Is electricity goods or services? That seemingly simple yet confounding question is illustrated by three recent bankruptcy cases (all of which consider whether an electricity provider is entitled to an administrative expense priority under Bankruptcy Code Section 503(b)(9) for “the value of goods received by the debtor” in the ordinary course within 20 days prior to the automatic stay):
- In Hudson Energy Services, LLC v. Great Atlantic & Pacific Tea Co, Inc., 2013 WL 5212141 (S.D.N.Y. Sept. 16, 2013) (A&P), the court held that because electricity is consumed only after it is measured (at the customer’s meter), electricity is a “thing that is movable at the time of identification” (UCC 2-105) and accordingly should be characterized as goods under the UCC, which is the reference standard for Section 503(b)(9).
- The bankruptcy court in In re NE OPCO, Inc., 501 B.R. 233 (Bankr. D. Del. 2013), agreed with A&P that the meaning of goods under Section 503(b)(9) “is primarily informed by the meaning of goods under the UCC,” but disagreed with A&P that electricity is goods, holding that because “the period between identification and consumption must be meaningful,” the “infinitesimal delay” between those acts in the case of electricity makes it unidentifiable and thus not goods.
- In contrast to A&P and OPCO, the lower bankruptcy court in Puerto Rico Electric Power Authority v. Rentas, B.A.P. 1st Cir. No. PR 13-050 (Sept. 23, 2014) (PREPA), rejected the UCC definition as controlling § 503(b)(9) and relied instead on the public utility’s monopoly status as the basis for denying the administrative expense priority. The First Circuit Bankruptcy Appellate Panel rejected that reasoning and remanded with instructions to determine whether furnishing electricity is goods, but declined to instruct the lower court to use the UCC definition (with the exception of PREPA, nearly all bankruptcy courts have agreed that the UCC controls the §503(b)(9) definition of “goods”).
This lack of agreement on a seemingly elementary question is not confined to bankruptcy — it existed before Section 503(b)(9) was enacted (2005) and continues. Courts peering into the sub-atomic qualities of electricity have reached opposite conclusions whether electricity is goods or services. Other courts have gone the opposite direction, eschewing quantum physics and comparing the “common understanding of electricity” (which is to say the common misconception that an electricity customer is buying a “stream of electrons”) to severed oil, gas and other things that are UCC goods in hopes of finding the UCC equivalent of a “unified field theory” (as in physics, that search continues). Still other courts have concluded that electricity in “its raw state” is a service, but when it passes the end user’s meter it becomes goods.
This leaves lawyers with the quandary of identifying (a) which state’s laws do or should apply to the power purchase transaction (keeping in mind that not always will the forum court enforce a contractual choice of law if that foreign state’s substantive law fails to bear a reasonable relationship to the transaction) and (b) whether that state’s laws will treat the power purchase agreement as a contract for sale of goods or as a services contract. Then, the power purchase counterparties must presciently evaluate which permutation of outcomes (UCC goods or common law services) will most likely benefit their respective positions. Resolution of the goods-versus-services issue can lead to different construction of a contract for the sale of electricity in at least five respects:
- Contract formation—common law requires mirror acceptance, while the UCC permits additional terms to be added by acceptance;
- Contract administration—common law seldom recognizes modification of an existing contract without new consideration, while the UCC foregoes the need for new consideration;
- Contract interpretation—common law only sometimes admits trade practices and the parties’ past conduct to interpret terms, while the UCC always admits such evidence;
- Contract enforcement—common law can require impossibility to excuse performance, while the UCC recognizes the lesser standard of commercial impracticability; common law does not always recognize anticipatory repudiation or the right to demand adequate assurances, while the UCC recognizes both; and
- Contract rights and remedies—common law statutes of limitations for breach of contract often differ from the UCC’s four-year statute of limitations; common law does not generally recognize cover, while the UCC requires cover.
Even if electricity is initially characterized as goods, when electricity is bundled with services (such as transmission/distribution services), yet another issue arises: should the predominant factor test be applied to assess whether the provision of electricity is predominantly goods or services, or should the apportionment test apply as it did in the OPCO case, which treated natural gas deliveries as goods entitled to the administrative expense priority and electricity deliveries as services not so entitled. Further, even if the parties to a power transaction can agree on the substantive law to be applied — UCC or common law — their agreement must clearly identify that choice as the court held in Lockheed Electronics Company, Inc. v. Keronix, Inc., 114 Cal. App.3d 304 (1981).
The Commodity Futures Trading Commission (CFTC) last week released a final rule excluding certain electricity and natural gas swaps with governmental agencies and municipalities from the lower de minimis threshold for swaps with special entities. The rule makes permanent currently existing no-action relief previously issued by CFTC Staff. The final rule is the result of a petition filed by advocates for public energy companies claiming that subjecting swap transactions with governmental entities to a lower de minimis threshold would reduce the number of available counterparties, raise market liquidity concerns and make it more difficult for public energy companies to mitigate risk. To address these concerns the CFTC will allow certain swaps with special entities to be counted as regular swaps for purposes of swap dealer registration.
Under the Commodity Exchange Act and the CFTC’s regulations, an entity is exempt from registration as a swap dealer if the aggregate notional value of the swaps it entered into during the preceding 12 month period does not exceed the de minimis threshold of $3 billion (subject to a phase-in level of $8 billion). However, for swaps with special entities—federal or state agencies, municipalities, employee benefits plans, governmental plans and endowments—the de minimis threshold is only $25 million. As a result, companies entering into swaps with special entities have to be aware of their counterparty’s special entity status and take care not to exceed the substantially lower de minimis threshold.
The CFTC’s new rule creates an exception to the $25 million special entity threshold, so that “utility operations-related swaps” entered into with “utility special entities” are subject to the general $3 billion de minimis threshold. To qualify for the exception the swap must be with a special entity that owns or operates electric or natural gas facilities; associated with the generation, production, purchase or sale of electricity or natural gas; and for the purpose of hedging or mitigating commercial risk. In explaining why the exception is necessary, the CFTC recognized that utility special entities have unique responsibilities to provide electricity or natural gas services that must be continuous and are important to public safety. The CFTC also acknowledged that utility special entities often conduct swaps in localized and specialized markets, and the lower de minimis threshold could limit the number of willing counterparties to these important risk mitigation transactions. The new rule treats utility special entities similarly to non-governmental entities and will reduce regulatory barriers to transacting with special entities. The rule will become effective October 27, 2014.
Tax reform has been a hot topic as of late, particularly for the energy sector. On September 17, 2014, the Senate Finance Committee continued the focus on energy tax reform by holding a hearing on “Reforming America’s Outdated Energy Tax Code.” The hearing followed a trio of major proposals released this past year to revise the Internal Revenue Code’s energy tax provisions. Last December, former Senate Finance Committee Chairman Max Baucus (D-MT) released a discussion draft proposal to streamline energy tax incentives to make them more predictable and technology-neutral. The proposal consolidates the various tax incentives for clean electricity into a single production tax credit (PTC) or an investment tax credit for all types of power generation facilities that are placed into service after December 31, 2016. In February, House Ways and Means Committee Chairman Dave Camp (R-MI) released a discussion draft of the Tax Reform Act of 2014, which sets forth a broad framework for general tax reform, including the phase out and repeal of many energy-related tax credits such as the PTC. And in March, the President released his fiscal year 2015 budget proposal, which contained energy-related tax provisions such as a permanent extension of the PTC and a provision making the PTC refundable thereby allowing taxpayers without current taxable income to take advantage of the credit. A detailed review and comparison of these three proposals can be found here.
The September hearing on energy tax reform included industry representatives and academic experts as witnesses. At the beginning of the hearing, Committee Chairman Senator Ron Wyden (D-OR) articulated three principles that he views are important in moving energy tax reform forward. First, “the tax code must take the costs and benefits of energy sources into account.” This would include factors “such as efficiency, affordability, pollution, and sustainability.” Second, he advocates replacing “today’s quilt of more than 40 energy tax incentives with a modern, technology-neutral approach.” Third, “the disparity in how the tax code treats energy sources – and the uncertainty it causes – has to end.”
During the course of the hearing, several topics were addressed. A central focus of the hearing centered on achieving “parity” between fossil fuels and renewable fuels through a technology neutral tax structure. The witnesses debated over various ways to achieve such parity, including the proposal to eliminate expensing for drilling intangible costs. Other topics addressed by the witness panel included how to encourage technology advancements in the transmission and storage of energy, allowing renewable energy production to be financed through master limited partnerships, and the carbon tax.
At the end of the hearing, Wyden again reiterated his focus for energy tax reform: a technology-neutral approach focused on performance not fuel type. Although it is unlikely that any broad tax reform will be accomplished in the near future, it appears that there is continued interest in structuring the energy tax provisions in a way that is technology neutral and that achieves parity between fossil and renewable fuels.
A recording of the hearing, as well as the prepared written statements of the witnesses and the introductory remarks of Senators Wyden and Orrin Hatch (R-UT), can be found here.
Commissioner Philip Moeller of the Federal Energy Regulatory Commission (FERC) held a public meeting on September 18, 2014 to discuss ideas to facilitate and improve the way in which natural gas is traded and to explore the concept of establishing a centralized natural gas trading platform. Although not an official FERC conference, the ideas at issue were an extension of FERC’s recent focus on gas-electric coordination. During the well-attended meeting, Commissioner Moeller presided over a large roundtable discussion of stakeholders, including electric generation owners, natural gas producers, pipelines and marketers, who engaged in a spirited discussion of whether natural gas supplies are meeting the needs of electric generators and improvement in supply practices. The central focus of the meeting was the creation of a natural gas information and trading platform containing bids and offers for the purchase and sale of commodity and capacity for receipt and delivery on points across multiple pipeline systems.
Participants agreed that the natural gas industry is evolving and an increasing share of natural gas is being supplied to electric generators—customers with different needs than the local distribution companies the natural gas pipeline industry was traditionally designed to serve. Most participants further agreed that the needs of generators do not always align with pipelines’ traditional services.
Natural gas-fired generation owners voiced concerns regarding unknown or unreasonable commercial terms in pipeline service agreements, a lack of transparency surrounding available services and illiquidity in the natural gas market. Pipeline representatives highlighted the availability of new services such as extra nomination cycles, no-notice service and the ability to reverse flow as examples of services intended to accommodate generators. Nevertheless, the pipeline representatives also made the point that natural gas liquidity is outside pipelines’ control as they do not have title to the gas they transport. Marketers and organized exchange representatives added that they have been responding to generators’ needs by making available bespoke products and exploring new standardized products to match generators’ demands.
In addressing possible solutions to transparency and liquidity problems, most meeting participants urged incremental change and expressed a preference for industry solutions over FERC’s regulatory intervention. Electric generators preferred increased use of non-ratable service, no-notice service and new, shaped products. Other proposals included eliminating the shipper-must-have-title rule, facilitating competition between capacity release and pipeline overrun services and encouraging generators to purchase firm transportation service rather than interruptible service.
FERC has established a docket number to allow interested parties to file written comments on any issue that was discussed at the meeting. Comments are limited to five pages and are due by October 1, 2014.
The U.S. Environmental Protection Agency (EPA) issued a proposed rule on September 5, 2014 that would prevent states from including affirmative defenses in their Clean Air Act state implementation plans (SIPs) for emissions exceedances that occur during startup, shutdown and malfunction (SSM) periods. The proposal would also require several states to revise their existing SIPs so as to conform with EPA’s new approach to affirmative defenses.
EPA’s proposal modifies an earlier February 2013 proposal and arises from a Sierra Club petition asking EPA to revise roughly 40 different SIPs. Under the new proposal, EPA would largely grant Sierra Club’s petition rather than granting it only as to certain types of affirmative defenses, as EPA had previously proposed. A list of the states affected by the proposed rule can be found on EPA’s rulemaking website. If the rule is finalized as proposed, those states will have 18 months from the date of the final rule to submit revised SIPs.
EPA has long allowed the use of affirmative defenses in SIPs, with at least one court holding that it has the authority to do so. But in April of this year, the D.C. Circuit held that the plain language of the Clean Air Act prohibits EPA from including affirmative defenses in its own non-SIP regulations under Clean Air Act Section 112. EPA’s September 5 proposal extends the logic of that decision to the SIP context. But regulated parties should also be aware that the new proposal provides a good illustration of EPA’s “Next Generation Compliance” initiative in action. The proposal is consistent with the agency’s stated desire to simplify its regulations by reducing the number of exceptions contained in those regulations.
Regulated parties may fear that under EPA’s new proposal they will be unduly penalized for emissions exceedances caused by events beyond their control. They can take some comfort in understanding that even without affirmative defenses, the Clean Air Act’s penalty provisions do allow the agency and the courts some discretion in setting penalty amounts. Thus, going forward, facility owners that experience an emission exceedance because of events beyond their control can still argue, on a case-by-case fact-specific basis, that it would be inappropriate to impose any penalties.
Comments on EPA’s proposal are due by November 6, 2014, and, under the terms of a settlement agreement with Sierra Club and WildEarth Guardians, EPA is required to issue a final rule by May 22, 2015.
A New York town’s challenge to the Federal Energy Regulatory Commission’s (FERC) siting authorization for a natural gas pipeline compressor station was rejected by the U.S. Court of Appeals for the D.C. Circuit in Minisink Residents for Environmental Protection and Safety v. FERC. The court’s August 15 decision denying the petition for review of residents of the Town of Minisink, when read in conjunction with its decision earlier this year in Delaware Riverkeeper Network v. FERC, delineates the scope of environmental impact analysis that the court will require of FERC under the National Environmental Policy Act (NEPA).
Residents of the Town protested the compressor station’s location and urged FERC and Millennium to pursue an alternative site referred to as the Wagoner Alternative. The Wagoner Alternative would have resulted in the compressor station being located in a less populous area but would have required the replacement of a seven mile pipeline segment (called the Neversink segment). In developing its environmental assessment, FERC had actively considered the Wagoner Alternative but concluded that because of the need to replace the Neversink segment, the environmental impact associated with the Minisink location would be less and the Minisink location was therefore preferable. FERC’s decision approving the Minisink proposal was split 3-2, with former Chairman Wellinghoff and current Chairman LaFleur dissenting, both Commissioners concluding that the Wagoner Alternative was the better option.
Fundamental to the D.C. Circuit’s decision was its finding that FERC had adequately analyzed the Wagoner Alternative and that there was ample evidence to support its determination that the Wagoner Alterative would have a greater impact due to the need upgrade the Neversink segment. The petitioners attempted to undermine this finding by pointing to a Millennium PowerPoint presentation that they alleged showed that even if the compressor station were to be located in Minisink, Millennium still planned to replace the Neversink segment. The court, however, did not consider the PowerPoint persuasive in light of both Millennium’s representation to FERC and Millennium’s counsel’s representation at oral argument that Millennium had no current plans to replace the Neversink segment.
In an instructive footnote, the D.C. Circuit contrasted this case to its recent decision in Delaware Riverkeeper, where it held that FERC improperly segmented and failed to consider the cumulative impact of four connected pipeline construction projects. The court clarified that the “critical” factor in Delaware Riverkeeper was that all of the pipeline’s projects were either under construction or pending before FERC for environmental review at the same time. The court acknowledged that the issue before them in Minisink Residents would potentially be “more troublesome” if Millennium were now planning to pursue the Neversink upgrade.
The Federal Energy Regulatory Commission’s (FERC) Order No. 1000 mandate that going forward the high-voltage electric transmission grid be planned and fairly financed regionally by all of its operators and beneficiaries, survived myriad challenges from 45 petitioners in the unanimous August 15 decision of a three-judge panel of the U.S. Court of Appeals for the D.C. Circuit in South Carolina Public Service Authority v. FERC. The rigorous 97-page opinion rejected challenges coming from all directions to the 2011 rulemaking entitled “Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities.”
According to the panel, nearly all of the challenges misapprehended Order No. 1000’s regional planning mandate. The court repeatedly emphasized that Order No. 1000’s mandate is nothing new, but rather the next step in evolving efforts under section 206 of the Federal Power Act to combat undue discrimination. That evolution, the panel explained, began in 1996 when Orders No. 888 and No. 889 required that electricity transmission be “unbundled” from sales and offered via the internet pursuant to open-access tariffs, and 11 years later continued in Order No. 890’s directive that a transmission provider standardize how it measures available transmission capacity and open to its customers the process for planning transmission upgrades and expansions.
The panel’s decision affirmed FERC’s authority to require each of the key elements that FERC prescribed for regional transmission planning. Those elements include:
- All public utility transmission providers are required to participate in a regional planning process, and non-public utilities such as cooperative or municipal utilities effectively must also participate pursuant to a reciprocity requirement carried forward from Order No. 888.
- The planning process must include procedures for taking into account federal, state and local laws and regulations affecting transmission, such as federal air quality rules and state or local renewable portfolio standards.
- Transmission tariffs must be amended to remove provisions that confer on the incumbent transmission provider a right of first refusal to construct, own, and operate new regional transmission, thereby opening the regional process to input, innovation, and investment from non-incumbents and new entrants, subject to state and local restrictions on siting and eminent domain.
- A methodology must be added to transmission tariffs for allocating up-front the cost of new regional transmission facilities, consistent with six principles, including a causation principle directing that the allocation be roughly commensurate with the benefits received by those consumers required to pay, and a prohibition on one region allocating costs to its neighbors without their advance consent.
FERC Chairman Cheryl LaFleur promptly praised the panel’s decision upholding Order No. 1000 in its entirety as critical for inducing the “substantial investment in transmission infrastructure [needed] to adapt to changes in its resource mix and environmental policies.” In its decision the panel noted that the electric industry in 2008 estimated the infrastructure investment needed at $298 billion between 2010 and 2030.
Following FERC’s lead, the panel chose not rule at this time on challenges that elements of the regional planning mandate violate the Mobile-Sierra doctrine —eponymously named for two 1956 Supreme Court decisions —which limits FERC’s authority unilaterally to alter the terms of bilateral contractual relationships. FERC explained that it would not rule on these challenges in the context of Order No. 1000, but would instead address them in connection with a transmission provider’s filing of tariff amendments in compliance with the Order. Mobile-Sierra challenges prosecuted at that time are unlikely to succeed since precedents interpreting the doctrine give the Commission much greater leeway when implementing industry-wide changes to tariffs than when seeking to alter individual contracts.
Last week, the New Jersey Board of Public Utilities (BPU) approved an agreement with the New Jersey Economic Development Authority (EDA) to establish and operate an Energy Resilience Bank in the state. The BPU approved a plan to direct over $200 million in federal aid to the bank. The Energy Resilience Bank (ERB) will focus on the development of distributed energy resources at critical facilities throughout the state, aiming to minimize the impacts of widespread power outages like the one Hurricane Sandy caused.
The ERB will be focused on providing capital, both low-interest loans and grants, to critical facilities that offer the greatest resilience benefits, including water and wastewater treatment plants and hospitals. Subsequent funding will be directed toward other critical facilities, such as transportation, emergency response and schools that can function as shelters in case of emergency. While other states, including New York and Connecticut, have recently launched green banks, the ERB will be the first to focus on resiliency.
The launch of the ERB followed a National Renewable Energy Laboratory study that found that distributed generation and microgrids are integral to energy resiliency. Distributed generation and microgrids have the potential to ‘island’ electricity at critical facilities with on-site generation, retaining power during bulk-power system blackouts. These technologies provide additional benefits such as increasing efficiency by cutting transmission losses and incentivizing clean energy deployment.
New York launched its Green Bank in December with an initial capitalization of $210 million. The New York model focuses on private-sector investment proposals and aims to support financing for local energy efficiency and clean-energy projects that larger financial institutions typically overlook. New York’s Green Bank envisions support such as credit enhancements, co-investing with the private sector in a loan fund for clean energy, loan warehousing/short-term project aggregation and similar arrangements. Connecticut launched the first green bank in the country in 2012, and, according to their 2013 report, roughly ten dollars was invested by private sources for every one dollar of ratepayer funds invested. It remains to be seen whether New Jersey will similarly leverage private investment in its model.
The energy reforms in Mexico have generated significant interest from energy investors around the world. McDermott has created a new LinkedIn Group, McDermott Discussion Group: Mexico’s Energy Reforms, to discuss legislative developments and their impacts on the changing energy private investment climate. Members of our team are well studied in these reforms and we will be posting updates on legislative developments and market updates. We encourage group member discussion and comments as well. Group participants stand to gain insight from our lawyers who are studying the reforms, from their peers who are also considering opportunities in Mexico, and from Mexican government officials who are tasked with executing the reforms. The impact of the reforms will be felt across the board, covering the oil, gas and power sectors.
Click here to join our group. If you have any questions or technical issues, please contact Taylor Shekarabi.
The D.C. Circuit Court of Appeals recently issued an opinion holding that the Federal Energy Regulatory Commission (FERC) violated the National Environmental Policy Act (NEPA) when it segmented its evaluation of the environmental impact of four separately proposed but connected projects to upgrade the “300 Line” on the Eastern Leg of Tennessee Gas Pipeline Company’s natural gas pipeline system. Going forward, the court’s ruling will likely compel proponents of interrelated or complimentary pipeline projects to seek their certification on a consolidated basis and will require FERC to evaluate their cumulative impact.
Tennessee Gas’s challenged Northeast Project was the third of four proposed upgrade projects to expand capacity on the existing Eastern Leg of the 300 Line. The Northeast Project added only 40 miles of pipeline, while the four proposed projects combined to add approximately 200 miles of looped pipeline. FERC approved Tennessee Gas’s first proposed upgrade, the “300 Line Project,” in May 2010. While that project was under construction, Tennessee Gas proposed three additional projects to fill gaps left by the 300 Line Project, one of which was the Northeast Project. As part of its review of the Northeast Project, FERC issued an Environmental Assessment (EA) required by NEPA that recommended a Finding of No Significant Impact. The EA for the Northeast Project, however, addressed only the Northeast Project’s environmental impact without reviewing the cumulative impact of all four projects.
The D.C. Circuit held that FERC was in error for failing to consider the cumulative impact. Under NEPA, the D.C. Circuit explained, FERC must consider all connected and cumulative actions. The D.C. Circuit found no “logical termini,” or rational endpoints to divide the four projects and found the projects were not financially independent. Rather, the court found the Northeast Project was “inextricably intertwined” with the other three improvement projects that, taken together, upgraded the entire Eastern Leg of the 300 Line. The court held that FERC must analyze the cumulative impact of the four projects and remanded the case to FERC for consideration.
The Court emphasized that in this case, “FERC was plainly aware of the physical, functional, and financial links between the two projects.” Regardless of whether an interstate pipeline initially plans to embark on a series of related upgrades, once FERC is aware of the interrelatedness of proposed expansion projects, it must take care to review any cumulative environmental impacts that may arise.
The D.C. Circuit’s decision may also be a warning that FERC must pay greater attention to the NEPA review in pipeline construction projects. The D.C. Circuit also has before it this term a case alleging that FERC did not sufficiently consider the environmental review of the siting of a new pipeline compressor station in light of less environmentally intrusive alternatives. See Minisink Residents for Environmental Preservation and Safety v. FERC, Case No. 12-1481. Both cases take issue with the rigor of FERC’s environmental review under NEPA, and the D.C. Circuit’s decisions may signal a new era of increased focus on the environmental review process.
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