reflected in the pending rulemakings and other energy storage initiatives. No matter what, the rapid development and deployment of energy storage technologies will profoundly alter FERC’s long-standing regulation of the U.S. power industry.

 

 

 


[1] U.S. Energy Information Administration, Nonhydro electricity storage increasing as new policies are implemented, (Apr. 3, 2015) available at https://www.eia.gov/todayinenergy/detail.php?id=20652.

[2] Energy Storage Association, Facts & Figures available at http://energystorage.org/energy-storage/facts-figures (last visited Dec. 8, 2016).

[3] Comments of External Affairs Policy Advisor Jennifer Richardson during a January 2016 workshop of the market subcommittee of the Midcontinent Indep. Sys. Operator, Inc. See Amanda Durish Cook, MISO Preparing a Place for Energy Storage in Tariff, RTO Insider (Jan. 11, 2016) available at www.rtoinsider.com.

[4]See The Nev. Hydro Co., Inc., 122 FERC ¶ 61,272 (2008).

[5]See Western Grid Development, LLC, 130 FERC ¶ 61,056 (2010).

[6]See Utilization of Elec. Storage Resources, 158 FERC ¶ 61,051 (2017).

[7]Small Generator Interconnection Agreements and Procedures, Order No. 792, 145 FERC ¶ 61,159 (2013).

[8]Midcontinent Indep. Sys. Operator, Inc., 155 FERC ¶ 61,211, at PP 17-19 (2016).

[9]Reform of Generator Interconnection Procedures and Agreements, 157 FERC ¶ 61,212 (2016).

[10]Frequency Regulation Compensation in the Organized Power Markets, Order No. 755, 137 FERC ¶ 61,064 (2011).

[11]Third Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, Order No. 784, 144 FERC ¶ 61,056 (2013).

[12]See Cal. Assembly Bill 2514 (directing utilities to develop proposals for energy storage procurement; see also Cal. Pub. Util. Comm’n, D.10-03-04 (Oct. 17, 2013) (establishing procurement target of 1,325 MW by 2020, with installations required no later than the end of 2024).

[13] CAISO Tariff, Section 8.4.1.2.

[14]See Elec. Storage Participation in Mkts. Operated by Regional Transmission Orgs. and Indep. Sys. Operators, 157 FERC ¶ 61,121 (2016).

[15]Indianapolis Power & Light Co. v. Midcontinent Indep. Sys. Operator, Inc., 158 FERC ¶ 61,107 (2017).

[16]Id. P 69.


DISCLAIMER: Because of the generality of this update, the information provided herein may not be applicable in all situations and should not be acted upon without specific legal advice based on particular situations.

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