Tag: Utilities

Supreme Court Questions Whether Highly Compensated Oil Rig Worker Is Overtime Exempt

On October 12, 2022, the Supreme Court of the United States heard oral arguments in a case regarding whether an oil rig worker who performed supervisory duties and was paid more than $200,000 per year on a day rate basis is exempt from the overtime requirements of the Fair Labor Standards Act (FLSA).

The case is especially significant for employers that pay exempt employees on a day rate. It could have a major impact on the oil and gas industry in the way that it recruits, staffs, and compensates employees who work on offshore oil rigs and at remote oil and gas work sites. In addition, depending on how the Supreme Court rules, its decision could have much broader implications.

During the arguments in Helix Energy Solutions Group, Inc. v. Hewitt, the justices questioned whether, despite the employee’s high earnings, he was eligible for overtime compensation because he was paid by the day and not on a weekly salary basis. There is no express statutory requirement that an employee be paid on a “salary basis” to be exempt from overtime requirements, but such a requirement has long been included in the regulations issued by the U.S. Department of Labor (DOL) applicable to the FLSA’s white-collar exemptions. Notably, Justice Brett Kavanaugh suggested during the arguments that the regulations may be in conflict with the text of FLSA, although Helix did not raise this issue in its petition for certiorari.

Background

The case involves an oil rig “toolpusher,” an oilfield term for a rig or worksite supervisor, who managed twelve to fourteen other employees, was paid a daily rate of $963, and earned more than $200,000 annually. Between December 2014 and August 2017, when Michael Hewitt was discharged for performance reasons, he worked twenty-eight-day “hitches” on an offshore oil rig where he would work twelve-hour shifts each day, sometimes working eighty-four hours in a week. After his discharge, Hewitt filed suit alleging that he was improperly classified as exempt and therefore was entitled to overtime pay. The district court ruled in favor of Helix.

In September 2021, a divided (12-6) en banc panel of the U.S. Court of Appeals for the Fifth Circuit held that Hewitt was not exempt from the FLSA because his payment on a day-rate basis did “not constitute payment on a salary basis” for purposes of the highly compensated employee (HCE) exemption that is found in the FLSA regulations.

The Fifth Circuit further concluded that the employer’s day-rate pay plan did not qualify as the equivalent of payment on a salary basis under another FLSA regulation because the guaranteed pay for any workweek did not have “a reasonable relationship” to the total income earned. In other words, the court found that the employee was not exempt because the $963 he earned per day was not reasonably related to the $3,846 the employee earned on average each week.

Oral Arguments

Oral arguments at the Supreme Court focused on the interplay between the DOL’s HCE regulation, 29 C.F.R. § 541.601, and another DOL regulation, 29 C.F.R. § 541.604(b), which states that an employer will not violate the salary basis requirement under certain limited circumstances even if the employee’s earnings are computed on an hourly, daily, or shift basis.

At the time of Hewitt’s employment, the HCE exemption required an employee to be paid at least $455 per week on a “salary or fee basis” and to earn at least $100,000 in total annual compensation. Those threshold amounts have since been increased to $684 per week and $107,432 per year.

The other regulation, 29 C.F.R. § 541.604(b), states that an employee whose earnings are “computed on an hourly, a daily or a shift basis” may still be classified as exempt if the “employment arrangement also includes a guarantee of at least the minimum weekly required amount paid on a salary basis regardless of the number of hours, days or shifts worked, and a reasonable relationship exists between the guaranteed amount and the amount actually earned. The reasonable relationship test will be met if the weekly guarantee is roughly equivalent to the employee’s usual earnings at the assigned hourly, daily, or shift rate for the employee’s normal scheduled workweek.”

Hewitt earned double the minimum total compensation level for the HCE exemption. Since the minimum salary level for the exemption was only $455 per week, and Hewitt was guaranteed that he would be paid at least $963 per week for each week he worked at least one day, Helix argued that he was exempt from the FLSA’s overtime requirements because the HCE exemption was completely self-contained and to be applied without regard to other regulations, including the “salary basis” test and the minimum guarantee regulation. Hewitt argued that the HCE exemption required compliance with either the “salary basis” test or the minimum guarantee regulation since he was admittedly paid on a day rate basis.

However, Justice Ketanji Brown Jackson suggested that it was not that simple. Justice Jackson said the question of salary basis is more about the “predictability and regularity of the payment” for each workweek. “What he has to know is how much is coming in at a regular clip so that he can get a babysitter, so that he can hire a nanny, so that he can pay his mortgage,” Justice Jackson stated. Justice Jackson echoed the language of the salary basis test requiring that an exempt employee be paid a predetermined amount for any week in which she performed any work.

Similarly, Justice Sonia Sotomayor asked Helix, “so what you’re asking us to do is take an hourly wage earner and take them out of 604, which is the only provision that deals with someone who’s not paid on a salary basis.” Justice Sotomayor additionally raised the FLSA’s goal of “preventing overwork and the dangers of overwork.”

In contrast, Justice Clarence Thomas suggested that Hewitt’s high annual compensation relative to the average worker is a strong indication that he was paid on a salary basis and should be exempt. “The difficulty is just, for the average person looking at it, when someone makes over $200,000 a year, they normally think of that as an indication that it’s a salary,” Justice Thomas stated.

Justice Kavanaugh asked if the issue of whether the DOL regulations conflict with the FLSA is being litigated in the courts. He said, “it seems a pretty easy argument to say, oh, by the way, or maybe, oh, let’s start with the fact that the regs [sic] are inconsistent with the statute and the regs [sic] are, therefore, just invalid across the board to the extent they refer to salary.” He further stated, “if the statutory argument is not here, I’m sure someone’s going to raise it because it’s strong.”

Key Takeaways

It is difficult to predict how the Supreme Court will rule in this case. A decision that requires strict adherence to the regulation’s reasonable relationship test, even when the minimum daily pay far exceeds the minimum weekly salary threshold, would have a significant negative impact on the manner in which certain industries compensate their workers. It also could lead to even more litigation by highly compensated employees, many of whom make more money without receiving overtime pay than what many people who currently are paid overtime compensation make.

Depending upon its breadth, a decision that the regulations are in conflict with the statutory text of the FLSA could provide a roadmap for additional challenges to other parts of the regulations. This could have a wide-ranging impact, as the DOL currently is in the process of preparing a proposal to revise its FLSA regulations. Then again, if a future litigant takes up Justice Kavanaugh’s invitation to challenge whether the salary regulations are overbroad compared to the language of the FLSA, the current effort to revise the regulations regarding exemptions for executive, administrative, and professional employees may be moot.

Article By Andrew P. Burnside, Steven F. Pockrass, and Zachary V. Zagger of Ogletree, Deakins, Nash, Smoak & Stewart, P.C.

For more supreme court and litigation legal news, click here to visit the National Law Review.

© 2022, Ogletree, Deakins, Nash, Smoak & Stewart, P.C., All Rights Reserved.

One Less Way for Ohio Landowners to Challenge Royalty Severances

On February 15, 2022, the Ohio Supreme Court issued a significant decision in Peppertree Farms, L.L.C. v. Thonen establishing that, unless expressly stated otherwise, an oil and gas royalty interest retained in a deed executed prior to 1925 is not limited to the lifetime of the grantor. In so holding, the Ohio Supreme Court cut off one of the only grounds, other than the Dormant Minerals Act and Marketable Title Act, for landowners to quiet title and eliminate past oil and gas severances.

Ohio follows a legal tradition under which the default rules of English “common law” were adopted and then adapted by statute to form the basis of our legal system. At common law, a conveyance of real property had to include “words of inheritance” (i.e., an express statement that the royalty interest would last in perpetuity and be inheritable) or the interest being conveyed would be limited to the lifetime of the grantee (a life estate). Additional complications arose when a grantor sought to retain an interest by deed. If the grantor was retaining a right which had already been conveyed to him in perpetuity, then the retention qualified as a “technical exception” of a pre-existing right and additional words of inheritance were not required. However, if the grantor was creating and then retaining a new right, the retention qualified as a “technical reservation” and was limited to a life estate.

As new modes of production and corresponding property rights were discovered, it became unclear exactly what rights pre-existed a severance and the whole system of distinctions fell apart. In 1925, the General Assembly passed a law establishing that all future conveyances of real property were presumed perpetual unless stated otherwise. While eliminating this issue as to future deeds, the General Assembly did not settle the issue as to deeds executed before 1925 or clarify whether the retention of an oil and gas royalty was a “technical exception” or “technical reservation.”

In the Peppertree Farms case, Plaintiffs Peppertree Farms, Jay Moore and Amy Moore (collectively, “Peppertree”) sought to quiet title to certain lands in Monroe County, Ohio, against a severed oil and gas royalty interest (the “Royalty Interest”) originally retained by the grantor under a 1921 deed. In addition to a claim for extinguished under Ohio’s Marketable Title Act, Peppertree asserted that the Royalty Interest did not include words of inheritance and was therefore a newly created right which terminated upon the death of the grantor under the 1921 deed. Conversely, the defendant royalty owners (“Royalty Owners”) argued that the Royalty Interest was a pre-existing right which the grantor already held, and therefore could retain, in perpetuity without words of inheritance.

While Peppertree was able to convince both the trial and appellate court that the Royalty Interest was a newly created interest which was limited to a life estate, it was unsuccessful with the Ohio Supreme Court. Reasoning that a royalty was nothing more than the retention of part of the right to receive the proceeds of oil and gas production, the Court ultimately found that the Royalty Interest was a “technical exception” which survived the lifetime of the grantor. As a result, Peppertree was limited to its claims for extinguishment under the Marketable Title Act and Ohio surface owners lost another means to challenge ancient royalty reservations.

©2022 Roetzel & Andress
For more articles on local state litigation, visit the NLR Litigation section.

Ongoing Canadian Protests Shine Spotlight on Ripple Effect of Supply Chain Disruptions

Although the last two years have seen a nearly never-ending line of supply chain impacts for manufacturers, the latest disruption is also serving to shine a spotlight on the broader impact that relatively small disruptions in the supply chain can have on the global economy.  We all know that trucking is a critical component of the economy.  The U.S. estimates seventy two percent of goods in the U.S. travel by truck.  Trucking has become even more important in this era of increased deliveries and backlogs at ports and other logistics hubs.

In Canada, what began as protests by truckers regarding certain pandemic-related restrictions and mandates have snowballed into broader protests and blockages of roads, bridges, and border crossings.

Protesters have been blocking various bridges and roads in Canada in protest of certain pandemic-related restrictions and mandates.  On Tuesday, the bridge connecting Windsor, Ontario to Detroit (a critical linkage for cross-border travel) was largely blocked, with traffic stopped going into Canada and slowed to a trickle going into the United States. The blockades are now leading U.S. automakers to begin trimming shifts and pausing certain operations in their Michigan and Canadian plants. The bridge protests and automakers’ reduction in capacity continued on Thursday without an end in sight.

The ongoing protests in Canada have also served as a reminder of how seemingly local trucking disruptions in one country can cascade through the supply chain.  This is not the first time that trucking strikes and blockages have rippled through the supply chain and economy.  In 1996, a truckers’ strike in France lasted 12 days, barricading major highways and ultimately leading to concessions from the French government over certain worker benefits and hours.  The resulting agreement led to heightened tensions with Spain, Portugal, and Great Britain due to the impact felt across borders.  In 2008, truckers went on strike in Spain and blocked roads and border crossings, protesting fuel prices.  In 2018, truckers in Brazil staged a large strike and protest that lasted for 10 days, blocking roads, disrupting food and fuel distribution, canceling flights, and causing certain part shortages for automakers.

The ongoing protests in Canada have similarly expanded from Ottawa to the current blockage of border crossings, further raising their profile internationally as they begin to impact global trade.  It remains to be seen how the blockades and protests will resolve, as leaders call for de-escalation and re-opening of roads and crossings.  However, the ripple effects of what started as a localized protest will continue to be felt far beyond Canada’s borders.

Article By Lauren M. Loew of Foley & Lardner LLP

For more COVID-19 and supply chain legal news, click here to visit the National Law Review.

© 2022 Foley & Lardner LLP

FERC Requires Public Utilities to Address Excess ADIT in Transmission Rates

On November 21, 2019, the Federal Energy Regulatory Commission (“FERC”) issued Order No. 864, a final rule on Public Utility Transmission Rate Changes to Address Accumulated Deferred Income Taxes. The new rule requires  public utilities with formula transmission rates to revise their formula rates to include a transparent methodology to address the impacts of the Tax Cuts and Jobs Act of 2017 (2017 Tax Act) and future tax law changes on customer rates by accounting for “excess” or “deficient” Accumulated Deferred Income Taxes (ADIT).  FERC also required transmission providers with stated rates to account for the ADIT impacts of the 2017 Tax Act in their next rate case.

Background

The 2017 Tax Act reduced the corporate income tax rate from 35 percent to 21 percent. The tax rate change will result in a reduction in a public utility’s future tax liabilities so that a portion of its ADIT balances (rate receipts collected in anticipation of future tax liability) will no longer be due to the IRS, and is thus considered excess ADIT.  This transmission-related excess ADIT must be returned to customers through a public utility’s transmission rates.

FERC issued a Notice of Proposed Rulemaking (NOPR) on ADIT issues on November 15, 2018.   In the NOPR, FERC proposed to require public utilities with formula rates to adjust their formula rates to include (i) a mechanism to reflect any excess or deficient ADIT resulting from the 2017 Tax Act, or any future tax rate change, in rate base; (ii) a mechanism to adjust income tax allowance to reflect amortization of excess or deficient ADIT; and (iii) a new worksheet in its transmission formula rate to track on an annual basis information related to excess/deficient ADIT.  FERC also proposed to require public utilities with stated rates to make a compliance filing to address excess ADIT resulting from the 2017 Tax Act.

Order No. 864 – Final Rule on ADIT Adjustments to Account for Tax Rate Changes

ADIT Adjustments in Formula Rates

In the final rule, FERC adopted each of its proposals to address ADIT adjustments for transmission providers with formula rates.

  • Rate Base Adjustment Mechanism.  FERC required public utilities with formula rates to include a mechanism by which excess ADIT is deducted from rate base, and deficient ADIT is added to rate base.  This mechanism must be broad enough to cover any future tax changes that might give rise to excess/deficient ADIT.  FERC did not require use of a specific mechanism, and instead will consider proposed changes on a case-by-case basis.  FERC noted that, consistent with its previous accounting guidance, public utilities are required to record a regulatory asset (Account 182.3) associated with deficient ADIT or a regulatory liability (Account 254) associated with excess ADIT.
  • Income Tax Allowance Adjustment Mechanism.  FERC required public utilities with formula rates to incorporate a mechanism to adjust income tax allowances to reflect amortized excess or deficient ADIT.  This mechanism must cover amortization of excess or deficient ADIT resulting from any future tax changes as well as the 2017 Tax Act.  FERC will consider proposed changes on a case-by-case basis.  FERC clarified that, consistent with guidance provided in the 2017 Tax Act, excess ADIT that is “protected” (i.e., plant-related) should be amortized no more rapidly than over the life of the underlying asset using the Average Rate Assumption Method (ARAM), or an alternative method if insufficient data is available to use ARAM.  FERC will evaluate proposed amortization methods for the return of excess ADIT that is “unprotected” (i.e., not plant-related) on a case-by-case basis. FERC clarified that regardless of the effective date of tariff changes submitted by a public utility, the full amount of excess ADIT resulting from the 2017 Tax Act must be returned to its customers.
  • New ADIT Worksheet.  FERC required public utilities to add a new permanent worksheet that will annually track information related to excess or deficient ADIT in their formula rates.  FERC required that the new ADIT worksheet address: (1) how any ADIT accounts were re-measured and the excess or deficient ADIT contained therein; (2) the accounting for any excess or deficient amounts in Accounts 182.3 (Other Regulatory Assets) and 254 (Other Regulatory Liabilities); (3) whether the excess or deficient ADIT is protected or unprotected; (4) the accounts to which the excess or deficient ADIT are amortized; and (5) the amortization period of the excess or deficient ADIT being returned or recovered through the rates. FERC expects public utilities to identify each specific source of excess/deficient ADIT, classify such excess/deficient ADIT as protected or unprotected, and list the proposed amortization period associated with each classification or source.  FERC also expects public utilities to provide supporting documentation in their compliance filings to justify the proposed amortization periods.  FERC did not require that use of a pro forma worksheet to convey such information, but did require that on compliance, public utilities populate the worksheets with excess/deficient ADIT resulting from the 2017 Tax Act to facilitate review by interested parties.

FERC clarified that given the formula rate changes required in the final rule, public utilities with formula rates would not be required to make subsequent FPA Section 205 filings to address rate impacts of excess/deficient ADIT associated with future tax rate changes.  FERC also stated that a public utility may show that existing ADIT-related mechanisms meet the requirements of this final rule.

ADIT in Stated Rates

FERC declined to adopt its proposal to require public utilities with stated rates to determine excess ADIT resulting from the 2017 Tax Act and return such amounts to customers in a single-issue filing responding to the final rule.  Instead, FERC stated it would maintain the status quo under its precedent, which requires public utilities with stated rates to address excess/deficient ADIT, including that caused by the 2017 Tax Act, in their next rate case.  FERC clarified it will address the timing of proposed excess ADIT amortization on a case-by-case basis, and that public utilities may propose to delay such amortization until its next rate case.

Compliance Filings 

FERC required that public utilities with formula rates submit a compliance filing by the later of 30 days after the effective date of the final rule (the effective date will be 60 days after publication of the rule in the Federal Register) or the public utility’s next annual informational filing. FERC stated that proposed tariff changes to address the final rule’s requirements should be made effective on the effective date of the final rule.

Several public utilities have already revised their formula rates to address excess ADIT resulting from the 2017 Tax Act.  These filings sought to implement the requirements proposed by FERC in the NOPR.  Under the final rule, these utilities will need to make a compliance filing, but can argue that the already-made changes satisfy the requirements of the final rule.  These past filings may serve as helpful models for compliance filings by other utilities, but must be considered in light of the requirements of the final rule.

Public utilities with stated rates are not required to make a compliance filing; excess/deficient ADIT issues will be considered in the next rate proceeding.

© 2019 Van Ness Feldman LLP

ARTICLE BY Van F. Smith and  Ani M. Esenyan of  Van Ness Feldman LLP.
Read more about utility tax regulation on the Environmental, Energy & Resource law page of the National Law Review.

Tesla Bringing Supercharger Stations to Boston and Chicago

On September 11th, Tesla announced the opening of Supercharger stations in downtown Boston and Chicago, representing the first step in the company’s effort to expand its Supercharger network into urban areas. The company currently operates 951 Supercharger stations worldwide, primarily along major highways to provide quick recharging on long trips. By bringing the network of charging stations into city centers, Tesla hopes to service growing demand among urban dwellers without immediate access to home or workplace charging.

Unlike the Destination Charging connectors at hotels and restaurants meant to replicate the longer home-charging process, Superchargers quickly deliver 72 kilowatts of power to each car for short-term boosts, resulting in charging times around 45-50 minutes. The new stations will be installed near supermarkets, shopping centers, and downtown districts, making it easy for drivers to charge their car while running errands. The Boston Supercharger station will be located at 800 Boylston Street and include 8 charging stalls.

Tesla announced plans to double its national charging network to 10,000 stations by the end of 2017. The company is bringing urban Superchargers to New York, Philadelphia, Washington, Los Angeles, and Austin by the end of this year. The expansion accompanies Tesla’s release of the Model 3 this summer, which boasts a lower starting price of $35,000 that is expected to bring more buyers to the brand.

A spike in Tesla sales would fall in line with the trend of increased demand for electric vehicles (EV) across the country. The year 2016 saw EV sales in the United States increase by 37% over 2015. Total EV sales topped out at roughly 160,000, with five different models (Tesla Model S, Tesla Model X, Chevrolet Volt, Nissan Leaf, and Ford Fusion Energi) selling at least 10,000 units. These sales, coupled with the expanding ease of access to charging station’s like Tesla’s, bode well for continued innovation and growth in the electric auto sector.

This post was written by Thomas R. Burton, III of  Mintz, Levin, Cohn, Ferris, Glovsky and Popeo, P.C. All Rights Reserved. ©1994-2017
For more legal analysis go to The National Law Review

IRS Releases Favorable Guidance for Individual Investors in Community Solar to Claim Section 25D Tax Credit

The IRS recently issued a Private Letter Ruling (PLR) clarifying that an individual investor in a net-meted community solar project may claim the federal residential Investment Tax Credit (ITC) under Section 25D of the Internal Revenue Code. (A copy of the PLR is available here.) The PLR is also significant because it appears to eliminate a number of contractual requirements that the utility and taxpayer needed to agree to regarding the tracking and ownership of the power produced by the solar project to be eligible for the credit.

Section 25D Tax Credit and Prior IRS Guidance

Just like the Section 48 ITC, the Section 25D ITC permits an owner of solar and other renewable energy property installed before January 1, 2017 to receive a 30% tax credit against federal income taxes. However, in order to claim the credit the property must “generate electricity for use in a dwelling … used as a residence by the taxpayer.” Some tax practitioners interpreted that to meant the credit was limited to solar projects on or adjacent to the taxpayer’s residence. A few years ago, the IRS provided some guidance in Notice 2013-70 (at Q&A Nos. 26 and 27) that taxpayers could in fact claim the credit for off-site solar projects. However, the fact pattern in the Notice described an off-site net-metered project that was owned by the taxpayer, so questions remained whether taxpayers could claim the credit for investments in co-owned community solar projects. Further, the IRS limited the Notice so that it only applied to net-metering arrangements whereby the taxpayer specifically contracts with its local utility to track “the amount of electricity produced by the taxpayer’s solar panels and transmitted to the grid and the amount of electricity used by the taxpayer’s residence and drawn from the grid” as well as stipulate in the contract that the taxpayer holds title to the energy until it is delivered to the taxpayer’s residence. These requirements were problematic because they were often at odds with utility tariffs and state net-metering laws.

The PLR

The PLR is partially redacted but it was provided to a Vermont taxpayer requesting clarification as to whether his investment to purchase 10 solar panels in a 640-panel community solar farm along with a partial ownership in related racking, inverters and wiring is eligible for the Section 25D ITC. (A brief write-up about the project and taxpayer in the local press is available here.) The PLR explains that the project’s entire solar energy output is provided to the taxpayer’s local utility which then calculates a net-metering credit pursuant to its tariff and applies a portion of that credit against the taxpayer’s monthly electric bills. The PLR also explains that the taxpayer’s solar panels are not expected to generate electricity in excess of what the taxpayer will consume at his residence and that the taxpayer along with the other owners of the community solar project are members of an entity that coordinates with the utility the information needed to calculate each person’s allocable share of energy produced by the entire project. Based on these facts, the IRS determined that the taxpayer is entitled to the Section 25D credit. The PLR makes clear the fact that other individuals own solar panels in the project’s solar array does not disqualify the taxpayer from claiming the Section 25D ITC. The PLR did away with the requirement the utility specifically track the exact amount of electricity produced by the taxpayer’s portion of the community solar project and can instead determine the taxpayer’s allocable share of the entire project. The PLR also did away with the requirement the utility contractually agree that the taxpayer retains ownership of the electricity until delivered at his residence. Thus, to recap, under the PLR a taxpayer investing in a community solar project is generally entitled to the Section 25D ITC so long as: (1) the community solar project provides power to the taxpayer’s local utility, (2) the utility provides a credit for the taxpayer’s allocated energy production of the entire project, and (3) the taxpayer’s allocable share is not in excess of its residential needs.

Impact

It is important to note PLRs only apply to the individual taxpayer requesting the ruling and may not be cited or relied upon as precedent by other taxpayers. That said, PLRs provide valuable insight to the IRS’s views on a particular matter, and we expect that this PLR should incentivize investment in community solar and lead to even further expansion in the market. Until now, the market has been primarily driven by tax equity investors claiming the Section 48 ITC and depreciation, however, this PLR opens up opportunities for homeowners who cannot install solar systems for various reasons to invest in community solar.

Article By David B. Weisblat & Kurt R. Rempe of Foley & Lardner LLP
© 2015 Foley & Lardner LLP

Study: Diluted Bitumen Poses No Greater Risk of Release from Pipelines than Conventional Crude Oil

Barnes & Thornburg

A new study released June 25, 2013, has found that diluted bitumen – a thick blend of Canadian crude oil derived from oil sands, a/k/a “dilbit” – presents no heightened risks of transport through pipelines in comparison to other types of crude oil. The study, conducted by the National Academy of Sciences (NAS) and sponsored by the Pipeline and Hazardous Materials Safety Administration (PHMSA), comes in the wake of a Congressional mandate to study whether the pipeline transportation of dilbit carries an increased risk of release (no doubt relative to consideration of the Keystone XL Pipeline project).

Opponents of pipeline transmission of dilbit have claimed that dilbit is more corrosive to pipelines than conventional crude oil and is therefore more prone to cause a pipeline failure and oil release. However, the new NAS study “did not find any causes of pipeline failure unique to the transportation of diluted bitumen” nor did it “find evidence of chemical or physical properties of diluted bitumen that are outside the range of other crude oils or any other aspect of its transportation by transmission pipeline that would make diluted bitumen more likely than other crude oils to cause releases.” Specifically, the NAS study’s three key findings are:

  1. Diluted bitumen does not have unique or extreme properties that make it more likely than other crude oils to cause internal damage to transmission pipelines from corrosion or erosion.
  2. Diluted bitumen does not have properties that make it more likely than other crude oils to cause damage to transmission pipelines from external corrosion and cracking or from mechanical forces.
  3. Pipeline operations and maintenance practices are the same for shipments of diluted bitumen as for shipments of other crude oils.

Committee for a Study of Pipeline Transportation of Diluted Bitumen, et. al., “TRB Special Report 311: Effects of Diluted Bitumen on Crude Oil Transmission Pipelines” (2013).

The study’s release comes on the heels of a petition to initiate rulemaking by a coalition of environmental groups urging the PHMSA and EPA to enact a host of sweeping pipeline regulations for dilbit. The Petition of Appalachian Mountain Club, et al., filed with the PHMSA and EPA on March 26, 2013, argued that dilbit should be regulated differently than other crude oils because it is more volatile and corrosive than conventional crude. The environmental groups urged the agencies to adopt regulations that would create significant economic and operational burdens on dilbit pipeline operators.

The study seemingly supports pipeline operators’ interests in the face of the Appalachian Mountain Club petition. For instance, many of the proposals are premised on the assumption that dilbit is more corrosive than conventional crude oil. Such proposals include the imposition of stricter safety standards, more burdensome reporting requirements, and rigorous pre-operation reviews unique to pipelines carrying dilbit. Also, the petition proposed a moratorium on expanding any transportation of dilbit until such regulations were imposed. Now, with credible scientific evidence pointing to no increased risk of pipeline releases associated with dilbit, these proposals likely face an uphill battle.

Additionally, the study comes at a crucial time for supporters of the proposed Keystone XL Pipeline, as the federal government is expected to make a decision on the project’s next phase as early as this summer. The Obama Administration has delayed approval of the project over those same concerns that dilbit is inherently more corrosive than conventional crudes, among other reasons. The study will strengthen Keystone advocates’ arguments that the 1,700-mile pipeline will be advantageous for the economy while posing no greater risk of release than a conventional crude oil pipeline.

However, some questions remain. Environmental groups are quick to point out that the study did not examine the potential differences in the environmental impact of a release involving dilbit compared to the release of conventional crude. Instead, the study only concerned a dilbit pipeline’s probability of failure, not the environmental consequences associated with a dilbit release. A finding that dilbit presents heightened environmental risks if released could reignite the push to regulate dilbit more aggressively, although PHMSA has not commissioned a study of dilbit’s environmental risks at this time. Still, for pipeline operators, the study provides strong support that dilbit pipelines do not require distinct regulatory scrutiny and can be protected by industry-standard integrity management programs.

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IRS Defends Discretion to Withhold Section 1256 Exchange Designation for ISOs

Recently posted at the National Law Review by William R. Pomierski of  McDermott Will & Emery an article about the IRS defending its decision not to designate independent system operators as qualified board or exchange:

The IRS defended its decision not to designate independent system operators asqualified board or exchange (QBE) principally on the grounds that, as a matter of law, it is not required to designate any exchanges as QBEs under Category 3 of Section 1256 Contracts.

In Sesco Enterprises, LLC (Civ. No. 10-1470, D.N.J. Nov. 16, 2010), the Internal Revenue Service (IRS) defended its discretion to refrain from extending qualified board or exchange status under Code Section 1256 to U.S. Federal Energy Regulatory Commission (FERC)-regulated independent system operators.  The district court dismissed the taxpayer’s claim that the IRS acted arbitrarily and capriciously when it refused to classify electricity derivatives that traded on independent system operators as “Section 1256 Contracts.

Section 1256 Contracts in General

For federal income tax purposes, a limited number of derivative contracts are classified as Section 1256 Contracts.   Absent an exception, Section 1256 Contracts are subject to mark-to-market tax accounting and the 60/40 rule.  The 60/40 rule characterizes 60 percent of the net gain or loss from a Section 1256 Contract as long-term and 40 percent as short-term capital gain or loss.  Corporate taxpayers often view Section 1256 Contracts as tax disadvantageous, relative to economically similar derivatives that are not taxed as Section 1256 Contracts, such as swaps, unless the business hedging or some other exception is available.

Section 1256 Contract classification is limited to regulated futures contracts, foreign currency contracts, nonequity options, dealer equity options and dealer securities futures contracts, as each is defined in the Internal Revenue Code.   Unless a derivative falls within one of these categories, it is not a Section 1256 Contract, regardless of its economic similarity to a Section 1256 Contract.

Except for foreign currency contracts, Section 1256 Contracts are limited to derivative positions that trade on or are subject to the rules of a qualified board or exchange (or QBE).  QBE status is extended only to national securities exchanges registered with the U.S. Securities and Exchange Commission (SEC) (a Category 1 Exchange); domestic boards of trade designated as contract markets by the U.S. Commodities Futures Trading Commission (CFTC) (a Category 2 Exchange); orany other exchange, board of trade or other market that the Secretary of the Treasury Department determines has rules adequate to carry out the purposes of Code Section 1256 (a Category 3 Exchange).

Category 1 and Category 2 Exchange status is automatic.   Category 3 Exchange status, however, requires a determination by the IRS.  In recent years, Category 3 Exchange designation has been extended to four non-U.S. futures exchanges offering products in the United States: ICE Futures (UK), Dubai Mercantile Exchange, ICE Futures (Canada) and LIFFE (UK).

Sesco Challenges IRS Discretion to Withhold Category 3 Exchange Designation

According to its website, the taxpayer in Sesco (Taxpayer) is an electricity and natural gas trading company. The facts of the case indicate that it traded electricity derivatives (presumably INCs, DECs, Virtuals and/or FTRs) on various independent system operators or regional transmission organizations regulated by the FERC (collectively, ISOs).  Because ISOs are not regulated by the SEC or the CFTC, they cannot be considered Category 1 or Category 2 Exchanges for purposes of Code Section 1256.  To date, no ISO has been designated as a Category 3 Exchange by the IRS.

According to the facts in Sesco, the Taxpayer took the position on its return that derivatives trading on ISOs were Section 1256 Contracts eligible for 60/40 capital treatment.  The IRS denied Section 1256 Contract status on audit.  Somewhat surprisingly, a footnote in Sesco suggests, without any further discussion, that the IRS agreed with the Taxpayer’s position that these electricity derivatives qualified as “regulated futures contracts” under Code Section 1256 except for satisfying the QBE requirement.

During the examination process, the Taxpayer apparently requested a private letter ruling from the IRS that the relevant ISOs were Category 3 Exchanges.   According to the district court, “The IRS refused, asserting that the request for a QBE determination must be made by the exchange itself.”  The Taxpayer then asked one of the ISOs to request Category 3 Exchange status, but the ISO declined to do so.  Taxpayer then filed suit challenging the IRS’s adjustments and asserted that the IRS “acted arbitrarily and capriciously and abused its discretion when it refused to make a QBE determination except upon request from the ISO.”  In essence, the Taxpayer was attempting to force the IRS to designate the ISOs at issue as QBEs.

The IRS defended its decision not to designate the ISOs as QBEs principally on the grounds that, as a matter of law, it is not required to designate any exchanges as QBEs under Category 3.   After briefly considering the wording of Code Section 1256 and the relevant legislative history, the court agreed with the IRS position and dismissed the case on procedural grounds (lack of jurisdiction).

Observations

Although the District Court’s decision in Sesco may be of little or no precedential value due to the procedural aspects of the case, the decision nevertheless is important in that it reflects what has long been understood to be the IRS’ position regarding Category 3 Exchange status, which is that Category 3 Exchange status is not automatic and requires a formal determination by the IRS.  Sesco also confirms that the IRS believes QBE classification can only be requested by the exchange at issue, not by exchange participants.

Unfortunately, Sesco does not address the separate question of whether the IRS could have unilaterally designated the ISOs at issue as QBEs without the participation of the exchanges.  Sesco also raises, but does not address, the issue of whether derivatives traded on exchanges that are not “futures” exchange can be considered “regulated futures contracts” for purposes of Code Section 1256.  These are critical questions that will become more relevant in the near future as the exchange-trading and exchange-clearing requirements imposed by the Dodd-Frank derivatives reform legislation begin to take effect.

© 2011 McDermott Will & Emery