The Washington Report

Energy regulatory developments in the United States impact multiple sectors of the energy industry and cut across a broad range of policies and issues. Such  developments arise at the federal level (such as the Federal Energy Regulatory Commission (FERC), the Department of Energy (DOE), Congress, and the federal courts) and the state level (at the public service/utility commissions or in the state courts.) Any report on what is happening in the energy regulatory space in America cannot, by its nature, be comprehensive. Instead, this report will highlight key developments expected to be of interest to readers of the Energy Regulation Quarterly.

Energy Sector Elements of President Obama’s Climate Action Plan

In June 2013, President Obama issued the President’s Climate Action Plan (Climate Plan) to reduce carbon emissions in the United States, prepare the nation for the impacts of climate change and other natural disasters, and participate in international efforts on climate change.1 The Climate Plan sets a goal of reducing U.S. greenhouse gas emissions to seventeen percent below 2005 levels by 2020.

The Climate Plan contains thirty measures, none  of  which  require  Congressional  action or approval. Four of these measures directly impact the energy sector: carbon emissions limits for new and existing power plants; promotion of renewable energy resources, investment in advanced energy technologies; and increased energy efficiency standards for appliances and federal buildings.

1)   Carbon Emissions from Power Plants

The centerpiece of the carbon reduction strategy is the adoption of federal standards to limit carbon emissions from U.S. power plants. In conjunction with the release of the Climate Plan, President Obama issued a Presidential Memorandum to the Administrator of United States Environmental Protection Agency (USEPA) directing the Administrator to expeditiously adopt carbon emissions standards for new and existing power plants pursuant to sections 111(b) and 111(d) of the federal Clean Air Act (June 25, 2013 – Power Sector Carbon Pollution Standards Executive, Order No 13657, 78 Fed. Reg. 39533 (2013); 42 USC § 7411).

For new power plants, the Presidential Memorandum  directed  the  Administrator to continue the rulemaking process initiated by the USEPA’s April 13, 2012 Notice of Proposed Rulemaking entitled “Standards of Performance for Greenhouse Gas Emissions for  New  Stationary  Sources:  Electric  Utility Generating Units.”2 That Notice of Proposed Rulemaking, which proposed an emissions standard of 1,000 pounds of carbon dioxide per megawatt hour on an annual or thirty- year average basis, had drawn criticism for proposing a fuel-neutral standard that would have departed from previous USEPA practice of adopting less stringent standards for coal- fired plants than for natural gas plants. The Presidential Memorandum directed the Administrator to issue a new proposal for limits on carbon emissions by September 20, 2013 and to adopt a final rule in a “timely fashion.”3 The USEPA issued the proposed rule on September 20, 2013, signaling how aggressive the Obama Administration will be in its efforts to address climate change through the regulatory process. Court challenges to any final rule are expected.

For modified, reconstructed, and existing power plants, the USEPA Administrator was directed to issue a proposed rule by June 15, 2014 and to adopt a final rule by no later than June 15, 2015.4 Under the Clean Air Act, states are responsible for implementation and enforcement of the federal standards. The Presidential Memorandum stated that the final carbon emissions regulations must require states to submit implementation plans by June 2016.

2)   Renewable Energy

The Climate Plan set a goal of doubling renewable energy generation in the United States  by  2020.5 According  to  a  report  by the Congressional Research Service, non- hydroelectric renewable generation in the United States was 219 million megawatt hours in 2011.6 To implement this goal, President Obama directed the Department of the Interior to accelerate its permitting process and permit an additional ten gigawatts of renewable generation on federal lands by 2020. The Climate Plan also directed the Department of Defense to install three gigawatts of renewable energy on military installations by 2025 and set a goal for federal agencies to install 100 megawatts of renewable energy in federally subsidized housing by 2020.

3)   Conventional Generation Resources

The Climate Plan promoted investment in clean energy technologies including clean coal and emerging nuclear technologies.7 In accordance with  the  Climate   Plan,   the   Department of Energy (DOE) issued a draft potential solicitation for up to eight billion dollars in loan guarantees for a wide array of advanced fossil fuel technology projects that reduce emissions of greenhouse gases.8 The DOE plans to issue the final solicitation this fall. In the international sector, the Climate Plan proposed to end United States government  support for financing of new coal plants overseas, unless there is no feasible alternative or if the facility uses carbon capture and sequestration technologies.9

4)   Energy Efficiency

The  Climate  Plan  set  a  goal  of  reducing carbon emissions  by  three  billion  metric tons by 2030 through implementing new efficiency standards for appliances and federal buildings during President Obama’s two terms in office.10 In accordance with the Climate Plan, the Department of Agriculture will finalize an update to its Energy Efficiency and Conservation Loan Program to provide up to $250 million for efficiency investments by rural utilities.

FERC Enforcement and Alleged Market Manipulation

The FERC has a robust enforcement program and recently issued several important decisions which reflect its continued focus on investigating alleged unlawful activities in electricity and natural gas markets. Three significant orders in the last quarter focused on alleged manipulation in markets subject to FERC’s jurisdiction. The agency has authority under the Federal Power Act (FPA) and the Natural Gas Act (NGA) to determine that market participants engaged in market manipulation or fraud,11 and impose civil penalties of up to $1 million per day.

1)   Barclays Bank PLC et al.

On July 16, 2013 FERC issued an order assessing civil penalties on Barclays Bank PLC (Barclays), Daniel Brin, Scott Connelly, Karen Levine, and Ryan Smith (Individual Traders) (Barclays and Individual Traders, collectively, Respondents).12 This was proceeded by an earlier order directing the Respondents to show cause why they should not be found to have violated section 1c.2 of the Commission’s regulations  by  manipulating  the  electricity markets in and around California from November 2006 to December 2008 and why they should not be assessed civil penalties as a result of their violations.13 Given the seriousness of these violations and the lack of any effort by the Respondents to remedy their violations, FERC determined that Barclays should be assed $435 million in civil penalties and each of the traders individually should be assessed at least $1 million in civil penalties pursuant to section 316A of the FPA, and Barclays should disgorge unjust profits of approximately $35 million pursuant to section 309 of the FPA.14

The Commission found that Respondents violated the Commission’s Anti-Manipulation Rule through the use of a coordinated, fraudulent scheme to manipulate prices  in the FERC-regulated physical markets at the four most liquid trading points in the western United States. FERC found that Respondents conducted the manipulation by building substantial monthly physical index  positions in the opposite direction of the financial swap positions they assembled at the same points and then trading a next-day fixed price, or “cash,” product at those points to “flatten” their physical index obligations in a manner intentionally designed to increase or lower the daily index at that point. FERC found that by intentionally increasing or decreasing the index, Respondents benefited Barclays’ financial swap positions whose value was ultimately determined by the same index.15

2)    BP America Inc. et al.

On August 5, 2013, the FERC directed BP America  Inc.,  BP  Corporation  North  America Inc., BP America Production Company,  and BP Energy Company (collectively “BP” or “Respondent”) to show cause why it should not be found to have violated section 1c.1 of the Commission’s regulations and section 4A of the Natural Gas Act. Respondent is alleged to have violated section 1c.1 and section 4A of the NGA by manipulating the next-day, fixed- price gas market at Houston Ship Channel from mid-September 2008 through November 30, 2008.16 The Commission directed BP to show cause why it should not be assessed a civil penalty in the amount of  $28  million and disgorge $800,000 plus interest, or a modification to these amounts as warranted.

The Enforcement Staff Report alleged that traders on the “Texas team” of BP’s Southeast Gas Trading (SEGT) desk traded physical natural gas at Houston Ship Channel (HSC) to increase the value of BP’s financial position at HSC. Specifically, staff alleged that the Texas team traders uneconomically used BP’s transportation capacity between Katy and HSC, made repeated early uneconomic sales at HSC, and took steps to increase BP’s market concentration at HSC as part of a manipulative scheme. In doing so, staff alleged, the Texas team traders suppressed the HSC Gas Daily index with the  goal  of  increasing  the  value of BP’s financial position at HSC from mid- September 2008 through November 2008.17

3)      JP   Morgan  Ventures Energy Corporation

On July 31, 2013 FERC approved a Stipulation and Consent Agreement (Agreement) between its Office of Enforcement (Enforcement) and JP Morgan Ventures Energy Corporation (JPMVEC)18 resolving allegations of JMVEC’s bidding and offering (collectively “bidding”) of power plants into the markets operated by the California Independent System Operator Corporation (CAISO) and the Midwest Independent Transmission System Operator, Inc. (MISO) between September 2010 and November 2012. Enforcement investigated potential violations of the Commission’s Anti- Manipulation Rule, 18 C-F-R §1c.2, and of tariff provisions.

Among other things, Enforcement alleged that JPMVEC submitted certain bids that falsely appeared economic to CAISO and MISO automated market software and that were intended to, and did, lead CAISO and MISO to pay it at rates  far above  market prices.19 JPMVEC admitted certain facts as set forth in the Agreement, neither admitted nor denied the violations set forth in the agreement, agreed to: 1) pay a civil penalty of $285,000,000; 2) disgorge alleged unjust profits of $125,000,000; 3) waive claims for additional Bid Cost Recovery and Exceptional Dispatch payments from CAISO; and 4) implement additional compliance measures. This was the largest settlement in FERC enforcement history.

Key Developments in Energy Storage Technologies

FERC and the California Public Utilities Commission (CPUC) recently took actions that could significantly open the market for energy storage technologies. In July, the FERC issued a Final Rule designed to encourage the participation of energy storage  technologies in electricity markets. In September, CPUC Commissioner Carla Peterman issued a proposed decision that would adopt an energy storage procurement requirement for the state’s retail providers.

1)   FERC Order 784

On July 18, 2013 the  FERC issued a final rule designed to foster competition and transparency in  ancillary  services  markets and to enable transmission customers to self- supply regulation and frequency response service requirements through energy storage technologies.20 The final rule, Order 784, revised market-based rate regulations, ancillary services requirements under the pro forma Open-Access Transmission Tariff  (OATT), and accounting and reporting requirements for public utility owned energy storage assets.

Order 784 revised the FERC’s Avista policy, which placed limits on the ability of third parties to provide ancillary services at market- based rates to public utility transmission providers for the purpose of satisfying its own OATT requirements to offer ancillary services to its own customers.21 Under Order 784, generators with market-based rate authority for sales of energy and capacity are permitted to sell imbalance services and operating reserves services at market-based rates to transmission providers in the same balancing authority area, or a different balancing authority area, provided those areas have adopted intra-hour scheduling for transmission service. Generators may also sell reactive supply and voltage control service and regulation and frequency response service at rates that do not exceed the utility’s OATT rate or at market-based rates if the services are acquired through a competitive solicitation.

The rule also implemented reforms to regulation service self-supply options for transmission customers by requiring transmission providers to add a statement to their OATT Schedule 3 that the provider “will take into account the speed and accuracy of regulation resources in its determination of reserve requirements for Regulation and Frequency Response service.”22 Before this reform, a transmission customer could self-supply regulation and frequency response services; however, the customer was still required to purchase a volume of regulation and frequency response service that was based on the mix of regulation resources used by the transmission provider. As a result, there was little incentive to the customer to self-supply resources that were faster and/or more accurate and which could provide the same level of service at lower volumes.23

Finally, to enhance transparency FERC revised accounting and reporting requirements under its “Uniform System of Accounts” for public utilities to track and report use and cost allocation for energy storage assets which can perform multiple functions. The final rule will take effect on November 27, 2013.

2)  CPUC’s Proposed Decision on Energy Storage Procurement Targets

On September  3,  2013,  the  CPUC  issued a proposed decision that would adopt procurement requirements for California’s three largest investor owned utilities, Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE) and San Diego Gas & Electric Company (SDG&E) (collectively, IOUs), as well as the state’s retail electric service providers and community choice aggregators.24

The proposed decision implemented a state law that required the CPUC to consider whether to adopt targets for the procurement of “viable and cost-effective energy storage systems,” defined as “commercially available technology that is capable of absorbing energy, storing it for a period of time, and thereafter dispatching the energy.”25 The procurement targets are guided by three policy goals: (1) grid optimization including reliability, peak reduction and deferred transmission and distribution system upgrades, (2) integration of renewable energy, and (3) the State’s goal of reduction of greenhouse gas emissions to eighty percent below 1990 levels by 2050.26

The proposed decision adopted a 1,325 gigawatt procurement requirement by 2020 for the IOUs allocated among three points of grid interconnection. This target excluded pumped storage projects larger than  fifty  megawatts on the basis that a single project could fulfill the entire procurement target for an IOU and thwart the goal of market transformation for energy storage applications.27

The proposed decision directed the IOUs to conduct all source solicitations every two years with the initial solicitation in December 2014. The proposed decision allows for a significant amount of flexibility in meeting  the  targets for the purpose of cost containment. The IOUs may shift up to eighty percent of the biannual targets between the transmission and distribution grid domains and may defer up to eighty percent of the targets to the subsequent solicitation if the IOU can demonstrate that the costs of the energy storage bids are unreasonable or a lack of an operationally viable number of bids in the solicitation.28

The proposed decision is scheduled to be voted on by the CPUC at its October 3, 2013 business meeting. If the CPUC adopts the proposed decision, each IOU will be required to file an application with the CPUC for approval of that IOU’s energy storage solicitation proposal, including operational requirements, a proposed methodology for a “least-cost, best-fit” analysis of the bids, draft agreements, and a schedule for the solicitation.29

New York’s Highest Court to Consider Hydraulic Fracking Preemption Issues

In August 2013, the Court of Appeals for New York, the state’s highest court, agreed to hear an appeal in Norse Energy Corp. v. Town of Dryden,30 setting up a long-anticipated decision concerning the ability of local municipalities to enact zoning laws that prohibit oil and gas mining and drilling. Potentially at issue are over 60 permanent hydraulic fracking bans and 111 temporary moratoria enacted by New York municipalities, including major population centers such as Buffalo, Rochester, Syracuse, Binghamton, Union, Utica, and Albany.31 The bans and moratoria serve to prevent access to the Marcellus Shale formation in New York, which some geologists estimate could contain from 168 trillion to over 500 trillion cubic feet of natural gas.32

Unlike other precedent-setting decisions that weighed in favor of state law preemption over local ordinances banning fracking,33 New York has a longstanding tradition of upholding the rights of local governments to control land use within their boundaries.34 Those rights, which derive from both the state’s constitution35 and various statutes, have empowered municipalities to enact ordinances banning fracking. For example, in Norse Energy Corp., the Town of Dryden amended its zoning ordinance to “ban all activities related to the exploration for, and the production or storage of, natural gas and petroleum.”36

While the local ordinances might differ slightly, their effect is the same: stopping fracking within a municipality’s boundaries. Consequently, New York state courts consistently confront a similar question in challenges brought against these  ordinances:  do  state  laws  preempt and therefore take precedence over local ordinances? State law preemption over local ordinances can occur either via conflict or field preemption. Conflict preemption arises when a local ordinance directly conflicts with a state law and field preemption occurs when the state has assumed sole responsibility for the regulation of a particular field. To date, New York municipalities have been successful at defending their zoning ordinances in state courts.37

Specifically, in three cases – Anschutz Exploration Corp. v. Town of Dryden, Cooperstown Holstein Corp. v. Town of Middlefield,  and  Norse Energy Corp. – New York courts upheld local ordinances that banned hyrdrofracking. In Anschutz Exploration Corp. v. Town of Dryden, the court held that the state Oil, Gas and Solution Mining Law (OGSML) did not preempt local restrictions banning gas drilling within boundary of the town. Similarly, the court in Cooperstown Holstein Corp. v. Town of Middlefield, ruled that a municipality is empowered to allow or disallow gas drilling within the powers granted to it by the state constitution and that OGSML did not preempt a  municipality  from  enacting  a land use regulation within its geographic jurisdiction. Finally, in Norse Energy Corp., the court concluded that “the OGSML does not preempt, either expressly or impliedly, a municipality’s power to enact a local zoning ordinance banning all activities related  to the exploration for, and the production or storage of, natural gas and petroleum within its borders.”38

Hydropower Regulatory Efficiency Act Of 2013

On August 9, 2013, President Obama signed into law H.R. 267, the Hydropower Regulatory Efficiency Act of 2013. The Act is intended to facilitate the development of new domestic hydropower resources by streamlining federal licensing requirements for small hydropower projects and qualifying conduit hydropower facilities.  Additionally,  the  Act  requires  the FERC to study avenues to improve, and potentially shorten, federal hydropower licensing for non-powered dams and closed- loop pumped storage facilities.

The Act made several reforms to existing energy laws, including the FPA and the Public Utility Regulatory Policies Act (PURPA), with an intended goal to increase hydropower capacity and create jobs. Specifically, it:

(1)       Raised the generation capacity threshold from 5 MW to 10 MW for a proposed project to remain eligible to receive a licensing exemption under Part I of the FPA;

(2)       Exempted qualifying conduit projects from federal licensing requirements upon  showing  that  the  project   meets the Act’s qualifying criteria: (a) uses the hydropower potential of a non-federally owned conduit; (b) is not otherwise subject to a FERC license or exemption; and (c) will have an installed capacity of less than 5 MW. To discourage project mischaracterizations intended to circumvent federal licensing requirements, the Act requires developers to file a notice with FERC, which will make a determination within 15 days as to whether the project meets the qualifying criteria. Following FERC’s determination, there is a 45-day notice period during which the public can contest whether the project meets the qualifying criteria; and

(3)       Directed FERC to hold workshops and conduct pilots to investigate the feasibility of implementing a two-year licensing process to “improve the regulatory process and reduce delays and costs for hydropower development at non-powered dams and closed loop pumped storage projects.”

In compliance with section 6 of the Act, FERC announced that it will hold a public workshop in October 2013 to investigate the feasibility of a two-year process for licensing hydropower development at non-powered dams and closed-loop pumped storage projects. Workshop topics include the feasibility of a two-year licensing process, potential criteria for identifying projects appropriate for a two- year licensing process, and recommendations for potential pilot projects to test a two-year licensing process.

DOE and Certain Exports of LNG

In the second quarter of 2013, DOE issued its first ruling in  more  than  two  years  on an application for authorization to export liquefied natural gas (LNG) from the United States to countries with which the United States does not have a free trade agreement (FTA). The DOE ruling conditionally authorized Freeport  LNG  Expansion,  L.P. and FLNG Liquefaction, LLC (collectively, Freeport) to export domestically produced LNG from the Freeport LNG terminal on Quintana Island, Texas, to non-FTA countries (Freeport Order). DOE followed this action by issuing similar, conditional authorizations in August and September 2013 to Lake Charles Exports, LLC and Dominion Cove Point LNG, L.P., respectively, to export LNG to non-FTA countries.

In 2011, DOE had granted Sabine Pass Liquefaction, LLC, authorization to export LNG to non-FTA countries from its Sabine Pass terminal, the first such authorization issued to a facility that would export LNG from the “lower-48” states. Thereafter, however, DOE delayed further action on applications to export natural gas to non-FTA countries until it received and reviewed studies performed by its Energy Information Administration, and by the NERA Economic Consulting firm, that would assess the economic effects of increased LNG exports from the United States (DOE Study). The DOE Study was published in December 2012 and received a large number of public comments on its analysis and conclusions.39

Under the NGA, exports of natural gas to FTA countries are presumed to be in the public interest. While DOE must authorize exports to FTA countries, applications for exports to FTA countries are typically expedited. For LNG exports to non-FTA countries, the NGA provides that the agency will grant the export authorization unless the agency determines whether the export authorization will not be consistent with the public interest. In reviewing an application to export natural gas to a non- FTA country, the DOE considers, among other factors, the potential economic, security, and environmental consequences.

The Freeport Order, issued on May 17, 2013, is a “Conditional Order,” in which DOE granted Freeport authorization to export up to 511 bcf/year to non-FTA countries, subject to satisfactory completion of the environmental review under the National Environmental Policy Act (NEPA) of the construction and operation of the liquefaction project and related facilities that Freeport will install to produce the LNG for export, and issuance by DOE of a record of decision pursuant to NEPA. The Freeport Order noted that  FERC  is  the  lead  agency to conduct the environmental review and directed parties to raise questions and concerns regarding environmental matters to FERC. Because DOE is required by NEPA to give appropriate consideration to the environmental effects of its proposed decisions, DOE will not issue a final order on an export authorization to non-FTA countries until it has “met its NEPA responsibilities.” DOE will be a cooperating agency in the environmental review being conducted by  FERC  Staff.  DOE  will  not be  a  forum  for  environmental  issues  absent a showing of good cause for not bringing an issue to FERC’s attention. The Freeport Order reserved the right, once FERC has completed its environmental review, to address any claims that FERC did not address issues raised by the parties.

DOE granted Freeport a 20 year export authorization, rather than a 25 year authorization as the application requested. DOE stated that it granted the 20 year authorization because the DOE Study had examined the economic effects of increased LNG exports for a 20 year period.

The Freeport Order spelled out several conditions to the export authorization that can be expected to appear in the final order. These include a requirement that the parties commence export operations commence no later than seven years from  the  issuance  of the Freeport Order; a detailed summary of reporting requirements that the parties must satisfy (and which must also be satisfied by persons on whose behalf the Freeport parties, as agent, export LNG). Those persons that will hold title to LNG, and for whom the Freeport parties, as agent, will export LNG, will need to be registered with DOE according to specifications laid out in the Freeport Order.

On July 12, 2013, Freeport filed a “Request for Clarification” with DOE, requesting that it issue a further order clarifying certain aspects of the Freeport Order. In its conditional authorizations for LNG exports by Lake Charles and Dominion Cove Point, DOE substantially followed the approach taken in the Freeport Order. In reviewing the evidence in the record, including the DOE Study and the public comments filed in response to the DOE Study, DOE determined that it has not found adequate basis to conclude that the request export of LNG to non-FTA countries will be inconsistent with the public interest.

In the Dominion Cove Point order, issued September 11, 2013, DOE highlighted that it has considered the cumulative impacts of its export authorizations to non-FTA countries. DOE further noted that the most recent order, issued to Dominion Cove Point, conditionally authorizes only up to the maximum liquefaction capacity of the planned LNG facility, which in that case is less than the volume requested in Dominion Cove Point’s application. The total volume of exports of natural gas authorized in DOE’s rulings to date is 6.37 Bcf/day of natural gas.

* Senior of Counsel at Morrison Foerster in Washington DC where he represents a range of clients on energy regulatory, enforcement, compliance, 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 & Forester’s energy regulatory team for their assistance in developing this report.

1 Executive Office of the President, The President’s Climate Action Plan, (11 September 2013) (Climate Plan) online: The White House Washington < pdf>

2    Notice of Proposed Rulemaking, Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units, 77 Fed Reg 22392 (2012).

3   78 Fed Reg 39533 (2013).

4   Id. at 39536.

Climate Plan, supra note 1 at 6-7.

6  Jane A. Leggett, Cong. Research Serv., R43120, President Obama’s Climate Action Plan at 3-4 (2013).

Climate Plan, supra note 1 at 7.

Notice of Agency Request for Comments on Draft Solicitation, 78 Fed Reg 41046 (2013).

Climate Plan, supra note 1 at 20.

10  Id. at 9.

11   16 USC § 824v (a) (2006); 15 USC § 717c-1 (2006).

12  Barclays Bank PLC, 144 FERC ¶ 61,041 (2013).

13  Order to Show Cause, Barclays Bank PLC, 141 FERC ¶ 61,084 (2012).

14   If the respondents do not pay the penalties, FERC’s next step would be to institute an action in federal district court to affirm the penalty assessment. In this order, we find that Respondents violated section 222 of the FPA and the Anti-Manipulation Rule.

15  Supra note 12 at 3.

16   144 FERC ¶ 61,000 (2013).

17  Id. at 2.

18  In Re Make-Whole Payments, 144 FERC ¶ 61,068 (2013).

19  Id. at 14.

20  Order No. 784, Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, 144 FERC ¶ 61,056 (2013) (to be codified at 18 CFR §§ 35, 101, 141).

21   Id. at 20-22.

22   Id. at 50.

23   Id. at 49-51.

24 CPUC, Proposed Decision of Commissioner Peterman Adopting Energy Storage Procurement Framework and Design Program (11 September 2013), online: CPUC < K387/76387254.PDF> (hereinafter, Proposed Decision).  Retail electricity service providers and community choice aggregators are lightly regulated by the CPUC and are often subject to different rules and requirements than the IOUs. The Proposed Decision requires retail electricity service providers and community choice aggregators to procure energy storage equivalent to one percent of the entity’s peak load by 2020.

25  California Public Utilities Code 1 ca pub util §§ 2835, 2836 (2010).

26  Proposed Decision, supra note 24 at Appendix A .

27  Id. at 33.

28  Id. at Appendix A at 3, 7.

29  Id. at Appendix A at 5-7.

30   Norse Energy Corp. USA v. Town of Dryden, 964 NYS (2d) 714 (NY App div 2013) . The appeal is case number 515227 in the Third Department of the New York State Supreme Court’s Appellate Division. Several groups have already requested, and been granted, leave to file amicus curiae briefs.

31  Karen Edelstein, NY State Hydraulic Fracturing Bans Relative to Population (4 July 2013), online: Fractracker <http://>; see also Jarit C. Polley, Uncertainty for the Energy Industry: A Fractured Look at Home Rule, (2013) 34 Energy LJ 261, 281 (stating that “New York . . . is a hotbed for municipal bans on fracing.”).

32  Eileen D. Millett, Will Fracking Become the Exception to the Rule of Local Zoning Control in New York State?(2013), 33 26 WESTLAW J. ENVTLat 4 (WL).

33  See e.g., Trial Order, Northeast Natural Energy, LLC v. City of Morgantown, 2011 WL 3584376 (W Va Cir Ct)

34  Millet, supra note 32 at 1.

35  Id. at 1,3.

36  Supra note 30 at 716.

37  See e.g., Cooperstown Holstein Corp. v. Town of Middlefield, 943 NY (2d) 722 (Sup Ct 2012) (holding that New York State’s Environmental Conservation Law (ECL) does not preempt local municipalities from enacting legislation that impacts the oil and gas industries); Anschutz Exploration Corp. v. Town of Dryden, 940 NYS (2d) 458 (Sup Ct 2012).

38  Supra note 30 at 724.

39  Department of Energy 2012 LNG Export Study, 77 Fed Reg 73,627 (2012).

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