President Obama’s recently released budget proposal for the 2016 fiscal year repeats many of his past energy-related tax proposals, including a permanent extension of the renewable energy production tax credit and a provision making it refundable. Making the production tax credit permanent and refundable signals the administration’s continued strong support for renewable energy. This Special Report offers a summary of the key energy-related tax provisions contained in the budget proposal and discussed further in the U.S. Department of the Treasury’s general explanation of the proposal.
On Tuesday, December 16, 2014, the U.S. Senate passed the tax extenders bill by a vote of 76-16, extending a number of energy tax incentives through the end of the year. The Senate’s passage of H.R. 5771 followed the U.S. House of Representatives’ (House) approval earlier this month (see our post on December 8), and the bill is expected to be signed into law by President Obama as early as this week.
The $42 billion bill includes extensions through the end of the year of nearly $10 billion in energy tax incentives, including the New Market Tax Credit in Section 45D, the Production Tax Credit in Section 45 (the PTC), and the bonus depreciation rules in Section 168(k).
Many were disappointed that some of the tax incentives – including the PTC – were extended retroactively only through the end of the year, meaning that tax payers have just a few weeks left to take advantage of them. There would have been far more certainty for companies looking to invest in renewable energy projects if the tax incentives were extended for one or more years beyond the end of 2014. Several lawmakers suggested that the two week extension was better than nothing, but the short extension period means that Congress has merely punted the need for greater tax reform in this area into 2015. As it stands, the energy tax incentives extended by this bill will have expired by the time Congress returns to Washington, D.C., on January 6, 2015, following its winter break. That means that Congress may be in the same place again next year under pressure to pass a year-end bill – instead of focusing on more comprehensive reform and a possible phase-out of the PTC.
“A long time ago in a [May 19, 1980 Federal Register] far, far away [or so it seems],” the U.S. Environmental Protection Agency (EPA) declared its authority to regulate all hazardous secondary material, whether discarded or reused, under the Resource Conservation and Recovery Act (RCRA), and that it would exercise its authority to promote properly conducted waste reclamation. Ever since then, a kind of Empire/Rebellion struggle has played out over the scope and extent of broad-based recycling exclusions to the RCRA’s solid waste definition.
Over the years, recycling exclusions generally focused on particular industries. However, EPA’s last final rule, issued in the October 30, 2008 Federal Register during the Bush administration, contained several much broader exclusions. Those exclusions covered a waste generator’s onsite recycling, offsite recycling in the United States, and transfers of hazardous secondary materials for recycling conducted outside the United States.
The 2008 rule prompted litigation from both industry and the Sierra Club. The Sierra Club also filed an administrative petition seeking EPA repeal of the final rule. On September 7, 2010, EPA reached a settlement agreement with the Sierra Club under which EPA agreed to issue a notice of proposed rulemaking and a final rule that addressed the Sierra Club’s concerns. EPA’s final rule announced on December 10 is the latest chapter in the ongoing saga.
The new final rule rolls back many of the Bush-era provisions that minimized agency filings and involvement. It contains revisions to the onsite generator recycling exclusion, replaces the exclusion for offsite recycling in the United States, eliminates the exclusion covering recycling outside the United States, and introduces a new exclusion for recycling of certain solvents. It also contains some new requirements applicable to all recycling activities, and to new variances and non-waste determinations for recycled materials.
EPA’s new final rule is intended to provide greater safeguards against sloppy and sham recycling. These provisions address accumulation of hazardous secondary materials when there is no near-term prospect for recycling, and require an up-front demonstration that the recycling process will generate a valuable product suitable for reuse. They also require offsite recycling by a facility with a Part B permit or interim status under the RCRA regulations, or by facility that has obtained a variance after meeting the same types of requirements imposed upon permitted and interim status facilities.
Offsite recyclers and waste generators engaged in onsite recycling must adopt new procedures that include notification and periodic updates of recycling activity, demonstration that the recycling is legitimate, documentation of when accumulation has commenced for the material being recycled, and compliance with recordkeeping requirements and with emergency response and preparedness procedures like those imposed on hazardous waste generators. In addition, the new rule provides a definition of “contained” that is intended to ensure proper storage of hazardous secondary materials.
Beside adding safeguards to two of the three exclusions instituted in 2008 and eliminating the third one, the new rule introduces an exclusion to cover the recycling of 18 commercial grade solvents. Under that exclusion, such solvents must be used in one of four industrial sectors that do not include waste management, and the remanufactured solvents must be employed for specified uses that do not include cleaning or degreasing.
The solvent exclusion is subject to notification and recordkeeping requirements similar to those contained in the previously described recycling exclusions. In addition, there must be compliance with the tank and container standards covering Part B permitted facilities and with air emission control requirements imposed under the federal Clean Air Act or, where not applicable, to the air emission standards covering Part B permitted facilities.
In its 2011 proposal, EPA sought to impose the new notification and containment requirements on facilities covered by a pre-2008 exclusion or exemption. In the preamble to its new rule, EPA has deferred adoption of those requirements have been deferred in order to more fully consider the comments and concerns that were raised. One pre-2008 exclusion that received particular attention is scrap metal recycling, since scrap metal being recycled may be left on the ground rather than in a receptacle.
The new provisions and a few other items of interest are summarized here.
Last week, the U.S. House of Representatives (House) overwhelming approved a $42 billion tax extenders bill. The bill, H.R. 5771, includes extensions of nearly $10 billion in energy tax incentives through the end of 2014. But by failing to extend the tax incentives beyond the end of this year, the House bill has been criticized by industry advocates that wanted stability and predictability as to the future availability of the incentives.
The bill extends the New Market Tax Credit in Section 45D, the Production Tax Credit in Section 45, the Research Credit in Section 41, the bonus depreciation rules in Section 168(k), the Energy Property Credit for individuals in Section 25C, the Second Generation Biofuel Producer Credit in Section 40(a)(4), the incentives for biodiesel and renewable diesel in Section 40A, the New Energy Efficient Home Credit in Section 45L, the Energy Efficient Commercial Buildings Deduction in Section 179D, the special rule for sales or dispositions to implement FERC or state electric restructuring policy for qualified electric utilities in Section 451 and the excise tax credits relating to certain fuels in Section 6427.
By extending the Production Tax Credit (PTC) and other incentives retroactively only through the end of this year, the House bill provides little reassurance to companies in the industry who are looking to invest in renewable energy products, given the long lead time required to get projects off the ground. With only three weeks left before the PTC expires again, the extension is unlikely to provide much incentive to invest in new renewables projects. The House Ways and Means Committee expects the extension to cost around $9.6 billion over the next 10 years. But industry insiders argue that the expiration of the PTC last year and the resulting uncertainty has caused a drop off in new renewables (non-solar) projects, and have called for a multi-year extension that would phase out the PTC over three years. This kind of phase-out generated bipartisan support in a Senate bill last month, but the bill ultimately died after the White House threatened to veto it over other matters. Although some in the Senate are still pushing for a two-year extenders bill, it is currently expected that the extenders package will ultimately be passed in the form adopted by the House.
The U.S. Environmental Protection Agency (EPA) is expected to announce between now and December 31, 2014 its plan for pursuing methane reductions from the oil and gas sector – including whether it will propose new emission reduction regulations. Additionally, the agency recently modified its greenhouse gas (GHG) reporting rules for oil and gas systems and also proposed expanding those rules so that they would cover many additional oil- and gas-related sources. This blog post briefly summarizes these recent developments.
Where is EPA Headed with Respect to New Emission Reduction Requirements?
In his March 2014 Methane Reduction Strategy, President Obama directed EPA to study opportunities for reducing methane emissions from the oil and gas sector and to make a determination by this fall as to how best to pursue further reductions. EPA has yet to announce its “determination” but it is widely anticipated that EPA will not propose new methane capture or leak detection and repair (LDAR) regulations; instead, EPA is generally expected to continue promoting voluntary emission reduction efforts. But the agency remains under pressure from environmental organizations to actually require emission reduction measures, such as new mandatory LDAR requirements. For example a recent report by a coalition of environmental organizations asserts that new LDAR regulations focused on methane, coupled with other mandatory methane reduction measures, could “reduce the sector’s methane pollution in half in just a few years.”
New GHG Reporting Requirements Take Effect January 1, 2015, and EPA has also Proposed a Significant Expansion of the Reporting Rules
Although EPA may not propose new methane emission reduction regulations, it is clearly interested in improving the range and quality of methane emission data that it receives – and that it makes available to the public. Thus, on November 13, 2014, EPA signed a final rule (published in the Federal Register on November 25, 2014) modifying the existing GHG reporting requirements for the oil and gas sector to clarify the exact equipment covered by the regulations and the precise methods that can be used to calculate emissions from that equipment. The modifications take effect on January 1, 2015 and apply to emissions occurring in 2015.
EPA also just signed a proposed rule that would expand the oil and gas sector GHG reporting requirements to several additional categories of equipment and activities. The proposed rule has not yet been published in the Federal Register, but it would expand the reporting requirements to include, among other sources, gathering and boosting facilities, completions of fractured oil wells (currently, the rules cover fractured gas wells) and natural gas transmission pipeline blowdowns. The proposed rule also discusses emission calculation methodologies and the confidentiality of data reported to EPA. Indeed, the proposed rule lists several categories of emission and equipment-related data and proposes to designate much of that information as not confidential. That feature of the proposal reflects the agency’s ongoing emphasis on “next generation compliance,” one element of which is greater public availability of environmental data. Comments will be due 60 days after the proposed rule is published in the Federal Register.
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.