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ENERGY LAWREPORT

P R A T T ’ S

JULY-AUGUST 2017

VOL. 17-7

EDITOR’S NOTE: ENERGY UNDER THE SUN Victoria Prussen Spears

FERC STEPS UP EFFORTS TO SUPPORT INTEGRATION OF ENERGY STORAGE TECHNOLOGIES INTO WHOLESALE POWER MARKETS A. Cory Lankford and Adam Wenner

SUNIVA REQUESTS GLOBAL SAFEGUARDS FOR U.S. SOLAR INDUSTRY UNDER SECTION 201 James McCall Smith, Victor D. Ban, Shara L. Aranoff, and John K. Veroneau

NEW JERSEY USES SOVEREIGN IMMUNITY TO ESCAPE SPILL ACT LIABILITY Edward F. McTiernan and Michael D. Daneker

ADMINISTRATION’S EXECUTIVE ORDER ON CLIMATE AND ENERGY IS CONTROVERSIAL, AND MAY SHIFT ACTION TO STATES Christopher J. Carr, Michael Jacob Steel, Robert S. Fleishman, and Ali A. Zaidi

HYDRAULIC FRACTURING DEVELOPMENTS Eric Rothenberg, John D. Renneisen, Brian Kenyon, Jesse Glickstein, Kathryn E. Turner, Matt Lavigueur, and Sylvia Sermons

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Pratt’s Energy Law Report

VOLUME 17 NUMBER 7 JULY/AUGUST 2017

Editor’s Note: Energy under the SunVictoria Prussen Spears 245

FERC Steps Up Efforts to Support Integration of Energy StorageTechnologies into Wholesale Power MarketsA. Cory Lankford and Adam Wenner 247

Suniva Requests Global Safeguards for U.S. Solar Industryunder Section 201James McCall Smith, Victor D. Ban,Shara L. Aranoff, and John K. Veroneau 259

New Jersey Uses Sovereign Immunity to Escape Spill Act LiabilityEdward F. McTiernan and Michael D. Daneker 262

Administration’s Executive Order on Climate and EnergyIs Controversial, and May Shift Action to StatesChristopher J. Carr, Michael Jacob Steel,Robert S. Fleishman, and Ali A. Zaidi 265

Hydraulic Fracturing DevelopmentsEric Rothenberg, John D. Renneisen, Brian Kenyon,Jesse Glickstein, Kathryn E. Turner, Matt Lavigueur,and Sylvia Sermons 269

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Editor-in-Chief, Editor & Board ofEditors

EDITOR-IN-CHIEFSTEVEN A. MEYEROWITZ

President, Meyerowitz Communications Inc.

EDITORVICTORIA PRUSSEN SPEARS

Senior Vice President, Meyerowitz Communications Inc.

BOARD OF EDITORS

SAMUEL B. BOXERMAN

Partner, Sidley Austin LLP

ANDREW CALDER

Partner, Kirkland & Ellis LLP

M. SETH GINTHER

Partner, Hirschler Fleischer, P.C.

R. TODD JOHNSON

Partner, Jones Day

BARCLAY NICHOLSON

Partner, Norton Rose Fulbright

BRADLEY A. WALKER

Counsel, Buchanan Ingersoll & Rooney PC

ELAINE M. WALSH

Partner, Baker Botts L.L.P.

SEAN T. WHEELER

Partner, Latham & Watkins LLP

WANDA B. WHIGHAM

Senior Counsel, Holland & Knight LLP

Hydraulic Fracturing DevelopmentsERIC ROTHENBERG

Partner, O’Melveny & Myers LLP

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Pratt’s Energy Law Report is published 10 times a year by Matthew Bender & Company, Inc.Periodicals Postage Paid at Washington, D.C., and at additional mailing offices. Copyright 2017Reed Elsevier Properties SA, used under license by Matthew Bender & Company, Inc. No partof this journal may be reproduced in any form—by microfilm, xerography, or otherwise—orincorporated into any information retrieval system without the written permission of thecopyright owner. For customer support, please contact LexisNexis Matthew Bender, 1275Broadway, Albany, NY 12204 or e-mail [email protected]. Direct any editorialinquires and send any material for publication to Steven A. Meyerowitz, Editor-in-Chief,Meyerowitz Communications Inc., 26910 Grand Central Parkway Suite 18R, Floral Park, NewYork 11005, [email protected], 718.224.2258. Material for pub-lication is welcomed—articles, decisions, or other items of interest to lawyers and law firms,in-house energy counsel, government lawyers, senior business executives, and anyone interestedin energy-related environmental preservation, the laws governing cutting-edge alternative energytechnologies, and legal developments affecting traditional and new energy providers. Thispublication is designed to be accurate and authoritative, but neither the publisher nor the authorsare rendering legal, accounting, or other professional services in this publication. If legal or otherexpert advice is desired, retain the services of an appropriate professional. The articles andcolumns reflect only the present considerations and views of the authors and do not necessarilyreflect those of the firms or organizations with which they are affiliated, any of the former orpresent clients of the authors or their firms or organizations, or the editors or publisher.

POSTMASTER: Send address changes to Pratt’s Energy Law Report, LexisNexis MatthewBender, 121 Chanlon Road, North Building, New Providence, NJ 07974.

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FERC Steps Up Efforts to Support Integrationof Energy Storage Technologies into WholesalePower Markets

By A. Cory Lankford and Adam Wenner*

This article explores the Federal Energy Regulatory Commission’s efforts tofacilitate the integration of energy storage resources into wholesale electricmarkets.

As momentum builds for wide-scale development and deployment of electricenergy storage technologies, the Federal Energy Regulatory Commission(“FERC”) has been taking a fresh look at how it can facilitate the integrationof energy storage resources into wholesale electric markets. Advancements inenergy storage technology and the ability of these resources to improve gridreliability and efficiency have been the primary drivers of FERC’s initiatives.Until recently, the only technology widely used for energy storage was pumpedstorage hydro, which can only be economically developed where there is viablegeography, topology and a significant discrepancy between on-peak andoff-peak power costs; in 2014, pumped hydroelectric resources representedapproximately 98 percent of the over 22 gigawatts of installed electric storagecapacity in the U.S.1 However, lithium-ion electric battery resources haverecently taken a larger role in ancillary services markets, and the developmentof other emerging storage technologies continues to advance. The EnergyStorage Association reports that the energy storage market is set to developrapidly, with an expected six gigawatts of storage capacity to be added in 2017and over 40 gigawatts of installed storage capacity by 2022.2 While conven-tional pumped storage hydro-electric 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 theirrespective market shares since 2010, and these technologies are poised forcontinued expansion.

* A. Cory Lankford is a senior associate at Orrick, Herrington & Sutcliffe LLP and is amember of the firm’s Energy and Infrastructure Group. Adam Wenner is a partner at the firm,where he heads the Energy Regulatory Group. The authors may be reached [email protected] and [email protected], respectively.

1 U.S. Energy Information Administration, Nonhydro electricity storage increasing as newpolicies 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).

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Based on its long history of licensing pumped storage projects, FERC isfamiliar with the capabilities of electric energy storage facilities to integrate withthe power grid. However, as new technologies with more diverse operatingcharacteristics have been deployed, FERC has grappled with how to treatstorage projects—should they be classified as generation, transmission, load orall of the above? Historically, FERC addressed the interconnection and sale ofelectricity from pumped facilities and other storage technologies, includingbatteries, flywheels, and compressed air resources just as it would any othergenerating facility. However, energy storage devices can play many differentroles. They can act like a generator, selling energy, capacity and ancillary servicesin wholesale electricity markets. They also can function as a transmission asset,correcting transmission voltage and frequency by absorbing or releasingelectricity, as needed. In addition, storage resources function as load centerswhen they charge from the grid to purchase energy for later discharge or toreduce system load by providing demand response services.

In many ways, advancements in energy storage technologies and theirdeployment have outpaced the development of wholesale electric market rulesthat recognize the unique abilities, limitations and needs of storage resources. Inthe absence of a clear federal policy, transmission-owning utilities and regionaltransmission organizations (“RTOs”) have developed disparate rules governingthe participation of energy storage resources in wholesale electric markets. Asone 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 proceedingsinitiated by FERC in late 2016 and early 2017 could result in clear,standardized RTO policies relating to the participation of energy storageprojects in wholesale electric power markets. There is, however, someuncertainty. The change in administration will result in the appointment ofthree new FERC commissioners, one of whom will be appointed chairman. ThePresident has not yet announced his nominations, and any candidates willrequire confirmation by the Senate, which means that we can expect at least afew more months without a quorum of FERC commissioners. However, oncethe new commissioners and chairman are in place, FERC could decide toabandon or shelve the rulemakings described below, but doing so would ignorethe need for clear rules for a growing industry. In addition, recent FERC ordershave set precedent that, in effect, implements many of the proposals set forth

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

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in the pending rulemakings, thereby making it more difficult for FERC’s newleadership to completely change course.

COMPENSATING ENERGY STORAGE PROJECTS

Among the more complicated issues now before FERC is how best tocompensate providers of energy storage services. Similar to its treatment ofwholesale power sellers that demonstrate that they lack market power, FERChas granted authority to owners of storage projects to sell energy and ancillaryelectric services at “market-based rates”—i.e., at rates established either byindependently-run auctions or by agreement between the seller and buyer,without regard to cost-of-service or other traditional ratemakingmethodologies. However, as discussed further below, wholesale market rulesrequire further improvements to capture the full value of energy storage servicesand to accommodate their unique limitations. Unlike conventional generatingtechnologies, which can generate as long as fuel or another energy input isavailable, storage projects have a finite run-time before they must recharge. Forexample, new utility scale lithium ion batteries can be designed to dischargeenergy for four hours or more, but older systems could discharge for a shortertime.

Finite run-times and the need to constantly recharge their facilities havepresented challenges to storage project owners seeking to participate inwholesale power markets. Many regional wholesale electric market rules, whichwere developed with conventional generation in mind, establish minimumrun-times for entities wishing to sell energy and capacity. Owners of storagedevices that participate in these markets are susceptible to penalties if theirprojects are unable to provide energy throughout the entire commitmentperiod. 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 toolow, storage owners might not earn enough to cover their fixed and operatingcosts, including the costs of power for charging.

The uncertainty of market-based rate revenues in wholesale electric marketshas led some storage owners to seek cost-based compensation in exchange forproviding ancillary electric transmission services, namely absorbing and dis-charging power to maintain electric transmission reliability. An advantage ofcost-based compensation is that it provides owners of storage devices with aconsistent rate-of-return that, among other things, covers the capital costs ofsupplying and installing their storage resources and the estimated costs topurchase energy necessary to recharge the devices. Under a cost-based approach,to the extent that they exceed estimated costs, actual costs to purchase energyto 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

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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) tostorage projects that improve reliability and reduce the cost of power deliveredto end-use customers.

In 2008, the developer of a large (500 megawatt) pumped-hydroelectricproject sought FERC approval to receive an incentivized rate of return underthe California Independent System Operator’s (“CAISO”) transmission tariff.In support of its application, the pumped storage project developer committedto cede operational control of the facility to CAISO. FERC rejected theproposal, finding that it would inappropriate for CAISO, which is intended tobe an independent RTO, to have operational control over, and receivecompensation from, the storage facility.4 FERC expressed concern that CAI-SO’s independence as an RTO would be compromised if CAISO were inposition where it would be submitting bids on behalf of the storage facility intothe competitive wholesale electric markets that CAISO administered.

FERC reached a different conclusion in 2010, when it determined that acollection of sodium sulfur batteries, ranging in size from 10 to 50 megawatts,located at various sites along the CAISO transmission grid, were wholesaletransmission facilities that qualified for incentivized rate treatment.5 In the2010 case, the battery project owner agreed to forego any sales into CAISO’swholesale electric markets. Instead, the owner committed that it would followCAISO’s directions in a manner similar to the way in which high-voltagetransmission lines are operated by investor-owned utilities under the directionof CAISO. As a result, CAISO would not be in a position where it would becharging or discharging the batteries, thereby maintaining its independence.

In November 2016, FERC convened a technical conference to explorewhether storage devices should receive market- or cost-based compensation.Many trade groups and utilities advocated that storage devices should be eligiblefor both depending on the services that they are providing at any givenmoment. FERC agreed. In January 2017, FERC issued a policy statement inwhich it clarified that electric storage resources can receive both cost- andmarket-based revenues for providing separate services.6 To qualify, owners ofstorage resources will need to (1) credit any market-based rate revenues to theircost-based ratepayers, (2) use market-based rate revenues to offset and reducetheir cost-based rates, or (3) otherwise ensure no double recovery of costs to thedetriment of electric ratepayers.

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).


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INTERCONNECTION OF ENERGY STORAGE PROJECTS

Until recently, energy storage developers seeking to interconnect theirprojects to the transmission grid were required to rely on procedures andagreements designed for generation facilities. In many cases, this approach hasworked. This result is not surprising since, for example, pumped storagehydroelectric facilities generate power much in the same way as conventionalhydroelectric facilities. As a result, when FERC adopted standardized utilityinterconnection procedures and agreements in 2003, it did not direct utilitiesor RTOs and utilities to include explicit provisions for energy storage devices.FERC has since recognized that differences between generation and storagetechnologies require different interconnection provisions.

In 2013, FERC held technical conferences and initiated a rulemakingproceeding to revise its pro forma “small generator” interconnection proceduresand agreement, which apply to the interconnection of generating facilities thatdo not exceed 20 megawatts. In response to comments from energy storagegroups, FERC proposed to include energy storage devices within the definitionof generation facilities eligible for interconnection service. The move was notuniversally applauded. CAISO commented that the revision was unnecessary,stating that storage devices were already able to interconnect to the CAISOtransmission system as small generating facilities. FERC agreed but ultimatelyadopted its proposal, explaining that explicitly including energy storage as asmall generating facility would improve transparency with regard to how itssmall generator interconnection procedures and agreement should beimplemented.7

Not all storage developers embraced FERC’s clarification. In March 2016,the Midcontinent Independent System Operator Inc. (“MISO”), the RTOresponsible for much of the Midwestern transmission grid, filed a disputedgenerator interconnection agreement for an approximately 20 megawatt batterystorage facility to be added to two existing 30 megawatt gas turbine generators.Known as the Harding Street battery storage project, it was the firsttransmission grid-scale lithium ion battery storage array located in the MISOfootprint. Indianapolis Power & Light Company (“IPL”), which owns theHarding Street facility, protested the filing, in part, because it referred to theHarding Street battery storage facility as a “generating facility”—IPL advocatedthe use a new term for storage facilities. Although the definitional debate mayseem of minor consequence, it was part of a larger effort to distinguish therights and responsibilities of owners of storage projects from those of generation

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


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project owners. IPL also sought more substantive changes to reflect the distinctoperating characteristics of its storage facility and to distinguish it from agenerating facility. Ultimately, however, FERC accepted the agreement based,in part, on the fact that MISO explicitly expanded the definition of “generatingfacility” to include storage facilities.8

In its final meeting of 2016, FERC proposed similar changes to its standardinterconnection rules and agreement for “large generators” with a capacity ofmore than 20 megawatts.9 Consistent with its 2013 revisions to the pro formasmall generator interconnection procedures and agreement, FERC proposed torevise the definition of “Generating Facility” in the pro forma large generatorinterconnection procedures and agreement to include electric storage resources.In addition, FERC proposed to require utilities and RTOs to evaluate theirmethods for modeling electric storage resources for interconnection studies andto report to FERC as to why and how their existing practices are or are notsufficient.

FERC also proposed to allow generator owners with excess transmissioncapacity on their interconnection facilities to install energy storage devices onthe same site as their existing generating facilities and to use the sameinterconnection facilities for the generation and storage facilities. FERC furtherproposed to allow interconnection customers to install more generating orstorage capacity than the megawatt limit of their interconnection service.However, under both of these proposals, the simultaneous combined output ofthe generation and storage facilities may not exceed the interconnection servicecapacity previously granted to the generator owner, unless the generator ownersubmits a request to increase its interconnection service capacity and pays forany necessary upgrades to the transmission system. For example, the owner ofa 50 megawatt solar project with 60 megawatts of interconnection service couldinstall a 30 megawatt or larger storage facility, provided that the simultaneouscombined output of the solar and storage facilities did not exceed 60megawatts. Similarly, the owner of a 30 megawatt battery storage project mightelect to obtain interconnection service for only 22 megawatts because, althoughthe storage facility is technically capable of discharging as much as 30megawatts over a 30-minute period, the owner might elect to reduce output to22 megawatts per hour, which it could discharge over a longer time period andthereby satisfy minimum run-time requirements to sell energy and capacity intowholesale markets.

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).


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

PARTICIPATION OF ENERGY STORAGE TECHNOLOGIES INWHOLESALE ELECTRICITY MARKETS

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

One area in which FERC has acted is in the provision of ancillary electricservices—i.e., services purchased by electric utilities to maintain the reliabilityof their transmission systems. Frequency regulation (or frequency response) isan ancillary wholesale electric market service whereby a resource injects orabsorbs power from the transmission system in order to maintain grid stability.In 2011, FERC directed RTOs to implement a compensation model thatrewarded fast-responding frequency response resources.10 Two years later,FERC directed RTOs to consider the speed and accuracy of resources providingregulation and frequency response services in determining its regulation reserverequirements.11 Unlike most conventional generation, storage devices, such asbatteries, flywheels, and compressed air resources can discharge electricityalmost 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 theenergy storage industry.

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

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


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Outside of the ancillary services markets, there is little uniformity amongRTOs as to the degree to which storage devices are permitted to participate inwholesale electric markets. In the MISO and New York Independent SystemOperator (“NYISO”) markets, storage resources are eligible to provide fre-quency regulation service. In addition, if their facilities are capable of providingenergy for at least four contiguous hours each day, storage resource owners canregister their facilities as “use limited resources” in MISO or “energy limitedresources” in NYISO and sell energy and capacity into the respective wholesalemarkets. In addition, MISO and PJM allow storage resources to register andparticipate in markets as generation resources, provided that they can meetcertain performance and eligibility criteria. All of the FERC-regulated RTOspermit storage resources to participate as demand response, shifting powerdemand away from peak periods.

CAISO has been a leader among the RTOs with respect to integration ofstorage resources in wholesale electric markets. CAISO’s successes are due inlarge part to a state mandate for California’s three investor-owned utilities toprocure a total of 1,325 megawatts 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 minimumcapacity of 0.5 megawatts, or 0.1 megawatts if participating as demandresponse, and they must commit provide this capacity for a minimum of 30minutes in the real-time market, or 60 minutes in the day-ahead market. If anenergy storage project can satisfies these eligibility requirements, it canparticipate in CAISO’s energy and ancillary service markets as generators,“Non-Generator Resources,” pumped storage hydroelectric or demand responseresources, or as part of an aggregation of distributed energy resources.Non-Generator Resources are defined under the CAISO tariff as “[r]esourcesthat operate as either Generation or Load and that . . . are . . . constrained bya [megawatt hour] limit to (1) generate Energy, (2) curtail the consumption ofEnergy in the case of demand response, or (3) consume Energy.”13

As mentioned above, minimum run-time requirements have raised barriersto entry for energy storage devices seeking to participate in some wholesalemarkets. In Southwest Power Pool markets, storage resources can participate inenergy, regulation and contingency reserve markets if they are able to sustain a

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

13 CAISO Tariff, Section 8.4.1.2.


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constant output for at least 60 minutes. Similarly, PJM requires resourcesparticipating in its reserve markets to respond to dispatch instructions withinten minutes and to maintain a constant level of output or curtailment for atleast 30 minutes. However, many storage resources are unable to sustain anoutput for 60 or even 30 minutes unless they significantly reduce their rate ofdischarge to a lower level, leading some storage owners to participate in anarrower subset of market products, including ancillary services and demandresponse.

REMOVING BARRIERS TO ENTRY TO WHOLESALE ELECTRICMARKETS

In 2016, FERC revisited energy storage, this time to address barriers to entryin wholesale electric markets, other than ancillary services. In April 2016, FERCissued data requests requiring each jurisdictional RTO to provide informationrelated to market rules that might affect the participation of storage resourcesin 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 energystorage projects, as well as aggregated distributed energy resources, in wholesaleelectric markets.14

As an initial step, FERC proposed to direct RTOs to add definitions to theirtariffs for “Energy Storage Resources.” As proposed, an Energy StorageResource would be defined broadly as “a resource capable of receiving electricenergy from the grid and storing it for later injection of electricity back to thegrid regardless of where the resource is located on the electrical system.” Inaddition, FERC proposed to direct RTOs to revise their market participationmodels—the framework by which an RTO operates its wholesale markets—toaccommodate the participation of energy storage resources in all wholesaleelectric markets, while recognizing their unique physical and operationalcharacteristics. As proposed, the participation models must satisfy each of thefollowing requirements:

1) energy storage resources must be eligible under the RTO’s tariffs toprovide all capacity, energy, and ancillary services that they aretechnically capable of providing;

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

3) energy storage resources must be able to be dispatched and set

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


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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 anenergy storage resource that the resource stores and subsequentlyresells back into electric markets must be the locational marginal pricepaid to generators—i.e., the marginal cost of supplying, at least cost,the next increment of electric demand at a specific location on thetransmission system.

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

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

In February 2017, industry groups and other stakeholders filed publiccomments that were generally supportive of FERC’s wholesale market partici-pation proposals. Assuming FERC’s new leadership does not abandon thisinitiative, it may be many months before FERC issues a final rule, but FERChas already put many of its proposals into action. On February 1, 2017, FERCissued an order granting in part a complaint filed by IPL alleging that MISO’stariff is discriminatory because it does not allow energy storage projects, such asthe Harding Street project, to offer all of the services that they are technicallycapable of providing in MISO’s wholesale electric markets.15 FERC agreed anddirected MISO to revise its participation model and its tariff to “accommodatethe unique features of energy storage technologies” and to allow energy storage

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


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resources to offer any wholesale electric service that they are technically capableof providing.16

ONGOING EFFORTS AND OPEN QUESTIONS

Looking ahead, FERC will need to address interconnection and marketparticipation issues relating to the combined use of generation and storageresources. IPL’s Harding Street battery storage project provides an example ofhow traditional combustion turbines are incorporating storage resources, andother gas-fired generation developers are following suit, but storage also offersobvious benefits to renewable generators. By their nature, intermittent tech-nologies such as solar and wind projects rely on the availability of their fuelsource to generate electricity. As a result, they are only able to generateelectricity when the sun is shining or the wind is blowing. In addition,depending on their contractual arrangements renewable projects can becurtailed when prices become sufficiently negative to overcome production taxcredits and other production-based incentives. By combining storage withgenerators, intermittent resource owners can ride through periods of curtail-ment by using production to charge their batteries for later discharge whenthere is great demand or higher prices. The ongoing rulemaking proceedings ongenerator interconnection and market participation could address questionsrelated to the development and use of combined generation and storagefacilities.

The combination of energy storage and power generation also raisesregulatory issues outside the context of generator interconnection or participa-tion in wholesale markets. For example, many owners of small renewable energyresources choose to certify their projects as qualifying small power productionfacilities under the Public Utilities Regulatory Policy Act of 1978 (“PURPA”).Under PURPA, qualifying facilities have federally-guaranteed rights to inter-connect with and to sell power to their interconnected utilities at favorable“avoided cost” based rates. In addition, most qualifying facilities are exemptedfrom utility-type regulation under Federal Power Act and the Public UtilityHolding Company Act of 2005. But eligibility requirements for qualifyingfacility certification and associated regulatory exemptions largely turn on thefuel source and the power production capacity of the qualifying facility. Addingan energy storage device to a qualifying facility could increase the overall facilitycapacity and raise questions about the source of energy used to recharge thestorage device. For example, does a 75 megawatt wind project with 10megawatts of storage exceed the 80 megawatt capacity limit for wind qualifyingfacilities? How will FERC account for grid-supplied storage energy, given the

16 Id. p. 69.


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PURPA requirement that the wind qualifying facility use only renewableresources for its energy input? FERC will face these and related issues as storagecombined with renewables becomes more commonplace.

On another front, changes may be required to the reliability standards anddefined terms administered by the North American Electric Reliability Corpo-ration (“NERC”), which develops and enforces mandatory reliability standardsfor users, owners and operators of the bulk electric system. In its proposedrulemaking on wholesale market participation, FERC acknowledged thatcertain definitions in NERC’s glossary of terms, including the definition offrequency response, were developed for generating facilities and requiredrevision 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 ofelectric storage resources or other non-synchronous technologies in wholesaleelectric markets. If FERC determines that it is necessary to adopt changes toNERC reliability standards or terminology to reflect the use of storagetechnologies, the proposed changes will need to be addressed through a NERCstakeholder process and submitted to FERC for public comment and review.

CONCLUSION

FERC’s recent initiatives suggest that it might address many questions relatedto energy storage interconnection and wholesale market participation by late2017 or early 2018. However, it is unclear how the RTOs and their stakeholderswill respond. FERC gives RTOs broad discretion in how they manage theirrespective wholesale markets, and FERC will approve deviations from its proforma tariff if an RTO can demonstrate that its alternative tariff provisions areconsistent with or superior to the pro forma tariff provisions established byFERC.

In addition, there is an overarching question as to the role of FERCleadership. The change in administration will result in the appointment of threenew commissioners, including a new chairman. New FERC leadership couldabandon or deviate from the policies reflected in the pending rulemakings andother energy storage initiatives. No matter what, the rapid development anddeployment of energy storage technologies will profoundly alter FERC’slong-standing regulation of the U.S. power industry.


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