Category: Energy Law

Historic Worldwide Deal Ends Oil Price War

Oil-producing nations around the world reached an unprecedented agreement over the weekend that will cut world oil output by nearly 10 percent in an effort to end the devastating price war waged worldwide this year over the price of oil. That price war had threatened to break the so-called OPEC+ alliance between members of the Organization of Petroleum Exporting Countries (OPEC), including Saudi Arabia and Iraq, and allied producer states such as Russia and Mexico; just a few weeks ago, that partnership appeared to be on life support.

But now, a deal has been struck between the OPEC+ nations and other leading producer nations, including the United States, Canada, and Brazil, under which OPEC+ nations will cut production by 9.7 million barrels a day, while the non-OPEC+ nations will consider, but have not committed to, further cuts in production. Talks had reportedly stalled at times over the last seven days, but the involvement of the non-OPEC+ nations in the agreement showed the lengths to which producer nations were willing to go to end the oil price war and is politically significant since nations like the United States have historically criticized OPEC+ production policies.

© Steptoe & Johnson PLLC. All Rights Reserved.

“Damaged Goods” Not Enough to Sway Third Circuit Court of Appeals

In early February, the Third Circuit Court of Appeals rejected the “damaged goods” approach to valuing property crossed by a pipeline. In UGI Sunbury LLC v. A Permanent Easement For 1.7575 Acres et al., the appeals court vacated the trial court’s property valuation that was based on an expert’s opinion that the stigma of a natural gas pipeline decreased the value of the property crossed by the pipeline.

The expert largely based his opinion on anecdotes from his past employment in an appliance shop where he noticed customers valued undamaged property more than damaged property. Under his “damaged goods” theory, the expert opined that property under which a pipeline crosses has a lower value because people perceive it as damaged. The panel held that the expert’s methodology was incapable of testing, had not been peer reviewed, was not generally accepted, and did not provide for a rate of error. While an expert’s opinion does not have to meet all, or even most, of those factors, the fact that this expert’s opinion met none left his opinion unreliable.

The panel noted that parts of the expert’s opinion compared the value of properties impacted by oil spills or the radiation emitted from the Three-Mile Island nuclear disaster. Those properties were figurative oranges to the apples and thus incapable of assisting the trier of fact in concluding the impact to the value of property under which a natural gas pipeline crosses.

Finally, the Third Circuit held that the district court must act as “gatekeeper” and ensure that expert opinions are based on reliable science.

© Steptoe & Johnson PLLC. All Rights Reserved.

For more on property valuation, see the National Law Review Real Estate law section.

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.

Predicting Old Man Winter and Energy Outlooks: Is it Anyone’s Guess?

Whether we have a strong winter impacts many things.  From our road conditions driving to work, the extent of demand for home heating fuels, how our livestock will fair, and our ski season (including vital tourist revenue that results from ski season), predicting the degree of the intensity of the winter season can be important.

But this year it looks like it could be anyone’s guess…some degree of certainty would be nice, as it can have a major impact on energy forecasts as well.  For example, natural gas and propane demand.

The U.S. Energy Information Administration (“EIA”) released its Short-Term Energy Outlook (“STEO”) earlier this month, which can be found here.  The October STEO contains a lot of interesting information, including, but not limited to, that the “EIA expects downward oil price pressure to emerge in the coming months as global oil inventories rise during the first half of 2020.”

However, what really caught my eye in the October STEO was the EIA’s prediction as to the upcoming winter.

In my neck of the woods, cattle ranchers are bracing for a big winter – folks are beefing up (pun intended) winter structures in their pastures to give their cows some protection from intense snow storms, and old timers are warning to push calving season later this year to avoid calves being born during the worst of the early spring snow storms.  Many people in my home state of Wyoming have already buttoned up their summer homes in the mountains and have had snowfall since the beginning of the month.  According to The Weather Channel article entitled, It’s a Record-Snowy Start For the Northern Rockies and Plains and Winter Is Still Over 2 Months Away, some areas have already been pounded by record-dumping snowstorms.

In fact, The Old Farmer’s Almanac similarly predicts in its winter 2019-2020 forecast, which can be found here, “below-normal winter temperatures” through most of the U.S. coupled with significant snowfall.  The 2020 Old Farmer’s Almanac predicts a “snow-verload” of “frequent snow events – from flurries to no fewer than seven big snowstorms coast to coast, including two in April for the Intermountain region west of the Rockies.”

The October STEO takes a different stance – The EIA forecast as to the winter fuels outlook is based upon a mild winter.  Indeed, the October STEO provides the following winter fuels outlook:

  • “The [EIA] forecasts that average household expenditures for all major home heating fuels will decrease this winter compared with the last.  This forecast largely reflects warmer expected winter temperatures compared with last winter.”

The National Oceanic and Atmospheric Administration (“NOAA”) also released the following prediction:  Winter Outlook: Warmer than average for many, wetter in the North, which forecasts “warmer-than-average temperatures…for much of the U.S. this winter.”  NOAA predicts that “[n]o part of the U.S. is favored to have below-average temperatures this winter.”

The Weather Channel seems to take the middle road in its forecast entitled, Winter 2019-20 Will Likely Be Warmer Than Average in Southern U.S. & Colder Than Average in Parts of Northern Tier, and also includes the following disclaimer: “Given some of the conflicting factors listed above, this forecast will likely change, so be sure to check back to weather.com for updates.”

What will this winter be like and what will the weather’s impact be on the domestic energy outlook?  It is anyone’s guess!

© Steptoe & Johnson PLLC. All Rights Reserved.

For more on the energy industry, see the National Law Review Environmental, Energy & Resources law page.

U.S. Department of Energy Withdraws Expanded General Service Lamp Definition and Refuses to Impose Backstop Efficiency Standard

On September 5, 2019, the U.S. Department of Energy (DOE) published a final rule and proposed rule regarding general service lamps and general service incandescent lamps with far-reaching implications for lamp manufacturers and retailers. DOE is withdrawing the Obama Administration’s revised definitions of general service lamps and general service incandescent lamps, which would have imposed federal efficiency standards on a wide array of lamps. DOE also asserts in the new rule that it has not triggered a statutory “backstop” efficiency standard, which would have prohibited the sale of all non-compliant lamps beginning January 1, 2020. In a separate proposed rule, DOE has initially determined that energy conservation standards for general service incandescent lamps are not justified. DOE’s decisions, which stall what was to be an accelerated transition away from incandescents and toward LEDs, will likely prompt a legal challenge by consumer and environmental groups, as well as a number of states and other interested stakeholders.

Background

As defined by Congress in the Energy Policy and Conservation Act of 1975 (EPCA), general service incandescent lamps (GSILs) are any “standard incandescent or halogen type lamp . . . intended for general service applications,” that “has a medium screw base,” that fits within statutorily defined lumen and operating voltage ranges, and that is not one of twenty-two exempted lamp types. General service lamps (GSLs), in turn, are GSILs or “any other lamps that the Secretary [of Energy] determines are used to satisfy lighting applications traditionally served by general service incandescent lamps.” With the Energy Independence and Security Act of 2007 (EISA), Congress directed DOE to initiate rulemaking procedures to determine whether efficiency standards for GSLs should be amended to be “more stringent” than those that currently apply to fluorescent lamps and incandescent reflector lamps and whether existing exemptions for “certain incandescent lamps should be maintained or discontinued.”

The EISA sought to prod DOE into moving quickly to establish GSL/GSIL efficiency standards. First, Congress provided that if DOE “determines that the standards in effect for general service incandescent lamps should be amended, the Secretary shall publish a final rule not later than” January 1, 2017. Second, Congress included a “backstop” measure: if the Secretary of Energy “fails to complete a rulemaking” as directed, “the Secretary shall prohibit the sale of any general service lamp that does not meet a minimum efficacy standard of 45 lumens per watt,” effective January 1, 2020. The 45-lumen standard is generally understood to be unachievable for many incandescents, and would, therefore, hasten an ongoing transition to LED lamps. The backstop standard is also unusual to the extent that it would apply as a prohibition on sale, while most other appliance and equipment standards enforced by DOE apply to import and manufacture, rather than sale. As a result, the backstop not only impacts lamp manufacturers, but also the retailers who market such lamps.

The Obama Administration in January 2017 promulgated final rules revising the GSL and GSIL definitions to no longer exempt five categories of specialty incandescent lamps (rough service lamps, shatter-resistant lamps, 3-way incandescent lamps, high lumen incandescent lamps, and vibration service lamps), incandescent reflector lamps, or a variety of decorative lamps (T-Shape, B, BA, CA, F, G16-1/2, G25, G30, S, M-14, and candelabra base lamps). Effective January 1, 2020, these lamp categories would be subject to the relevant efficiency standards. The Obama Administration, however, did not initiate rulemaking with regard to the efficiency standards themselves because an appropriations rider prevented it from doing so.

The Trump Administration’s recent move withdraws these revised definitions to maintain the current efficiency regulatory scheme. Without deciding whether or not to amend the efficiency standards themselves, DOE’s new rule prevents those standards from applying to the specialty, decorative, and reflector lamps identified under the earlier rule. Some commenters argue that the new rule violates the EPCA’s “anti-backsliding” provision, while DOE asserts that the provision applies only to efficiency standards and not to the categories to which those standards apply.

Regulatory Uncertainty Regarding “Backstop” Standards

With the new rule, DOE concludes that the backstop will not take effect on January 1 and so will not prohibit the sale of GSLs not meeting the 45 lumens per watt standard. DOE agreed with electrical and lighting trade associations and manufacturers that the backstop would only be triggered if DOE had actually determined to maintain, amend, or eliminate GSL and GSIL efficiency standards but failed to do so, whereas to date, DOE had determined only to maintain the currently effective list of exemptions from the GSL and GSIL definitions. Additionally, DOE states that the backstop is not self-executing but rather requires the Secretary to take action to prohibit the sale of less efficient lamps. DOE asserts that this interpretation of the backstop provision prevents the Secretary of Energy from having to enforce a more stringent efficiency standard that he has not yet determined to be necessary or unnecessary.

A variety of environmental commenters, utility companies, and state attorneys general disagree with DOE’s reading and argue that, without further action, the backstop provision will indeed be triggered on January 1, 2020, because DOE has “fail[ed] to complete” the congressionally directed rulemaking to determine the need for amended efficiency standards. These commenters argue that the backstop is self-executing and requires no further DOE action to go into effect.

Preemption

In recent years, states have begun to enact their own lamp efficiency standards in line with the Obama Administration’s proposal and Congress’ “backstop” standard, in part out of concern that DOE might seek to delay or reverse the federal standard. More states are likely to do so in light of DOE’s latest move, creating the possibility that lamp manufacturers, importers, and retailers will have to navigate a patchwork of state regulations. Such state regulations will likely be subject to litigation, as DOE asserts that even though it has not yet promulgated an efficiency standard, state standards for covered products are preempted.

Next Steps

DOE’s withdrawal of the revised GSL/GSIL definitions or its interpretation of the backstop provision has not yet prompted a legal challenge. Some environmental advocates, however, have raised the possibility of bringing suit to force implementation of the lamp efficiency standards.

 

© 2019 Beveridge & Diamond PC

ARTICLE BY Daniel A. Eisenberg and Jack Zietman of Beveridge & Diamond PC.

Politics Trumps Economics? Trump’s Revocation of California’s Waiver Under the Clean Air Act

Today President Trump announced on Twitter that the U.S. was revoking California’s waiver under the Clean Air Act (CAA) which allowed it to impose stricter tailpipe emission standards than the federal ones. California’s Governor Newsom and Attorney General Becerra immediately announced that the state would file suit to challenge the revocation.

While the revocation has been characterized as an immediate rollback, the federal corporate average fuel economy (CAFE) standards[1] established under the previous administration, which are consistent with California’s, remain in place. Last year the Trump administration proposed to rollback those standards, freezing the efficiency and emission rules in 2021 and canceling further increases in stringency set through 2028. The final rule has not yet been issued. It is rumored that it will not be, as the administrative record supporting it has many problems and most acknowledge that it faces significant legal hurdles.

A little historical context is helpful. California began regulating tailpipe emissions in the 1960’s under then-Governor Reagan to combat air pollution. When the CAA was signed by President Nixon in 1970 it included a provision, Section 209, that allows California to establish stricter standards by obtaining a waiver of the normal federal preemption rules from U.S. Environmental Protection Agency (EPA). Once granted, other states then can adopt California’s standards. Thirteen states and the District of Columbia have adopted California’s current standards.

For 30 years, under both Republican and Democratic administrations, Section 209 waivers to combat air pollution were routinely granted. In April 2007, the U.S. Supreme Court decided Massachusetts v. EPA, 549 U.S. 497 (2007), ruling that greenhouse gases (GHGs) are pollutants under the CAA. In December 2007, the Bush administration denied California’s request for a waiver to impose tailpipe emission standards aimed at reducing GHGs. California promptly sued in January 2008, joined by 11 other states. That case was pending before the U.S. Supreme Court when President Obama took office. In 2009, the parties settled the case before the Court issued its decision, and in 2010 the U.S. and California reached an agreement that aligned the state and federal standards. Those standards were subsequently expanded and a new waiver was granted in January 2013. It is that waiver that is now being revoked.

While litigation is inherently uncertain, it appears that California has a good case for challenging the revocation. Not only is the revocation unprecedented, there is no provision in the CAA providing for it. Section 209 only establishes the criteria for granting a waiver; it’s silent as to revocation. In 2013, the U.S. determined that the criteria for the waiver had been met, and both the states and the industry have acted in reliance on that determination for more than 6 years. The U.S. has also asserted that the federal Energy Policy and Conservation Act (EPCA) preempts California’s standards. However, in Massachusetts v. EPA, the Supreme Court ruled that EPCA does not displace EPA’s authority to regulate GHGs, and courts subsequently have extended that rationale to hold that EPCA does not preempt states’ regulation of GHGs under the waiver.

Just as it was in the late aughts, the automobile industry has been put in an extremely difficult position by this dispute. California has the 5th largest economy in the world, and when one adds in the 13 other states that have adopted its standards – states like New York and Pennsylvania – that equates to a large segment of the auto market. Having to produce vehicles to meet two different sets of emission standards would be extremely costly. The industry desperately needs regulatory certainty. Reflecting this, in June, 17 automakers sent a letter to President Trump calling for one national standard that included California, and in July, four automakers reached an agreement of sorts with California on emission standards.

Instead of the regulatory certainty that is needed for the economy to operate efficiently, it appears that this dispute will move into a phase of protracted litigation and years of regulatory uncertainty. The dispute may be good politics for those that want to motivate their base on each side, both Republicans in Washington D.C. and Democrats in Sacramento, but it is pretty clearly bad economics.

[1]   CAFE is, essentially, the average fuel efficiency of an automaker’s fleet of vehicles.

Copyright © 2019, Sheppard Mullin Richter & Hampton LLP.

For more on the Clean Air Act, see the National Law Review Environmental, Energy & Resources law page.

Commercial PACE Works: National Study Shows Only One Default Out of 1,870 Deals

A recent study by the US Department of Energy’s Lawrence Berkeley National Lab shows that commercial property assessed clean energy loans (PACE) are growing in popularity and are a good bet for lenders and property owners. Through 2017, projects worth $887 million have been completed, creating more than 13,000 jobs.1 The study found just one default on a PACE loan out of 1,870 deals nationwide since 2008.2

PACE is an innovative program that enables property owners to obtain low-cost, long-term loans for energy efficiency, renewable energy, and water conservation improvements. Projects financed using PACE can generate positive cash flow upon completion with no up-front, out-of-pocket cost to property owners—eliminating the financial barriers that typically prevent investment in revitalizing aging properties. The term of a PACE Financing may extend up to the useful life of the improvement, which may be as high as 20 years or more, and can result in cost savings that exceed the amount of the PACE financing. The result is improved business profitability, an increase in property value, and enhanced sustainability. PACE financing is also available for new construction under Wisconsin law.

Along with the Wisconsin Counties Association, Slipstream and other partners, von Briesen had a leadership role in creating PACE Wisconsin, a joint powers commission comprising a consortium of Wisconsin counties. von Briesen’s vision of a uniform PACE program throughout the state was implemented through creation of a joint powers commission open to any county that wishes to join. PACE is now available in 43 Wisconsin counties, representing 85% of the state’s population.

The recent PACE study also showed that most jurisdictions adopting PACE programs are using a model similar to the one adopted in Wisconsin, because it is easy for local governments to administer.3 Midwestern states are leading the way in expanding PACE. Wisconsin now ranks 11th in PACE financing deals completed, according to PACENation data through 2017.4 In 2019 PACE Wisconsin closed an $8.8 million deal on a historic hotel renovation in Green Bay, financed with a taxable bond offering by the Public Finance Authority. PACE Wisconsin has $15 million in total closings so far in 2019, and over $10 million in the pipeline for the rest of the year.

PACE Wisconsin has registered more than 80 contracting firms that are ready to make buildings more efficient and more comfortable, and has 17 capital providers available to finance building upgrades and new construction. PACE Wisconsin is also supporting legislation to improve the program by reducing paperwork requirements and making financing available for electric vehicle charging equipment. More information about PACE Wisconsin can be found on its website, www.pacewi.org.

1 PACE Market Data, PACENation website, https://pacenation.us/pace-market-data/(accessed August 4, 2019)
2 Commercial PACE Financing and the Special Assessment Process: Understanding Roles and Managing Risks for Local Governments, Greg Leventis and Lisa Schwartz, Lawrence Berkeley National Laboratory, June 2019, http://eta-publications.lbl.gov/sites/default/files/final_cpace_brief_1_ 112308-74205-eere-c-pace-report-arevalo-fz.pdf (accessed August 4, 2019).
3 Commercial PACE Financing and the Special Assessment Process: Understanding Roles and Managing Risks for Local Governments, Greg Leventis and Lisa Schwartz, Lawrence Berkeley National Laboratory, June 2019, http://eta-publications.lbl.gov/sites/default/files/final_cpace_brief_1 _112308-74205-eere-c-pace-report-arevalo-fz.pdf (accessed August 4, 2019).
4 Study: Nonpayment risk remote for commercial clean energy loans, Frank Jossi, Midwest Energy News, July 31, 2019, https://energynews.us/2019/07/31/national/study-nonpayment-risk-remote-for-commercial-clean-energy-loans/ (accessed August 4, 2019) (citing PACE Market Data, PACENation website, https://pacenation.us/pace-market-data/ (accessed August 4, 2019)).

©2019 von Briesen & Roper, s.c

Executive Orders Aim to Streamline Energy Infrastructure Projects

On April 10, 2019, President Trump signed two executive orders intended to address a range of legal and procedural hurdles commonly facing infrastructure projects, particularly in the energy sector. Most notably, the executive orders require the U.S. Environmental Protection Agency (EPA) to review and revise Section 401 water quality certification procedures and increase the president’s direct role in permitting cross-border projects.

In recent years, states and tribes have increasingly utilized Section 401 of the Clean Water Act, 33 U.S.C. § 1341, to delay, condition, or deny permits and licenses for projects within their borders that may violate established water quality standards. Executive Order 13868 directs EPA to review these water quality certification procedures in consultation with states, tribes, and other federal agencies, with a focus on:

    • Promoting federal-state cooperation.
    • Clarifying the appropriate scope of water quality reviews.
    • Identifying appropriate conditions for certifications.
    • Establishing reasonable review times for certifications.
    • Delineating the nature and scope of information that states and tribes may need in acting promptly on a certification request.

The executive order contemplates several forthcoming EPA actions with aggressive deadlines. Within 60 days, EPA must issue new water quality certification guidance to states, tribes, and federal agencies. Within 120 days, EPA must publish a proposed rule revising the existing regulations that implement Section 401. Other federal agencies that issue permits or licenses subject to Section 401 certification requirements must then revise their regulations and guidance to conform to EPA’s actions. These actions will afford numerous commenting opportunities and, given the executive order’s focus on “Promoting Energy Infrastructure,” the agencies likely will be interested in specific ideas, experiences, and feedback of project proponents.

Executive Order 13868 is not limited to Section 401. It further directs the U.S. Department of Transportation (DOT) to propose a rule newly allowing transport of liquefied natural gas (LNG) in rail tank cars. DOT must also revise its safety regulations for LNG facilities to reflect modern industry practices. Additionally, the executive order calls for scrutiny of retirement funds’ divestments from the energy sector. It also aims to facilitate renewals and reauthorizations of energy rights-of-way and similar authorizations. Lastly, it seeks information from agencies on barriers to a national energy market, intergovernmental assistance, and opportunities for economic growth in the Appalachian region.

Executive Order 13867 aims to end the multi-year reviews of cross-border infrastructure, such as pipelines and bridges, principally administered by the State Department. These projects have attracted national attention and controversy, as well as litigation. The Secretary of State will continue to receive all applications for such cross-border projects but will face a highly aggressive 60-day deadline to complete its review and provide recommendations to the president for a final permitting decision. The executive order stipulates that the State Department must revise its regulations to reflect these requirements by May 29, 2020. Because presidential actions are not subject to National Environmental Policy Act (NEPA) review, and to meet the tight deadline, such projects might undergo less review than they do today, which in turn may foster more litigation.

Overall, these executive orders afford opportunities to reduce barriers to energy infrastructure projects and improve the efficiency of the permitting process. Whether they yield tangible results remains to be seen. The substantive details and any legal challenges will emerge through the various agency actions implementing these executive orders, which the regulated community should follow and closely participate in.

 

© 2019 Beveridge & Diamond PC.

Three Strategies to Develop Renewable Energy Projects on Potentially Contaminated Lands

Developing renewable energy on contaminated lands has proven to be both effective and cost-effective for companies pursuing a new solar or wind energy project. The utility-scale solar farm constructed on the 120-acre Reilly Tar & Chemical Corporation Superfund site is a great example, and there are thousands more that are ripe for redevelopment.

Renewable energy continues to grow in volume and importance in the U.S. as corporations drive demand for sustainable energy, with 166 companies to date committing to go 100 percent renewable as part of a global initiative called RE100. At the same time, states and local governments are driving policy that prioritizes sustainable energy development. Two recent Illinois bills, the Path to 100 Act (HB 2966/SB1781) and Clean Energy Jobs Act (HB3624/SB2132), seek to incentivize the development of new renewable energy and move the state to 100 percent renewable energy by 2050. Other states, including California, New Jersey, New York, and Wisconsin, have called for or passed similar laws.

Using Superfund sites, brownfields, retired power plants, and landfills offers potential benefits to developers and community stakeholders:

  • Preserve Open Space: Large-scale renewable energy facilities – often called “utility scale” projects – can require a lot of land that may displace or impact agricultural lands, open space, or other “greenspace.” Developing renewable energy on potentially contaminated properties can help to preserve the “greenspace” while returning blighted lands to sustainable and productive use.

  • Lower Costs and Shorter Timeline: Developers can significantly lower costs and timelines because contaminated sites are usually already served by existing infrastructure, like substations, power lines, and roads, which would otherwise need to be constructed. Streamlined permitting and zoning can also reduce costs and timelines because potentially contaminated property is often already zoned for industrial or commercial use, which likely poses fewer obstacles to constructing renewable energy structures. Decreased land costs, programs for the procurement of renewable energy credits generated from developing renewable energy projects on brownfields or potentially contaminated properties, and federal and state brownfield tax incentives can drive costs down even further.

  • Greater Community Support: Communities may be quicker to get behind renewable energy projects that are sited on potentially contaminated lands because, rather than taking agricultural land out of production, the projects can clean up the otherwise abandoned sites, boost surrounding property values, increase tax revenues, and provide low-cost clean power.

Despite these benefits, developers often build renewable energy facilities on greenspaces rather than brownfields because of concerns related to potential liabilities or contamination. Below are three strategies that developers can use to move past those concerns and develop a successful renewable energy project on potentially contaminated lands.

  1. Screen Sites for Renewable Energy Potential

Screen potentially contaminated properties to see whether they’d be a good fit for your renewable energy project. For example, confirm that a property has enough usable space and is close enough to transmission or distribution lines to support development. Determine whether a site is free from land-use restrictions that would preclude the use of your chosen renewable energy. Ensure the community doesn’t already have a plan in mind to redevelop the property you’re assessing. And inspect the property for evidence of potential contamination, like soil surface staining or debris stockpiles. If a site has not yet been assessed, you will need to investigate the site to determine whether redevelopment is appropriate. To help, the EPA has published guidance to assist prospective developers in screening prospective sites for solar and wind projects on potentially contaminated lands.

  1. Coordinate the Cleanup and Renewable Energy Development

Developing renewable energy can occur at any stage of a property cleanup, from site inspection and preliminary assessment to post-construction completion. However, identifying and coming to a site at the beginning of or early on in the cleanup process has its advantages. It allows you to engage the community and other stakeholders, including potentially responsible parties, from the start of the redevelopment. It also allows you to coordinate and integrate the cleanup and renewable energy development decisions. For example, you can work with the governmental agency overseeing the site to fold renewable energy design requirements into the remedial design, rather than having to construct renewable energy structures on top of and around the completed remedy. Getting in early will ensure that the renewable energy project is compatible with the remedial design, institutional controls, monitoring activities, and engineering controls.

  1. Protect Yourself from Liability Exposure

Many prospective developers, purchasers, and lenders stay away from or tread cautiously around building on contaminated properties for fear of liability under federal or state cleanup laws. However, many state cleanup programs provide liability protections for new owners or lessees, like a developer, who are not responsible for prior contamination at a site. The federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) also generally limits EPA enforcement at certain qualifying brownfield sites, known as “eligible response sites”, where a party is conducting a response action in compliance with a state cleanup response program. Contact a lawyer and work with state government early on in the process to see what liability protections are available to you and how to qualify.

Other contaminated properties may be addressed under the CERCLA cleanup program. CERCLA has several self-implementing liability protections for developers and the like who acquire contaminated property but did not cause the contamination, including a protection for “bona fide prospective purchasers.” Ensure that you take the required steps to qualify for the BFPP protection, which will include, among other things, working with an environmental consultant to conduct “all appropriate inquiries” through a Phase I environmental site assessment. CERCLA can also offer liability protections for people who lease contaminated properties.

 

© 2019 Schiff Hardin LLP
This post was written by Alex Garel-Frantzen and Amy Antoniolli of Schiff Hardin LLP.

Sixth Circuit Compels Arbitration in Putative Class Action between Shell Oil and Ohio Landowners

Plaintiff entered into a lease agreement with Defendants (Shell Oil entities) governing extraction of oil and gas from his five-acre property located in Guernsey County, Ohio. The agreement provided a signing bonus to Plaintiff of $5,000 per acre, contingent upon Shell’s timely verification that he possessed good title to the property. The lease also contained a broad arbitration clause providing that any dispute under the lease was to be resolved by binding arbitration. Plaintiff brought suit, individually and on behalf of other landowners having similar contracts with Shell, for breach of contract after Shell allegedly failed to pay the signing bonus. The District Court for the Southern District of Ohio subsequently denied Shell’s motion to compel arbitration, and Shell appealed.

The Sixth Circuit reversed and remanded, compelling arbitration and a directing the district court to decide whether the lease allowed for class-wide arbitration. The panel found that the district court failed to address the threshold issue of who decides arbitrability and further reasoned that Plaintiff did not attack the enforceability of the “specific arbitration clause” but rather “argued that much of the contract, which happens to include the arbitration clause, is unenforceable.” In so finding, the panel determined that the arbitration clause was triggered at signing, leading to the applicability of the severability doctrine and the determination that an arbitrator must consider the issue first. As to the class-wide arbitration question, the Panel reasoned that because the parties did not identify a provision in the contract that clearly and unmistakably gave the arbitrator the power to decide the matter, and in light of “the importance of this issue to the case, given that the class could include hundreds of Ohio landowners,” that question would be for the district court to decide upon remand. In a dissenting opinion, Judge Moore opined that the district court was the proper body to decide whether the dispute should be arbitrated in light of the lease agreement’s two distinct triggering events – the signing of the agreement and the payment of the bonus. As such, Judge Moore opined that only after payment of the bonus would the arbitration clause apply.

Rogers v. Swepi LP, No. 18-3229 (6th Cir. Dec. 10, 2018).

 

©2011-2019 Carlton Fields Jorden Burt, P.A.
Read more about Oil and Gas lease agreements on the National Law Review’s Energy and Environment Page.