The Washington Report

Energy regulatory developments in the United States impact numerous sectors of the energy industry and address a wide swath of issues. We reported on key federal and state energy regulatory developments in the United States during 2013 in the Winter 2014 volume of the ERQ. This report highlights significant developments in 2014 which should be of interest to readers of the ERQ.

I. LNG Exports

Because of the huge amount of shale gas in the United States there is a substantial push to export liquefied natural gas (LNG); thus, 2014 was an extremely active year at two key agencies – the U.S. Department of Energy (DOE) and U.S. Federal Energy Regulatory Commission (FERC).


DOE adopted in 2014 a new process to implement its authority under Section 3 of the Natural Gas Act1 to determine that an application to export LNG to a non-Free Trade Agreement (“non-FTA”) country is not inconsistent with the public interest.2 Previously, DOE would issue an export authorization conditioned on the outcome of the review of the proposed export under the National Environmental Policy Act (“NEPA”). Under the new procedures, DOE will not conditionally approve export authorizations. Instead, DOE will act on applications to export LNG to non-FTA countries only after the NEPA review is completed.3 Rather than processing applications to export LNG to non-FTA countries in the published order of precedence, DOE will take up the applications “in the order they become ready for final action.”4 By “final action,” DOE means that “DOE has completed the pertinent NEPA review process and […] DOE has sufficient information on which to base a public interest determination.”

An application will be deemed to have completed the NEPA review process: (1) for those projects requiring an Environmental Impact Statement (EIS), 30 days after publication of a Final EIS; (2) for projects for which an Environmental Assessment has been prepared, upon publication by DOE of a Finding of No Significant Impact; or (3) upon a determination by DOE that an application is eligible for a categorical exclusion from NEPA pursuant to applicable DOE regulations. DOE expects that the new process will enhance its ability to judge the cumulative market impacts of an LNG export request because “projects that have undertaken the expense to complete NEPA review are, as a group, more likely to proceed than those that have not.”5 DOE will apply the new procedures to applications to export natural gas from the lower 48 United States to non-FTA countries but not to applications for authorization to export LNG from the State of Alaska.


In 2014, FERC granted applications by several prospective exporters of LNG for authorization under Section 3 of the Natural Gas Act to develop, construct and operate new or expanded liquefaction facilities, and authorization under Section 7(c) of the Natural Gas Act to construct new interstate pipelines to transport natural gas supplies to the liquefaction facilities. As required under Section 3, FERC’s authorizations are based upon an analysis, pursuant to NEPA, as to whether there are significant environmental impacts from the proposed facilities and how such significant impacts should be mitigated. In addition to protests by, and arrests, of environmental activists near FERC in each of these proceedings, environmental advocates led by the Sierra Club challenged the adequacy of FERC’s NEPA analysis.

The most significant issues raised by Sierra Club relate to whether NEPA requires FERC to: 1) analyze, as an indirect effect of the proposed project, induced production of natural gas, in particular from shale gas basins using hydraulic fracturing and similar extraction mechanisms; and 2) analyze the cumulative impacts of all proposed LNG export facilities in analyzing any particular proposed project. FERC has consistently ruled that these effects are not “reasonably foreseeable” within the meaning of NEPA and relevant court precedents and has not addressed these effects in its decisions authorizing the LNG projects. Sierra Club has appealed these FERC authorizations to the D.C. Circuit6 and is expected to ask the court to find that FERC failed to satisfy its obligations under NEPA and that NEPA requires FERC to consider the effects of proposed export facilities on natural gas production throughout the United States.

II. Obama Administration Climate Action Plan, Review of EPA actions on GHG emissions and emissions standards, and Related Issues

A. Administrative Efforts Under President Obama’s Climate Action Plan

With the Republican Party gaining control of the U.S. Senate in November 2014, the chances of significant federal legislation addressing climate change have become remote. The Obama Administration continues to push forward aggressively with the strategies outlined in the President’s 2013 Climate Action Plan,7 and President Obama could leave office with the most aggressive, far-reaching environmental legacy of any previous President.8

In June 2014, the U.S. Environmental Protection Agency (EPA) proposed new rules to regulate emissions of greenhouse gases from existing and modified power plants under Section 111(d) of the federal Clean Air Act.9 The proposal would implement one of the key features of the Climate Action Plan. As we wrote previously,10 EPA proposed a rule in January 2014 that would establish greenhouse gas performance standards for new stationary sources; that effort is still underway and is expected to be finalized in 2015.11 The new proposal, the “Clean Power Plan,” would cover a significantly larger sector of sources than the new source rules, and, by 2030, would reportedly cut carbon emissions from the power sector 30 percent below 2005 levels. EPA would set a “carbon intensity” goal for each state to meet by 2030, while allowing states to develop their own plans for achieving the goals; these initial plans are to be submitted to EPA by June 30, 2016. If it is promulgated, the rule would have a significant impact on, among other things, utility regulation for decades to come.

Although EPA is touting the benefits of the proposal and the flexibility it provides the regulated community, it has already generated huge controversy—and even litigation, despite the fact that the regulations have yet to be finalized. Murray Energy Corp. and twelve coal-producing states filed suit to stop the rulemaking in the which has original jurisdiction over certain Clean Air Act challenges12; a separate challenge filed by the state of Nebraska has been dismissed on procedural grounds.13 Assuming the draft rules are finalized, more legal challenges are certain to follow, likely continuing beyond President Obama’s term in office.

The Climate Action Plan also called for expanded multilateral and bilateral efforts to address climate change on an international level. The Administration took a major step in this regard on November 11, 2014, when President Obama and President Xi Jinping of China jointly announced a cooperative deal to reduce greenhouse gas emissions from both countries: the U.S. targeting a 28 per cent reduction from 2005 levels by 2025, and China to achieve peak emissions around 2030 while increasing the share of non-fossil fuels in energy to approximately 20 per cent.14 The two leaders also expressed their intent to enter into a binding protocol or similar legal instrument binding on all participating parties at the United Nations Climate Conference to be held in Paris in 2015. Like the Clean Power Plan, any commitments made at the Climate Conference would effectively fall to President Obama’s successor for implementation, and media outlets are characterizing climate action measures as a potential hot-button issue in the 2016 Presidential election.15

B. U.S. Supreme Court Review of EPA Rules

We previously reported16 on the U.S. Supreme Court’s ruling in Environmental Protection Agency v EME Homer City Generation, L.P.,17 a Clean Air Act case where the Court upheld EPA’s latest effort to force upwind states to reduce emissions contributing significantly to pollution in downwind states. EPA did not fare as well in the Court’s next Clean Air Act opinion, Utility Air Regulatory Group v Environmental Protection Agency,18 which represented only a partial victory for EPA.

In that case, the Court rejected EPA’s application of the Clean Air Act to require a stationary source to obtain a Prevention of Significant Deterioration (PSD) permit or a Title V “major source” permit based solely on potential greenhouse gas (GHG) emissions. The Court, however, upheld EPA’s determination that a GHG emissions source that would otherwise require a PSD permit, known as an “anyway” source, can be required to use “best available control technology” emissions standards to control those GHG emissions.

Although the Court’s opinion makes clear that EPA can regulate stationary source GHGs under the Clean Air Act, it also indicates the divided Court’s willingness to view EPA’s regulations with a critical eye, particularly its attempts to tailor regulations in a manner beyond Congress’ explicit intentions.

C. Coal Ash

On December 19, 2014, the EPA issued its final rule governing the storage and disposal of coal combustion residuals (CCR) (i.e. “coal ash,” by electric utilities). This long-awaited rule was developed pursuant to Subtitle D of the Resource Conservation and Recovery Act and establishes comprehensive requirements for the disposal of coal ash at both existing and new CCR landfills and surface impoundments.19 It establishes national minimum criteria for existing and new CCR landfills, and for existing and new CCR surface impoundments. These criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements, and post-closure care, and recordkeeping, notification, and internet posting requirements.20

III. Fracking

Hydraulic fracturing (“hydrofracking” or “fracking”) remains a controversial practice subject to a regulatory patchwork primarily imposed by states and localities.21 This regulatory framework is due to a law that specifically exempts fracking from federal oversight.22 Consequently, many of the decisions relating to fracking have come from state courts. One of the most significant fracking decisions in 2014 was Wallach v Town of Dryden, in which the New York Court of Appeals held that local governments have the power to ban fracking activities under their authority to enact zoning ordinances.23

The state’s highest court applied its three-part framework set forth in Frew Run Gravel Products Inc. v Town of Carroll24 and found that the plain language, statutory scheme, and legislative history of the statewide Oil, Gas, and Solution Mining Law (OGSML) supported localities’ ability to adopt fracking bans.25 Specifically, the court said that the OGSML is “most naturally read as preempting only local laws that purport to regulate the actual operations of oil and gas activities, not zoning ordinances that restrict or prohibit certain land uses within town boundaries.”26 Furthermore, the court said that

it is readily apparent that the OGSML is concerned with the Department’s regulation and authority regarding the safety, technical and operational aspects of oil and gas activities across the state . . .
nothing in the various provisions of the OGSML indicat[e] that the supersession clause was meant to be broader than required to preempt conflicting local laws directed at the technical operations of the industry.27

In December 2014, New York became the largest oil and gas producing state to ban fracking. The governor and its commissioners for health and the environment did so based on health concerns.28

Also in 2014, several localities adopted fracking bans, including Mendicino and San Benito counties in California,29 and the cities of Denton, Texas, and Athens, Ohio.30 Just days after the City of Denton passed its fracking ban, the Texas General Land Office and Texas Oil and Gas Association sued to prevent it from enforcing the ban.31 Moreover, the Chairwoman of the Texas Railroad Commission said that she plans to issue fracking permits for activities in the City of Denton despite its fracking ban.32

The Illinois Department of Natural Resources (IDNR) published rules that regulate fracking, which opens the door to fracking activities within the state.33 The rules are the IDNR’s third attempt to codify the Hydraulic Fracturing Regulatory Act,34 which was signed into law in 2013 and applies to all wells in which fracking may take place in Illinois.

The Nevada Commission on Mineral Resources (NCMR) issued regulations governing fracking activities in the state.35 The rules were issued on the heels of a federal court refusing to grant an injunction to prevent the NCMR from issuing its fracking regulations.36 The court said that it lacked subject matter jurisdiction to review the challenge because final agency action, which is a jurisdictional prerequisite to obtaining judicial review, had not yet occurred because leases had not yet been issued by the Bureau of Land Management.37

IV. Gas-Electric Coordination and FERC Order 1000

A. Natural Gas Scheduling and Electric Transmission Orders

In 2014, FERC issued three interrelated orders addressing issues that arise from the scheduling practices of interstate natural gas pipelines and electric transmission operators. The Commission’s concern is the potential impact on the reliable and efficient operation of electric transmission systems and interstate natural gas pipelines, divergences between the start times of the natural gas and electric operating days, and mismatches in the timelines for scheduling interstate natural gas pipeline transportation service and wholesale electric sales made by gas-fired generators on the next day. The Commission is also concerned about existing scheduling practices of interstate natural gas pipelines and the application of some Commission regulations by pipelines which may not provide sufficient flexibility to meet the needs of natural gas-fired generators, and may be limiting the capacity available to shippers (including natural gas-fired generators).

1. FERC Proposal on Natural Gas and Electricity Scheduling

FERC issued a Notice of Proposed Rulemaking proposing revisions to its regulations to better coordinate the scheduling of natural gas and electricity markets in light of increased reliance on natural gas for electricity generation.38 The revised rules would start the natural gas operating day earlier, move back the timely nomination cycle and increase from two to four the number of intraday nomination opportunities to help shippers adjust to changes in demand. Comments on FERC’s proposed rulemaking were filed on November 28, 2014.

2. Proceeding Examining ISO and RTO Scheduling Practices

FERC also initiated a proceeding under Section 206 of the Federal Power Act to examine whether day-ahead scheduling practices by Independent System Operators and Regional Transmission Organizations are just and reasonable.39 Following FERC’s issuance of a final rule in the Coordination rulemaking, each ISO and RTO must: (1) make a filing that proposes tariff changes to adjust the time at which the results of its day-ahead energy market and reliability unit commitment process (or equivalent) are posted to a time that is sufficiently in advance of the Timely and Evening Nomination Cycles, respectively, to allow gas-fired generators to procure natural gas supply and pipeline transportation capacity to serve their obligations, or (2) show cause why such changes are not necessary. In their responses, each ISO and RTO must explain how its proposed scheduling modifications are sufficient for gas-fired generators to secure natural gas pipeline capacity prior to the Timely and Evening Nomination Cycles.

3. Show Cause Proceeding Regarding Posting of Offers to Purchase Capacity

Finally, FERC initiated a show cause proceeding pursuant to Section 5 of the Natural Gas Act, requiring all interstate pipelines to submit filings to the Commission either revising their tariffs to provide for the posting of offers to purchase released capacity or otherwise demonstrating that they are in full compliance with the Commission’s regulations regarding posting of offers to purchase released capacity.40 Section 284.8(d) of the Commission’s regulations states that pipelines “must provide notice of offers to release or purchase capacity [and] the terms and conditions of such offers[…], on an internet website, for a reasonable period.”

B. FERC Order 1000

FERC Order No. 1000 and its progeny adopted significant regulatory reforms that will materially impact the planning, development and operation of electric transmission infrastructure in North America.41 In 2014, a three-judge panel of the D.C. Circuit unanimously upheld Order No. 1000 on grounds that the Order and its reforms were within FERC’s scope of authority under the Federal Power Act, supported by substantial evidence, and not arbitrary and capricious.42

Pursuant to Order No. 1000: (1) public utility transmission providers must participate in an open and nondiscriminatory transmission planning process for the development of new transmission facilities, on a regional basis; (2) regional transmission plans must identify transmission needs driven by public policy requirements; (3) adjacent regions must establish procedures to share planning data and identify more efficient interregional solutions to transmission needs; (4) incumbent transmission providers no longer have a right of first refusal to construct new regional transmission facilities; and (5) the costs of new transmission will be allocated to the beneficiaries of new transmission facilities “in a manner that is at least roughly commensurate with estimated benefits.”43

In upholding Order No. 1000, the court deferred to FERC’s interpretation of its authority under Section 206 of the Federal Power Act to regulate “practices” affecting FERC-jurisdictional rates. Transmission planning, the court ruled, is a “practice” that affects FERC-jurisdictional transmission rates. Accordingly, the court found FERC properly exercised its authority in requiring transmission providers to participate in specific transmission planning processes.

The court rejected arguments that FERC had not demonstrated that it was necessary to adopt the transmission planning reforms set forth in Order No. 1000. The court found substantial evidence of a theoretical threat of unjust and unreasonable transmission service rates in the event Order No. 1000 was not adopted. FERC’s determination of the necessity of transmission planning reform was adequately supported by prior Commission transmission rulemakings and by comments submitted by DOE, industry consultants, and FERC technical conferences.

The court agreed with FERC that it had the authority under Section 206 of the Federal Power Act to direct transmission providers to remove rights of first refusal from their transmission tariffs. The court determined that it was reasonable for FERC to conclude that rights of first refusal pose a barrier to entry that made the transmission market inefficient and increased costs for transmission customers. Rights of first refusal were properly determined to be a “practice” affecting wholesale transmission service rates and therefore within FERC’s authority to regulate.

The court upheld FERC’s decision that the costs of new transmission must be allocated among the beneficiaries and found that the language and context of Federal Power Act Section 206 does not limit FERC’s authority to oversee practices involving prior commercial relationships. Petitioners argued that Section 206 precluded the Commission from allocating costs “beyond pre-existing commercial relationships.” Yet, the Court found that “Section 206 empowers the commission to fix any ‘practice’ affecting rates, and the Commission reasonably understood beneficiary-based cost allocation—or its absence—to be a practice affecting rates.”  Thus, the Court held that the “use of ‘any’ to describe ‘rate,’ ‘public utility,’ and ‘transmission’ bestows authority on the Commission that is not cabined to pre-existing commercial relationships of any given utility.”44

Order No. 1000 requires regional planning to include consideration of transmission needs driven by public policy requirements. Petitioners challenged this requirement as impermissibly vague. The court said that FERC had simply directed that each region develop mechanisms for addressing public policy requirements and that this was sufficient to satisfy any requirements for legal specificity in the agency’s action.

FERC has issued a series of orders implementing its rule across the country.

V. Dodd-Frank and CFTC Developments

The Commodity Futures Trading Commission (CFTC or Commission) experienced significant turnover in leadership during 2014 with the appointment of three new commissioners, including new Chairman Timothy Massad.45 Statements and actions of the newly comprised Commission suggest that it may be more willing to work with industry participants to minimize the effect of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) on commercial end users, including energy companies, than the previous Commission headed by former Chairman Gary Gensler.46 Notable energy-related CFTC developments are discussed below.

A. Proposed Interpretation of the “Swap” Definition’s Seven-Part Test for Forwards with Volumetric Optionality

In response to requests from market participants, on November 13, 2014, the CFTC together with the Securities and Exchange Commission (SEC) proposed an interpretation47 of the seven-part test for forward contracts with embedded volumetric optionality, as set forth in the agencies’ joint rulemaking further defining “swap” under Dodd-Frank.48 The test’s seventh prong has become the subject of intense scrutiny in requiring that “[t]he exercise or non-exercise of the embedded volumetric optionality [be] based primarily on physical factors, or regulatory requirements, that are outside the control of the parties and are influencing demand for, or supply of, the nonfinancial commodity,” for a contract with embedded volumetric optionality to be classified as a forward.49 Commentators were concerned that the test, principally the seventh prong, classified as swaps certain commercial contracts that did not need to be regulated as such and introduced needless uncertainty regarding the regulatory treatment of commercial contracts with embedded volumetric optionality.50

The new proposal would make the seventh prong easier to satisfy, thereby reducing the likelihood of a commercial contract with embedded volumetric optionality being treated as a swap subject to regulation under Dodd-Frank. Specifically, it would modify the prong to read: “The embedded volumetric optionality is primarily intended, at the time that the parties enter into the agreement, contract, or transaction, to address physical factors or regulatory requirements that reasonably influence demand for, or supply of, the nonfinancial commodity.”51 The bolded language represents changes from the original test and relieves parties from having to anticipate the reason an embedded option might be exercised at some point in time in the future. The public comment period for the interpretative proposal ended on December 22, 2014.

B. Final Rule Exempting Utility Special Entity Swaps from the Lower Swap Dealer Threshold Applicable to Dealing with Special Entities

On September 17, 2014, the CFTC approved a final rule52 that amends the CFTC’s definition of “swap dealer,” the entity subject to the highest level of CFTC regulation under Dodd-Frank, to permit persons who enter into “utility operations-related swaps”53 with “utility special entities”54 to exclude those swaps from the determination of whether that person has exceeded the $25 million de minimis swap dealing threshold specific to dealing with special entities. Instead, such swaps must only be counted for determining whether the general, $8 billion dealing de minimis threshold applies (if the swaps constitute dealing and are not otherwise eligible for another exemption from the determination). The final rule effectively codifies no-action relief previously issued by CFTC staff in March of 2014.55

C. Proposed Margin Rules for Uncleared Swaps

On October 3, 2014, the CFTC re-proposed margin rules for uncleared swaps entered into by registered swap dealers and major swap participants that are not banks (the U.S. Prudential Regulators56 have proposed comparable rules that would apply to banks).57 The CFTC initially proposed rules on the subject in 2011 but re-proposed the rules in response to comments received and the publication of the Final Policy Framework for Margin Requirements for Non-Centrally Cleared Derivatives, published in September 2013 by the Basel Committee on Banking Supervision and the Board of the International Organization of Securities Commissions.58 Notably, the new proposal would not require non-financial end users, a category that encompasses most energy companies, to post margin for swaps executed with swap dealers or major swap participants. The comment period for the proposed rulemaking closed on December 2, 2014.

D. Proposed Amendment of Recordkeeping Rule for Members of Swap Execution Facilities

On November 4, 2014, the CFTC proposed to amend Commission Rule 1.35(a)59 to provide permanent relief from compliance with certain recordkeeping requirements applicable to members of swap execution facilities (SEFs).60 Most notably, the proposal would codify existing staff no-action relief that relieves unregistered members (i.e., entities who transact on SEFs that are not registered as swap dealers or major swap participants) from the requirements to keep records of text messages and to store all required records in a form and manner that is identifiable and searchable by transaction. The comment period for the proposed rulemaking closed on January 13, 2015.

E. CFTC Ownership and Control Final Rule and FIA Tech Rollout

The CFTC published final rules for ownership and control reporting on November 18, 2013.61 The new rules include significantly expanded data requirements and tight reporting deadlines that, will affect the way futures commission merchants and swap dealers collect and report data as part of their reporting obligations under CFTC rules.

In response to the new rulemaking, the trade group Futures Industry Association (“FIA”) has created a web-based application called “FIA Tech”62 that will allow firms to manage account ownership and control data and report required information to the CFTC. Specifically, FIA Tech facilitates the reporting obligations for Forms 102,63 4064 and 71.65

F. Proposed Position Limits Rule

As previously reported,66 the CFTC reopened the comment period for its position limits proposal in conjunction with a staff roundtable to consider certain issues related to physical commodities (including energy commodities).67 The CFTC asked market participants to comment on the following topics: 1) hedges of a physical commodity by a commercial enterprise, including gross hedging, cross-commodity hedging, anticipatory hedging, and the process for obtaining a non-enumerated exemption; 2) the setting of spot month limits in physical-delivery and cash-settled contracts and a conditional spot-month limit exemption; 3) the setting of non-spot limits for wheat contracts; 4) the aggregation exemption for certain ownership interests of greater than 50 percent in an owned entity; and 5) aggregation based on substantially identical trading strategies. The comment period closed on August 4, 2014 and the proposed rule is still pending.68

VI. FERC Enforcement and compliance

FERC’s Office of Enforcement (Enforcement) focused its 2014 efforts in four principal areas: (1) fraud and market manipulation; (2) serious violations of mandatory reliability standards; (3) anticompetitive conduct, and (4) conduct threatening the transparency of regulated markets.69 In 2014, Enforcement continued to prosecute matters under FERC’s authority to impose civil penalties of up to $1 million per day for market manipulation and fraud.70 FERC opened 17 new investigations and obtained monetary penalties and disgorgement of unjust profits totaling $29 million. Notable matters are briefly described below.

A. BP America Inc. et al.

On August 5, 2013, FERC ordered BP America Inc., BP Corporation North America Inc., BP America Production Company, and BP Energy Company (collectively, BP) to show cause why BP should not be: (1) found to have illegally manipulated a certain natural gas market in Houston from September to November 2008; (2) assessed penalties totaling $28 million; and (3) forced to disgorge $800,000 in unjust profits.71 On October 4, 2013, BP filed an answer denying all wrongdoing and requesting that FERC dismiss the proceeding, or, in the alternative, set the matter for a full evidentiary hearing before an administrative law judge at the agency. On May 15, 2014, FERC rejected BP’s request to dismiss the proceeding citing the existence of genuine issues of material fact and ordered that the matter be set for a hearing.

On June 13, 2014, BP filed a request for rehearing of FERC’s order rejecting BP’s motion to dismiss the proceeding and ordering a public hearing. BP argued that the order improperly expands FERC’s jurisdiction beyond the statutory limits of the Natural Gas Act. FERC issued an order on July 14, 2014 granting BP’s rehearing request for the limited purpose of affording additional time for consideration of the matters raised without addressing BP’s specific request for FERC to rehear the May 15, 2014 order. FERC further stated that the specific rehearing request would be addressed in a future order.72

On September 22, 2014, FERC Enforcement Staff submitted testimony by three witnesses who analyzed BP’s trading activity during the relevant period.73 All of them witnesses agreed that BP engaged in manipulation, citing, among other things, markedly changed market activity by BP following Hurricane Ike from September through November 2008. The hearing before the ALJ is scheduled to commence on March 30, 2015, and the ALJ’s Initial Decision is scheduled for issuance on or before August 14, 2015.

B. Lincoln Paper and Tissue et al.

On August 29, 2013, FERC issued orders74 assessing civil penalties of $5 million, $7.5 million, and $1.25 million against Lincoln Paper and Tissue LLC (Lincoln), Competitive Energy Services, LLC (“CES”), and Richard Silkman (Silkman), CES’ managing partner, respectively, alleging that these parties manipulated ISO New England’s demand response markets.75 The orders also sought disgorgement of unjust profits of approximately $380,000 from Lincoln and $170,000 from CES.

On December 2, 2013, FERC filed petitions in the U.S. District Court for the District of Massachusetts seeking orders affirming the imposition of penalties against Lincoln, CES, and Silkman.76 FERC sought relief in federal district court after the parties did not pay the assigned penalties within the allotted 60 day period.

On February 14, 2014, Lincoln moved to dismiss FERC’s complaint, arguing that: (1) FERC’s claim for civil penalties is barred by the five-year statute of limitation in Section 2496; (2) FERC lacks jurisdiction over Lincoln’s conduct; (3) FERC failed to provide fair notice of the conduct it now considers improper; and (4) FERC’s complaint fails to plead its claim with particularity.77 The motion raises a number of important legal questions relating to FERC’s authority to police electricity markets. The motion, for example, argues that FERC lacks jurisdiction over the relevant transactions because the States have exclusive control over demand response regulation under 16 U.S.C. § 824(a).78

On June 2, 2014, FERC moved to stay the proceedings in light of the United States Court of Appeals for the D.C. Circuit’s issued decision in Elec. Power Supply Ass’n v. FERC79 (Order No. 745, discussed below), which vacated FERC’s final rule on demand response compensation in organized wholesale energy markets.80 However, the district court judge denied FERC’s motion to stay.

C. Barclay’s Bank PLC

On July 16, 2013, FERC assessed civil penalties totaling $435 million and ordered $34.9 million in disgorgement against Barclays Bank PLC (Barclays) and further assessed civil penalties totaling $18 million against certain individual traders for allegedly manipulating energy markets in and around California between 2006 and 2008.81 The penalty ordered against Barclays marks the largest of its kind in the agency’s history. Barclays and the individual traders have denied FERC’s allegations and elected to challenge the penalties in federal court.

On October 9, 2013, FERC petitioned the U.S. District Court for the Eastern District of California to issue an order affirming the assessment of penalties against Barclays and the individual traders. Barclays and the individual traders responded on December 16, 2013 by filing a motion to dismiss FERC’s petition.82 The motion raises a number of important legal questions relating to FERC’s authority to police electricity markets. The motion, for example, argues that FERC lacks jurisdiction over the relevant transactions because they were commodity futures transactions over which the Commodity Futures Trading Commission (CFTC) has exclusive jurisdiction under the Commodity Exchange Act, and because they did not result in physical delivery or transmission of electricity, as the movants claim is required for FERC jurisdiction under the FPA. FERC filed a brief opposing Barclay’s and the individual traders’ motion to dismiss on February 14, 2014 and Barclay’s accordingly filed a reply brief on March 21, 2014.83 The motion is still pending before the court.

D. Up-To Congestion Investigations, Settlements, and Proceedings

FERC has also focused on investigating “gaming” of market rules in the PJM market under the Anti-Manipulation Rule with respect to so-called Up-to Congestion (“UTC”) transactions. FERC defines UTC transactions as a “product that enables a trader to profit if the congestion price spread between two nodes changes favorably between the Day Ahead Market (DAM) and the Real Time Market (RTM).”84 To be profitable, the spread change must exceed the costs of the trade. Notable investigations and settlements are discussed below.

1. Oceanside Power, LLC

In 2013, FERC settled allegations that Oceanside Power, LLC and an individual trader (“Oceanside”) violated the Anti-Manipulation Rule by allegedly entering into UTC transactions in PJM markets designed to appear to be spread trades for the purpose of collecting “Marginal Loss Surplus Allocation” (MLSA) payments provided for in PJM’s tariff.85 Oceanside agreed to pay a $51,000 civil penalty and to disgorge $29,563, plus interest.86 The trader also agreed not to trade in FERC regulated electricity markets, or in products or instruments that are based on the price of electricity for one year.

2. Powhatan Energy Fund, LLC

On December 17, 2014, FERC issued an Order to Show Cause and Notice of Proposed Penalty against Powhatan Energy Fund, LLC, HEEP Fund Inc. CU Fund Inc., and the companies’ principal trader (collectively, “Powhatan Respondents”).87 The order alleged that the Powhatan Respondents engaged in manipulative UTC trading by “plac[ing] UTC trades in opposite directions on the same paths, in the same volumes, during the same hours for the purpose of creating the illusion of bona fide UTC trading and thereby to capture large amounts of MLSA that PJM distributed at that time to UTC transactions with paid transmission,” and proposed civil penalties totaling almost $29 million against the companies and $1 million against the trader.88

The Order to Show Cause and Notice of Proposed Penalty comes after months of public disagreement between the Powhatan Respondents and FERC. On August 5, 2014, FERC issued a Notice of Alleged Violation against the Powhatan Respondents alleging violations of the Anti-Manipulation Rule based on UTC trading.89 Earlier in 2014, in an unprecedented move, Powhatan launched a website publicly responding to a non-public Preliminary Notice of Violation90 alleging the same violations set forth in the Notice of Alleged Violation. The website contained a summary of communications between FERC and Powhatan’s legal representatives, position papers and videos from experts, and other materials related to Powhatan’s defense. The website claimed that FERC’s investigation violates due process because there were no pre-existing FERC rules stating that the trades were unlawful. Powhatan also claimed that the Fund entered into the subject transaction in an open, transparent manner without concealment or misrepresentation, and that such actions to take advantage of market flaws are not manipulative.91

3. City Power Marketing, LLC

On August 25, 2014, FERC issued a Notice of Alleged Violation against City Power Marketing, LLC (“City Power”) and its principal owner for alleged manipulation relating to UTC trading in the PJM regional market from 2010 to 2014.92 In the Notice, FERC also alleged that City Power made false statements and omitted material information during the investigation.93 The investigation is ongoing.

VII. Demand Response

On May 23, 2014, the D.C. Circuit vacated FERC Order No. 745 in its entirety by a vote of 2 to 1.94 Order No. 745 had directed Regional Transmission Organizations and Independent System Operators to pay suppliers of cost-effective demand response resources in their day ahead and real-time wholesale power markets the full locational marginal price (LMP) used to compensate generation suppliers to these markets.

The court vacated Order No. 745 on two separate grounds. First, the court held that the order directly regulates retail markets which are outside of FERC’s jurisdiction. The court rejected FERC’s argument that it had statutory authority to set rates for demand response in wholesale markets because the Federal Power Act authorizes FERC to ensure all rules and regulations “affecting…rates” in connection with the wholesale sale of electric energy are “just and reasonable.” The court ruled that demand response involves retail customers and their decisions whether to purchase electricity at retail and the resulting level of retail electricity consumption are within the exclusive ambit of state regulation.

Second, the court ruled that even if FERC had jurisdiction to adopt Order No. 745, the Order No. 745 was “arbitrary and capricious” in violation of the Administrative Procedure Act. FERC failed to respond directly to the dissenting opinion of FERC Commissioner Moeller to Order No. 745, which posited that the LMP payment mechanism mandated in Order No. 745 over-compensated demand response resources, because in addition to being paid the full LMP demand response providers may retain the savings associated with the provider’s avoided retail generation cost.

In dissent, Senior Circuit Judge Edwards criticized the majority decision for not deferring to FERC’s reading of the Federal Power Act. According to Judge Edwards, the Federal Power Act is ambiguous as to whether demand response falls within FERC’s jurisdiction over wholesale sales of electric energy. Amid such ambiguity, Judge Edwards concluded that the court must defer to FERC’s permissible construction of the Federal Power Act. Judge Edwards also deferred to FERC with respect to its mandate that demand response resources be paid the full LMP, finding FERC’s defense of the LMP payment mechanism adequate.

The Solicitor General of the United States, representing FERC before the Supreme Court, filed a petition with the U.S. Supreme Court for a writ of certiorari to review the decision and stated that the rules in Order No. 745 for participation by demand-response resources in wholesale electric-power markets are an “integral feature” of the markets “that is of substantial importance to the proper functioning of those markets and to assuring just and reasonable rates for wholesale power in those markets.”95

VIII. Crude Oil by Rail

National and state agencies took numerous steps in 2014 to regulate crude oil shipments by rail. The number of such shipments has increased significantly as producers extract more oil from the Bakken Shale region. In the wake of several high-profile rail accidents involving Bakken crude, the Pipeline and Hazardous Materials Safety Administration (PHMSA) and U.S. Department of Transportation (DOT) issued two important emergency orders and released a Notice of Proposed Rulemaking (NPRM) in an effort to increase safety. In addition, the North Dakota Industrial Commission issued an order to establish conditioning standards for crude oil prior to shipment.

A. Emergency Orders Requiring Proper Testing, Safer Treatment, and Advance Notification of Crude Oil Shipments

On February 25, 2014, DOT issued an Emergency Order requiring proper testing of crude oil prior to shipment and mandating safer treatment of the less-hazardous “packing group III” crude oil.96 Specifically, the Order requires that companies offering crude oil for shipment: (1) ensure that the crude oil is tested with sufficient frequency and quality; and (2) treat crude oil shipments as packing group I or packing group II hazardous materials even if the oil has been classified as less-hazardous packing-group III.

The Order was preceded by a Safety Advisory on November 20, 2013, which warned that Bakken crude oil may be more flammable than traditional heavy crude and emphasized the importance of proper characterization, classification and selection of a packing group for flammable liquids such as crude oil. Consistent with the Safety Advisory, the Order explained that misclassification can lead to the “use of unauthorized containers that lack the required safety enhancements necessary to safely transport PG I and PG II materials.”97 PHMSA had issued $93,000 in proposed civil penalties earlier in the month, after investigations of Bakken crude oil for the agency’s “Operation Classification” revealed that companies had classified shipments improperly.98

DOT issued another Emergency Order on May 7, 2014, requiring railroad carriers that transport one million gallons or more of Bakken crude oil in a single train to inform first responders in towns and communities through which the train passes.99 The Order requires that such railroad carriers notify the State Emergency Response Commission (SERC) in each state in which it operates and provide information regarding the expected volume, frequency and transportation route of those shipments. The Order also requires that carriers include emergency response information and a point of contact in their notifications, as well as alert the SERC to any material changes in volume or frequency of shipments by rail.

B. Notice of Proposed Rulemaking for “High-Hazard Flammable Trains”

On July 23, 2014, PHMSA issued a comprehensive NPRM aimed at establishing new safety requirements for “high-hazard flammable trains” (HHFTs).100 The NPRM defines an HHFT as any train comprised of 20 or more carloads of Class 3 flammable liquid, and thus would primarily impact materials shipped in high-volume, such as crude oil and ethanol. The NPRM proposes enhanced tank car standards, a new classification and testing program, and operational requirements such as restrictions on speed and improved braking controls. It also proposed to codify the May 7, 2014 Emergency Order requiring trains containing one million gallons of Bakken crude to notify SERCs of their expected volume, frequency and transportation routes.

Importantly, the NPRM would set new standards for future tank cars and proposes the phase out of older DOT 111 tank cars used in HHFTs, unless the tank cars are retrofitted to improve safety. The NPRM was accompanied by a report showing that Bakken crude oil tends to be more volatile and flammable, and therefore more likely to be classified as a packing group I flammable liquid.

C. North Dakota Order to Establish Conditioning Standards

The North Dakota Industrial Commission issued an order on December 9, 2014, requiring North Dakota operators to properly separate production fluids into gas and liquid prior to shipment.101 The order sets temperature and pressure standards for conditioning equipment to ensure that light hydrocarbons are removed properly. If production facilities use conditioning equipment that does not meet those standards, the order requires companies to ensure that the crude oil has a Reid Vapor Pressure of no more than 13.7 pounds per square inch. Finally, the order prohibits the blending of light hydrocarbons back into oil supplies prior to shipment.

IX. Electric Generating Capacity Markets Ligitation

As previously reported,102 two federal district court decisions, one in New Jersey and one in Maryland, struck down state programs that encouraged the construction of new gas-fired capacity in the PJM region where generating capacity was deemed insufficient by state authorities.103 Both cases were upheld on appeal to the Third and Fourth Circuits, respectively, and may be considered by the U.S. Supreme Court as petitions for certiorari have been filed.

On September 12, 2014, the Third Circuit ruled that New Jersey’s subsidy program for new power plant construction usurped FERC’s jurisdiction over electricity markets, affirming the district court’s decision.104 The court reasoned that the Federal Power Act gives FERC authority to regulate interstate sales of electric capacity, and that the incentives impermissibly constituted regulation of capacity rates, because they essentially set capacity prices. The court noted the concern of amici for appellants that a ruling against the program would “hamstring state-led efforts to develop renewable and reliable electric energy resources,” but noted that states are free to use other means.105

The ruling came just three months after the Fourth Circuit similarly concluded that Maryland’s program subsidizing new gas-fired power development encroached on FERC territory.106 Relaying on a “wealth of case law” confirming the exclusive power of FERC to regulate wholesale sales of energy in interstate commerce, the Fourth Circuit concluded that the Maryland order was field preempted because it essentially “supplants the rate generated by the auction with an alternative rate preferred by the state.”107 The court rejected the argument that the Maryland program does not actually set a rate, and found that, while states retain the ability to regulate generating facilities, they may not exercise that authority in such a manner as to impinge on FERC’s exclusive jurisdiction over wholesale rates.

The rulings do not mean that the door is shut on state incentives. The Third Circuit said that New Jersey could offer other incentives to developers, such as tax breaks or favorable lease terms. The state could even “directly subsidize generators so long as the subsidies do not essentially set wholesale prices.”108 Similarly, in the Fourth Circuit, the court expressly noted that its holding was limited to the Maryland program, and that it was not offering an opinion on other state efforts to incentivize new generation. The court concluded that “[o]bviously, not every state regulation that incidentally affects federal markets is preempted.”109

X. Renewables and Distributed Generation

State public utility commissions across the United States grappled in 2014 with how to incorporate distributed generation and “net metering” into rate design. Utilities argued that giving consumers credit for energy produced with distributed generation (such as residential solar panels that connected with the grid) unfairly reduced utility revenues. Because many utilities’ costs were recovered with variable, per-KWh charges, utilities argued that distributed generation users were not paying their fair share of the fixed costs needed to provide the electricity they used. Advocates of distributed generation countered that high fixed prices (coupled with lower variable prices) encouraged energy use and would allow the utilities to avoid competition from distributed generation. Fixed rate and other proposals have been introduced in many states, and Minnesota is developing an innovative solution to the issue.

Statehouses and utility commissions also debated other efforts to promote renewable energy and energy efficiency. Some states, such as Washington and Nevada, initiated or implemented measures that would reduce the environmental impact of energy production. Ohio, on the other hand, passed legislation to limit wind energy and roll back renewables targets.

A. Rate Changes as a Response to Distributed Generation

In 2014, utilities proposed fixed rate increases in many states in response to increasing use of distributed generation. In Wisconsin, Madison Gas and Electric had proposed an increase in residential fixed rates from $10.50 per month in 2014 to $67 in 2017 while dropping variable rates by over 67 per cent.110 After a dispute with Wisconsin’s Citizen’s Utility Board, the utility altered the plan to increase the fixed charge to $22 in 2015 and reduce per-KWh charges only fractionally.111 Other Wisconsin utilities also enacted fixed charge increases of $7 to $15 per month.112

In Arizona, where the climate is ideally suited to distributed solar generation, the Arizona Corporation Commission approved by a 3-2 vote new charges for users of distributed generation to help recover utilities’ fixed costs.113 Users will be charged $0.70 per KW per month.114 Arizona also ordered a new docket to study the costs and benefits of distributed generation. Dissenting commissioners argued that the new charge only accounted for a small portion of the fixed cost that is shifted to consumers who do not use distributed generation.115

In California, the Public Utility Commission implemented certain changes to its distributed generation program that were mandated by a 2013 law. The commission ruled that distributed generation would be entitled to the compensation structure in effect at the time of installation for 20 years to promote investment by providing revenue certainty.116 In 2015, the commission will take up further rate design changes.117 (These initiatives in California are discussed in more detail below.) In Hawaii, another state with significant solar production, Hawaiian Electric Co. has proposed increasing fixed charges to $61 per month and adding a charge to connect distributed solar generation to the grid of $16.118

In Iowa, conflict over distributed generation reached the courts, as Interstate Power and Light Co. challenged the right of consumers to satisfy their own energy needs with distributed generation within the utility’s exclusive territory.119 In July 2014, the Iowa Supreme Court ruled that the on-site solar company at issue was not regulated as a utility and could therefore sell its electricity to the City of Dubuque.120

The New York Public Service Commission initiated a proceeding to look at transforming utility practices to improve efficiency, facilitate customer choices, and account for new generation and distribution technologies121 (discussed further below) and the Colorado Public Utility Commission opened a proceeding to solicit input on the impact of net metering and other approaches to distributed generation.122

B. Minnesota Implements New Formula to Calculate the “Value of Solar”

In 2014, Minnesota pushed toward implementation of 2013 legislation requiring that utilities have the option to provide distributed generation users with a rebate based on the “value of solar” rather than the ordinary variable per-KWh charge. This value accounts separately for avoided fuel cost, avoided fixed and variable operations and maintenance, avoided capacity and distribution charges, and avoided environmental cost.123 Minnesota’s Department of Commerce laid out a detailed methodology for calculating each element of this cost.124 However, the Public Utilities Commission has so far declined to use value of solar pricing, instead opting for further study.125

Under Minnesota’s 2013 law, solar customers are to be billed for gross electricity consumption at the standard rate for electricity and then receive a credit for solar generation based on the value of solar.126 The program is not intended to be an incentive to install distributed generation, but instead has the goal of evenhandedly valuing energy from distributed generators to ensure efficient market signals and eliminate cross-subsidization of distributed generation by conventional generation.127

C. Other State Renewable Energy and Energy Efficiency Proposals

States and localities took up other issues related to renewables and energy efficiency in 2014. Arizona approved a rate increase of $0.01/KWh to cover costs of renewable generation needed to meet a state mandate.128 In Washington, an executive order convened a task force to recommend market mechanisms to reach carbon reduction thresholds set by the Pacific Coast Collaborative.129 On the other hand, the Ohio legislature introduced bills to curtail environmental initiatives, requiring that wind turbines be set farther back from adjacent property130 and reducing “advanced energy” and other renewable mandates.131

XI. New Electric Distribution Platforms

A. New York Public Service Commission’s Reforming Energy Vision

In December 2013, the New York Public Service Commission (NYPSC) announced a fundamental reconsideration of regulatory paradigms and markets of electric power systems, examining how its policy objectives are served by both clean energy programs and the regulation of distribution utilities.132 Following the NYPSSC’s Order, the New York State Energy Planning Board released a draft of the 2014 State Energy Plan, which called for the NYPSC to enable and facilitate new energy business models for utilities, energy service companies, and customers to be compensated for activities that contribute to grid efficiency.

Thereafter, the NYPSC initiated Case 14-M-0101, Reforming the Energy Vision (REV). In its order, the Commission described core policy objectives of customer knowledge, market animation, system-wide efficiency, fuel and resource diversity, system reliability and resiliency, and indicated that reduction in carbon emissions was also implied in its objectives.133 In support of Case 14-M-0101, NYPSC Staff prepared a proposal articulating a preliminary framework for REV that recommended that utilities alter their operation to become Distributed System Platform Providers (DSPP).134 As a DSPP, a utility would actively manage and coordinate distribution energy sources or generate power from many small resources and connect them to the system. The Staff proposal asserts such an approach would better achieve the NYPSC’s policy objectives.

As a companion to the REV order, the NYPSC in May initiated a proceeding (Case 14-M-0094) to address the future of New York clean energy programs that are currently funded by a surcharge on the delivery portion of customers’ utility bills. The proposed New “Clean Energy Fund” (CEF) is intended to ensure the delivery and continuity of clean energy programs, enhance program efficiency, and manage the transition of current programs, such as the System Benefit Charge, the Renewable Portfolio Standard and the Energy Efficiency Portfolio Standard, to better align with the market outcomes approach envisioned by the REV. According to the draft environmental statement prepared for the REV and CEF, the overreaching goal of the two proposed programs is to transform the ways in which New York State generates, distributes and manages energy, and, in so doing, reduce the State’s dependence on fossil fuels, increase system reliability and resilience, reduce harmful environmental pollution and lower the overall costs of power across all sectors of the economy.135

The NYPSC adopted a two-phase schedule for Case 14-M-0101. Track 1 considers issues related to the concept and feasibility of a DSPP, as described in the NYPSC Staff preliminary framework. Track 2 focuses on regulatory changes and ratemaking issues. Task Forces and working groups have been formed and are working on both tracks.

With regard to Track 1, the NYPSC Staff released a further straw proposal on August 22, 2014. Comments have been filed by the interested parties, and the NYPSC has indicated it expects to reach a generic policy determination in 2015. With regard to Track 2, the stakeholders have responded to a series of questions, and the NYPSC Staff is now working on a definitive straw proposal on regulatory and ratemaking issues.

The NYPSC made a Determination of Significance, noting that the REV and CEF actions could potentially have one or more significant adverse impacts on the environment, and called for the preparation of an Environmental Impact Statement. A draft EIS was issued on October 14, 2014.

B. California’s Distributed Resources Rulemaking

For more than a decade, it has been California’s policy to require each of its investor-owned electric utilities to consider nonutility-owned Distribution Energy Resources (DERs) as a possible alternative to investments in its distribution system in order to ensure reliable electric service at the lowest possible cost.136 In 2013, the legislature enacted PU Code Section 769 requiring IOUs to submit Distribution Resource Plan Proposals (DRPs) to the California Public Utilities Commission (CPUC). Section 769 requires investor-owned utilities (IOUs) to submit DRPs that recognize the need for investment, to integrate cost-effective DERs and for activity identifying barriers to the deployment of DERs. The CPUC is authorized to modify and approve an IOU’s DRP “as appropriate to minimize overall system costs and maximize ratepayer benefit from investments in distributed resources.”137

In August 2014, the CPUC opened Rulemaking 14-08-013 to establish policies, procedures, and rules to guide IOUs in developing their DRPs and to review, approve, or modify and approve the plans. The goal of the plans is to begin the process of moving the IOUs towards a more full integration of DERs into distribution system planning, operations, and investment. Section 769 requires that DRPs must provide a roadmap for integrating cost-effective DERs into the planning and operations of IOUS’ electric distribution systems with the goal of yielding net benefits to ratepayers. In their DRPs, the IOUs are required to define the criteria for determining what constitutes an optimal location for the deployment of DERs, and then to identify specific locational values for DERs, augmented or new tariffs, and programs to support efficient DER deployment, and the removal of specific barriers to deployment of DERs.

The IOUs were required to respond (and other interested parties were invited to respond) to a number of specific questions related to implementing Section 769 and a draft paper for shaping the California’s energy framework with regard to DERs. Comments were filed and a workshop was held in September. IOUs will file their DRPs in July 2015, and final CPUC approval of the DRPs is anticipated to occur toward the end of the first quarter of 2016.

XII. Energy Storage

A. Federal Developments

1. Department of Energy

In December 2013, the U.S. Department of Energy (DOE) issued a report entitled “Grid Energy Storage” in which it discussed the importance of energy storage systems in the modernization of the U.S. electric grid. The report discussed the need to modernize the electric grid to help the nation meet the challenge of climate change by relying on more energy from renewable sources while maintaining a robust and resilient electricity delivery system. Specifically, the report stated:

Energy Storage Systems (ESS) will play a significant role in meeting these challenges by improving the operating capabilities of the grid as well as mitigating infrastructure investments. ESS can address issues with timing, transmission, and dispatch of electricity, while also regulating the quality and reliability of the power generated by traditional and variable sources of power. ESS can also contribute to emergency preparedness.138

It concluded that modernizing the grid will require substantial deployment of energy storage. Quoting from an Information Handling Services, Cambridge Energy Research Associates report, DOE stated that the energy storage business could grow from $200 million in 2012 to a $19 billion industry by 2017.139

Further, in December 2014, DOE published a report on energy storage safety and reliability—one of the key challenges identified in the Grid Energy Storage report relating to the widespread deployment of energy storage.140 The report identified three components to safety: (1) system engineering and validation techniques; 2) incident response; and 3) standardization of safety determinations in the form of codes, standards and regulations. The report explored each component with a view toward current practices and best practices going forward, with the ultimate goal of developing a high-level roadmap to enable the safe deployment of energy storage.

B. State Storage Proposals

1. California

California has taken the lead to include energy storage in its electric utilities and energy suppliers resource planning. In 2010, the California legislature enacted AB 25141421directing the CPUC to determine appropriate targets, if any, for each load-serving entity to procure viable energy storage systems (ESS) and to set dates for any targets deemed appropriate to be achieved. Under AB 2514, an ESS is defined as commercially available technology that is capable of absorbing energy, storing it for a period of time, and thereafter dispatching the energy. To qualify as an ESS under AB 2514, the storage system also must have certain other delineated characteristics, including being cost-effective and either reducing emissions of greenhouse gases, reducing demand for peak electric generation, deferring or substituting for an investment in generation, transmission or distribution asset or improving the reliable operation of the electric transmission or distribution grid.142

In December 2010, the CPUC opened a rulemaking143 to implement the provisions of AB 2514. Thereafter, in October 2013 (Decision (D.) 13-10-040), the CPUC established procurement targets for each of the IOUs and procurement requirements for other load-serving entities.144 The CPUP ordered that by 2020, the three major IOUs should procure a total of 1.35 GW of storage (580 MW each for Southern California Edison Company (SCE) and Pacific Gas and Electric Company (PG&E); and 165 MW for San Diego Gas & Electric Company (SDG&E)). Individual targets were set for each utility for years 2014, 2016, 2018 and 2020, as well as for each point of interconnection (i.e., transmission, distribution and customer (behind the meter)).

On February 28, 2014, the three IOUs submitted applications for approval of their respective storage procurement plans. In its filing,145 SDG&E noted that based on existing projects, it is already in compliance with 2014 procurement targets for the transmission and customer domain and is in compliance with the distribution domain if it elects to transfer energy between domains or to defer procurement as allowed by D.13-10-040. Nevertheless for transmission and distribution domains, SDG&E said that it is still planning to conduct solicitations for the 2014 cycle in order to capture any cost-effective, viable storage. It stated that it is interested in procuring 10 MW of local and flexible capacity requirements (transmission connected), 2 MW of local and flexible capacity requirements (distribution connected) and 4 MW of distribution reliability/power quality, but may procure more or less based on the bids received. SDG&E included a proposed Energy Storage System Power Purchase Tolling Agreement as part of its application.

PG&E also submitted its application.146 D.13-10-040 pre-approved certain transmission, distribution and customer-side energy storage projects for which PG&E had previously executed contracts or to which it had otherwise committed. PG&E indicated that it intends to count projects that are currently operational towards its 2014 targets. Including these projects will reduce PG&E’s 2014 distribution storage by 8.5 MW, leaving a total 2014 procurement of 21.5 MW, and will also reduce its customer-related procurement target by 3.5 MW, resulting in a total customer-side target in 2014 of 6.5 MW. PG&E also stated that it has procured 150 MW of pre-approved transmission-level storage that it will apply to future energy storage procurement targets between 2016 and 2020. PG&E anticipates that 38 MW will be used to offset its transmission related energy storage targets in 2016, 49 MW in 2018 and 63 MW in 2020. PG&E stated that it intends to meet its remaining energy storage requirements through an RFO process, but reserved the right to use other means too.

SCE stated that it intends to meet its ESS target of 90 MW of energy storage procurement in 2014 and that it may procure additional storage.147 SCE’s application identified certain existing storage targets that are eligible to count towards SCE’s procurement targets. SCE included a Pro Forma Energy Storage Agreement in its application and indicated that it did not intend to limit itself to procuring storage through a competitive solicitation, but planned to consider bi-lateral contract opportunities as well as utility owned storage. RFP’s were issued in December 2014.

In September 2013, the California ISO (CAISO), CPUC, and the California Energy Commission announced that they were partnering to develop a joint energy storage roadmap to advance energy storage in California. The roadmap will propose action and venues to address identified barriers related to storage. Based on inputs received from various stakeholders, a draft roadmap was made available in early October and a workshop was held on October 13 to discuss the draft and solicit feedback.148 The final roadmap was completed by the end of 2014. 149

The storage targets set forth in D.13-10-040 for SCE are only part of SCE’s energy storage plans. ESS is also being considered as a part of the utility’s long-term procurement planning process. In the same general time frame as the CPUC was conducting its rulemaking on energy storage (R.10-12-007), the CPUC also was considering its Long-Term Procurement Planning Process (LTPP) for the ten-year period 2012-2022.150 The CPUC divided the 2012 LTPP into four tracks, two of which are relevant here. First, the CPUC indicated that it would consider whether there is a local resource need over the next several years. Track 1 examines the local requirement need for SCE’s two local capacity areas—the Los Angeles Basin and Big Creek/Ventura. SCE’s long-term local capacity requirements are expected to increase significantly due to the retirement of 4,900 MW of steam-generating plants in the Los Angeles Basin that utilize once-through cooling.151

In February 2013, the CPUC issued D.13-02-015 regarding SCE’s Phase 1 procurement for local capacity requirements. The Commission authorized SCE to procure between 1,400 MW and 1,800 MW of electrical capacity in the West Los Angeles subarea and between 215 MW and 290 MW in the Moorpark subarea. Of the total 1,800 MW authorized, the Commission mandated that at least 50 MW be procured from energy storage resources and said that an additional 750 MW of new capacity could be satisfied by energy storage.

Second, the CPUC also established as part of the LTPP a Track 4 requirement to consider the impacts of the premature retirement of the San Onofre Nuclear Generating Station (SONGS) on local reliability needs. SCE has indicated that it intends to institute a pilot program targeted at transmission substations in areas highly affected by the retirement of SONGS to acquire up to 400 MW of competitively priced preferred resources or ESS to meet its reliability needs.

On November 5, 2014, SCE announced it had signed contracts for 2,221 MW of power in compliance with D.13-02-015. Of this total, SCE signed contracts with storage providers for 260 MW, involving 24 separate contracts. This is five times the amount mandated by the CPUC in D.13-02-015 for energy storage resources.

2. New York

Under its operating agreement152 with the Long Island Power Authority (LIPA), PSEG-Long Island is required to submit a Utility 2.0 Plan to LIPA for approval. On July 1, 2014 PSEG-Long Island released its plan,153 which it later updated in October. The plan includes 5 MW/25MWh of battery storage on the South Fork of Long Island, which would be owned and operated by PSEG-Long Island. Previously, in 2013 LIPA issued its own RFP154 for approximately 150 MW of energy storage. No action has been taken to date.

* Senior of Counsel at Morrison & Foerster LLP in Washington, D.C., where he represents a range of clients on energy regulatory, enforcement, compliance, transactional, commercial, legislative, and public policy matters. He serves as Editor-in-Chief of the Energy Law Journal (published by the Energy Bar Association) and is a former General Counsel and Vice-President for Legislative and Regulatory Policy at Constellation Energy. The author would like to thank members of Morrison & Foerster’s energy regulatory team for their assistance in developing this report. The views expressed in this report are his own, and do not necessarily reflect those of Morrison & Foerster or any of its clients.

  1. 15 USC § 717.
  2. Liquefied Natural Gas Export Decisions, 79 Fed Reg 48132, (2014).
  3. Ibid at 48133.
  4. Ibid at 48135.
  5. Ibid.
  6. Sierra Club v FERC, No 14-1249 (DC Cir filed 17 November 2014); Sierra Club v FERC, No 14-1190 (DC Cir filed 29 September 2014).
  7. Executive Office of the President, The President’s Climate Action Plan (June 2013), online: The White House <>.
  8. Coral Davenport, Obama Builds Environmental Legacy with 1970 Law (26 November 2014), online: New York Times <>.
  9. Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, 79 Fed Reg 34830 (2014).
  10. Robert S. Fleishman, “The Washington Report,” Energy Regulation Quarterly (5 May 2014), online: [The Washington Report].
  11. Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units, 79 Fed Reg 1430 (2014).
  12. In re Murray Energy Corp., No 14-1112 (DC Cir filed 18 June 2014); West Virginia v EPA, No 14-1146 (DC Cir filed 1 August 2014).
  13. Nebraska v EPA, No 4:14-cv-3006, 2014 WL 4983678 (D Neb 2014).
  14. Office of the Press Secretary, Press Release, U.S.-China Joint Announcement on Climate Change (12 November 2014), online: The White House <>.
  15. See, e.g., Coral Davenport, In Climate Deal with China, Obama May Set 2016 Theme (12 November 2014), online: New York Times <>.
  16. The Washington Report, supra note 10.
  17. 134 S Ct 1584 (2014).
  18. 134 S Ct 2427 (2014).
  19. Envtl. Prot. Agency, Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities (19 December 2014), online: EPA <>.
  20. Ibid at 10-14.
  21. See, e.g., Wallach v Town of Dryden, 23 NY (3d) 728 (2014), reargument denied, 24 NY (3d) 981 (2014) [Wallach].
  22. 42 USC § 300h(d)(1)(B)(ii) (2014).
  23. Wallach, Supra note 754-55.
  24. Frew Run Gravel Products v Town of Caroll, 71 NY (2d) 126 (1987).
  25. Wallach, supra note 21 at 753.
  26. Ibid at 746.
  27. Ibid at 749-50.
  28. Alan Neuhauser, New York, Citing Health Risks, Moves to Ban Fracking (2014 December 17), online: US News <>.
  29. Keith Goldberg, Calif. County Fracking Bans Set Stage for Statewide Brawl (7 November 2014), online: Law360 <>.
  30. Molly Hennessy-Fiske, In Denton, Texas, Voters Approve “Unprecedented” Fracking Ban (7 November 2014), online: LA Times <>; Laura Arenschield, Athens Votes to Ban Fracking (6 November 2014), online: Columbus Dispatch <>.
  31. Patterson v City of Denton, No D-1-GN-14-004628 (Tex Dist Ct 53d filed 5 November 2014).
  32. Nicholas Sakelaris, Railroad Commission Head Talks Denton Frack Ban, What Agency Did Wrong (7 November 2014), online: Dallas Business Journal <>.
  33. Illinois Department of Natural Resources, Hydraulic Fracturing (last visited 30 January 2015), online: IDNR <>.
  34. Ill Pub Act No 98-22 (2013).
  35. Nevada. Commission on Mineral Resources, Adopted Regulation of the Commission on Mineral Resources, (effective 24 October 2014); online: NCMR <>.
  36. Reese River Basin Citizens Against Fracking, LLC v Bureau of Land Management., No 3:14-cv-00338-MMD-WGC, 2014 WL 4425813 (D Nev 8 September 2014).
  37. Ibid at 3-4.
  38. Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities, 18 CFR Part 284, 146 FERC ¶ 61,201 (20 March 2014).
  39. California System Operator Corporation, 146 FERC ¶ 61,202, Docket No ELI4-22000 (20 March 2014).
  40. Posting of Offers to Purchase Capacity, 146 FERC ¶ 61,203, (20 March 2014).
  41. Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 136 FERC ¶ 61,051 (21 July 2011) [Order No 1000].
  42. South Carolina Public Service Authority v FERC, 762 F.3d 41 (DC Cir 2014) [South Carolina Public Service Authority].
  43. Order No 1000, supra note 41 at paras 6-10.
  44. South Carolina Public Service Authority, supra note 42 at 84.
  45. Sharon Brown, a securities lawyer, was appointed to fill an open Democratic seat. J. Christopher Giancarlo, a brokerage executive, was appointed to fill an open Republican seat. See U.S. Commodity Futures Trading Comm’n, Commissioner Terms of Office, online: CFTC <>.
  46. For example, Chairman Massad has described his responsibility as both to “meet the congressional mandate of bring this [the swaps industry] out of the shadows, and build conditions that allow the market to thrive. Markets thrive when private actors find it beneficial to trade.” See Aaron Timms, New CFTC Boss Timothy Massad Goes Soft on Regulation (13 November 2014), online: Institutional Investor <>.
  47. Forward Contracts with Embedded Volumetric Optionality, 79 Fed Reg 69073 (proposed 20 November 2014).
  48. Further Definition of “Swap,” “Security-Based Swap,” and “Security-Based Swap Agreement”; Mixed Swaps; Security-Based Swap Agreement Recordkeeping, 77 Fed Reg 48208 (2012).
  49. Ibid at 48238.
  50. See, e.g., Statement of Commissioner Wetjen, 79 Fed Reg 69077 (2014).
  51. Ibid (emphasis added).
  52. Exclusion of Utility Operations-Related Swaps with Utility Special Entities from De Minimis Threshold for Swaps with Special Entities, 79 Fed Reg 57767 (2014) (to be codified at 17 CFR pt 1).
  53. A “utility operations related swap” would be a swap to which at least one of the parties is a utility special entity that is using the swap to hedge or mitigate commercial risk, and that is related to an exempt commodity. In addition, the swap must be an electric energy or natural gas swap, or associated with the operations or compliance obligations of a utility special entity as set forth in the CFTC’s final rule.
  54. A “utility special entity” is defined as a special entity (generally, certain governmental entities, pension plans, government plans or endowments) that owns or operates electric or natural gas facilities, electric or natural gas operations or anticipated electric or natural gas facilities or operations; supplies natural gas or electric energy to other utility special entities; has public service obligations or anticipated public service obligations under federal, state, or local law or regulation to deliver electric energy or natural gas service to utility customers; or is a federal power marketing agency as defined in Section 3 of the FPA, 16 USC § 796(19).
  55. See CFTC Letter, Staff No-Action Relief: Revised Relief from the De Minimis Threshold for Certain Swaps with Utility Special Entities, No 14-34 (21 March 2014), online: CFTC <>.
  56. The “Prudential Regulators” are the Board of Governors of the Federal Reserve System, the Office of the Comptroller of the Currency, the Federal Deposit Insurance Corporation, the Farm Credit Administration, and the Federal Housing Finance Agency.
  57. See Margin Requirements for Uncleared Swaps for Swap Dealers and Major Swap Participants, 79 Fed Reg 59898 (proposed 3 October 2014) (to be codified at 17 CFR pts 23 and 140).
  58. See Basel Comm. on Banking Supervision, Margin Requirements for Non-Centrally Cleared Derivatives (September 2013), online: Bank for International Settlements <>.
  59. Records of Commodity Interest and Related Cash or Forward Transactions, 17 CFR § 1.35(a)(1).
  60. Records of Commodity Interest and Related Cash or Forward Transactions, 79 Fed Reg 68140 (2014).
  61. Ownership and Control Reports, Forms 102/102S, 40/40S, and 71, 78 Fed Reg 69178 (2013) (to be codified at 17 CFR pts 15, 17, 18, and 20).
  62. “OCR” stands for Ownership and Control Reporting.
  63. Reporting entities must file a Form 102A when an account becomes reportable; a Form 102B when an account reaches a “Reportable Trading Volume Level” of 50 or more contracts on a designated contract market or SEF with the same product identifier during a single trading day; and a Form 102S for a swap counterparty or customer consolidated account with a reportable position.
  64. Form 40s must be filed by owners and controllers upon special call by the CFTC.
  65. Form 71s must be filed by originators of an omnibus volume threshold account or an omnibus reportable sub-account.
  66. The Washington Report, supra note 10.
  67. Position Limits for Derivatives and Aggregation of Positions, 79 Fed Reg 71973 (2014).
  68. In December 2014, the CFTC reopened the comment period again with respect to certain issues as they pertain to agricultural commodities. The reopened comment period closed on January 22, 2015.
  69. Federal Energy Regulatory Commission, 2014 Report on Enforcement, FERC Docket No AD07-13-008 (20 November 2014), online: FERC <>. The Report provides additional transparency and guidance for regulated entities and the public.
  70. See Prohibition of Energy Market Manipulation, 16 USC § 824v(a) (2012); Prohibition on Market Manipulation 15 USC § 717c-1 (2012).
  71. BP America Inc., 144 FERC ¶ 61,100 (Docket No IN13-15-000) (2013).
  72. Order Granting Rehearing for Further Consideration at 1, BP America Inc., FERC (Docket No IN13-15-001) (14 July 2014).
  73. Direct testimony was submitted by Dr. Rosa M. Abrantes-Metz, Dr. Patrick J. Bergin, and Dr. Ehud I. Ronn.
  74. Lincoln Paper & Tissue, LLC, 144 FERC ¶ 61, 162 (2013); Competitive Energy Services LLC, 144 FERC ¶ 61, 163 (2013); Richard Silkman, 144 FERC ¶ 61, 164 (2013).
  75. “Demand response” refers to a reduction in customers’ consumption of electricity from their anticipated consumption in response to an increase in the price of electricity or to incentive payments designed to induce lower electricity consumption.
  76. Petition for an Order Affirming the Federal Energy Regulatory Commission’s August 29, 2013 Order Assessing Civil Penalty Against Lincoln Paper and Tissue, LLC, FERC v Lincoln Paper & Tissue, LLC, No. 1:13-cv-13056-DPW (D Mass) (2 December 2013). The motion argues, among other things, that FERC’s position is time-barred by the applicable statute of limitations and that FERC lacks jurisdiction over demand response. CES and Silkman also filed motions to dismiss.
  77. Lincoln Paper and Tissue, LLC’s Motion to Dismiss Complaint, FERC v Lincoln Paper & Tissue, LLC, No. 1:13-cv-13056-DPW (D Mass) (14 February 2014).
  78. Ibid at 3.
  79. 753 F.3d 216 (DC Cir 2014), petition for cert. filed, No 14-840 (US 15 January 2015).
  80. Demand Response Compensation in Organized Wholesale Energy Markets, Order No 745, 134 FERC ¶ 61,187 (2011), order on reh’g, Order No 745-A, 137 FERC ¶ 61,215 (2011).
  81. Barclays Bank PLC, 144 FERC ¶ 61041 (2013).
  82. Notice of Motion and Motion to Dismiss, FERC v Barclays Bank PLC, No 2:13-cv-02093-TLN-DAD (ED Cal) (16 December 2013).
  83. Petitioner’s Opposition to Respondents’ Motion to Dismiss, FERC v Barclays Bank PLC, No 2:13-cv-02093-TLN-DAD (ED Cal) (14 February 2013).
  84. FERC, Electric Power Markets: PJM (26 November 2013), online: FERC <>.
  85. In re PJM Up-To Congestion Transactions, 142 FERC ¶ 61,088 (2013).
  86. Ibid at P1.
  87. Powhatan Energy Fund LLC, 149 FERC ¶ 61261(Docket No IN15-3-000) (2014).
  88. Ibid at paras 1, 3.
  89. FERC, Staff Notice of Alleged Violations (5 August 2014), online: FERC <> (Enforcement alleges that the principal trader made “millions of megawatt hours of offsetting trades” between the same two trading points, with the same volumes and for the same hours, to cancel out the financial consequences from any spread between the points and capture marginal loss of surplus payments from PJM.”).
  90. See FERC Office of Enforcement, Preliminary Findings of Enforcement Staff’s Investigation of Powhatan Energy Fund, LLC (9 August 2013), online: FERC <>.
  91. See Powhatan Energy Fund, LLC, FERC vs. Powhatan Energy Fund, LLC (last visited 30 January 2015), online: <>.
  92. FERC, Staff Notice of Alleged Violations (25 August 2014), online: FERC <>.
  93. Ibid.
  94. Elecectric Power Supply Association v FERC, 753 F (3d) 216 (DC Cir 2014).
  95. Application of the Solicitor General for an Extension of Time Within Which to File a Petition for a Writ of Certiorari at 4, FERC v Electric Power Supply Association, No 14A596 (US 5 December 2014); see Petition for Writ of Certiorari at 29-35, FERC v Electric Power Supply Association, No 14-840 (US 15 January 2015).
  96. DOT amended its order on March 6, 2014, to provide further clarity regarding specific tests required and to prohibit alternate classification that involves less stringent packaging. See U.S. Dep’t of Transp., Amended and Restated Emergency Restriction/Prohibition Order, Docket No DOT-OST-2014-0025 (6 March 2014), online: DOT <>.
  97. Ibid at 12.
  98. Pipeline & Hazardous Materials Safety Admin., Press Release, PHMSA Ongoing Bakken Investigation Shows Crude Oil Lacking Proper Testing, Classification (4 February 2014), online: DOT <>.
  99. U.S. Department of Transportation, Emergency Restriction/Prohibition Order, Docket No DOT-OST-2014-0067 (7 May 2014), online: DOT <>.
  100. Hazardous Materials: Enhanced Tank Car Standards and Operational Controls for High-Hazard Flammable Trains, 79 Fed Reg 45016 (2014).
  101. North Dakota Industrial Commission, Industrial Commission Adopts New Standards to Improve Oil Transportation Safety (9 December 2014), online: <>.
  102. The Washington Report, supra note 10.
  103. The New Jersey decision is PPL EnergyPlus LLC v Hanna, No 11-745, 2013 WL 5603896 (DNJ) (11 October 2013). The Maryland decision is PPL EnergyPlus LLC v Nazarian, No MJG-12-1286, 2013 WL 5432346 (D Md) (30 September 2013).
  104. PPL EnergyPlus LLC v Solomon, 766 F (3d) 241 (3d Cir 2014)[Solomon].
  105. Ibid at 254.
  106. PPL EnergyPlus LLC v Nazarian, 753 F (3d) 467 (4th Cir 2014) [Nazarian].
  107. Ibid at 475-476.
  108. Solomon, supra note 104 at 253 note 4.
  109. Nazarian, supra note 106 at 479.
  110. Application of Madison Gas and Electric Company for Authority to Change Electric and Natural Gas Rates (Ex. 1 to Testimony of Steven James at 3), Docket No 3270-UR-120 (Wis Pub Serv Comm’n, 2 June 2014).
  111. Application of Madison Gas and Electric Company for Authority to Change Electric and Natural Gas Rates(Final Decision Matrix) at 27, Docket No 3270-UR-120 (Wis Pub Serv Comm’n 13 November 2014) at 27.
  112. Joint Application of Wisconsin Electric Power Company and Wisconsin Gas LLC, both d/b/a We Energies, for Authority to Adjust Electric, Natural Gas, and Steam Rates (Final Decision Matrix), Docket No 5-UR-107 (Wis Pub Serv Comm’n, 5 November 2014).
  113. Arizona Public Service Company’s Application for Approval of Net Metering Cost Shift Solution, Decision No 74202, Docket No E-01345A-13-0248 (Ariz Corp Comm’n, 3 December 2013) at 19-20 [Arizona Application].
  114. Ibid.
  115. Arizona Application, supra note 114, (Pierce, Comm’r, dissenting).
  116. Order Instituting Rulemaking Regarding Policies, Procedures and Rules for the California Solar Initiative, the Self-Generation Incentive Program and Other Distributed Generation Issues, Decision Establishing a Transition Period for Customers Enrolled in Net Energy Metering Tariffs at 2, Decision No 14-03-041 (Cal Pub Utils Comm’n,27 March 2014).
  117. Ibid at 8.
  118. Instituting a Proceeding to Review the Power Supply Improvement Plans for Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc., and Maui Electric Co., Ltd., Hawaii Electric Light Power Supply Improvement Plan at 6-4, Docket No 2014-0183 (Haw Pub Utils Comm’n,, 26 August 2014).
  119. SZ Enterprises LLC v Iowa Utilities Board, No 13-0642, 2014 WL 3377074 (Iowa 2014)[Iowa].
  120. Ibid at 6.
  121. Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision, Order Instituting Proceeding at 5, Docket No 14-M-0101 (NY Pub Serv Comm’n 25 April 2014).
  122. Commission Consideration of Retail Renewable Distributed Generation and Net Metering, Decision No C14-0615-I at ¶ 10, Docket No 14M-0235E (Colo Pub Utils Comm’n 28 May 2014).
  123. Minnesota Department of Commerce, Minnesota Value of Solar: Methodology (2014) at 43, online: [Minnesota Solar].
  124. Ibid.
  125. In the Matter of the Petition of Northern States Power Company, dba Xcel Energy, for Approval of Its Proposed Community Solar Garden Program, Order Approving Solar-Garden Plan with Modifications at 4, Docket No E-002/M-13-867 (Minn Pub Utils Comm’n 17 September 2014).
  126. Minnesota Solar, supra note 123, at ii.
  127. Ibid at 1.
  128. In the Matter of Arizona Public Service Company – Request for Approval of Its 2014 Renewable Energy Standard Implementation Plan for Reset of Renewable Energy Adjustor, Decision No 74237 at 15, Docket No E-01345A-13-0140 (Ariz Corp Comm’n 7 January 2014).
  129. State of Washington, Office of the Governor, Washington Carbon Pollution Reduction and Clean Energy Action, Exec. Order No. 14-04 (29 April 2014).
  130. Am. Sub. H.B. 483, 130th Gen. Assemb., Reg. Sess. (Ohio 2014).
  131. Sub. S.B. 310, 130th Gen. Assemb., Reg. Sess. (Ohio 2014).
  132. Proceeding on Motion of the Commission Regarding an Energy Efficiency Portfolio Standard, Order Approving EEPS Program Changes, Docket No 07-M-0548 (NY Pub Serv Comm’n 26 December 2013).
  133. Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision, Order Instituting Proceeding, Docket No14-M-0101,(NY Pub Serv Comm’n 25 April 2014).
  134. Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision, NYS Department of Public Service Staff Report and Proposal, Docket No 14-M-0101 (NY Pub Serv Comm’n 24 April 2014).
  135. Draft Generic Environmental Impact Statement at ES-2, Docket Nos14-M-0101, 14-M-0094 (NY Pub Serv Comm’n 24 October 2014).
  136. Cal Pub Util Code § 353.5.
  137. Cal Pub Util Code § 769(c).
  138. U.S. Dep’t of Energy, Grid Energy Storage at 7 (December 2013), online: DOE <>.
  139. Ibid at 9 (citing IMS Research, The Role of Energy Storage in the PV Industry (2013)).
  140. U.S. Dep’t of Energy, Energy Storage Safety Strategic Plan (December 2014), online: DOE <>.
  141. Cal Pub Util Code § 2835 et. seq.
  142. Cal Pub Util Code § 2835(a)(2)-(4). In its decisions implementing AB 2514, the CPUC also placed certain limitations on what qualifies as an ESS. The Commission excludes pumped storage greater than 50 MW from a qualifying ESS.
  143. Order Instituting Rulemaking Pursuant to Assembly Bill 2514 to Consider the Adoption of Procurement Targets for Viable and Cost-Effective Energy Storage Systems, Docket No R10-12-007 (Cal Pub Utils Comm’n 16 December 2010).
  144. Decision Adopting Energy Storage Procurement Framework and Design Program, Decision No 13-10-040, Docket No R10-12-007 (Cal Pub Utils Comm’n 17 October 2013).
  145. Application of San Diego Gas & Electric Company for Approval of its Energy Storage Procurement Framework and Program as Required by Decision 13-10-040, Docket No A14-02-006 (Cal Pub Utils Comm’n 28 February 2014).
  146. Application of Pacific Gas and Electric Company for Authorization to Procure Energy Storage Systems During the 2014 Biennial Procurement Period Pursuant to Decision 13-10-040, Docket No A14-02-007 (Cal Pub Utils Comm’n 28 February 2014).
  147. Application of Southern California Edison Company for Approval of its 2014 Energy Storage Procurement Plan, Docket No A14-02-009 (Cal Pub Utils Comm’n 28 February 2014).
  148. Cal. Indep. Sys. Operator, Energy Storage Roadmap (2014), online: CAISO <>.
  149. California Independent System Operator, Advancing and Maximizing the Value of Energy Storage Technology: A California Roadmap (December 2014), online: CAISO <>.
  150. Order Instituting Rulemaking to Investigate and Refine Procurement Policies and Consider Long-Term Procurement Plans, Docket No R12-03-014 (Cal Pub Utils Comm’n 22 March 2012).
  151. The State Water Quality Control Board’s regulations now consider heated water to be water pollution under the Federal Clean Water Act. As a result, steam generation plants that use once through cooling will have to be retrofitted or retired.
  152. Long Island Power Authority, Amended and Restated Operating Services Agreement (31 December 2013), online: LIPA <>; see also NY Pub Auth Law § 1020-f(ee).
  153. PSEG-Long Island, Utility 2.0 Long Range Plan, Prepared for Long Island Power Authority (1 July 2014), online: <>.
  154. Long Island Power Authority, Request for Proposals for New Generation, Energy Storage and Demand Response Resources (18 October 2013), online: LIPA <>.

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