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 2014 in Volume 3, Issue 1 of the ERQ in 2015. This report highlights significant developments in 2015 and early 2016 which should be of interest to readers of the ERQ.


In 2015 and early 2016, the U.S. Department of Energy, Office of Fossil Energy (“DOE”) authorized the sponsors of two LNG projects located in Nova Scotia, to export natural gas produced in the United States to Canada, where it would be liquefied and re-exported to countries that do not have in place a free trade agreement with the United States requiring national treatment for trade in natural gas (“non-FTA” countries).1 A threshold issue that DOE had not previously addressed was whether the exports should be deemed to be exports to Canada – which has in place a free trade agreement (“FTA”) with the United States – or to the non-FTA countries to which the gas, as LNG, would be delivered when re-exported. Under Section 3 (c) of the Natural Gas Act, applications for authority to export LNG to FTA countries are deemed consistent with the public interest and must be granted “without modification or delay.”2 Under Section 3(a) of the Natural Gas Act, DOE must undertake a public interest review and provide notice and opportunity for public participation to find that an application to export LNG to non-FTA countries is not inconsistent with the public interest. DOE determined that “[t]he destination of the U.S. sourced natural gas or LNG for end use is critical to [DOE]’s determination, as is the trade status of that destination country or countries.”3 DOE required, as a condition of the export authorization, that contracts for the sale of LNG require the purchaser to provide a report to the authorization holder that identifies the country into which the re-exported LNG is “actually delivered and/or received for end use….”4 Unless it based its determination on the trade status of the “end use” country, DOE opined, exporters would be allowed “to evade the public interest review and opportunity for public participation afforded in non-FTA export proceedings under NGA section 3(a), simply by transiting the natural gas or LNG through a FTA country en route to a non-FTA country,” and it did not believe Congress intended the “dual-track scheme” in the NGA to be “so easily evaded.”5

In Order No. 3769,6 DOE addressed for the first time its jurisdiction under Section 3 of the Natural Gas Act with respect to “in-transit shipments” of Canadian natural gas, travelling by pipeline through the United States on the way back to Canada, the country of origin. The Canadian gas would pass through the United States only “temporarily” on its way back to Canada where it will be liquefied for subsequent export as LNG. DOE’s analysis focused on whether these shipments were “imports” or “exports” within the meaning of Section 3 of the Natural Gas Act. DOE concluded that Congress likely did not intend the words “import” and “export” to capture any movement of natural gas across the U.S. border, but to be applied only to categories of shipments “that, by their nature, could have a material effect on the U.S. public interest.”7 In-transit shipments, DOE concluded, are “categorically unlikely” to materially impact the U.S. public interest, and any environmental or economic issues such shipments create for the U.S. natural gas pipeline system could be addressed by FERC or state regulators.8 DOE also noted the 1977 Agreement between the Government of the United States of America and the Government of Canada Concerning Transit Pipelines, which “generally espouses a laissez-faire policy between the two governments for in-transit shipments of hydrocarbons.”9 DOE concluded that in-transit shipments returning to the country of origin – shipments of natural gas through the United States between points of a single foreign nation that are physical and direct – are not “imports” or “exports” within the meaning of section 3. Virtual shipments including exchanges by backhaul or displacement are not “in transit” shipments for purposes of Order 3769.10 While DOE dismissed the application for lack of jurisdiction, it directed the applicant to submit specific information on its in-transit shipments, including an explanation to DOE to show that no deliveries into United States commercial markets have occurred.11

Both the United States Senate and House of Representatives passed legislation in 2015 and early 2016 that expedites DOE’s processing of applications for authorizations for exports to non-FTA countries under Section 3 of the Natural Gas Act. DOE would be required to issue a final decision no later than 30 days (the House bill) or 45 days (the Senate bill) after the conclusion of the review required by the National Environmental Policy Act of 1969 (NEPA).12 For an LNG export project that requires an Environmental Impact Statement (i.e. the most substantial review), the bills specify that such NEPA review is considered “concluded” after the publication of a Final Environmental Impact Statement. The bills will need to be addressed by a Conference Committee before further action by Congress.

On March 11, 2016, FERC issued an order denying applications filed by Jordan Cove Energy Project under Section 3 of the Natural Gas Act to site, construct and operate an LNG export terminal at Coos Bay, Ore. and by Pacific Connector Gas Pipeline to construct an interconnected interstate natural gas pipeline.13 FERC found that “Pacific Connector has presented little or no evidence of need” for the pipeline, stating that it had “neither entered into any precedent agreements for its project, nor conducted an open season, which might (or might not) have resulted in ‘expressions of interest’ the company could have claimed as indicia of demand.”14 Having found that the pipeline did not meet the requirements under Section 7 for a certificate of public convenience and necessity, FERC determined that it would be impossible for Jordan Cove’s liquefaction facility to function” as it would not be able to access natural gas supplies and, therefore, the Jordan Cove project “can provide no benefit to the public to counterbalance any of the impacts which would be associated with its construction.”15 The applicants have filed requests for rehearing, citing new commitments they contend satisfy the requisite criteria under Section 7(c) and Section 3 of the Natural Gas Act.

As required under Section 3, FERC’s authorizations to site, construct and operate LNG export facilities and interconnected interstate pipelines 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. FERC has consistently rejected environmental intervenors’ contentions that FERC must analyze the potential environmental impacts from increased natural gas production resulting from the proposed LNG export projects, greenhouse gas emissions, and other environmental issues that could be attributed to a project and the project’s effects on domestic natural gas prices. The adequacy of FERC’s environmental review of applications for authorization to site, construct and operate LNG export facilities is the subject of multiple petitions for review pending before the United States Court of Appeals for the District of Columbia Circuit. In 2015, the court heard oral arguments in appeals filed by the Sierra Club of FERC’s orders authorizing construction of the Freeport liquefaction export facilities in Texas, and expansion of the Sabine Pass liquefaction facility’s capacity.16 In May 2015, FERC denied Sierra Club’s request for rehearing of FERC’s order granting authorization for construction of the Corpus Christi Liquefaction LNG export terminal in Texas, and an interconnected pipeline.17 Sierra Club has filed a petition for judicial review of FERC’s authorizations for the Corpus Christi project.18

In May 2015, FERC denied rehearing of its order that authorized expansion of the LNG export facilities at the Dominion Cove Point facilities in Maryland. In that case, Sierra Club and other environmental intervenors had asked FERC to grant a stay of its authorization pending appeal.19 FERC denied the request for a stay. The environmental intervenors filed a petition for judicial review challenging FERC’s authorizations and, in addition, filed with the court an emergency motion for a stay of construction of the project pending judicial review. The motion was denied, and the court ruled that the parties “neither satisfied the stringent requirements for a stay pending court review … nor articulated ‘strongly compelling’ reasons justifying expedition.”20

In Pivotal LNG,21 FERC issued a declaratory order finding that liquefaction and transportation facilities being developed by Pivotal would not be “LNG terminals” and that it would not exercise jurisdiction under Section 3 of the Natural Gas Act. Pivotal explained that the LNG it plans to sell will be: (1) produced at inland LNG facilities or supplied by a third party; (2) transported by Pivotal, an affiliate, or third party in interstate and intrastate commerce by means other than interstate pipeline; and (3) subsequently exported, or resold for ultimate export, by a third party. Pivotal asserted that none of the facilities constitute an “LNG terminal” as defined by NGA section 2(e), since they are all located inland unlike border crossing pipelines and coastal LNG terminals that FERC has traditionally regulated under Section 3. FERC noted that it has only exercised its authority under section 3 to regulate (1) pipelines constructed at the place of entry for imports or exit for exports and (2) coastal LNG terminals such that the LNG is transferred to ocean-going, bulk-carrier LNG tankers and that are connected to pipelines that deliver gas to or take gas away from the terminal. FERC noted that Pivotal’s facilities are located inland and are therefore not capable of transferring LNG directly onto ocean-going tankers.22 FERC found that no “regulatory gap” to justify an “over-expansive application” of section 3 to the LNG facilities owned by Pivotal and its affiliates, noting that the facilities are regulated by various federal, state and local agencies.23 In a dissenting opinion, FERC Commissioner (now Chairman) Norman Bay argued that the plain language of Section 3 of the NGA provides FERC jurisdiction with respect to “export” and “import” facilities, Pivotal’s facilities are “export facilities,” which are not the same as “LNG terminals,” and “nothing in Section 3 conditions the Commission’s jurisdiction upon the existence of a pipeline running to the point of export.”24

Finally, in 2015 the sponsors of some of the proposed LNG export projects in the United States chose to delay, or terminate altogether regulatory proceedings on their projects in response to changes in market conditions, including falling oil prices and competition from Australia and other foreign LNG supply sources. Early in 2015, Excelerate Liquefaction Solutions announced that it would postpone its proposed floating LNG export terminal at Port Lavaca-Point Comfort, Texas. Subsequently, Excelerate asked FERC to hold its application proceedings in abeyance. Finally, in September 2015, Excelerate withdrew its application, stating it had evaluated the economic value of the project and determined not to proceed further.25 In November 2015, the sponsors of the Downeast LNG proposed export terminal to be located in Robbinston, Maine asked FERC to hold its proceedings in abeyance until February 29, 2016 while the sponsor and its investors undertake an economic analysis of current market conditions and the associated impact on the proposed Downeast LNG project.”26 The hold was subsequently extended to June 1, 2016.


A. Colorado State Supreme Court Decision

On May 2, 2016, the Colorado Supreme Court overturned local hydraulic fracturing (“fracking”) bans in two separate decisions that may have far reaching implications for local governments seeking implementation of, or defending, existing fracking bans nationwide.27

Two Colorado cities, Longmont and Fort Collins, had previously instituted local bans on fracking. Longmont’s permanent ban on fracking cited several concerns including public health, safety, the environment and local property values. In contrast, Fort Collins implemented its fracking ban as only a five-year moratorium to permit the locality additional time to study the impact of fracking. The Court held that the bans were preempted by state law, rendering each unenforceable and invalid, and affirming the lower courts’ rulings. The Court held that the local bans were preempted due to the prevalence of fracking in Colorado and the existing regime of regulation by Colorado regulatory authorities of such practices. Although the Colorado decision will not directly govern future cases regarding fracking bans in other jurisdictions, the ruling may shape how other state courts will address the issue.

Overturning the local fracking bans may have shifted the energy of Colorado’s fracking opponents to seek a ballot measures restricting fracking – three separate ballot initiatives are currently gathering the required 100,000 signatures to be placed on Colorado’s November 2016 ballot. One proposed measure would effectively reinstate local control over fracking and related activities and another would impose significant limitations on the ability to conduct fracking operations by banning such activities within 2,500 of occupied buildings, waterways and other open public spaces.

B. New Federal Fracking Regulations

With the rapid increase of fracking development in the U.S., the Obama Administration has attempted to implement new measures designed to improve regulatory oversight of the industry. In March 2015, the U.S. Department of the Interior (“DOI”) drafted new rules regarding drilling safety of fracking operations. The rules sought to improve the ability of the federal government to inspect the safety of concrete barriers used to line fracking wells, as well as require companies to publicly disclose the chemicals used in their fracking operations.28 However, in September 2015, Judge Scott Skavdahl, a District Court Judge in the U.S. District Court for Wyoming, issued a preliminary injunction preventing DOI from carrying out the rules.29 The Court cited concerns with creating an “overlapping federal regime” that interferes with state sovereign interests in regulating fracking absent any congressional mandate.30 DOI has since appealed the ruling to the Tenth Circuit Court of Appeals.


On January 25, 2016, the U.S. Supreme Court reversed a May 2014 decision of the U.S. Court of Appeals for the D.C. Circuit which had vacated in its entirety FERC’s Order No. 745, its final rule on wholesale demand response compensation for the curtailment of electric use during periods of peak demand and high system marginal cost.31 The Supreme Court held that FERC has the authority under the Federal Power Act (FPA)32 to regulate demand response bids in wholesale markets, and that FERC’s Order No. 745 was not arbitrary and capricious by requiring that demand response providers be paid the same amount for conserving electricity as generators are paid for producing it (“the EPSA decision”).

The D.C. Circuit had vacated Order No. 745 in a highly controversial opinion, on two separate grounds. First, the Court held that the order directly regulates retail markets which are outside of FERC’s jurisdiction, because demand response involves retail customers and their decisions whether to purchase and consume electricity at state-jurisdictional retail rates. Second, the D.C. Circuit had ruled that, even if FERC had jurisdiction to adopt Order No. 745, the Order was “arbitrary and capricious” in violation of the Administrative Procedure Act33, in part because the required payment mechanism over-compensated demand response resources.34 Order No. 745 directed Regional Transmission Organizations and Independent System Operators (RTO/ISOs) 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.35

Supporters of FERC’s rule argued that participation by demand response resources in wholesale electric-power markets is an “integral feature” of those markets and that FERC regulation of demand response is critical to proper market functioning to ensure just and reasonable rates for wholesale power. Opponents argued that it encroached on states’ authority over retail power markets, because end-use consumption and demand response are fundamentally retail activities, and that FERC was effectively setting retail rates. Justice Elena Kagan, who delivered the 6-2 majority opinion for the Supreme Court, wrote that FERC acted within its powers enumerated under the FPA in issuing Order No. 745, reasoning that “[i]t is a fact of economic life that the wholesale and retail markets in electricity, as in every other known product, are not hermetically sealed from each other. To the contrary, transactions that occur on the wholesale market have natural consequences at the retail level. And so too, of necessity, will FERC’s regulation of those wholesale matters.”36

The EPSA decision stands for the proposition that FERC is within its powers to regulate the wholesale markets even when such regulation has indirect consequences on retail market conditions.37 The Court held that because the FPA delegates responsibility to FERC to regulate the interstate wholesale market for electricity—“both wholesale rates and the panoply of rules and practices affecting them”—the FPA establishes a scheme for federal regulation which “means FERC has the authority—and, indeed, the duty—to ensure that rules or practices ‘affecting’ wholesale rates are just and reasonable.”38 The Court based its decision in part on the reality that adopting EPSA’s position would be the death knell for demand response programs by forcing them into a “gap” beyond the regulatory reach of either FERC or the states. The Court reasoned that such an outcome would contravene the structure set up by the FPA, which “makes federal and state powers ‘complementary’ and ‘comprehensive.’”39

The decision eliminates uncertainty about the future of the demand response industry in the United States since the D.C. Circuit opinion. The decision also will potentially catalyze the development of emerging technologies including distributed generation and energy storage, because products and services operating “behind the meter” will be able to capture demand response payments as part of their revenue streams.

Although the EPSA decision characterized FERC’s Order No. 745 as an exercise in “cooperative federalism,” the decision may have broader implications for federal preemption of state regulation. More than a half century ago, the Supreme Court described the FPA’s division of federal and state jurisdiction over electric energy transactions as a “bright line, easily ascertained ….”40 That bright line is becoming increasingly “hazy” as legal and regulatory frameworks necessarily adapt to an ever-evolving industry.41 The EPSA decision could be interpreted to support federal jurisdiction over electric markets preempting state regulation in other contexts, depending on how broadly courts construe the decision’s holding that the “FPA leaves no room either for direct state regulation of the prices of interstate wholesales or for regulation that would indirectly achieve the same result.”42


A. Hughes v Talen

In another U.S. Supreme Court case regarding federal jurisdiction over electric markets the Court unanimously ruled in favor of federal jurisdiction.43 The State of Maryland had implemented an incentive program which subsidized the participation of a new power plant in the wholesale energy market administered by PJM Interconnection (PJM). That subsidy was deemed preempted by the FPA because it conflicted with FERC’s exercise of its authority over the field of wholesale electricity markets and the state program had the effect of distorting an interstate wholesale rate required by FERC.

The Hughes decision limits the extent to which state actions in the retail market are allowed to impinge on federal-jurisdictional wholesale markets and affect wholesale rates set by mechanisms approved by FERC. The key holding is that “Maryland’s program invades FERC’s regulatory turf” by impermissibly infringing on the FERC “exclusive jurisdiction over ‘rates and charges […] received […] for or in connection with’ interstate wholesale rates.”44 The Court was careful to narrowly tailor its ruling in Hughes: “Neither Maryland nor other States are foreclosed from encouraging production of new or clean generation through measures that do not condition payment of funds on capacity clearing the auction.”45 Many energy market participants had been concerned that an expansive ruling by the Court would negatively impact scores of state programs designed to promote clean energy. Justice Sotomayor wrote a concurring opinion to reiterate the limited nature of the Court’s ruling and emphasize that the FPA envisioned a cooperative federal-state relationship, but that the Maryland program impermissibly infringed on that relationship.46

B. Ohio PPAs

In a pair of orders issued on April 27, 2016, FERC blocked two power purchase agreements (PPAs) approved by Ohio state regulators to subsidize coal and nuclear plants owned by FirstEnergy and AEP Ohio on the basis that they were inconsistent with FERC’s polices on transactions by affiliated entities. The PPAs sought to guarantee income for aging generating plants, under the guise of ensuring system reliability.47 Opponents of the utilities’ PPA arrangements had argued to the Public Utilities Commission of Ohio that the proposals were preempted by the FPA as interfering with FERC’s exclusive jurisdiction over wholesale electricity markets and rates, much like the subsidies at issue in Hughes v Talen. FERC’s orders are perceived as avoiding another round of extended state-federal jurisdictional turf war over electricity regulation.


There have been a number of developments impacting energy companies with regard to U.S. derivatives regulation under the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”).48

On March 16, 2016, the U.S. Commodity Futures Trading Commission (“CFTC”) approved a final rule that eliminates the reporting and recordkeeping requirements in current CFTC regulations for trade option counterparties that are neither swap dealers nor major swap participants (“Non-SD/MSPs”), including commercial end users such as energy companies that transact trade options in connection with their businesses.49 Significantly, the final rule eliminates the requirement that such counterparties annually file a Form TO in connection with their trade options, and does not require them, as had been proposed, to notify the CFTC’s Division of Market Oversight if they enter into trade options that have, or are expected to have, an aggregate notional value in excess of $1 billion in any calendar year.

In a related development, the CFTC last year issued a final interpretation clarifying its interpretation concerning forward contracts with embedded volumetric optionality (“Final Interpretation”).50 The Final Interpretation appears to signal that, going forward, the CFTC will take a more relaxed view of which transactions constitute “forward contracts” that are not subject to regulation as swaps. This view should be helpful to many commercial parties entering into contracts that provide for volumetric optionality, which means the right to receive or deliver a commodity in an amount that is more or less than was originally contracted for, including many types of energy supply contracts. Under the Final Interpretation, so long as the embedded volumetric optionality is primarily intended, at the time that the parties enter into the contract, to address physical factors or regulatory requirements that reasonably influence demand for, or supply of, the nonfinancial commodity, and the contract otherwise qualifies as a forward under the Final Interpretation, it will be considered a forward contract exempt from swaps regulation.

The CFTC (along with the Prudential Banking Regulators) took action to exempt from the uncleared swaps margin rules swaps between swap dealers and commercial end users, including energy companies, that are eligible for the exemption from mandatory clearing, in accordance with the Business Risk Mitigation and Price Stabilization Act of 2015. Under an interim final rule issued by the agencies, so long as the counterparty qualifies for the exemption from mandatory clearing under Section 2(h)(7)(A) of the Commodity Exchange Act,51 uncleared swaps with that counterparty are not subject to the uncleared swaps margin rules.52

Another issue of concern to many energy companies involves the CFTC’s proposed position limits rules, which were re-proposed in November 2013, and, if adopted, would impose position limits on four energy reference contracts, including economically equivalent futures, options and swaps. Last fall, the CFTC issued for public comment a supplement (the “Supplemental Aggregation Proposal”) to its proposed aggregation rules for position limits for related entities that were issued in November 2013.53 The Supplemental Aggregation Proposal, if adopted, will in many cases make it easier for closely affiliated entities to obtain an exemption from aggregation of their derivatives positions, which otherwise would be required under the rules, and, therefore, will permit affiliated entities to engage in a larger amount of overall trading. Under the Supplemental Aggregation Proposal, the key change from the 2013 proposed rules is that a market participant that owns greater than 50 per cent of another entity would be allowed to obtain an exemption from aggregation with respect to positions of the owned entity by filing a notice that includes certifications regarding trading independence with the CFTC under the same process that market participants with 10 per cent to 50 per cent ownership interest are permitted to use. By contrast, under the 2013 aggregation proposed rules, in order to obtain an exemption for majority-owned entities, market participants would have been required to obtain affirmative approval from the CFTC and to provide certain additional certifications.


FERC’s Office of Enforcement (Enforcement) continued to focus its efforts during 2015 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.54 In FY 2015, 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.55 FERC opened 19 new investigations and obtained monetary penalties and disgorgement of unjust profits totaling approximately $27 million. With the pending litigation in U.S. federal district courts and before the Commission, Enforcement is seeking to recover more than $544 million in civil penalties and disgorge more than $42 million in allegedly unjust profits.

The Commodities Futures Trading Commission (CFTC) also continued to aggressively exercise its enforcement authority in FY 2015, initiating more than 220 investigations and brining 69 enforcement actions, resulting in more than $3 billion in monetary sanctions. A significant portion of the CFTC’s enforcement actions continue to involve the energy sector, and the CFTC has prohibited disruptive trading practices on the commodities exchanges under its jurisdiction. Notable FERC and CFTC matters are briefly described below.

A. Berkshire Power Co. (FERC)

On March 30, 2016, FERC approved a settlement agreement for more than $3 million in civil penalties and disgorgement from Berkshire Power Co. and its management company, Power Plant Management Services LLC, after the companies admitted to intentionally misrepresenting the availability of a gas-fired generating facility located in Massachusetts.56 FERC found that the companies violated the Commission’s Anti-Manipulation Rule,57 Market Behavior Rules,58 the ISO New England (ISO-NE) Tariff, and certain Commission-Approved Reliability Standards by concealing plant maintenance. The companies also pled guilty to felony violations of the Clean Air Act59 for tampering with emissions monitoring equipment at the plant. This case is notable as an example of increasing cooperation between FERC Enforcement and U.S. Attorneys at the Department of Justice.

B. Maxim Power Corporation (FERC)

On May 1, 2015, FERC issued an Order Assessing Civil Penalties against Maxim Power Corporation, several of its affiliates, and one individual employee, alleging that they had violated the Commission’s Anti-Manipulation Rule through a scheme to collect approximately $3 million in inflated payments from ISO-New England (ISO-NE) for reliability runs by charging the ISO for costly oil when it actually burned much less expensive natural gas.60 FERC also found that Maxim had violated FERC’s false statements regulation by misleading and omitting material omissions in its communications with the ISO-NE Market Monitor.61 FERC assessed civil penalties of $5 million against Maxim and $50,000 against an individual employee, with one Commissioner dissenting from the Commission’s Order.

On July 1, 2015, Enforcement staff filed a petition in the United States District Court for the District of Massachusetts to enforce the Commission’s Order, and the respondents filed a motion to dismiss the petition on September 4, 2015.62 That motion is pending before the court.

C. BP America Inc. et al. (FERC)

On August 13, 2015, an Administrative Law Judge at FERC issued an Initial Decision, finding that BP America Inc., BP Corporation North America Inc., BP America Production Company, and BP Energy Company (collectively, BP) illegally manipulated a certain natural gas market in Houston from September to November 2008. Enforcement Staff alleged manipulation by citing, among other things, markedly changed market activity by BP at points in Texas following Hurricane Ike, and a recorded telephone demonstrating that a junior trader realized BP’s trading was manipulative and expressed concern to his supervisor.

The Initial Decision assessed penalties totaling $28 million; and disgorgement of $800,000 in unjust profits, which is equal to the amount sought in the Commission’s Order to Show Cause issued on August 5, 2013.63 The hearing lasted approximately two weeks, and was the first evidentiary hearing in several years regarding alleged market manipulation. Pre-trial discovery included testimony by 23 witnesses, including several expert witnesses offered by both Enforcement staff and BP, and the hearing record consisted of 325 exhibits and 2,657 pages of transcripts. The Initial Decision and the parties’ post-hearing briefs are pending before the Commission.

D. Lincoln Paper and Tissue et al. (FERC)

On August 29, 2013, FERC issued orders64 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.65 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.66 On December 19, 2013, and February 14, 2014, the parties moved to dismiss FERC’s complaint, arguing that: (1) FERC’s claim for civil penalties is barred by a five-year statute of limitation; (2) FERC lacks jurisdiction over Lincoln’s conduct because the States have exclusive control over demand response regulation; (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.67

The Supreme Court’s decision in EPSA, discussed above, upholding FERC’s authority over demand response compensation in organized wholesale energy markets eliminated speculation over whether the courts would dismiss the demand response enforcement litigation for lack of jurisdiction. On April 11, 2016, the court denied the Motions to Dismiss and transferred the demand response litigation to the federal district court for the District of Maine.68

E. Barclay’s Bank PLC (FERC)

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 2008.69 The penalty assessed 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.70 On May 20, 2015, the court denied the Motion to Dismiss.71 The matter is still pending before the court, which has not yet determined whether the defendants are entitled to full discovery rights as part of the de novo review mandated by the FPA. Defendants’ appeal of two preliminary district court orders to the U.S. Court of Appeals for the Ninth Circuit was dismissed as premature.72

F. Up-To Congestion Investigations, Settlements, and Proceedings (FERC)

FERC has continue to pursue allegations of “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).”73 To be profitable, the spread change must exceed the costs of the trade. Notable investigations and litigation are discussed below.

1. Powhatan Energy Fund, LLC

On May 29, 2015, the Commission issued an Order Assessing Civil Penalties, in which it assessed penalties against Powhatan Energy Fund, LLC ($16.8 million), HEEP Fund Inc. ($1.92 million), CU Fund Inc. ($10.08 million), and the companies’ principal trader Houlian “Alan” Chen ($1 million) (collectively, “Powhatan Respondents”) and ordered the corporate entities to disgorge allegedly unjust profits. The order followed FERC’s December 17, 2014, Order to Show Cause and Notice of Proposed Penalty alleging 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 proposing civil penalties of the same amounts.74

In 2014, following FERC’s issuance of a Notice of Alleged Violation against the Powhatan Respondents alleging violations of the Anti-Manipulation Rule based on UTC trading,75 Powhatan took an unprecedented step by launching a website publicly responding to a the allegations.76 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.77

On July 31, 2015, Enforcement staff filed a petition in the United States District Court for the Eastern District of Virginia to enforce the Commission’s Order.78 On October 19, 2015, the respondents filed a motion to dismiss the petition, and that motion was denied on January 8, 2016. The Powhatan Respondents have also submitted a motion for leave to file supplemental material beyond what was included in FERC’s investigative record, and the court has not yet ruled on that motion or determined the scope of the de novo review required by the Federal Power Act.

2. City Power Marketing LLC

On July 2, 2015, the Commission issued an Order Assessing Civil Penalties against City Power Marketing, LLC (City Power) and its owner, K. Stephen Tsingas.79 The Commission found that City Power and Tsingas had violated the Commission’s Anti-Manipulation Rule by engaging in fraudulent Up-To Congestion trades in the PJM market during the summer of 2010. As part of that finding, the Commission determined that City Power and Tsingas had engaged in three types of trades to improperly collect MLSA payments intended for bona fide Up-To Congestion trades: (1) “roundtrip” trades that constituted wash trades, (2) trading between export and import points (SOUTHIMP and SOUTHEXP) that had the same prices, and (3) trading between two other points (which had minimal price differences) not to profit from spread changes but instead for the purpose of collecting MLSA payments. The Commission reasoned, in part, that City Power’s trades were inherently fraudulent because they were pre-arranged to cancel each other out and involved little to no economic risk.

The Commission also found that City Power had violated section 35.41(b) of the Commission’s regulations by making false and misleading statements and material omissions in its communications with Enforcement staff to conceal the existence of relevant instant messages. The Commission assessed $14 million in civil penalties against City Power and $1 million against Tsingas and ordered disgorgement of $1,278,358 in unjust profits, plus interest.

On September 1, 2015, Enforcement staff filed a petition in the United States District Court for the District of Columbia to enforce the Commission’s Order.80 On November 2, 2015, the respondents filed a motion to dismiss the petition, and that motion remains pending. As in the other pending federal litigation, Respondents have challenged FERC’s enforcement procedures and have briefed the issue of the appropriate scope and nature of de novo review.

3. Settlements for Reliability Standards Violations (FERC)

FERC continues to actively oversee and enforce Reliability Standards compliance, in coordination with the North American Electric Reliability Corporation (NERC), an industry self-regulatory organization, and NERC’s regional reliability entities. Reliability enforcement is of particular interest because the Reliability Standards are also mandatory and enforceable in the provinces of Ontario, New Brunswick, Alberta, British Columbia, Manitoba, and Nova Scotia and are in the process of being adopted in Quebec.81

In 2015, FERC reached major settlements with four entities related to a widespread power outage on September 8, 2011 which caused over 30,000 MWh of lost firm load in the San Diego area, as well as parts of Arizona and Mexico. For their significant violations stemming from inadequate operational procedures and failures to take necessary emergency measures to limit cascading failures and blackouts during the event, CAISO, Southern California Edison Company, the Western Area Power Authority-Desert Southwest Region, and Western Electricity Coordinating Council paid civil penalties totaling more than $22 million and agreed to numerous mitigation activities and compliance monitoring.82

4. Panther Energy / Coscia Spoofing (CFTC)

The CFTC filed and settled charges, collecting a $2.8 million civil penalty and ordering disgorgement totaling $1.4 million, against commodities trading firm Panther Energy Trading LLC and its trader Michael J. Coscia in 2013. The entities engaged in the disruptive trading practice of “spoofing” by using a computer algorithm to illegally place and quickly cancel bids and offers in exchange-traded futures contracts, including for crude oil and natural gas, to create the false impression that there was significant buying interest in the markets.83 Coscia was convicted on federal criminal charges in November 2015 involving the same allegations that formed the basis for the civil penalty, in the first criminal prosecution for spoofing.84


As an alternative to transporting crude oil via pipeline, the North American crude oil industry has increasingly turned to transportation by rail to supply crude in the U.S. Between 2008 and 2014, crude by rail (“CBR”) tank car loads have increased approximately exponentially. However, corresponding with the surge of CBR, derailments and explosions have also increased, raising significant public safety and environmental concerns. In perhaps the most prominent CBR disaster, a CBR train transporting crude oil from North Dakota exploded in Lac-Mégantic, Quebec killing 47 people in July 2013. Since the 2013 disaster, several more derailments and explosions have occurred across the U.S., endangering the lives of approximately 25 million American citizens who live within the evacuation area surrounding CBR transportation routes.

In the U.S., several regulatory agencies exercise the ability to implement rules and guidelines shaping CBR safety. In general, the U.S. Department of Transportation (“DOT”) is charged with regulatory oversight of CBR as a means of rail transport. The DOT also oversees two important sub-agencies to assist with its regulatory mandate – The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and Federal Railroad Administration (“FRA”). The PHMSA retains regulatory authority of hazardous materials transport packaging, including the tank cars used for CBR transportation, while the FRA implements the DOT’s promotion of rail safety in regional safety offices.

Concerns regarding CBR transportation safety have led to the implementation of several new administrative rules and policies over the past few years. Most recently, on May 1, 2015, the DOT announced a final rule for safe transportation of flammable liquids by rail. The rule requires: (1) more stringent tank car standards and retrofitting requirements for older CBR tank cars; (2) new braking standards to reduce accident severity and “pile-ups”; (3) new operational protocols for CBR trains, including routing requirements, speed restrictions and information for local government agencies; and (4) new sampling and testing requirements to improve the classification of energy products placed into the rail transportation system.85 The rules apply to a new category of transport, high-hazard flammable trains, which are defined as a “continuous block of 20 or more tank cars loaded with a flammable liquid or 35 or more tank cars loaded with a flammable liquid dispersed through a train.”


On December 18, 2015, the President Obama signed into law a $1.8 trillion spending bill which contained a reversal of a 40-year ban on crude oil exports from the U.S. Pursuant to the Energy Policy and Conservation Act of 1975,86 exportation of crude oil was prohibited absent specific exceptions granted by the U.S. Commerce Department in response to the 1973 oil crisis.

Inclusion of the reversal in the spending bill was considered a compromise between Republicans and the oil industry, who had long called for the end of the ban, in return for several environmental measures broadly supported by Democrats and environmental organizations, including the extension and eventual phasing out of certain renewable energy tax credits, reauthorizing a conservation fund for three years, and the exclusion of other measures designed to thwart President Obama’s environmental regulatory efforts. In particular, the spending bill extended the expiration date for the production tax credit to December 31, 2019, for wind facilities commencing construction, with a phase-down beginning for wind projects commencing construction after December 31, 2016.

Pressure to reverse the crude oil export ban was partially due to the rapid increase in U.S. oil production in recent years. Between August 2008 and the end of 2015, U.S. oil production increased approximately 90 per cent. Although the Obama Administration had previously threatened to veto legislation including a reversal of the ban, the White House noted that the U.S. is already a major exporter of refined crude oil products. Certain domestic oil refiners expressed their disapproval of the ban, citing concerns that lifting the ban will negatively impact their businesses by driving crude oil overseas to be refined. Oil refiners have also noted that the ban will increase costs to consumers and will reduce U.S. energy independence by increasing reliance on foreign oil refiners to provide the U.S. with products derived from crude oil.

The impact of reversing the crude oil ban reflects a new geopolitical reality of America’s increased crude oil security. Supplying global markets with U.S. crude oil may improve the global community’s hand in dealing with Russia and Iran, as the threat of losing Russian and Iranian crude oil supplies for Europe, India and Japan could be mitigated by the potential for replacement by U.S. exports. Domestically, environmental groups have expressed concern about the ban’s reversal, citing corresponding increases to fracking, air and water pollution, and decreased support for renewable energy.


The Obama Administration’s signature climate rule under its Climate Action Plan —the Clean Power Plan (CPP)—is largely on pause as legal challenges wind their way through the federal courts. In the meantime, states are responding in a variety of ways, some moving forward with implementation of the CPP, while others have halted their efforts. The ultimate fate of the CPP may depend greatly on the next person to fill the U.S. Supreme Court seat vacated upon the death of Justice Antonin Scalia, which will, in turn, likely depend on the outcome of November’s presidential election.

A. Overview of the CPP

The U.S. Environmental Protection Agency (EPA) issued a final rule adopting the CPP in August 2015, citing “immediate risks” to national security, public health, and the economy.87 These ambitious policies, adopted pursuant to Section 111(d) of the Clean Air Act, establish the first ever national standards to limit greenhouse gas (GHG) emissions from existing power plants. If fully implemented, the rule will have significant implications for how energy is generated, transmitted, and consumed in the United States.

Under the CPP, states are required to reduce GHG emissions from power plants 32 per cent below 2005 levels by 2030, achieving interim emissions reduction targets for 2022 through 2029. Final compliance targets for 2030 are to be maintained thereafter. Individualized targets for each state are established by analyzing pounds of carbon emissions per megawatt-hour (MWh) of electricity generated based on 2012 historical data.

The CPP gives states flexibility to adopt individually tailored approaches for meeting compliance goals. By allowing conversion of rate-based target emission goals into standards based on tons of emissions per year (mass-based standards), the rule leaves the door open for adoption and further elaboration of market-based programs such as the carbon cap-and-trade program in California and Regional Greenhouse Gas Initiative in the Northeast.

The final rule set a deadline of 2018 for states to submit final implementation plans for achieving their compliance targets, and a deadline of 2022 for states to take action. However, it is unclear whether the CPP’s goals will be achieved in the established timeframes, as it has been the subject of a number of legal twists and turns. In October 2015, several states and industry groups challenged the rule in the Circuit Court of Appeals for the D.C. Circuit, which declined to stay the rule pending decision. The challengers then sought a stay from the U.S. Supreme Court, which surprised observers by granting the stay in February 2016. That decision was seen by many as an indication of the high court’s concerns about the CPP and seemed to bode well for the challengers. But that stay was granted in a 5-4 decision, with Justice Scalia voting in favor of the stay, just days before his death.

Another surprise came in mid-May 2016, just weeks before the D.C. Circuit was scheduled to hear oral argument, when that Court announced its decision to push arguments to September 2016 and to have the case reviewed en banc (that is, before a full bench of ten judges rather than the usual three.) An en banc hearing is unusual, and an en banc hearing in the first instance—as opposed to on rehearing from a three-judge panel—seldom happens.

Despite the stay, the Obama Administration and nineteen states continue to plan for implementation of the CPP. For example, the EPA is moving forward on its Clean Energy Incentive Program, which is a voluntary program that allows states to incentivize early investments in wind and solar power generation, as well as energy efficiency measures in low-income communities. However, another twenty states have suspended their efforts, and three states and Washington, D.C. are exempt from the rule. Legislators in nearly 20 states have introduced legislation, with support from industry-funded groups, which would prohibit any work on CPP compliance planning activities.

B. Methane Emissions Regulations

The Obama Administration finalized three new rules aimed at curbing methane emissions from new, reconstructed, or modified oil and gas wells.88 Methane is a prevalent GHG, second only to carbon dioxide, with 25 times the global warming potential on a pound-for-pound basis.89 This is the first time that the EPA has regulated methane in any industry.

These rules are designed to prevent 510,000 short tons of methane—11 million metric tons of carbon dioxide equivalent emissions—by 2025. EPA estimates these regulations will result in $690 million of climate benefits, as compared to the rule’s estimated costs of $530 million, in 2025. EPA also expects reductions in volatile organic compounds and other air toxics, which would yield health benefits.

The first rule establishes methane emissions standards for new, reconstructed, and modified sources under Section 111(b) of the Clean Air Act. The second rule clarifies the rules for determining whether oil and gas equipment and activities are part of a single “stationary source. The third rule finalizes and amends regulations regarding minor sources on Federal Indian lands.

While environmentalists applaud these steps, the oil and gas industry has criticized EPA for basing the rules on inconsistent data regarding current methane emission levels. The industry is also bracing itself for future rules that may be imposed on existing sources, as indicated by EPA’s Information Collection Request for information from oil and gas companies regarding their existing operations.


New York Public Service Commission’s Reforming Energy Vision

The New York Public Service Commission (“NYPSC”) in 2014 initiated Case 14-M-0101, Reforming the Energy Vision (REV), along with a companion proceeding (Case 14-M-0094). The REV is intended to improve customer knowledge, market animation, system-wide efficiency, fuel and resource diversity, system reliability and resiliency, and reduce carbon emissions. The companion proceeding is to address the future of New York clean energy programs currently funded by a surcharge on the delivery portion of customers’ utility bills. This proceeding is being closely watched by many states across the U.S.

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. In a February 26, 2015 Order in the REV Proceeding, the NYPSC instituted a REV large-scale renewable (LSR) track as well.

The NYPSC has issued a series of orders over the last two years on various REV issues. The orders serve principally to establish analytical frameworks for issues such as how to conduct cost-benefit analyses, and also to expand the scope of the proceeding.90

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. The NYPSC accepted the EIS as complete on February 24, 2016.91


Energy storage continues to draw ever greater attention from state and federal governments, as utilities and grid operators wrestle with how best to integrate large volumes of intermittent resources like wind and solar into power grids designed for more traditional energy generation sources. Storage, whether at the utility scale, the customer scale, or sizes in between, offers one additional way to balance and shape output from intermittent resources to meet customer demands.

However, storage poses unique regulatory challenges. Energy storage systems allow individual storage units to be classified as generation, as transmission or distribution, and/or as load, making it difficult to fit into existing regulatory structures.

A. Federal Developments

FERC issued Order 78492 in 2013. That order directed wholesale market operators to find ways to monetize “fast response” resources; code for storage devices such as batteries and flywheels. After a number of orders in various RTOs/ISOs implementing Order 784, FERC issued a follow-up order on April 11, 2016, in Docket Number AD16-20-000 concerning the “participation of electric storage resources in the organized wholesale electric markets, that is, the regional transmission organizations or RTOs and the independent system operators or ISOs.” FERC is seeking input on “whether additional action is necessary to address potential barriers to electric storage participation in the RTO and ISO markets.”

B. California

As detailed in last year’s Washington Report, California has taken the lead to include energy storage in resource planning by its electric utilities and energy suppliers. Assembly Bill (“AB”) 251493 required the California Public Utilities Commission (“CPUC”) to determine appropriate targets, if any, for each load serving entity (“LSE”) to procure viable and cost-effective energy storage systems. The CPUC opened Rulemaking (“R.”) 10-12-007 to implement AB 2514. R.10-12-007 culminated in Decision (“D.”) 13-10-040 in 2013. That decision requires California’s three large investor-owned electric utilities (“IOUs”) to procure 1,325 MW of energy storage capacity by 2020. The CPUC divided the 1,325 MW into biennial procurement targets by “grid domain” in 2014, 2016, 2018, and 2020:

  • IOU targets: 1,325 MW of storage by 2020 in 4 biennial solicitations (starting December 2014)
    • PG&E 580 MW
    • SCE 580 MW
    • SDG&E 165 MW
  • Above targets divided into three “storage grid domains”:
    • Transmission-connected,
    • Distribution-level and
    • Customer-Side of the Meter applications
  • Non-utility load serving entity targets ~ 1 per cent of peak load by 2020

In September 2013, the California ISO (“CAISO”), CPUC, and the California Energy Commission announced 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 and a workshop was held in October to discuss the draft and solicit feedback. The final roadmap was completed by the end of 2014.

D.13-10-040 directed a comprehensive evaluation of the Energy Storage Framework and Design Program no later than 2016, and once every three years thereafter. In compliance with D.13-10-040’s direction, the CPUC last year opened a new rulemaking as part of its ongoing implementation of AB 2514. The new OIR is docketed as R.15-03-011, and is entitled “Order Instituting Rulemaking to consider policy and implementation refinements to the Energy Storage Procurement Framework and Design Program (D.13-10-040, D.14-10-045) and related Action Plan of the California Energy Storage Roadmap.” As the proceeding’s name implies, it is a broad review of all CPUC policies (and associated IOU practices) relating to energy storage.94 The CPUC has conducted a workshop in the proceeding, and further workshops are anticipated. The CPUC has not yet issued any decisions in the new rulemaking.

The CPUC has also encouraged acquisition of storage resources in its proceeding addressing the premature retirement of the San Onofre Nuclear Generating Station (SONGS). D.13-02-015 directed SCE to undertake an “all-sources” bidding process for resources to address local reliability needs resulting from SONGS’ closure. 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.

On November 5, 2014, SCE announced that 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 for SCE in D.13-02-015 for energy storage resources, though only slightly more than a third of the maximum SCE might have procured. In November 2015, the CPUC approved SCE’s filing for approval of these contracts.


State public utility commissions across the United States continue to grapple with how to incorporate distributed generation and “net metering” into rate design. Traditional utilities contend that giving consumers credit for energy produced with distributed generation (such as residential solar panels that connected with the grid) unfairly reduces utility revenues. Utilities recover a large portion of costs through per-KWh charges. Such utilities also contend that distributed generation users, and particularly net metering customers, do not pay a fair share of the fixed costs needed to provide the electricity they use. Advocates of distributed generation counter that high fixed prices a(coupled with lower variable prices) encouraged energy use and would allow the utilities to avoid competition from distributed generation. Different states are addressing these issues in divergent ways.

A. Distributed Resources Rulemakings

1. Distribution Energy Resources and Distribution Resources Plan Proposals

For more than a decade, California has required each of its IOUs to consider nonutility-owned Distribution Energy Resources (DERs) as a possible alternative to investments in its distribution system to ensure reliable electric service at the lowest possible cost.95 In 2013, the California legislature enacted PU Code Section 769 requiring IOUs to submit Distribution Resource Plan Proposals (“DRPs”) to the CPUC. Section 769 requires 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.”96

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.

R.14-08-013 remains open, and is consolidated with the large utility applications for approval of individual DRPs: A.15-07-002 (SCE), A.15-07-003 (SDG&E), and A.15-07-006 (PG&E). The CPUC projects a decision in this proceeding in early 2017.

In parallel, the CPUC is moving forward with R.14-10-003, the “Order Instituting Rulemaking to Create a Consistent Regulatory Framework for the Guidance, Planning and Evaluation of Integrated Distributed Energy Resources.” Issues in that proceeding include:

“1) a determination of how the distributed energy resources, needed to fill the required characteristics and the values—to be determined in R.14-08-013 et al.—will be procured;

2) a focus on the integration of distributed energy resources in a holistic way; and

3) a consideration of the adoption of localized incentives and the methodology used in determining the incentives.”97

2. Net Energy Metering

Under A.B. 327,98 enacted in 2013, CPUC had until December 31, 2015 to develop a standard contract or tariff that applies to customer-generators who own rooftop solar installations or other distributed generation.

On January 28, 2016, the CPUC approved Decision (D.) 16-01-044, adopting a NEM successor tariff that continues the existing NEM structure while making adjustments to align the costs of NEM successor customers more closely with those of non-NEM customers.99 The CPUC’s decision:

  • largely preserves retail payments for residential rooftop solar generators;
  • adds new interconnection costs and non-bypassable charges to distributed solar systems;
  • and imposes new minimum bill requirements.

The proposed decision declines to “impose any demand charges, grid access charges, installed capacity fees, standby fees, or similar fixed charges on [net energy metering] residential customers, while the [CPUC] continues to evaluate the need for them.” Also, solar projects larger than 1 megawatt are eligible for net metering provided they can pay related interconnection and upgrade fees.

Utilities filed Advice Letters with the CPUC implementing the new requirements on February 29, 2016. The Advice Letters are currently under review by CPUC staff.

Senate Bill 793,100 The Green Tariff Shared Renewables Program, was enacted October 8, 2015, and requires the CPUC to require that a participating utility’s green tariff shared renewables program permit a participating customer to subscribe to the program and receive a reasonably estimated bill credit and bill charge, as determined by the commission, for a period of up to 20 years.

B. Nevada – Rooftop Solar Installations and Net Metering

In 2015, the Nevada legislature enacted SB 374.101 This law directed utilities to prepare a cost-of-service study for rooftop solar installations, and to prepare a new tariff to go into effect once solar rooftop installations in Nevada exceeded a cumulative 235 MW of installed capacity. Nevada’s two major utilities, NV Energy and Sierra Pacific, filed cost-of-service studies, and, on December 23, 2015, the Public Utilities Commission of Nevada (PUCN) entered an order approving tariff filings by the two utilities.102

The tariffs contain the following departures from the relevant prior tariffs.

  • The approved tariffs net customer generation and customer load hourly, rather than monthly, as had previously been the case.
  • The approved tariffs value of the excess energy that rooftop solar customers “sell” to the utilities at 2.6 (NV Energy) and 2.7 (Sierra Pacific) cents per kWh—a 76 per cent and 71 per cent reduction, respectively, in the value that rooftop solar customers were previously credited.103
  • The approved tariffs nearly triple the fixed charges that net metering customers must pay the utilities. In Sierra Pacific’s service territory, the basic monthly service charge for residential solar customers rose from $15.25 to $44.43, and in Nevada Power’s service territory, the monthly fixed charges imposed on residential solar customers increased from $12.75 to $38.51.104

The PUCN declined to “grandfather” the approximately 17,000 existing solar customers who had already installed and interconnected rooftop solar systems into the pre-existing rate regime.105 Thus Nevada is the first state in the country to significantly change the economics of net metering without grandfathering existing customers. This decision is being challenged in the Nevada state courts.

* 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 the following members of Morrison & Foerster’s energy practice for their assistance in developing this report: Zori Ferkin; Julian Hammar; Todd Edmister; Paul Varnado; Ben Fox; Megan Jennings; and Lala Wu. The views expressed in this report are his own, however, and do not necessarily reflect those of Morrison & Foerster or any of its clients.

  1. Pieridae Energy (USA) LTD, DOE/FE Order No 3639 (22 May 2015) [Order No 3639]; Bear Head LNG Corp, DOE/FE Order No 3681 (17 July 2015)(authorizing re-export of United States gas, as LNG, to FTA countries); Pieridae Energy (USA) Ltd., DOE/FE Order No 3768 [Order No 3768]; Bear Head LNG Corp, DOE/FE Order No 3770 (5 February 2016) (authorizing re-export of United States gas, as LNG, to non-FTA countries) [Order No 3770].
  2. 15 USC 717b(c).
  3. Order No 3770, supra note 1 at 194. “End use,” as defined by DOE is “combustion or other chemical reaction conversion process (e.g., conversion to methanol.)”; Order No 3639, supra note 1 at 3 n7.
  4. Order No 3768, supra note 1 at 229; Order No 3770, supra note 1 at 190.
  5. Order No 3639, supra note 1 at 4.
  6. Bear Head LNG Corporation, DOE/FE, Order No 3769 (5 February 2016) [Order No 3769].
  7. Ibid at 9.
  8. Ibid at 9-10.
  9. Ibid at 10.
  10. Ibid at 10.
  11. Ibid at 11.
  12. 42 USC § 4321 [NEPA].
  13. Jordan Cove Energy Project LP, Pacific Connector Gas Pipeline LP, 154 FERC 61190 (11 March 2016).
  14. Ibid at 39.
  15. Ibid at 43-44.
  16. 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).
  17. Corpus Christi Liquefaction LLC, 149 FERC 61238 (2014), reh’g denied, 151 FERC 61098 (2015).
  18. Sierra Club v FERC, No 15-1133 (DC Cir filed 11 May 2015).
  19. Dominion Cove Point LNG LP, 148 FERC 61 244 (29 September 2014), reh’g and motion for stay denied, 151 FERC 61095 (May 4, 2015).
  20. Earthreports Inc v FERC, No 15-1127 (filed 7 May 2015), order denying emergency motion for stay filed June 12, 2015.
  21. Pivotal LNG Inc, 151 FERC 61006 (2015) at 5.
  22. Ibid at paras 11-12.
  23. Ibid at paras 13.
  24. Ibid at p 2-3 (Commissioner Bay dissenting).
  25. Notice of Withdrawal of Application, Excelerate Liquefaction Solutions (Port Lavaca I) LLC, Docket No CP14-71-000 et al. (3 September 2015).
  26. Downeast Liquefaction LLC et al, Letter to FERC Secretary Bose, Docket Nos PF14-19-000 et al (2 November 2015).
  27. City of Fort Collins v Colorado Oil and Gas Association, 2016 CO 28; City of Colorado v Colorado Oil and Gas Association, 2016 CO 29; see also “Colorado High Court Ban on Fracking Bans Could Set Precedent”, Law360 (10 May 2016), online: Law 360 <>.
  28. 44 Fed Reg 16128 (2015); Coral Davenport, “New Federal Rules Are Set for Fracking”, The New York Times (20 March 2015), online: New York Times <>.
  29. Wyoming v US Department of the Interior, No 2:14-CV-043-SWS, 2015 WL 5845145 (D Wyo 2015) [Wyoming]; see Coral Davenport, “Judge Blocks Obama Administration Rules on Fracking”, The New York Times (30 September 2015), online: New York Times <>.
  30. Wyoming, supra note 29 at p 40.
  31. FERC v Electric Power Supply Ass’n, 577 US (2016); For a case comment on this decision previously included in this quarterly, see Scott Hempling, “The Supreme Court Saves Demand Response: Now What?” (2016) 4:1 Energy Regulation Quarterly 35.
  32. 16 USC 791a.
  33. Administrative Procedure Act, Pub L 79-404, 60 Stat 237 (1946).
  34. Electric Power Supply Ass’n v FERC, 753 F (3d) 216 (DC Cir 2014) [EPSA].
  35. Demand Response Compensation in Organized Wholesale Energy Markets, Order No 745, 134 FERC 61187 (2011), order on reh’g, Order No 745-A, 137 FERC 61215 (2011). The Order required that demand resources actually be capable of supplying the claimed reduction in demand, that the resources pass a ‘net benefits test’ and that the applicable state regulatory commission permit the bidding of the demand in an organized wholesale market.
  36. Ibid at p 18.
  37. See ibid at p 19 (“When FERC regulates what takes place on the wholesale market, as part of carrying out its charge to improve how that market runs, then no matter the effect on retail rates, §824(b) [of the FPA] imposes no bar.”)
  38. Ibid at p 15.
  39. Ibid at pp 26-27.
  40. Federal Power Commission v Southern California Edison Company, 376 US 205 (1964).
  41. See Robert R. Nordhaus, “The Hazy Bright Line: Defining Federal and State Regulation of Today’s Electric Grid” (2015) 36 Energy Law Journal 203.
  42. EPSA, supra note 34 slip op at 26.
  43. Hughes v Talen, 578 US (2016).
  44. Ibid at 12.
  45. Ibid at 3.
  46. Ibid. (Sotomayor, J, concurring).
  47. Electric Power Supply Association v FirstEnergy Solutions Corp, Order Granting Complaint, 155 FERC 61101 (2016); Electric Power Supply Association v AEP Generation Resources Inc, Order Granting Complaint, 155 FERC 61102 (2016). The orders rescinded affiliate abuse waivers which had allowed FirstEnergy and AEP to avoid proving that the PPAs were at competitive prices, such as by showing evidence that unaffiliated buyers were willing to pay similar prices for the same generation, or that unaffiliated generators have made sales at similar prices.
  48. Dodd-Frank Wall Street Reform and Consumer Protection Act, Pub L No 111-203, 124 Stat 1376 (2010).
  49. 81 Fed Reg 14966 (2016) (to be codified 17 CFR Part 32); See US Commodity Futures Trading Commission, News Release, PR7343-16, “CFTC Approves Final Rule to Amend the Trade Option Exemption by Eliminating Certain Reporting and Recordkeeping Requirements for End-Users” (16 March 2016) online: CFTC <>.
  50. Forward Contracts with Embedded Volumetric Optionality, Final Interpretation, 80 Fed Reg 28239 (2015).
  51. 7 USC §§ 1 et seq [CEA].
  52. 81 Fed Reg 635 677 (2016); 80 Fed Reg 74915 (2015).
  53. 80 Fed Reg 58365 (2015).
  54. Federal Energy Regulatory Commission, 2015 Report on Enforcement, FERC Docket No AD07-13-009 (19 November 2015), online: FERC <>. The Report provides additional transparency and guidance for regulated entities and the public.
  55. See 16 USC § 824v(a) (2012); 15 USC § 717c-1 (2012).
  56. Berkshire Power Company LLC, 154 FERC 61259 (2016).
  57. 18 CFR § 1c.1 (2015).
  58. 18 CFR § 35.41(a),(b).
  59. 42 USC §701.
  60. Maxim Power Corporation, 15 FERC 61094 (2016).
  61. 18 CFR 35.41(b) (2015).
  62. FERC v Maxim Power Corporation, No 15-cv-30113 (D Mass.)
  63. BP America Inc, 152 FERC 63 016 (2015); BP America Inc., 144 FERC 61100 (2013).
  64. Lincoln Paper & Tissue LLC, 144 FERC 61 162 (2013); Competitive Energy Servs LLC, 144 FERC 61163 (2013); Richard Silkman, 144 FERC 61164 (2013).
  65. “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.
  66. 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).
  67. CES and Richard Silkman’s Motion to Dismiss Complaint, FERC v Lincoln Paper & Tissue LLC, No 1:13-cv-13056-DPW (D Mass) (19 December 2013); 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).
  68. Memorandum and Order Regarding Motions to Dismiss, FERC v Lincoln Paper & Tissue LLC, No. 1:13-cv-13056-DPW (D Mass) (11 April 2016). The order contained rulings favorable to FERC Enforcement on the issues of statute of limitations, waiver of all defenses and arguments not raised during the Commission penalty assessment process, applicability of the Anti-Manipulation Rule to individual persons, and fair notice of which fraudulent conduct is proscribed. The Court did not provide clarity sought on the scope of de novo review under the FPA.
  69. Barclays Bank PLC, 144 FERC 61041 (2013).
  70. Notice of Motion and Motion to Dismiss, FERC v Barclays Bank PLC, No 2:13-cv-02093-TLN-DAD (ED Cal) (16 December 2013). The motion raised a number of important legal questions relating to FERC’s authority to police electricity markets. The motion, for example, argued that FERC lacks jurisdiction over the relevant transactions because they were commodity futures transactions over which the 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.
  71. Order, FERC v Barclays Bank PLC, No 2:13-cv-02093-TLN-EFB (ED Cal) (20 May 2015). The court found, among other things, that FERC’s petition was not time-barred by the statute of limitations, that FERC has adequately established its jurisdiction under the FPA, that the CFTC does not have exclusive jurisdiction over the trades at issue, that individual persons are “entities” subject to the anti-manipulation rule, and that open-market trades can be manipulative.
  72. FERC v Barclays Bank PLC, No 15-17251 (9th Circuit) (08 March 2016).
  73. Re PJM Up-To-Congestion, Order Approving Stipulation and Consent Agreement, 14 FERC 61088 (2015) at para 3.
  74. Powhatan Energy Fund LLC, 149 FERC 61261 (2014).
  75. 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).
  76. See FERC Office of Enforcement, Preliminary Findings of Enforcement Staff’s Investigation of Powhatan Energy Fund LLC (9 August 2013), online: FERC <>.
  77. See Powhatan Energy Fund LLC, FERC v Powhatan Energy Fund LLC (last visited 18 May 2016), online: <>.
  78. FERC v Powhatan Energy Fund LLC, No 3:15-cv-00452 (ED Va).
  79. City Power Marketing LLC and K. Stephen Tsingas, 152 FERC 61012 (2015).
  80. FERC v City Power Marketing LLC, No 15-cv-01428 (DDC)
  81. NERC, Canada, online: NERC <>.
  82. CAISO, 149 FERC 61189 (2014); Southern California Edison Co, 149 FERC 61061 (2014); Western Area Power Authority-Desert Southwest, 149 FERC 61157 (2014); Western Electricity Coordinating Council, 151 FERC 61175 (2015).
  83. Panther Energy Trading and Michael J. Coscia, CFTC Docket No 13-26 (22 July 2013).
  84. See United States v Coscia, No 14-cr-00551 (ND Ill).
  85. U.S. Department of Transportation, Press Release, DOT 42-15, “DOT Announces Final Rule to Strengthen Safe Transportation of Flammable Liquids by Rail (1 May 2015)”, online: <>.
  86. Pub L No 94-163, 89 Stat 871.
  87. The Final Rule was published in the Federal Register in October 2015. 80 Fed Reg 64662 (23 October 2015).
  88. EPA, Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources (12 May 2016), online: EPA <>.
  89. Ibid at 31; see also EPA, Overview of Greenhouse Gases, online: EPA <>.
  90. The NYPSC has collected its REV orders here: DPS – Reforming the Energy Vision, online: Government of New York State <>.
  91. New York Public Service Commission, Resolution Accepting Draft Generic Supplemental Environmental Impact Statement as Complete (24 February 2016), online: Government of New York State <>.
  92. Re Third-Party Provision of Ancillary Services; Accounting of Financial Reporting for New Electric Storage Technologies, 144 FERC 61056 (2013).
  93. Stats 2010, ch 469.
  94. Order Instituting Rulemaking to consider policy and implementation refinements to the Energy Storage Procurement Framework and Design Program (D.13-10-040, D.14-10-045) and related Action Plan of the California Energy Storage Roadmap, CPUC, Rulemaking 15-03-011, online: CPUC <>.
  95. Cal Pub Util Code § 353.5.
  96. Cal Pub Util Code § 769(c).
  97. Order Instituting Rulemaking to Create a Consistent Regulatory Framework for the Guidance, Planning and Evaluation of Integrated Distributed Energy Resources, CPUC, Rulemaking 14-10-003 (2 October 2014), online: CPUC <>.
  98. AB 327, An Act to Amend Sections 382, 399.15, 739.1, 2827, and 2827.10 of, to Amend and Renumber Section 2827.1 of, to Add Sections 769 and 2827.1 to, and to Repeal and add Sections 739.9 and 745 of, the Public Utilities Code, Relating to Energy, 2013-2014, Reg Session, Cal 2013 (enacted).
  99. Decision Adopting Successor Tariff to Net Energy Metering Tariff, CPUC, Decision 16-01-044 (28 January 2016).
  100. SB 793, Green Tariff Renewables Program, 2015-2016 Reg Sess, Cal, 2015 (enacted).
  101. SB 374, Revises Provisions Relating to Energy, 78th Legislature, Reg Session, Nev, 2015 (enacted).
  102. Order Re: NV Energy and Sierra Pacific Power Applications, Nos 15-0741 and 15-0742 (December 23, 2015).
  103. Docket 15-07041, Advice Letter No 453-R at 2 (Dec 30, 2015), 6 ROD 006938.
  104. Ibid; Docket 15-07041, Advice Letter No. 453-R at 2 (Dec. 30, 2015), 6 ROD 006938.
  105. Order Re: NV Energy and Sierra Pacific Power Applications, Nos 15-07041 & 15-07042, at p 108 (23 December 015), 7 ROD 007515.

Leave a Reply