The Washington Report

Energy regulatory developments in the United States impact numerous sectors of the energy industry and address a wide range of issues. We report on key federal and state energy and environmental regulatory and litigation developments in the United States during 2017 and early 2018 that should be of interest to readers of the ERQ.


Stymied by Congressional inaction on climate change, President Obama issued the Climate Action Plan (the Plan) in June 2013,1 a series of administrative – rather than legislative – actions aimed at reducing greenhouse gas (GHG) emissions throughout the U.S. Over the course of President Obama’s second term, his administration implemented the Plan across U.S. federal agencies primarily through administrative rulemaking, policy guidance and changes to government spending, lending and leasing. Among the hundreds of actions falling under the Plan, the Obama Administration’s effort to limit GHG emissions from power plants through rulemaking under the Clean Air Act2 – known as the U.S. Environmental Protection Agency’s (EPA) Clean Power Plan (CPP)3 – was perhaps the most significant in terms of cost and complexity.

In 2017, President Trump began systematic efforts to unwind the Obama Climate Action Plan. The new president is able to do this because the Plan was made up of administrative actions. However, few changes were possible overnight, and the Trump Administration continues to move along the long and uncertain path to unwind the Climate Action Plan. Like the Plan itself, the Trump Administration’s efforts are also quite numerous and being advanced formally and informally across administrative rulemaking, policy guidance and changes to government spending, lending and leasing.

A subset of these efforts has received the most attention from the president and press corps largely as a result of their potential economic impact and the clout of associated constituencies. These include: fuel economy standards for automobiles; emissions standards for power plants (i.e., the previously mentioned CPP); and two tools used to harmonize decisions across the government – the National Environmental Policy Act (NEPA)4 climate guidance and guidance on the “Social Cost of Carbon” (SCC).

First, on March 15, 2017, the EPA announced that the agency and the U.S. Department of Transportation (DOT) would jointly reconsider an Obama-era determination by the EPA not to change GHG emission standards for light-duty cars and trucks manufactured in model years (MYs) 2022–2025. Although this decision did not alter the 2012 regulations that require automakers to achieve specified GHG emission–reduction standards for MYs 2022–2025, it kicked off a process of revisiting those requirements. After the initial reconsideration announcement, both DOT and EPA took key procedural steps toward reconsideration. In July 2017, DOT published a “Notice of Intent” to reopen the environmental impact review associated with the standards.5 And between August and October 2017, EPA held a public comment period open associated with the reconsideration.6 These steps lay the groundwork for decision-making by the agencies in mid-2018. Any decision is likely be litigated upon finalization.

Second, as part of the sweeping March 28, 2017 “Executive Order on Promoting Energy Independence and Economic Growth” that took aim at a broad range of federal climate and energy programs and regulations,7 the Trump Administration started a process to roll back the CPP. On the same day the executive order was signed, the U.S. Department of Justice on behalf of the EPA filed a motion asking the D.C. Circuit to hold CPP litigation pending from the prior administration “in abeyance” while the EPA conducts a review of the CPP. This suspension of litigation in the courts opened the window for a repeal-and-replace strategy now being advanced by the EPA. Specifically, EPA proposed a repeal of the Obama-era CPP in October 2017,8 and, in late December 2017, announced that it was starting the lengthy process of developing a replacement rule with an “Advance notice of proposed rulemaking.”9 Together, these steps do more to stall the CPP than to repeal or replace the standards – given the complexity of the subject matter and process that will likely take years.

Third, the March 28, 2017 Executive Order also took two other significant steps that cascade through many features of government decision-making: the repeal of the NEPA climate guidance and guidance on the SCC. Unlike the formal rulemaking process associated with the fuel economy standards and CPP, the NEPA and SCC guidance documents were put in place more informally by the Obama Administration. As a result, their repeal was easier for the Trump Administration to execute. The implication is significant, as the U.S. government today no longer has a standard, harmonized approach to how it factors climate change into its environmental reviews as part of NEPA, nor does it have a consistent way to calculate SCC for use in rulemaking, procurement and other economic analyses. However, even this success for the Trump Administration may be limited in impact as courts have already started to opine – with different effect – on these issues of administration.10


A. Litigation

Seeking compensation for the costs of mitigating climate change impacts, the City of New York and various local governments in California have filed civil lawsuits against major oil companies. The suits allege that the oil companies bear responsibility for large percentages of total GHG emissions in the previous century and endangered the public despite having knowledge for decades of the catastrophic impacts of climate change.11 While the U.S. Supreme Court dismissed a similar suit brought under federal law in 2011,12 the local governments’ current suits claim damages under state law theories, including public nuisance, negligence and negligent failure to warn. The oil industry has disparaged the lawsuits as a distraction and is expected to defend the suits aggressively in court.13 It remains to be seen whether the current round of litigation will gain any traction in New York and California state courts.

The five oil company defendants named in New York City’s suit have not yet responded to the city’s complaint.14 In three of the suits brought by cities and counties in California, the parties are currently litigating whether the claims should be heard in federal or state court.15

B. Methane Emissions

The U.S. Department of the Interior (DOI) under the Trump Administration has taken steps to roll back regulations intended to reduce GHG emissions from on-shore oil and gas production. In November 2016, the Bureau of Land Management (BLM) under Obama finalized a regulation known as the “Methane and Waste Prevention Rule” that limited venting, flaring and leaking from oil and gas operations. In December 2017, the BLM issued a rule delaying the Methane and Waste Prevention Rule’s compliance dates until January 2019 to allow the agency time to reexamine the costs and benefits of oil and gas operators’ compliance with this regulation.16

A coalition of state governments, tribes and environmental groups has filed suit to block the BLM’s suspension of the Methane and Waste Prevention Rule.17 As with the proposed CPP repeal, ongoing litigation over regulatory rollbacks of GHG regulations is likely to continue as the Trump Administration implements its policy of reducing regulatory burdens on energy production.

C. Withdrawal from Paris Agreement

In June 2017, President Trump announced his intention to withdraw the United States from the Paris Agreement, a global accord among nations to limit GHG emissions and mitigate the effects of climate change. However, the official withdrawal process does not allow a nation to leave the agreement until November 2020.18 Further muddying attempts to understand the United States’ current position on the accord, the Trump Administration sent delegates and negotiators to the November 2017 Paris Agreement Summit in Bonn, Germany.

In opposition to President Trump’s stated decision to leave the agreement, state and local governments within the United States have committed to independently upholding the country’s obligations in the absence of federal participation.19 Although President Trump’s statements regarding withdrawal could shake global commitment to the Paris Agreement, it is too early to discern the effect on the accord’s success.


Although federal climate policy took a hit in 2017, carbon markets continued to take root in the United States – with action being led by the states. Three key events confirm this momentum.

First, in July 2017, California passed legislation to extend its cap-and-trade program by ten years until 2030.20 The legislation includes a broad suite of new policies. The most significant, however, is the ratcheting down of emissions over time. Under the new law, California will reduce free carbon allowances over 40 per cent by 2030, decarbonizing its economy and increasing the value of carbon-reducing investment. Second, in September 2017, California, Ontario and Quebec announced a linkage agreement between the jurisdictions’ cap-and-trade programs.21 The addition of Ontario to this linkage builds out the sort of cross-border collaboration that has previously limited the full effect of cap-and-trade mechanisms. Third, in December 2017, the nine states participating in the Regional Greenhouse Gas Initiative – a Northeast and Mid-Atlantic centered cap-and-trade program – announced a Model Rule that, once implemented, will allow the states to achieve their new consensus target of an additional 30 per cent regional cap reduction between 2020 and 2030.22


On January 4, 2018, the DOI released its Draft Proposed Program (DPP) for offshore leasing in U.S. waters. Interior Secretary Ryan Zinke’s announcement is in response to President Trump’s April 2017 executive order, “Implementing an America-First Offshore Energy Strategy.”23 It directs DOI to review the five-year leasing program for offshore oil and gas exploration and production on the Outer Continental Shelf (OCS), while reconsidering certain regulations pertaining to offshore energy potential. The DPP is the second of five regulatory steps under the OCS Lands Act24 and NEPA prior to program approval.

The DPP dramatically expands proposed offshore leasing in U.S. waters, allowing for lease sales in 25 of the 26 planning areas, approximately totalling ninety per cent of U.S. offshore waters. In contrast, the Obama Administration’s final National OCS Program for 2017-2022 allowed for lease sales in only six per cent of coastal waters.

The DPP drew fierce criticism following its announcement. Of the 32 potentially affected coastal state governors and state agencies that DOI surveyed for the DPP, only seven offered full support for the plan, while 23 stood in opposition.25

Secretary Zinke withdrew waters surrounding the state of Florida from consideration for offshore leases in his Department’s 2019-2024 plan following a meeting with Florida Governor Rick Scott. California Congressman Ted Lieu and Delaware Attorney General Matthew Denn, among others, suggested the Secretary’s unilateral action to remove Florida from the Program was arbitrary, capricious and illegal under federal law.26 The Secretary’s public actions to remove the “unique” state of Florida from the DPP will provide fodder for states’ legal challenges to the DPP.

The DOI’s proposed opening of vast planning areas for offshore leasing comes at a time when regulatory controls over offshore extraction lessen under a Republican-controlled government. As of 2018, the previous nine cents-per-barrel companies were taxed to support the Oil Spill Liability Trust Fund was eliminated.27 As of late 2017, the DOI’s Bureau of Safety and Environmental Enforcement (BSEE) announced it was embarking on a major overhaul of post-Deepwater Horizon safety regulations.28 Finally, included in the December 2017 tax overhaul sought by the Trump Administration was the opening of the Arctic National Wildlife Refuge (ANWR) to oil drilling. In the tax plan that lifted the ban on drilling ANWR, Congress ordered the DOI to conduct two lease sales within the wildlife refuge, one within four years and the second within seven.29

For Canadian-American relations, the DPP is a sharp contrast to the cooperation exhibited in imposing the December 2016 Arctic offshore drilling moratorium, put into place simultaneously by President Obama and Prime Minister Trudeau. The DPP has the potential to place planning areas along the Canadian borders in the Arctic, Pacific and Atlantic regions under offshore lease sales, exacerbating tensions between the national governments on both sides.

The Obama-era 2017-2022 offshore leasing program will continue to be implemented until the new National OCS Program is approved and the DPP for 2019-2024 is still three comment periods away from final program approval. As such, expect to continue seeing a wide variety of stakeholders, including governments, agencies, public interest groups, industry and the public get involved in this process.


At both the state and federal levels, policymakers pursued new coal and nuclear subsidies designed to improve the economics of those generation sources, especially in organized power markets. Notably at the state level, both New York and Illinois targeted nuclear generation – focusing the subsidy on a cleaner power source.

In New York, the state began implementation of a new Clean Energy Standard (CES) in 2017,30 which created new zero emissions credits (ZECs) compensating “the zero-emissions attributes of one megawatt-hour of electricity production by” an eligible facility. In part, the ZEC program was designed to “encourage the preservation of the environmental values or attributes of zero-emissions nuclear-powered electric generating facilities for the benefit of the electric system, its customers and environment.” Competitive generators unsuccessfully challenged New York’s program in federal district court as a July 25, 2017 decision concluded that the New York program is constitutional. That decision is now before the Second Circuit on appeal.31

A similar ZEC program was created contemporaneously in Illinois.32 On December 7, 2016, Illinois also passed the Future Energy Jobs Act which included a ZEC program to subsidize baseload nuclear generation for ten years, prompting competing generators to file legal challenges at FERC and in federal court. On July 14, 2017, a federal district court judge upheld the legality of the Illinois program. That decision is now before the Seventh Circuit on appeal.33

At the federal level, the U.S. Department of Energy (DOE) relied upon on rarely used authority in Section 403 of the DOE Act34 to propose a rule on “Grid Resiliency Pricing” for action by the Federal Energy Regulatory Commission (FERC).35 The proposed rule sought to create out-of-market compensation for certain coal and nuclear generation on the contention that those sources of electricity generation were “fuel secure,” meaning ready access to on-site fuel. In framing resilience in that way, the proposed rule drew a contrast with shipped natural gas as well as renewable sources like solar and wind. After an extremely short comment period and review process, FERC ultimately chose to reject the DOE’s proposal.36 However, the issue of grid resilience continues to be a point of focus for the Commission as it opened a new proceeding to examine the issue.


A. Millennium Pipeline

On June 23, 2017, the U.S. Court of Appeals for the District of Columbia Circuit denied Millennium Pipeline Co. (Millennium)’s petition under Section 19(d)(2) of the Natural Gas Act to review “an alleged failure to act by a . . . State administrative agency acting pursuant to Federal law to issue, condition, or deny any permit required under Federal law.”37 Under Section 19(d)(3), if the court finds that the state agency has delayed unlawfully, the court must remand the proceeding to the agency and “set a reasonable schedule and deadline for the agency to act on remand.”38 Millennium argued in its petition that the New York State Department of Environmental Conservation (NYSDEC) failed to act within the one-year window under Section 401 of the U.S. Clean Water Act39 to issue a water quality certificate, and asked the court to compel the NYSDEC either to grant its application or to take action within a specified schedule. The court held that Millennium lacked standing to pursue its petition. The court ruled that, even if NYSDEC unlawfully delayed acting on Millennium’s application, its inaction would operate as a waiver of the certification requirement and Millennium would be able to proceed with its application at FERC: “If we were to determine the Department exceeded the Clean Water Act deadline, we necessarily would conclude the Clean Water Act requirements have been waived. At that point, the Department’s decision to grant or deny would have no legal significance.”40 Because the NYSDEC’s inaction would not cause Millennium “cognizable injury,” the court held that Millennium lacked standing.41 The court said that Millennium could petition FERC to find that NYSDEC had waived the certification requirement.

On July 21, 2017, Millennium filed a request with FERC to approve issuance of a notice to proceed with construction and to find that NYSDEC had waived the Section 401 certification requirement.42 While that request was pending, NYSDEC on August 30, 2017 “deemed denied” Millennium’s water quality certification and its requests for state law stream disturbance and freshwater wetlands permits, until FERC reopens its environmental review process under the National Environmental Policy Act (NEPA) to adequately address downstream greenhouse gas (GHG) impacts of the power plants to be served by the Millennium pipeline. On September 15, 2017, FERC issued a Declaratory Order finding that NYSDEC waived certification because it had not acted within one year of receipt of Millennium’s “application”, which FERC interpreted to mean the date that Millennium filed the application, notwithstanding NYSDEC’s position that receipt of the application means receipt of a “complete” application and that was not the case when Millennium filed, as the agency issued several notices that the application was incomplete.43 On October 13, 2017, NYSDEC filed a request for rehearing, and request for a stay, of the Declaratory Order, which FERC denied in an order issued November 17, 2017. That same date, NYSDEC filed a petition for review with the U.S. Court of Appeals for the Second Circuit of FERC’s finding in the Declaratory Order that NYSDEC had waived the certification requirement.

On October 27, 2017, Millennium filed in the federal district court for the Northern District of New York claiming that the Natural Gas Act preempted NYSDEC from applying any state permitting requirements that would delay or interfere with the construction and operation of the project.44 On December 13, 2017, the court ruled that New York’s stream disturbance permit regulations and freshwater wetlands permit regulations are preempted by the Natural Gas Act. The court held that “States may deny [a] Section 401 certification based on state environmental standards that have been approved by the EPA … but states are preempted from independently enforcing those standards through the denial of state permits.”45 A federal district court in Massachusetts reached a similar decision in 2017 involving a local government’s determination that the developer of a proposed pipeline compressor station needed an environmental permit. In Algonquin Gas Transmission, LLC v. Weymouth Conservation Commission, the court granted summary judgment in favor of the pipeline, holding that a town’s wetland protection ordinance that required the pipeline to obtain a permit as a condition to constructing a compressor station that had been approved by FERC was preempted.46

B. Constitution Pipeline

On August 18, 2017, the Second Circuit upheld NYSDEC’s April 2016 decision denying a Section 401 water quality certification for Constitution Pipeline Co. (Constitution)’s proposed 121-mile pipeline in Pennsylvania and New York.47 Constitution had argued that the state had waived certification or, alternatively, that its denial was an unlawful attempt to impose a preferred route for the pipeline. The court upheld NYSDEC’s decision to deny the certification, and dismissed Constitution’s failure-to-act claims on grounds that Section 19(d)(2) of the Natural Gas Act vests original and exclusive jurisdiction to hear those claims in the D.C. Circuit. On October 19, 2017, the court denied Constitution’s petition for rehearing en banc.

On October 11, 2017, Constitution petitioned FERC for a declaratory order finding that NYSDEC had failed to act within a reasonable period of time on its application.48 FERC denied Constitution’s petition on January 11, 2018.49 FERC affirmed that one year is “a reasonable period of time” for the state agency to act on a water quality certificate application under Section 401. Here, however, FERC focused on the fact that Constitution had withdrawn and resubmitted its application to the NYSDEC. FERC held that “once an application is withdrawn, no matter how formulaic or perfunctory the process of withdrawal and resubmission is, the refiling of an application restarts the one-year waiver period….”50

C. Northern Access

On February 3, 2017, FERC approved the application by National Fuel Gas Pipeline to construct and operate a new natural gas pipeline, Northern Access, conditioned among other things on receipt of all required state authorizations.51 On March 3, 2017, National Fuel filed a request for clarification or rehearing asking FERC to find (1) that state permits, approvals, authorizations and requirements are preempted by the Natural Gas Act and not required to commence construction of the pipeline, and (2) that NYSDEC’s failure to issue a decision on the pipeline’s application for a water quality certificate by the end of the authorization period in FERC’s Notice of Schedule for Environmental Review was a failure to act within a “reasonable period of time” as required by Section 401 and therefore resulted in a waiver of any requirement to obtain the water quality certificate with respect to its facilities in New York State. National Fuel argued that NYSDEC’s failure to act on the application was one of many allegedly improper actions to “blockade” construction of a FERC-authorized natural gas pipeline. Subsequently, on April 7, 2017, NYSDEC issued a denial of the water quality certificate.52 On April 21, 2017, National Fuel filed a petition with the Second Circuit challenging NYSDEC’s denial.53


A. State Developments

In April 2017, Maryland banned fracking statewide. In a reversal from his past position that fracking could be conducted in a safe manner, Republican Governor Larry Hogan supported the ban and urged state legislators to send fracking ban legislation to his desk.54 Following Vermont and New York, Maryland is now the third U.S. state to have enacted a statewide fracking ban. However, it is the first U.S. state with significant shale resources to pass a ban through the legislative process, as Vermont’s ban is largely symbolic due to the state’s lack of gas resources and New York’s ban was enacted via executive order.55

In November 2017, the Delaware River Basin Commission, an interstate regulatory body covering territory in Delaware, New Jersey, Pennsylvania and New York, proposed a fracking ban in the basin. The proposed ban has significant ramifications for natural gas exploration in Pennsylvania, as the location of the Marcellus Shale formation has led to significant fracking activity throughout the state, including the state’s northeastern counties abutting the Delaware River Basin.56 The draft regulations notably permit importing and exporting of water within the basin for fracking purposes, which has led to criticism from environmental groups.57 The proposal remains in its comment period, with a final vote expected later in 2018.58

Legal challenges opposing a fracking ban passed by ballot initiative in Monterey County, California secured a partial victory – a ruling by the Monterey County Superior Court struck portions of the ballot measure prohibiting the drilling of new wells and phasing out of wastewater impoundment and injections due to preemption by existing state and federal law.59 The fracking ban itself remains in place, as the court ruled that plaintiffs lacked standing because no fracking operations are currently conducted within the county.60 The fracking ban, passed in November 2016 with 56 per cent of voters, drew national attention and heavy opposition from the oil and gas industry. Unlike the other five counties in California that have already banned fracking, Monterey County has a significant oil and gas industry.61 The decision is likely to be appealed and may ultimately be decided by the California Supreme Court.

B. Federal Developments

In December 2017, the BLM rescinded proposed environmental regulations implemented under the Obama Administration regulating fracking activities on federal and tribal lands.62 The prior regulation, which concerned water contamination, well integrity and containment and recovery of hydraulic fluids, had initially been issued in March 2015 but remained stayed pursuant to a decision from the U.S. federal district court in Wyoming.63

In response, California Attorney General Xavier Becerra filed suit to block the repeal in January 2018. The lawsuit argues for the imposition of a mandatory injunction that would reinstate the Obama Administration fracking regulations due to the fact that the rescission was not based on any “reasoned analysis.”64 Environmental organizations, including the Sierra Club and Earthjustice, filed similar actions against the government.65 The litigation represents the latest development in a string of environmental legal challenges brought by the California Attorney General’s office against the Trump Administration – Becerra and New Mexico Attorney General Hector Belderas successfully sued the BLM regarding its decision to stop enforcing a waste rule designed to limit “flaring” and venting of unused methane from oil and natural gas wells and continue to seek legal remedies against the Trump Administration for attempting to rescind the rule.66


A. FERC Enforcement

In 2017, FERC Enforcement settled two long-running market manipulation cases that involved extensive non-public investigations, show cause proceedings and hard-fought federal district court litigation.

1. Barclays Bank PLC

On November 7, 2017, FERC approved a Stipulation and Consent Agreement between Enforcement and Barclays Bank PLC, Daniel Brin, Scott Connelly and Karen Levine (together, the Barclays Defendants) resolving all claims for alleged violations of Federal Power Act section 222 67 and the FERC’s Anti-Manipulation Rule,68 as well as the FERC’s federal district court action to enforce such alleged violations, captioned FERC v. Barclays Bank et al., 2-13-cv-02093-TLN-DC (E.D. Cal.).69 Under the Stipulation and Consent Agreement, the Barclays Defendants neither admitted nor denied the allegations and agreed to pay a $70 million civil penalty and to disgorgement of $35 million.70 In addition, the traders each agreed to trader bans.

Earlier in 2017, the court in the federal court action granted defendant Ryan Smith’s motion for judgment on the pleadings and dismissed him from the case, holding that the FERC’s claims against Smith were time-barred by the applicable federal statute of limitations, 28 U.S.C. § 2462.71 FERC’s prior Order Assessing Penalties found that the Barclays Defendants were liable for $435 million in civil penalties and $43.9 million in disgorgement, the largest amounts ever assessed by the agency in an enforcement case.72

2. City Power Marketing, LLC and K. Stephen Tsingas

On August 22, 2017, the FERC approved a Stipulation and Consent Agreement between Enforcement and City Power Marketing, LLC (City Power), and its owner, K. Stephen Tsingas (together, the City Power Defendants). The agreement resolved allegations that the City Power Respondents violated FPA Section 222 and the FERC’s Anti-Manipulation Rule, 18 C.F.R. § 1c, by placing Up-To-Congestion (UTC) transactions in the market operated by PJM Interconnection, L.L.C. (PJM) in a manner designed to artificially inflate City Power’s eligibility for Marginal Loss Surplus Allocation (MLSA) payments. Enforcement alleged that the City Power Respondents had placed UTC transactions in a manner designed to minimize the risk of the transaction while increasing City Power’s trading volume and eligibility for MLSA payments.

The FERC previously had issued an Order Assessing Penalties finding that the City Power Respondents’ conduct violated the Anti-Manipulation Rule and assessing a $14 million civil penalty against City Power and a $1 million civil penalty against Mr. Tsingas and directing City Power collectively to disgorge about $1.3 million. FERC later brought an action in the U.S. District Court for the District of Columbia seeking to enforce its assessment of civil penalties. In the settlement, the City Power Defendants stipulated to the facts set forth in the agreement, but neither admitted nor denied the alleged violations. To resolve the allegations, City Power agreed to pay a civil penalty of $9 million, and Mr. Tsingas agreed to pay a civil penalty of approximately $1.4 million and disgorge $1.3 million to PJM. In addition, Mr. Tsingas agreed to a trading ban on participating directly or indirectly in any FERC-jurisdictional market.

B. CFTC Enforcement Advisories

1. January 2017 Cooperation Advisories

On January 19, 2017, the Commodity Futures Trading Commission (CFTC) issued two Enforcement Advisories – one for individuals and one for companies – outlining factors that the CFTC’s Enforcement Division will consider in evaluating cooperation in a CFTC investigation or enforcement action.73 Both advisories note that “[t]he Division considers three broad policy issues in its assessment of whether cooperation was provided and the quality of that cooperation: (1) the value of the company’s cooperation to the Division’s investigation(s) and enforcement actions; (2) the value of the company’s cooperation to the Commission’s broader law enforcement interests; and (3) the balancing of the level of the company’s culpability and history of prior misconduct with the acceptance of responsibility, mitigation and remediation.”74

2. September 2017 Enforcement Advisory on Self Reporting and Full Cooperation

On September 25, 2017, the CFTC issued an additional advisory to provide further guidance and clarity regarding the earlier January advisories.75 The goal of the September 2017 Advisory is to “encourage companies and individuals to detect, report, and remediate wrongdoing, thus increasing voluntary compliance with the law.”76 The CFTC notes that any disclosure must have been made “prior to an imminent threat of exposure of the misconduct,” “within a reasonably prompt time after the company or individual becomes aware of the misconduct” and “must include all relevant facts known to the company or individual at the time of the disclosure, including all relevant facts about the individuals involved in the misconduct.”77 “To receive full credit under this self-reporting program, the company/individual must adhere to the terms of the Division’s January 2017 Advisories,” and the CFTC’s evaluation of whether a company timely and appropriately remediated flaws in compliance and control programs “[w]ill be fact and circumstance dependent.”78

With respect to the credit given to a company or individual, the advisory states that “[i]n all instances, the company or individual will be required to disgorge profits (and, where applicable, pay restitution) resulting from any violations.”79 Given satisfaction of this requirement, “[i]f the company or individual self-reports, fully cooperates, and remediates,” the Enforcement Division “will recommend the most substantial reduction in the civil monetary penalty that otherwise would be applicable.”80 In a September 25, 2017 speech at the NYU Institute for Corporate Governance & Finance, the CFTC’s Enforcement Division Director James McDonald discussed the three advisories and how the CFTC’s Enforcement Division might rely on them going forward.81


The year 2017 was a relatively quiet year for energy companies with regard to the CFTC, with most of the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”)82 regulations regarding derivatives already completed and the outgoing administration under Chairman Timothy Massad having granted significant relief in important areas of concern, specifically with respect to forward contracts with volumetric optionality and trade options, for energy companies. Other areas of concern to the energy industry, such as position limits, appear to not likely see action in the short term, since the new CFTC Chairman, J. Christopher Giancarlo, has publicly stated that he does not want to take action on position limits until there is a full panel of commissioners.83 Currently, there are two vacancies at the Commission that remain to be filled, and it could be some time before there is a full panel again. Still, there were a few developments relevant to energy companies that use derivatives in the areas of recordkeeping and the de minimis exception from swap dealer registration, which we describe below.

With regard to recordkeeping, on May 23, 2017, the CFTC finalized rule amendments to its recordkeeping rule, CFTC Reg. 1.31, which became effective on August 28, 2017.84 CFTC Reg. 1.31 specifies the form and manner in which records required by CFTC regulations must be kept by entities required to keep such records, referred to in the rule as “records entities.” The regulation does not specify the types of records required to be kept; types of records are specified in other CFTC regulations. For example, for swaps, most of the types of records required to be kept are specified in CFTC Reg. 45.2. In general, the amendments to CFTC Reg. 1.31 modernize and make technology neutral the form and manner in which regulatory records must be kept. The CFTC notes that the final rule amendments do not impose any new recordkeeping requirements on any records entity and that existing recordkeeping methods under CFTC Reg. 1.31 remain valid for compliance with the rule as amended.

Moreover, the CFTC notes that the amendments “[d]o not override other methods of maintaining records that may be specified elsewhere in the [Commodity Exchange] Act or other Commission regulations.” Thus, the CFTC states that commercial end-users, such as energy companies, that are records entities, for example, “may continue to maintain records in accordance with their current practices if such are permitted by the Act, Commission regulations, or existing relief or guidance.”85

With regard to the de minimis exception from swap dealer registration, the CFTC issued an order on October 26, 2017, extending by one year the date on which the CFTC may lower its swap dealer de minimis threshold.86 The de minimis threshold is the amount of swap dealing activity in a 12-month period that if exceeded requires a swap market participant to register as a swap dealer. The order has the effect of preserving the de minimis threshold at its current level, $8 billion in aggregate gross notional amount, which was set to drop at the end of December 2018, until December 31, 2019. The order means that, at least until the end of 2019, no swap dealing entities will likely be required to register as regulated swap dealers on the basis of dealing activity of less than $8 billion in notional amount over a 12-month period.


On January 23, 2018, President Trump signed a proclamation increasing tariffs on solar cells and modules under section 201 of the Trade Act of 1974.87 This law has not been used to impose tariffs since 2002, when it was used on steel imports. The solar imports tariff goes into effect February 7, 2018 and is set at 30 per cent in the first year, decreasing to 25 per cent in the second year, 20 per cent in the third year and 15 per cent in the fourth year.88 The first 2.5 gigawatts of imported cells (but not modules) are excluded from the new tariffs, establishing a tariff rate quota, meaning that exporters will likely rush to import cells in order to be within the 2.5 gigawatt exclusion.

This is the third set of tariffs the U.S. government has issued on solar imports in recent years; however, the Obama Administration’s tariffs were on a narrower set of imports.89 The Trump Administration’s tariffs are based on the International Trade Commission’s recommendations, which found that low-priced imports have been negatively impacting domestic manufacturers.90 Currently, more than 95 per cent of America’s solar panels are imported, with half of those imports coming from Malaysia and South Korea. Two solar manufacturers, Suniva Inc. and SolarWorld Americas, requested the tariffs.

The Trump Administration has stated that the tariffs are largely directed at China, which has moved its production to other countries to avoid prior U.S. restrictions imposed on Chinese solar products. The tariff applies to solar products worldwide, and no countries with free trade agreements with the United States are excluded. However, countries that are eligible for the General System of Preferences benefits (some less developed countries) are excluded if they account for less than three per cent of total imports of the solar products.91

Tariffs are opposed by most of the solar industry, as companies fear that trade barriers will thwart the solar industry’s growth. Goldman Sachs analysts predict a potential three to seven per cent cost increase for residential and utility-scale solar costs, respectively, with a declining effect as the penalties lessen in later years.92 It is uncertain whether certain components of solar panels or modules are covered. The Office of the U.S. Trade Representative has stated that by the end of February 2018, it will publish procedures in the Federal Register for requests for exclusion of particular components from the tariffs.93


State public utility/service commissions across the United States continue to grapple with how to incorporate distributed generation and net metering into rate design. Different states are addressing these issues in divergent ways.

A. California’s Integrated Resource Plan and Long Term Procurement Plan Proceedings (IRP-LTPP)

1. California’s Distribution Energy Resources and Distribution Resources Plan Proposals

For more than a decade, it has been California’s policy to require each of its investor-owned utilities (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.94

Senate Bill (SB) 350 (2015) required the California Public Utilities Commission (CPUC) to undertake an integrated approach to resource planning.95 The CPUC historically dealt with various different types of resources in proceedings specific to those resources (e.g., the Integrated Distributed Energy Resources proceeding (R.14-10-003)). While resource-specific proceedings have continued, the Commission’s goal is to wrap as many of these proceedings as possible into an omnibus planning proceeding. The planning for this omnibus approach is happening in R.16-02-007, the Rulemaking to Develop an Electricity Integrated Resource Planning Framework and to Coordinate and Refine Long-Term Procurement Planning Requirements.

On December 28, 2017, the CPUC issued a proposed decision in R.16-02-007 for consideration at the CPUC’s February 8, 2018 meeting. The proposed decision directs utilities to file integrated resource plans covering three years (but reviewed every two years). If the CPUC adopts the proposed decision, the first plans will be due June 1, 2018.

2. California Net Energy Metering

Under Assembly Bill (AB) 327,96 enacted in 2013, the 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 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. The CPUC has stated it will not revisit NEM policy for three years.

AB 327 mandated each large investor-owned utility to adopt the successor tariff either on July 1, 2017 or when NEM generating capacity exceeded five per cent of their aggregate peak demand. SDG&E and PG&E hit the program limit on June 29, 2016 and December 15, 2016, respectively, and SCE rolled over on July 1, 2017. New NEM customers must now (a) pay a one-time interconnection fee, (b) pay non-bypassable charges and (c) transfer to a time-of-use rate.

B. Nevada’s Evolving Regulatory Regime for Rooftop Solar

In 2015, the Nevada legislature enacted SB 37497 directing utilities to prepare a cost-of-service study for rooftop solar installations and to prepare a new tariff. On December 23, 2015, the Public Utilities Commission of Nevada (PUCN) issued a controversial order approving tariff filings by Nevada’s two major utilities98 that significantly reduced the economic benefits customers would see when they installed rooftop solar panels.99

In the wake of public criticism and court challenges, Nevada courts and the PUCN in 2016 restored some net metering benefits to some rooftop solar customers, including by restoring the status quo ante for grandfathered customers. Subsequently, the PUCN reopened net metering for new customers in the Northern portion of the state (Sierra Pacific’s service territory).100

In 2017, the Nevada legislature passed AB 405.101 It sets net metering compensation at 95 per cent of retail rates; a highly favorable amount for rooftop solar owners. As solar installations proliferate, at 80 MW increments, the compensation steps down by seven percentage points, bottoming out at 75 per cent of retail rates. In September, the PUCN ordered utilities to implement AB 405. The PUCN rejected utility proposals to increase fixed charges for rooftop solar customers and to eliminate “netting” of customer generation and load.

C. Hawaii Rooftop Solar Rule Changes

In October 2017 in the same order establishing a storage program for rooftop solar, Hawaii established the “CGS+” or “Controllable CGS” as a successor to its Customer Grid Supply (CGS) program – Under this new program, CGS+ customers can install a solar PV-only system (no energy storage needed) that exports energy to the electric grid during the daytime, if they use advanced equipment that allows the electric utility to manage power from the CGS+ system. When grid conditions require, the electric utility may alter CGS+ system output in order to maintain a stable grid. It also allowed existing customers to add “non-export” systems and retain their status in the NEM program and authorizes activation of new “advanced inverter” functions in PV and storage systems.102

D. State Rate Changes Regarding Distributed Generation

In Hawaii, a state with the highest penetration rate for rooftop solar in the country, customers reached the state’s limit on rooftop solar eligible to export power to the grid. Rooftop solar customers in Hawaii must now use the customer self-supply (CSS) option, which is for solar PV installations that are designed to not export any electricity to the grid. Customers are not compensated for any export of energy. CSS customers must pay a minimum $25/month to their utility.

Another state with considerable insolation, Arizona, allowed utilities to impose fixed charges on distributed generation owners of $0.70 per KW/month.103 Arizona has now ended its retail net metering program for new customers.104 Customers who already have solar rooftops will be grandfathered under the prior rate structure. New customers will receive 12.9 cents/kWh, but each year the rate for new customers will be stepped down, until reaching wholesale prices.


A. Background

FERC issued an important order regarding energy storage—Order 784—in 2013.105 That order directed wholesale market operators to find ways to monetize “fast response” resources–storage devices such as batteries and flywheels. On April 11, 2016, FERC issued a series of data requests and requests for comments in a new informational docket, “Electric Storage Participation in Regions with Organized Wholesale Electric Markets,” Docket No AD16-20-000.106 This docket concerns 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.107

FERC opened another informational docket concerning storage in late 2016: “Utilization In the Organized Markets of Electric Storage Resources as Transmission Assets Compensated Through Transmission Rates, for Grid Support Services Compensated in Other Ways, and for Multiple Services,” Docket No. AD16-25-000.108 FERC staff convened a technical conference on November 9, 2016. FERC then issued a Notice of Proposed Rulemaking to “remove barriers to the participation of electric storage resources and distributed energy resource aggregations in the organized wholesale electric markets.”109 The proposed rulemaking would also allow storage to provide services not necessarily procured through markets, such as black start, primary frequency response and reactive power. FERC has not yet acted on the proposed rulemaking.

FERC issued a “policy statement” on cost recovery for storage resources in January 2017.110 The statement established that storage resources may provide transmission grid support services at a cost-based rate while participating in organized markets and earning market-based revenues. The policy statement, however, establishes no precedent. Cost recovery will be determined on a case-by-case basis.

B. State Storage Proposals

1. California

As detailed in prior years’ Washington Reports, California has taken the lead to include energy storage in its electric utilities and energy suppliers’ resource planning. Assembly Bill (AB) 2514 required the CPUC to determine appropriate targets, if any, for each load-serving entity to procure viable and cost-effective energy storage systems. In response to AB 2514, the CPUC set a target of 1,325 megawatts (MW), allocated to each of the investor-owned utilities. Subsequently, AB 2868 required utilities to propose programs and investments up to 500 megawatts of additional distributed energy storage resources. In Decision (D.) 17-04-039, the CPUC determined that the 500 MW of distributed resources described in AB 2868 are to come out of the amounts already specified under AB 2514 (“no additional increase to the existing 1,325 MW target is warranted.”)111 Utilities continue to make progress towards, those storage targets, as reported in Table 2 of D.17-04-039:

On January 11, 2018, the CPUC issued a “Decision On Multiple-Use Application Issues.” The decision addresses “the fact that current market rules (i.e., utility standard contracts and program tariffs) do not support the ability of an energy resource to access, or ‘stack,’ more than one service, including any incremental values to the wholesale market, distribution grid, transmission system, resource adequacy requirements and customers. As a result, energy storage cannot realize its full economic value to the electricity system even though it may be capable of providing multiple benefits and services to the electricity system.” D.18-01-003. The decision adopts a matrix of definitions of compensable storage services and establishes rules governing utility payment for those services. The decision also passes a number of issues to a working group, contemplates utility storage RFOs for 2018 and closes the CPUC’s long-running storage Rulemaking (R.) 15-11-030.

Energy Storage Procurement to Date (MWs) Data as of February 2017
Service TerritoryProcurement Approved by Commission Customer/Distribution/TransmissionTOTAL BY UTILITYRemaining Obligation
TOTAL BY DOMAIN192.6312295.87190478.5846.5

Also noteworthy is storage’s role in backing up California’s electricity grid in the face of reduced natural gas supplies caused by the Aliso Canyon storage leak. California deployed 100 megawatts of storage across several sites in just six months.

The CPUC also rejected a Southern California Edison request for approval of a PPA with NRG for the Puente power plant. This decision was based in part on the availability of storage as an alternative to the power plant.

In addition to activities at the CPUC, stakeholders have been focused in parallel on the California Independent System Operator’s (CAISO’s) ongoing Energy Storage and Distributed Energy Resources (ESDER) stakeholder initiative to enable wholesale market level participation of energy storage systems interconnected to the distribution grid.

2. Oregon

The Oregon legislature passed an energy storage bill in 2016, Oregon House Bill 2193 (HB 2193),123 requiring Oregon’s major investor owned utilities to obtain up to one per cent of 2014 load of energy storage in service by January 1, 2020 and directing the Oregon Public Utility Commission to adopt guidelines for proposals of projects providing at least 5 MWh of storage. On December 28, 2016, the Commission adopted the required guidelines, establishing a technology-neutral framework for development and evaluation of storage proposals but leaving many details to utilities, bidders and Commission staff.124 In November 2017, Portland General Electric Company filed a proposal with the Oregon PUC for up to 39 MW of storage in its service area.

3. Massachusetts

Massachusetts adopted an energy storage law in August of 2016, deferring to the Massachusetts Department of Energy Resources (MADERS) on whether to set appropriate targets for electric companies to procure viable and cost-effective energy storage systems to be achieved by January 1, 2020. 125 In response to this legislation, MADERS adopted an “aspirational” 200 Megawatt hour (MWh) energy storage target for electric distribution companies, to be achieved by January 1, 2020. In December 2017, Massachusetts disbursed $20m in grants to fund storage projects. Electric distribution companies were to submit annual reports on storage activities beginning on January 1, 2018.

4. Other States With Newly-Adopted Storage Laws/Regulations

In 2017, New York joined the club of states with energy storage mandates. AB 6571 requires NYPSC to develop an Energy Storage Deployment Program, including a storage procurement target for 2030. The NYPSC is to determine by December 31, 2018 the “appropriate suite of policies” for an energy storage deployment goal.

Nevada passed SB 204.126 This bill “Requires the Public Utilities Commission of Nevada to investigate and establish biennial targets for certain electric utilities to procure energy storage systems under certain circumstances.” Nevada regulators are to implement the bill by October 1, 2018. In addition, Nevada SB 145127 establishes an incentive program for energy storage within the state’s solar program.

Hawaii has not adopted storage targets. However, in an October 20, 2017 decision, the Hawaii Public Utilities Commission (“HPUC”) approved two new programs that will expand opportunities for customers to install rooftop solar and battery energy storage systems.128


The federal government has long promoted energy efficiency in various ways, ranging from setting efficiency standards for consumer products such as lightbulbs129, sponsoring research at National Laboratories into how to build more energy efficient buildings, and implementing the “Energy Star” labelling program overseen by the EPA.

Many states have laws requiring regulated entities to undertake energy efficiency activities. State-mandated energy efficiency activities commonly include rebates for efficient equipment and efficiency-focused changes to building codes. For illustrative purposes, we will focus on California.130

Public Utilities Code Sections 454.55 and 454.564131 require the CPUC, in consultation with the California Energy Commission (CEC), to identify potentially achievable cost-effective electricity and natural gas efficiency savings and establish efficiency targets for electrical or gas corporations to achieve. Public Utilities Code Section 381 mandates that the CPUC “allocate funds spent to programs that enhance system reliability and provide in-state benefits including: (1) cost-effective EE and conservation activities . . .”132

The CPUC devotes approximately $1 billion per year in customer funds to energy efficiency programs, spread across all CPUC-jurisdictional energy utilities. The CPUC devotes another approximately $300 million per year to low-income energy efficiency programs. The CEC, for its part, develops building codes, appliance standards and also funds energy efficiency research. Utilities have filed “business plans” with the CPUC to administer energy efficiency programs for up to ten years. The CPUC is evaluating these plans in proceeding A.17-01-013.

The CPUC rejected a PG&E proposal to spend an additional $200 million per year to procure energy efficiency to partially offset the loss of capacity from PG&E’s proposed closure of the Diablo Canyon Nuclear Power Plant (Diablo Canyon).133

Assembly Bill 793134 directed California IOUs to provide incentives to residential and small and medium business (SMB) customers for “energy management technology” (EMT), which may include a product, service, or software that allows a customer to better understand and manage electricity or gas use in the their home or place of business. AB 793 also required the IOUs to educate residential and SMB customers about incented EMT offerings available to them. On March 23, 2017, the CPUC approved the utility AB 793 programs.


Demand response−compensation for the curtailment of electric use during periods of peak demand and high system marginal cost−is an increasingly integral feature of wholesale power markets by reducing peak system demands and forestalling the need for costly new generation capacity. On December 28, 2017, FERC staff issued its annual Assessment of Demand Response and Advanced Metering Staff Report.135 The report provides a comprehensive survey of state and local demand response activities. Perhaps the more interesting observation in the report is that “the contribution of demand resources to meeting peak demand decreased to 5.7 per cent in 2016 from 6.6 per cent in 2015.”136 Demand response programs are growing, but peak demand is growing faster.


Community Choice Aggregators (CCAs) are governmental entities that purchase power on behalf of, and sell that power at retail to, their residents and businesses. CCAs displace private utilities from the power procurement role within the CCA footprint, though customers may opt back in to utility service. The incumbent utility remains responsible for transmission and distribution services.

CCAs are legal in a handful of U.S. states – California, Illinois, Massachusetts, New York, New Jersey, Ohio and Rhode Island. Legislation authorizing CCAs has been in place in some cases for over two decades. However, CCA formation has remained slow until recently.

After a delayed start – Marin formed the state’s first CCA in 2010 – CCA formation has rapidly accelerated in California. By late 2017, CCAs had formed in San Francisco, Sonoma County, San Mateo County, Lancaster, Richmond and parts of Contra Costa County. New CCAs that the CPUC certified to begin serving customers in 2017 were Silicon Valley Clean Energy, Apple Valley Energy, Hermosa Beach Choice Energy and Redwood Coast Energy Authority. CCAs are now on track to serve up to or over half of the load historically served by private utilities, including customers currently served by Southern California Edison in Los Angeles County.

* 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 and environment practice for their assistance: Zori Ferkin, Julian Hammar, Todd Edmister, Ben Fox, Megan Jennings, Tim Kline, Justin Fisch, Rylee Kercher, Ali Zaidi, and Dustin Elliott. The views expressed in this report are his own, however, and do not necessarily reflect those of Morrison & Foerster or any of its clients.

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  37. 15 USC § 717r(d)(2); Millennium Pipeline Co v Seggos, 860 F3d 696, 699 (DC Cir 2017).
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  39. Clean Water Act, 33 USC § 1251 et seq (1972).
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  41. Millennium Pipeline Co, 860 F.3d at 699-700.
  42. Meghan Mandel & Daniel Archuleta, “FERC Rules that NY DEC Waived Authority on Water Quality Permit for Pipeline Project,” Troutman Sanders LLP (20 September 2017), online: <>.
  43. Declaratory Order, In re Millennium Pipeline Co, No CP16-17-000 (FERC 15 September 2017).
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  49. Order on Petition for Declaratory Order, Docket No CP18-5-000, 162 FERC ¶ 61,014 (11 January 2018), online: <>.
  50. Ibid at para 23.
  51. Order Granting Abandonment and Issuing Certificates, Docket Nos CP15-115-000, CP15-158-001, 158 FERC ¶ 61,145 (3 February 2017), online: <>.
  52. NY State Department of Environmental Conservation, “DEC Statement Regarding Water Quality Certificates for the Proposed Northern Access Pipeline,” (8 April 2017), online: <>.
  53. Natural Fuel Gas Supply Corp v NYSDEC, No 17-1164 (2d Cir, filed 21 April 2017).
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  55. Pamela Wood, “Maryland General Assembly approves fracking ban,” Baltimore Sun (27 March 2017), online: <>.
  56. Jon Hurdle, “Fracking ban proposed for Delaware River basin; ‘significant risks’ cited,” NPR StateImpact (30 November 2017), online: <>.
  57. Ibid.
  58. Susan Phillips, “Delaware River Basin fracking ban hearings center on environment, economy,” NPR StateImpact (25 January 2018), online: <>.
  59. James Herrera, “Monterey County Judge: Measure Z fracking ban remains; two other bans preempted, invalid by existing laws,” Monterey Herald (29 December 2017), online: <>.
  60. Ibid.
  61. Claudia Melendez Salinas, “Big Oil sues Monterey County to stop Measure Z,” Mercury News (16 December 2016), online: <>.
  62. Chris Mooney, “To round out a year of rollbacks, the Trump administration just repealed key regulations on fracking,” Washington Post (29 December 2017), online: <>.
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  65. Ibid.
  66. Bryan Koenig, “Calif., NM Warn BLM Over Suspending Methane Waste Rule,” Law360 (6 November 2017), online: <>.
  67. 16 USC § 824v.
  68. 18 CFR § 1c.
  69. Order Approving Stipulation and Consent Agreement, Docket No IN08-8-000, 161 FERC ¶ 61,147 (7 November 2017), online: <>.
  70. Ibid at ¶ 10.
  71. Order, FERC v Barclays Bank, et al, No 2-13-cv-02093, ECF No 234 (ED Cal 29 September 2017).
  72. Order Assessing Civil Penalties, Docket No IN08-8-000, 144 FERC ¶ 61,041, at paras 132, 151 (16 July 2013), online: <>.
  73. US Commodity Futures Trading Comm’n, Enforcement Advisory, Cooperation Factors in Enforcement Division Sanction Recommendations for Companies (19 January 2017), online: <> [hereinafter Company Advisory]; US Commodity Futures Trading Comm’n, Enforcement Advisory, Cooperation Factors in Enforcement Division Sanction Recommendations for Individuals (19 January 2017), online: <> [hereinafter Individual Advisory].
  74. Company Advisory, at 1; Individual Advisory at 1.
  75. US Commodity Futures Trading Comm’n, Enforcement Advisory, Updated Advisory on Self Reporting and Full Cooperation (25 September 2017), online: < >.
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  79. Ibid.
  80. Ibid.
  81. US Commodity Futures Trading Comm’n, Enforcement Advisory, Speech of James McDonald, Director of the Division of Enforcement Commodity F utures Trading Commission Regarding Perspectives on Enforcement: Self-Reporting and Cooperation at the CFTC (25 September 2017), online: <>.
  82. Dodd-Frank Wall Street Reform and Consumer Protection Act, Pub L 111-203, 124 Stat 1376.
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  84. 17 CFR § 1.31 (2017).
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  86. See Order Establishing a New De Minimis Threshold Phase-In Termination Date, 82 Fed. Reg 50,309 (31 October 2017), online: <>.
  87. Proclamation No 9693, 83 Fed Reg 3541 (23 January 2018), online: <>.
  88. US Trade Representative, Fact Sheet (22 January 2018), online: <>.
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  90. Proclamation No 9693, 83 Fed Reg 3541 (23 January 2018), online: <>.
  91. US Trade Representative, Fact Sheet (22 January 2018), online: <>.
  92. Henning Gloystein & Christoph Steitz, “U.S. solar panel import tariff to hit European, Asian manufacturers,” Reuters (23 January 2018), online: <>.
  93. Proclamation No 9693, 83 Fed Reg 3541 (23 January 2018), online: <>.
  94. Cal Pub Util Code § 353.5.
  95. US, SB 350, Clean Energy and Pollution Reduction Act of 2015, 2015-2016, Cal, 2015.
  96. US, 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, Cal, 2013.
  97. US, SB 374, An act relating to energy; revising provisions relating to certain energy conservation standards adopted by the Director of the Office of Energy and the governing body of a local government, 78th session, Nev, 2015.
  98. Order re NV Energy and Sierra Pacific Power Applications, PUCN Docket Nos 15-07041 and 15-07042, Doc ID No 8412 (23 December 2015).
  99. Ibid; Advice Letter No 453-R, PUCN Docket No 15-07041, Doc ID No 8551 (30 December 2015) at 2, 6 ROD 006938.
  100. Order Granting in Part and Denying in Part General Rate Application by Sierra Pacific Power, PUCN Docket Nos 16-06006, 16-06007, 16-06008, 16-06009, Doc ID No 17757 (20 December 2016).
  101. US, AB 405, An act relating to renewable energy; creating the contractual requirements for an agreement for the lease or purchase of a distributed generation system and a power purchase agreement, 79th Sess, Nev, 2017.
  102. Decision and Order No 34924, Instituting a Proceeding to Investigate Distributed Energy Resource Policies, Docket No 2014-0192 (Haw 20 October 2017), online: <>.
  103. Order approving Arizona Public Service Company’s Application for Approval of Net Metering Cost Shift Solution at 19-20, Ariz Corp Comm’n Docket No E-01345A-13-0248, Decision No 74202 (3 December 2013).
  104. Arizona Corp Comm’n, Docket No E-00000J-14-0023 (20 December 2016).
  105. Order 784, Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, Docket Nos AD10-13-000, RM11-24-000, 144 FERC ¶ 61,056 (18 July 2013).
  106. Data Requests and Request for Comments, Electric Storage Participation in Regions with Organized Wholesale Electric Markets, FERC Docket No AD16-20-000 (11 April 2016).
  107. Transcript of Commission Meeting, (FERC, issued 21 April 2016), online: <>.
  108. Utilization In the Organized Markets of Electric Storage Resources as Transmission Assets Compensated Through Transmission Rates, for Grid Support Services Compensated in Other Ways, and for Multiple Services, FERC Docket No AD16-25-000 (30 September 2016).
  109. Notice of Proposed Rulemaking, Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, Docket Nos AD16-20-000, RM16-23-000, 157 FERC ¶ 61,121 (17 November 2016).
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  111. Decision on Track 2 Energy Storage Issues, Cal Pub Util Comm’n, Decision 17-04-039 at 65 (8 May 2017), online: <>.
  112. 6.5 MWs of SGIP/Permanent Load Shifting projects (A.1512004, page 1, footnote 2) + 3.13 MWs of 2016 SGIP (PG&E Advice Letter (AL) 4968E).
  113. 6 MWs (D.1410045, Attach A.) + 10 MWs in 2014 procurement (D.1609004).
  114. 60 MWs in 2014 solicitation (D.1609004) less termination of a 10 MW project as of February 14, 2017 PG&E Update.
  115. 16.34 MW existing (D.1410045, Attach A.) + 163.64 MWs in West LA Basin via SCE 2013 LCR RFO to replace San Onofre Nuclear Generating Station’s (SONGS) capacity (D.1511041) + 10.3 MWs of 2016 SGIP (SCE AL 3521E).
  116. 13.78 MW existing (D.1410045, Attach A.) + 22 MW of ACES storage projects (Resolution E4804) + 16.3 MWs in 2014 procurement (D.1609004).
  117. 100 MWs in West LA Basin via SCE 2013 LCR RFO to replace SONGs capacity (D.1511041).
  118. As SCE can only count up to 170 MWs of customer domain resources (200 per cent of 85 MW target), the total for “remaining procurement obligation” only considers 170 MWs, and not the actual total.
  119. 0.05 MW of 2016 SGIP credits, per SDG&E AL 3011E) + 8.29 MWs of SGIP (A.1603003, Attachment B) + 4.66 MWs existing (D.1410045, Attach A.).
  120. 6.15 MWs existing (D.1410045, Attach A.) + 37.5 MWs Aliso Canyon (Resolution E4798).
  121. 40 MWs existing (D.1410045, Attach A.).
  122. Only 170 MWs of SCE customer domain procurement is counted.
  123. US, HB 2193, An act relating to energy storage; and declaring an emergency, 78th Leg Assemb, Reg Sess, Or, 2015.
  124. Order Implementing Energy Storage Program Guidelines pursuant to House Bill 2193, Docket No UM 1751, Order 16-504 (Or 2016).
  125. US, HB 4568, An act to promote energy diversity, 2015-2016, Mass, 2016.
  126. US, SB 204, An act relating to energy; requiring the Public Utilities Commission of Nevada to investigate and establish biennial targets for certain electric utilities to procure energy storage systems if certain criteria are satisfied, 79th Sess, Nev, 2017.
  127. US, SB 145, An act relating to energy; establishing as part of the Solar Energy Systems Incentive Program a program for the payment of incentives for the installation of certain energy storage systems, 79th Sess, Nev, 2017.
  128. Decision and Order No 34924, Instituting a Proceeding to Investigate Distributed Energy Resource Policies, Docket No 2014-0192 (Haw 20 October 2017), online: <>.
  129. See, e.g., Energy Independence and Security Act of 2007, HR 6, 110 Cong (2007).
  130. The American Council for an Energy Efficient Economy (ACEEE) ranks states annually on the extent to which states promote energy efficiency. In 2016, the two states tied for first place on the “ACEEE Scorecard” were California and Massachusetts, online: Weston Berg et al, “The 2016 State Energy Efficiency Scorecard,” American Council for an Energy-Efficient Economy (26 September 2016), online: < >.
  131. Cal Pub Util Code §§ 454.55, 454.564.
  132. Cal Pub Util Code § 381.
  133. Decision Approving Retirement of Diablo Canyon Nuclear Power Plant, Cal Pub Util Comm’n, Decision 18-01-022 (16 January 2018), online:>.
  134. US, AB 793, An act to amend Section 2790 of, and to add Section 717 to, the Public Utilities Code, relating to public utilities, 2015-2016, Cal, 2015.
  135. Fed Energy Regulatory Comm’n, Assessment of Demand Response and Advanced Metering Staff Report (28 December 2017), online: <>.
  136. Ibid at 1.

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