54 Search Results

October 7, 2020 |
33 Gibson Dunn Partners Recognized in Banking, Finance and Transactional Expert Guide

Expert Guides has named 33 Gibson Dunn partners to the 2020 edition of its Banking, Finance and Transactional Guide, which recognizes the top legal practitioners in the industry.  Selection to this guide is determined by a survey of fellow legal practitioners in more than 80 jurisdictions.  The Gibson Dunn partners included in the guide are Frankfurt partner Dirk Oberbracht, Hong Kong partners Albert Cho, John Fadely, Scott Jalowayski, Michael Nicklin, and Patricia Tan Openshaw, Houston partner Hilary Holmes, London partners Christopher Haynes and Steve Thierbach, Los Angeles partners Jennifer Bellah Maguire, Dennis Arnold and Robert Klyman, New York partners Barbara BeckerAndrew Fabens, David Feldman, Dennis Friedman, Sean GriffithsShukie Grossman, Michael RosenthalRoger Singer, and Edward Sopher, Orange County partners Jonathan Layne and James Moloney, Palo Alto partner Russell Hansen, San Francisco partners Stewart McDowell, Robert Nelson and Douglas Smith, Singapore partner Brad Roach, and Washington, D.C. partners Mark Director, Stephen Glover, Elizabeth Ising, Brian Lane and Ronald Mueller.  The guide was published on September 21, 2020.

October 6, 2020 |
Shalla Prichard Named Among 50 Most Powerful Women in Oil and Gas

The National Diversity Council named Houston partner Shalla Prichard among the 50 Most Powerful Women in Oil and Gas.  The list was published on October 6, 2020. Shalla Prichard represents clients who are in the upstream, midstream and downstream energy sectors, including clients in the oil and gas, private equity, chemical, pipeline and offshore drilling industries.

October 5, 2020 |
Gibson Dunn Ranked in the 2021 UK Legal 500

Gibson Dunn earned 13 practice area rankings in the 2021 edition of The Legal 500 UK. Four partners were named to Legal 500’s Hall of Fame, recognizing individuals who receive consistent feedback from their clients for continued excellence, and four other partners were named Leading Lawyers in their respective practices. The firm was recognized in the following categories:

  • Corporate and Commercial: Corporate Tax
  • Corporate and Commercial: Equity Capital Markets – Mid-High Cap
  • Corporate and Commercial: EU and Competition
  • Corporate and Commercial: M&A: upper mid-market and premium deals, £500m+
  • Dispute Resolution: Commercial Litigation: Premium
  • Dispute Resolution: International Arbitration
  • Dispute Resolution: Public International Law
  • Human Resources: Employment – Employers
  • Projects, Energy and Natural Resources: Oil and Gas
  • Public Sector: Administrative and Public Law
  • Real Estate: Commercial Property – Investment
  • Real Estate: Property Finance
  • Risk Advisory: Regulatory Investigations and Corporate Crime (advice to corporates)
Legal 500’s Hall of Fame for 2021 consists of: Steve Thierbach – Corporate and Commercial: Equity Capital Markets; Philip Rocher – Dispute Resolution: Commercial Litigation; Cyrus Benson – Dispute Resolution: International Arbitration; and Alan Samson – Real Estate: Commercial Property – Investment and Real Estate: Property Finance. The partners named as Leading Lawyers are Sandy Bhogal – Corporate and Commercial: Corporate Tax; Ali Nikpay – Corporate and Commercial: EU and Competition; Jeffrey Sullivan – Dispute Resolution: International Arbitration; and Anna Howell – Projects, Energy and Natural Resources: Oil and Gas. Benjamin Fryer has been named a Next Generation Partner for Corporate and Commercial: Corporate Tax. Additionally, Claibourne Harrison has been named a Rising Star for Real Estate: Commercial Property – Investment, and Mitasha Chandok has been named a Rising Star for Projects, Energy and Natural Resources: Oil and Gas. The guide was published on September 30, 2020. Gibson Dunn’s London office offers full-service English and U.S. law capability, including corporate, finance, dispute resolution, competition/antitrust, real estate, labor and employment, and tax.  Our lawyers advise international corporations, financial institutions, private equity funds and governments on complex and challenging transactions and disputes.

September 22, 2020 |
Thirteen Gibson Dunn Partners Recognized in Expert Guides’ Women in Business Law

Expert Guides has named 13 Gibson Dunn partners to its 2020 Guide to the World’s Leading Women in Business Law, which recognizes top female legal practitioners advising on business law. Selection to this guide is determined by a survey of fellow legal practitioners. The Gibson Dunn partners included in the guide are Hong Kong partners Kelly Austin and Patricia Tan Openshaw, London partners Anna Howell and Penny Madden, Los Angeles partners Jennifer Bellah Maguire, Catherine Conway, Ruth Fisher and Amy Forbes, New York partners Barbara Becker, Lauren Elliot and Jane Love, San Francisco partner Mary Murphy and Washington, D.C. partner Judith Alison Lee. The guide was published on September 7, 2020.

August 12, 2020 |
Who’s Who Legal 2020 Asset Recovery, Energy, and Product Liability Defence Guides Recognize Eight Gibson Dunn Partners

Eight Gibson Dunn partners were recognized in Who’s Who Legal Asset Recovery 2020, Energy 2020, and Product Liability Defence 2020 guides. Dubai partner Graham Lovett was recommended in Asset Recovery. Houston partners Michael P. Darden, Tull Florey and Hillary Holmes, London partner Anna Howell, Singapore partner Brad Roach, and Washington, D.C. partner William Scherman were recommended in Energy. New York partner Daniel Thomasch was recommended in Product Liability Defence. The Product Liability Defence guide was published on June 17, 2020; the Asset Recovery guide was published on August 3, 2020; and the Energy guide was published on August 6, 2020.

August 4, 2020 |
Navigating the Battleground State

Denver partners Beau Stark and Frederick Yarger and associate Graham Valenta are the authors of "Navigating the Battleground State," [PDF] published by Oil and Gas Investor in its August 2020 issue.

August 3, 2020 |
NEPA Review Revamp: What Developers Should Expect from the CEQ’s New Rule and the Incoming Litigation Storm-Front

Click for PDF

After 40 years without an update, the White House Council on Environmental Quality (CEQ) has recently revamped its National Environmental Policy Act (NEPA) implementing regulations.

The revised NEPA regulations were published in the Federal Register on July 16, 2020. They include both substantive and procedural changes with the stated goal of streamlining and accelerating the environmental review process federal agencies are required to conduct under NEPA. The final rulemaking is the culmination of a Trump Administration directive to the CEQ to modernize the NEPA review process,[1] and follows a proposed rulemaking published in January of this year.

The most significant aspects of the CEQ’s final rule for project developers are that the CEQ: (1) clarified which undertakings should and should not be subject to NEPA environmental analysis; (2) created new time limits for environmental assessments (EAs) and environmental impact statements (EISs); (3) eliminated the requirement to consider whether a project is “highly controversial”; (4) revamped and streamlined the environmental “effects” analysis; and (5) revised the definition of a “reasonable alternative” to limit alternatives to those that are technically and economically feasible and consistent with the goals of the applicant.

The final rule has already been challenged and more challenges, both facial and as-applied, are expected. As such, project sponsors and private parties who are working with federal and state agencies who are relying on the new regulations must weigh the time saved under the new rule against the litigation risk that all or a portion of the regulations may not survive.

Below we discuss the most significant aspects of the new rulemaking and the threat of litigation on the horizon.

Clarifying the Scope of Projects Subject to NEPA

Several elements of the CEQ’s rulemaking function to reduce the number of projects subject to NEPA review. Most notably, the CEQ attacks the long-standing “small handle” problem head-on by carving “non-Federal projects with minimal Federal funding or minimal Federal involvement” out of the definition of “major actions” subject to NEPA.[2] This revision likely excludes a broad swath of state-led infrastructure projects from NEPA review, as well as privately funded transportation projects, but the CEQ left the task of defining “minimal Federal funding” or “minimal Federal involvement” to each of the reviewing agencies.[3]

The CEQ also encourages the identification, adoption, and use of categorical NEPA exclusions for agency activities deemed to consistently have an insignificant environmental impact, in part by providing reviewing agencies the flexibility to adopt another agency’s categorical exclusions.[4]

Time Limits for Environmental Reviews

Once it is determined that a project is subject to a NEPA review, the new regulations set presumptive time limits for the completion of a NEPA environmental review: one year (following the decision to prepare the review) for an environmental assessment (EA) and two years for an environmental impact statement (EIS).[5] This represents a significant time savings: According to the CEQ, the median time required for the preparation of an EIS is currently 3.5 years,[6] and so the new limits may provide relief to many developers.

However, these time limits are merely presumptive. Reviewing agencies may extend the deadlines should they deem it necessary, considering factors such as the number of the persons and agencies affected by the action under review;[7] more complex environmental reviews may therefore continue to run beyond the time limits. Still, some have expressed concern that, should agencies strictly adhere to the time goals and consequently rush through the drafting of an EA or EIS, such reviews may be more subject to legal challenge than they otherwise would be.

Eliminates Requirement to Consider Whether Project Effects Are “Highly Controversial”

The final rule removes the requirement that agencies consider “[t]he degree to which the effects on the quality of the human environment are likely to be highly controversial” when determining whether an environmental impact is “significant.”[8] The “highly controversial” prong has itself been highly controversial; as the CEQ explains, whether a project is “highly controversial” is “subjective and is not dispositive of effects’ significance.”[9]

Revamps the Environmental Effects Analysis

NEPA requires federal agencies to consider the “adverse environmental effects” of any “major federal action” which will significantly impact the human environment.[10] For decades, NEPA implementing regulations elaborated on this statutory mandate by directing reviewing agencies to categorize and analyze a proposed federal action’s adverse environmental effects as either “direct,” “indirect,” or “cumulative.”[11]

No longer. The new rulemaking simplifies the environmental effects analysis by instructing agencies to only assess environmental impacts which are “reasonably foreseeable” and have a “reasonably close causal relationship” to the action under review.[12] This revision will enable a reviewing agency to focus its time and resources on analyzing those environmental impacts which are most likely to be significant and eliminate highly unlikely or highly attenuated potential effects.[13]

Commenters critical of this change have attacked it as a means of excluding climate change concerns from the scope of NEPA review. To address such concerns, the CEQ explains that the new effects analysis framework does not explicitly bar reviewing agencies from considering a federal action’s climate change impacts,[14] and requires agencies conducting an EIS to consider “reasonably foreseeable” environmental trends when analyzing baseline conditions at the site of a proposed project.[15] The CEQ also pulled back from its proposal that effects should not be analyzed if remote in time, geographically remote, or the result of a lengthy causal chain, adding the word “generally” before those provisions.[16]

Despite this revision, this portion of the rule is expected to be challenged, as some courts have previously invalidated agency actions for failing to take a hard look at an action’s indirect impacts or cumulative impacts on climate change.[17]

Streamlines the Definition of “Reasonable Alternatives”

Under the prior rule, agencies were often required to consider alternatives to proposed actions that were not economically feasible, that the agencies had no ability to implement due to their jurisdiction, or that were unrelated to the goal of the applicant proposing the project.[18] The new definition of a “reasonable alternative” now bounds the analysis of alternatives by limiting the definition to alternatives that are technically and economically feasible and consistent with the goals of the applicant, where applicable.[19]

The NEPA Forecast: Cloudy, with a Certainty of Litigation

Litigation storm clouds are already brewing over the nascent NEPA overhaul.

The CEQ’s final rule is set to take effect on September 14, 2020.[20] Federal agencies may continue adhering to the preexisting NEPA review procedures with respect to any reviews commenced prior to September 14,[21] but will be required to implement the revised regulations for reviews commenced after the new rule’s effective date unless there is a clear and fundamental conflict with another applicable statute.[22] Agencies have a one-year grace period to actually revise their own implementing NEPA regulations to align with the CEQ’s update.[23]

The new regulations have already been challenged in court. On July 29, 2020, two lawsuits were filed in district courts challenging the rule under the Administrative Procedures Act—one in the Western District of Virginia, brought by the Southern Environmental Law Center on behalf of seventeen wildlife groups, and another in the Northern District of California, brought by the Western Environmental Law Center and Earthjustice on a behalf of a coalition of twenty environmental justice and outdoor recreation groups.[24] The two existing lawsuits emphasize the alleged environmental harms that will be caused by the changes to the CEQ’s NEPA regulations and protest the CEQ’s alleged dismissal of many of the rule commenters’ concerns. It is expected that these or other plaintiffs will seek preliminary injunctions to delay the effective date of the new CEQ rule, arguing that alleged defects in the rule stand to cause imminent and irreparable harm.

The existing facial suits face difficult standing and ripeness headwinds, in part because NEPA’s implementing regulations are directed at federal agencies and do not take effect until at least September 14. And the flexibility agencies have to apply the preexisting environmental review procedures to pending reviews will hamper any injunction requests lodged prior to the effective date. Moreover, NEPA’s broad, open-ended statutory language, as well as the deference afforded to agencies when issuing rules interpreting an ambiguous statute, will narrow challengers’ potential avenues of success on the merits.[25] Unchallenged provisions will likely be allowed to be implemented even while legal challenges to other provisions proceed, as the CEQ has specifically provided for its various revisions to be severable from one another.[26]

However, a storm-front of as-applied challenges is also on the horizon. Once the new rule becomes effective, and as agencies begin conducting their NEPA reviews in compliance with them, as-applied challenges to various revisions will proliferate.[27] Individual agencies’ various decisions regarding what actions entail “minimal federal involvement” or what indirect effects require analysis, for example, are likely to spawn litigation across the nation. Challenges to CEQ rules are not automatically brought to the Circuit of the U.S. Court of Appeals for the District of Columbia, meaning both facial and as-applied lawsuits will likely be filed in district courts across the country, potentially creating a patchwork of conflicting judicial guidance.

Of course, any legal wrangling will be for naught if Democrats sweep November’s election and invoke the Congressional Review Act (CRA) to rescind the CEQ’s rule. The CRA allows Congress, with Presidential approval, to rescind a rulemaking by simple majority within 60 legislative days of the rule’s finalization, and the Biden campaign has already indicated a desire to wield this weapon against vulnerable Trump Administration environmental rules.[28]

__________________________

   [1]   See Executive Order No. 13,807 (Aug. 15, 2017).

   [2]   40 C.F.R. § 1508.1(q)(vi).

   [3]   85 Fed. Reg. at 43347.

   [4]   40 C.F.R. § 1507.3(d)(2).

   [5]   85 Fed. Reg. 43304, 43326 (July 16, 2020); 40 C.F.R. § 1501.10.

   [6]   85 Fed. Reg. at 43305.

   [7]   40 C.F.R. § 1501.10.

   [8]   85 Fed. Reg. at 43322.

   [9]   Id.

[10]   42 U.S.C. § 4332.

[11]   85 Fed. Reg. at 43343.

[12]   Id.; 40 C.F.R. § 1508.1(g). Furthermore, the CEQ states that a “but for” causal relationship is insufficient to make an agency responsible for reviewing a particular effect under NEPA. 40 C.F.R. § 1508.1(g)(2).

[13]   85 Fed. Reg. at 43343, 43344.

[14]   85 Fed. Reg. at 43344.

[15]   40 C.F.R. § 1502.15.

[16]   85 Fed. Reg. at 43343, 43344.

[17]   See, e.g., WildEarth Guardians v. Zinke, 368 F. Supp. 3d 41 (D.D.C. 2019) (holding that the U.S. Bureau of Land Management was required to quantify downstream greenhouse gas emissions and reasonably foreseeable cumulative climate impacts of oil and gas development when authorizing leases on federal land); see also Juan Carlos Rodriquez, WH Tweak To Enviro Review Rule May Bring New Headaches, Law360 (July 26, 2020), https://www.law360.com/transportation/articles/1292130/wh-tweak-to-enviro-review-rule-may-bring-new-headaches.

[18]   See, e.g., Citizens Against Burlington, Inc. v. Busey, 938 F.2d 190, 194 (D.C. Cir. 1991) (“[T]he rule of reason does not give agencies license to fulfill their own prophecies, whatever the parochial impulses that drive them. . . . [A]n agency may not define the objectives of its actions in terms so unreasonably narrow that only one alternative from among the environmentally benign ones in the agency’s power would accomplish the goals of the agency’s action.”).

[19]   85 Fed. Reg. at 43343, 43376.

[20]   40 C.F.R. § 1506.13.

[21]   Id.

[22]   40 C.F.R. § 1507.3.

[23]   Id.

[24]   Niina H. Farah, Enviros to court: Trump “cut every corner” on NEPA overhaul, E&E News (July 29, 2020), here.

[25]   See National Cable & Telecommunications Assn. v. Brand X Internet Services, 545 U.S. 967 (2005) (giving deference an agency when issuing a rule that overturns a previous judicial precedent interpreting an ambiguous statute that the agency is tasked with executing).

[26]   40 C.F.R. § 1500.3.

[27]   Dawn Reeves, Critics Blast CEQ Rule Overhaul As Cutting ‘Heart’ Out Of NEPA’s Purpose, Inside EPA (July 16, 2020), https://insideepa.com/daily-news/critics-blast-ceq-rule-overhaul-cutting-‘heart’-out-nepa’s-purpose.

[28]   Coral Davenport, Democrats Eye Trump’s Game Plan to Reverse Late Rule Changes, N. Y. Times (July 17, 2020), https://www.nytimes.com/2020/07/17/climate/trump-regulations-election.html.


Gibson Dunn’s lawyers are available to assist in addressing any questions you may have regarding the developments discussed above.  To learn more about these issues, please contact the Gibson Dunn lawyer with whom you usually work, the following authors and members of the firm’s Environmental Litigation and Mass Tort or Energy, Regulation and Litigation practice groups:

Michael K. Murphy - Washington, D.C. (+1 202-955-8238, mmurphy@gibsondunn.com) Jason J. Fleischer - Washington, D.C. (+1 202-887-3737, jfleischer@gibsondunn.com) Kyle Neema Guest - Washington, D.C. (+1 202-887-3673, kguest@gibsondunn.com) Ruth M. Porter - Washington, D.C. (+1 202-887-3666, rporter@gibsondunn.com)

Please also feel free to contact the following practice leaders and members:

Administrative Law and Regulatory Group: Helgi C. Walker - Washington, D.C. (+1 202-887-3599, hwalker@gibsondunn.com) Lucas C. Townsend - Washington, D.C. (+1 202-887-3731, ltownsend@gibsondunn.com)

Energy, Regulation and Litigation Group: William S. Scherman - Washington, D.C. (+1 202-887-3510, wscherman@gibsondunn.com)

Environmental and Mass Tort Group: Stacie B. Fletcher - Washington, D.C. (+1 202-887-3627, sfletcher@gibsondunn.com) Daniel W. Nelson - Washington, D.C. (+1 202-887-3687, dnelson@gibsondunn.com)

© 2020 Gibson, Dunn & Crutcher LLP Attorney Advertising:  The enclosed materials have been prepared for general informational purposes only and are not intended as legal advice.

July 15, 2020 |
Webcast: Public Energy Company Briefing: Considerations for Second Quarter 2020 Reports and Board Meetings

As oil and gas companies enter the second quarterly reporting cycle in the current industry downturn, please join members of Gibson Dunn’s Securities Regulation and Corporate Governance, Capital Markets, Oil and Gas and Restructuring Practice Groups as they provide both practical advice and information about the latest legal developments. Specifically, the panelists discuss:

  • Disclosure considerations for your second quarter earnings release and Form 10-Q, including newest SEC guidance
  • Navigating securities laws and good governance during a crisis
  • Fulfilling fiduciary duties in the challenging environment
  • New considerations for capital raising
View Slides (PDF)

PANELISTS: Hillary H. Holmes is a partner in the Houston office of Gibson, Dunn & Crutcher, Co-Chair of the firm’s Capital Markets practice group, and a member of the firm’s Securities Regulation and Corporate Governance, Oil and Gas, M&A and Private Equity practice groups. Ms. Holmes advises companies in all sectors of the energy industry on long-term and strategic capital planning, obligations and issues under U.S. federal securities laws and corporate governance matters. Band 1 ranked by Chambers USA, she represents issuers, underwriters, MLPs, private investors, management teams and private equity firms in all forms of capital markets transactions. Ms. Holmes also advises boards of directors, special committees and financial advisors in M&A transactions and situations involving complex issues and conflicts of interest. Ronald Mueller is a partner in the Washington, D.C. office of Gibson Dunn and a founding member of the firm’s Securities Regulation and Corporate Governance practice group. He advises public companies on a broad range of SEC disclosure and regulatory matters, executive and equity-based compensation issues, and corporate governance and compliance issues and practices. He advises some of the largest U.S. public companies on SEC reporting, proxy disclosures and proxy contests, shareholder engagement and shareholder proposals, and insider trading and Section 16 reporting and compliance. He also advises on many corporate governance matters, including governing documents for companies, boards, and board committees, such as bylaws and committee charters, director independence and related party transaction issues, and corporate social responsibility. Mr. Mueller worked as legal counsel to Commissioner Fleischman at the SEC. Michael A. Rosenthal is a partner in the New York office of Gibson, Dunn & Crutcher and Co-Chair of Gibson Dunn’s Business Restructuring and Reorganization Practice Group.  Mr. Rosenthal has extensive experience in reorganizing distressed businesses and related corporate reorganization and debt restructuring matters.  He has represented complex, financially distressed companies, both in out-of-court restructurings and in pre-packaged, pre-negotiated and freefall chapter 11 cases, acquirors of distressed assets and investors in distressed businesses.  Mr. Rosenthal’s representations have spanned a variety of business sectors, including investment banking, private equity, energy, retail, shipping, manufacturing, real estate, engineering, construction, medical, airlines, media, telecommunications and banking. Gerry Spedale is a partner in the Houston office of Gibson, Dunn & Crutcher and a member of the firm’s M&A, Capital Markets, Oi and Gas, Securities Regulation and Corporate Governance and Private Equity practice groups. He has a broad corporate practice, advising on mergers and acquisitions, joint ventures, capital markets transactions and corporate governance. He has extensive experience advising public companies, private companies, investment banks and private equity groups actively engaging or investing in the energy industry. His over 20 years of experience covers a broad range of the energy industry, including upstream, midstream, downstream, oilfield services and utilities.
MCLE CREDIT INFORMATION: This program has been approved for credit in accordance with the requirements of the New York State Continuing Legal Education Board for a maximum of 0.5 credit hour, of which 0.5 credit hour may be applied toward the areas of professional practice requirement.  This course is approved for transitional/non-transitional credit. Attorneys seeking New York credit must obtain an Affirmation Form prior to watching the archived version of this webcast. Please contact Victoria Chan (Attorney Training Manager) at vchan@gibsondunn.com to request the MCLE form. Gibson, Dunn & Crutcher LLP certifies that this activity has been approved for MCLE credit by the State Bar of California in the amount of 0.75 hour. California attorneys may claim “self-study” credit for viewing the archived version of this webcast.  No certificate of attendance is required for California “self-study” credit.

July 1, 2020 |
UK Publishes Consultation on MER Strategy for the Oil and Gas Industry – Transitioning or Maximising – The Road to Net Zero

Click for PDF This briefing examines the United Kingdom’s latest oil and gas industry sector consultation relating to the regulator’s (the Oil and Gas Authority (the OGA)) strategy to maximise economic recovery from the basin, and integrating this strategy with the United Kingdom’s carbon emissions reduction ambitions. This briefing will be relevant to all existing and prospective market actors in the United Kingdom’s offshore hydrocarbons industry, as well as those companies involved in the United Kingdom’s energy transition to a low carbon economy.

Background to the MER Strategy The United Kingdom’s Continental Shelf (the UKCS) is a mature basin with many ageing assets. In 2013, the UK Government announced a review of UKCS recovery and regulation by Sir Ian Wood (the Wood Review). The Wood Review report was published in 2014 with key recommendations to maximise economic recovery from the UKCS, including the establishment of a new regulator and the development of a new strategy to maximise economic recovery, which recommendations were accepted by the Government. The UK’s upstream oil and gas sector has since been regulated by the OGA. The OGA is required to set strategies for achieving the “principal objective” under Part 1A of the Petroleum Act 1998 (the Act), which is to maximise the economic recovery of the UK’s oil and gas resources. In 2016, the OGA set its first strategy to achieve this objective – the Maximising Economic Recovery, or MER Strategy, which came into force on 18 March 2016. Under the Act, the OGA has the power to produce a new strategy or revise a current strategy at any time, and is also required to review each current strategy every four years (s.9F of the Act).
Proposal to revise the MER Strategy On 6 May 2020, the OGA launched a formal consultation to review the MER Strategy. The OGA has invited comments, and the UK oil and gas industry is actively engaged in dialogue, on the terms of the revised proposal for the MER Strategy (the Proposal). The terms of the Proposal remain open to the consultation process, with the OGA due to review responses to the consultation before a draft of the revised strategy is laid before Parliament. At the heart of the Proposal is the integration of the maximisation of economic recovery from the UKCS with the UK’s recent commitments to reducing carbon emissions and achieving a transition to net zero by 2050. This significantly widens the original scope of the MER Strategy from one that focussed on the economic and commercial considerations of recovery of oil and gas from the basin to the environmental impacts of recovery and associated infrastructure.
Background to the UK’s net zero ambitions In the backdrop to this consultation is the UK’s statutory commitment to the net zero carbon emission 2050 target. Under the Climate Change Act 2008, the UK initially committed to achieving an 80% reduction (to 1990 levels) in greenhouse gas (GHG) emission levels by 2050. In June 2019, this target was revised upward to 100% (net zero reduction in GHG levels) by 2050 by way of the Climate Change Act 2008 (2050 Target Amendment) Order 2019 (SI 2019/1056). Referring to the Committee on Climate Change’s “Net Zero” report, the OGA has reemphasised in the consultation (p.6) that, although the UK will be transitioning to net zero, for the foreseeable future, oil and gas will remain a crucial part of the UK’s energy mix and that the oil and gas industry’s capital, skills and technology will be vital in achieving the net zero target. The OGA also expects the oil and gas industry to play “a critical role in delivering net zero for the UK as a whole” (p.7).
Given that oil and gas accounts for around 75% of the UK’s total energy needs,[1] working towards carbon neutrality and playing a critical role in delivering the transition is the right step for the industry. Extent of existing statutory mandate In integrating the net zero commitments in the Proposal however, the OGA has expanded the “Central Obligation” to include the requirement to assist the Secretary of State in meeting the net zero target – both by reducing GHG emissions and by supporting, in particular, carbon capture and storage (CCS) projects. By way of the “Supporting Obligations”, these obligations apply at each stage of operations – so relevant persons must consider reduction of GHG emissions and support for CCS from exploration to decommissioning. The attempt to tie-in net zero to the original scope of the MER Strategy is clear – the inclusion of the words “and, in doing so” at the end of the original MER central obligation (s.2a) is an attempt to preserve the sanctity of the legislative mandate (i.e. the primary objective under the Act). However, carbon neutrality does not fall within the existing “principal objective” as the statutory basis for the MER Strategy under the Act. Whilst supporting obligations can rightly be used to deliver the central obligation, the central obligation remains a reflection of the principal objective under the Act and we question whether this can be expanded without a new legislative mandate notwithstanding the terms of the Energy Act (which empower the OGA in connection with certain CCS matters) and the Climate Change Act (as amended). Given the UK oil and gas industry is in no way ignoring the need to transition by 2050, inclusion of the net zero target as a central obligation rather than a supporting obligation in this way seems unnecessary. The industry is working with industry bodies, the Government and regulators (see below) to commit not only to a “Net-Zero Basin” but also towards developing a “Sector Deal” which will ultimately have legislative force.
Industry commitments to emission reduction and the Sector Deal In September 2019, UK’s oil and gas industry group, the Oil & Gas UK (OGUK), released “Roadmap 2035: A Blueprint for Net Zero” highlighting the role that the industry can play in the transition to a decarbonised economy. On 16 June 2020, working with industry and regulators, the OGUK also set targets in the “Pathway to a Net-Zero Basin: Production Emissions Targets” to reduce emissions associated with the UKCS oil and gas production – through changes to operations, reductions in flaring and venting, capital investment programmes for the electrification of offshore facilities. The industry has committed to halving the GHG emissions from UKCS exploration and production activities by 2030, delivering 90% reduction by 2040. Alongside the recent emissions targets, the industry is also in formal discussions with the Government on a range of options for a sector deal (the Sector Deal) to support a green recovery. The Sector Deal is expected to act as a catalyst in delivering both energy security and a transition to net zero, whilst stimulating jobs growth and technological advancements and the supply chain.[2]
The inclusion of the net zero target in this way also seems premature. The Government has not yet delivered its wider strategy roadmap to achieving energy transition (the Energy White Paper – see further below). This move by the regulator, in the absence of the Government’s direction and the Energy White Paper creates a potential for inconsistency and overlap. With an Environment Bill also in Parliament, there remains a lack of clarity on the authority/ies that wield(s) enforcement powers on environmental and emissions matters. At a time when the oil and gas industry is facing a “triple whammy” and about to embark on a fundamental re-set, it would be better guided by a more co-ordinated and holistic Government approach – with the Energy White Paper leading the way, followed by a Parliament-approved Sector Deal and any required strategy or guidance rounding up the rough edges (if any).
Energy White Paper and enforcement of climate change commitments The Energy White Paper – the Government’s roadmap to achieving net zero 2050 – was initially scheduled for an early summer 2019 release. Following the Department for Business, Energy & Industrial Strategy’s (BEIS) release of a number of consultations in summer 2019 targeting these areas, there was speculation that the Energy White Paper would eventually include clear direction on new nuclear, CCS and similar projects to transition the UK to net zero. Through the course of 2020, the Government has indicated different timelines for the release of the Energy White Paper, which is yet to be published. Though the global COVID-19 pandemic has in many ways reinforced the need to push ahead with de-carbonisation of the economy, the effects of global shut-down measures has also arguably slowed the pace of change in some respects, with the COP26 United Nations climate change conference being postponed from November 2020 until 2021 and the Government having substantial competing legislative priorities. The Government also introduced the Environment Bill in October 2019. This Bill envisages the establishment of a new independent regulator – the Office for Environmental Protection – with enforcement powers, covering all climate change legislation and the UK’s commitment to reaching its net zero target.
Under the Energy Act 2016 (s.8), the OGA must have regard, when exercising its functions, to the storage of carbon dioxide, including “[t]he development and use of facilities for the storage of carbon dioxide, and of anything else (including, in particular, pipelines) needed in connection with the development and use of such facilities, and how that may assist the Secretary of State to meet the target in section 1 of the Climate Change Act 2008”. The OGA is also the licensing authority for carbon dioxide storage. However, these powers do not extend to the entire CCS value chain – perhaps the OGA needs to clarify that it is not seeking to (and it has no legislative mandate to) regulate the entire CCS chain, which is the domain of BEIS. The Proposal refers specifically to CCS and hydrogen. Although the OGA may not have intended to discourage investment in other green technologies and clean energy strategies, clearer drafting could be used to clarify that the references to CCS and hydrogen are not to the exclusion of other welcome green investment. ESG and Governance The non-binding introductory “high-level principles” introduce ESG and governance for the first time (para (c)), requiring relevant persons to “develop and maintain good environmental, social and governance practices in their plans and daily operations”. At one level, it would have been remiss of the OGA not to refer to both ESG and governance – these are fundamental pillars, which are intrinsically linked, to ensure a careful and appropriate approach to meeting the UK’s net zero targets. There are no binding obligations included in the Proposal supporting ESG, which area is already covered by other governance standards, including the 2020 UK Stewardship Code. However, a significant change to the scope of the MER Strategy and the OGA’s own powers is the introduction of “Governance” as a new Supporting Obligation (s.3). This obligation requires offshore licensees and the joint ventures in which they engage to “apply good and proper governance at all times, including complying with any principles and practices as the OGA may from time to time direct”. Prior to making a direction, the OGA “would consult on what is proposed and consider any responses made”. However, it is worth noting that there are no such corporate governance requirements in the Act, the Energy Act or the model clauses that apply to UKCS petroleum licences. In the consultation, the OGA rightly acknowledges (para 39) that a number of governance codes/principles already exist for both public and private companies (referring specifically to the 2018 UK Corporate Governance Code, 2020 UK Stewardship Code and the Wates Corporate Governance Principles for Large Private Companies), which would indicate that the OGA intends to direct companies to follow the “Comply or Explain” approach under existing codes and principles. However, the OGA also believes (para 40) it “requires the flexibility to be able to update and adapt what is considered good and proper governance based on current events and learning”. Whilst good governance systems are necessary, this indicates a wider approach to governance than currently exists – this power could extend further than a direction to comply or explain non-compliance to the OGA. Neither the consultation nor the Proposal clarify the scope of the OGA’s powers in this regard – it is unclear whether the OGA has identified gaps in applicable principles, the companies covered by the scope of existing principles or if it expects to hold licensees to a higher standard than other private and public companies, which would be both unusual and dangerous. If the intention is to hold private companies to public company standards, query whether this should be expressly acknowledged and, in any event, whether instead consultation through existing codes should be undertaken. This new inclusion is likely to make the area of governance murkier rather than clearer – inevitably leading to overlapping (and potentially conflicting) governance standards, enforcement powers and increasing the administrative burden on companies in reporting to multiple regulators on governance matters. Collaborate and co-operate Originally, the MER Strategy required relevant persons (as a “Behaviour”) to “where relevant, consider whether collaboration or co-operation with other relevant persons and those providing services” would achieve cost reduction or improve recovery (s.28). The Proposal (s.21) states that relevant persons “must” collaborate and co-operate with other relevant persons, the supply chain and “persons seeking to acquire an interest or invest in offshore licences or infrastructure in a region”. This subtle change in language from “consider” to “must” signifies a fairly significant shift in position – this is the first time the OGA has required collaboration and co-operation in the UKCS. The industry recognises the importance of collaboration, which is indeed crucial during a transition period. However, the OGA has not explained why the wording in the existing MER Strategy did not meet the OGA’s expectations. The OGA has also changed the focus of this provision – collaboration previously tied into the obligations under the MER Strategy – the Proposal de-links the collaboration requirement from the central obligation(s) under the Proposal, significantly expanding the scope of the requirement. Although the Act (s.9A(1)(b)) includes “collaboration” in meeting the principal objective of MER, it does not require collaboration with the categories of persons included in the Proposal – the addition of new entrants/potential licensees and the wider industry supply chain are not covered by the Act. Whilst the Act always referred to collaboration[3], the solution reached by the OGA when drafting the original MER Strategy was sensible, i.e. to “consider” collaboration as opposed to requiring it. It is unclear how the OGA will implement, monitor compliance or enforce the collaboration or co-operation requirement also noting that agreements to agree are not enforceable under English law. Existing players and new entrants will likely watch this area closely, as it also requires collaboration and co-operation with new entrants, potentially easing the way for further private equity access to the basin.
Collaboration and Competition Law In connection with the Energy Act 2016 and the creation of the OGA, the UK Competition and Markets Authority (the CMA) and the Government had discussed the approach to collaboration objectives.   The CMA had confirmed that the collaboration objectives of the OGA were not necessarily inconsistent with UK competition law. However, it also identified risks (inherent in the proposals) in terms of encouraging or facilitating anti-competitive information exchange or anti-competition collusion or agreements, with care required to avoid breaching competition laws.[4] The Proposal (s.1) clarifies that the Supporting Obligations and any Required Actions and Behaviours “must be read subject to the Safeguards”. According to the Safeguards provision (s.32), “[n]o obligation imposed by or under this Strategy permits or requires any conduct which would otherwise be prohibited by or under any legislation, including legislation relating to competition law, health, safety or environmental protection”. The Proposal (including the obligation to collaborate) is therefore expressly subject to competition law. Relevant persons are expected to consider whether any proposed arrangement or collaboration complies with competition law on a case-by-case basis.
Third Party Access to Infrastructure The Proposal includes new supporting obligations requiring infrastructure owners to negotiate access to infrastructure (terminals and, upstream of a terminal, equipment, pipelines, platforms, production installations and subsurface facilities) in a timely fashion and in good faith (s.12a). The Proposal requires access to the infrastructure to be provided on “fair, reasonable and non-discriminatory terms” (s.12b). Notably, the Proposal now expressly requires infrastructure owners and operators to achieve optimum potential for the re-use and re-purpose of infrastructure taking account of the UK’s net zero target (s.10c) and to negotiate access to infrastructure for CCS projects (s.22). The newly introduced supporting obligations are consistent with the existing access to infrastructure principles set out in the non-statutory Infrastructure Code of Practice (the Code). The OGA encourages all parties to follow the Code and, when considering third party access disputes under the Energy Act 2011, the OGA will assess the extent to which parties have followed the Code (see also Third Party Access Disputes Guidance). The supporting obligations in the Proposal therefore represent a continued shift in emphasis from a voluntary industry-led access to infrastructure regime (with the OGA resolving issues) to a requirement under the Proposal enforceable directly by the OGA. When negotiating access to infrastructure, owners and operators should also remain conscious of the CMA powers to investigate abuses of a dominant position under UK competition law; and the European Commission’s (the EC) ability to investigate similar breaches under EU competition laws, where conduct may have an effect on trade between Member States. The OGA stated in the Third Party Access Disputes Guidance that the CMA “is unlikely to consider that infrastructure owners infringe the Chapter II prohibition on abuse of a dominant position where they offer third parties use of their infrastructure on fair, reasonable and non-discriminatory terms”. This is now the test that the OGA has included in the Proposal. The changes proposed may potentially overlap with the CMA’s and EC’s jurisdiction. The consultation also states that the OGA will, in due course, work with industry to provide further guidance on the asset stewardship supporting obligations. Such guidance should specifically address how parties are expected to negotiate access to infrastructure whilst balancing the potential competing or conflicting demands of (i) the maximising economic recovery objective, (ii) the net zero target, (iii) the commercial objectives and existing contractual commitments of the infrastructure owners and operators, and (iv) competition law. Conclusion The OGA’s bold steps towards the integration of the path to net zero within the oil and gas industry’s roadmap are likely to be welcomed by society and industry. Engagement by industry in committing to emission reduction targets and developing a Sector Deal with the Government show buy-in from industry into delivering energy transition. The industry and industry bodies are actively engaging in the consultation process. In the absence of any clear policy steer by the Government by way of the Energy White Paper or agreement on a Sector Deal, the OGA’s move has jumped ahead of the more logical sequence of the Government’s fully framed strategy and action plan leading the way. The twin-track being created by the Proposal may not only dilute the purpose of the MER Strategy but also confuse the net zero message. The OGA may therefore want to reconsider whether the MER Strategy is the right instrument by which to introduce the energy transition obligations. Perhaps if covered by a separate instrument for energy transition, there may be an ability to consider collaboration with offshore renewables – an area currently missing in the Proposal as it is not within the OGA’s purview. Where the OGA intends to integrate two fundamental concepts, the Proposal leaves potential for conflicts between maximising economic recovery of natural resources and the UK’s net zero objective. In any redraft, the OGA should ensure that the primacy of the MER principal objective is clear over energy transition – perhaps delivering the transition net zero as a supporting obligation, rather than a central obligation. The OGA will need to work closely with industry and other existing regulatory bodies to ensure that projects are able to maintain a reasonable balance between maximising and transitioning and that there is no overlapping areas of authority and jurisdiction between regulators. These areas would benefit from clarity – preferably by way of the original drafting rather than future guidance. Over the past four years, the OGA has been flexible and supportive in the interpretation and implementation of the MER Strategy. The extensive proposed amendments require industry to place a lot of reliance on that behaviour. In order to future-proof the MER Strategy, it would be prudent and good practice to clarify the OGA’s intentions in relation to a number of the changes and also to include more clear drafting to avoid ambiguity.
Next steps The consultation closes on 29 July 2020, followed by a period of (potential) redrafting by the OGA based on representations received. The process for revising an existing strategy is set out in the Act (s.9G) and summarised below:
  • OGA produces a draft of the revised strategy;
  • OGA consults with persons it thinks appropriate;
  • OGA considers representations / responses to consultation;
  • OGA sends the draft (original or modified) to the Secretary of State for BEIS (the SoS), who may return it if he/she considers that the draft does not enable the principal objective to be met or if the consultation process was not followed;
  • SoS lays the draft before each House of Parliament;
  • If neither House of Parliament passes a negative resolution after 40 days (excluding periods of Parliament adjournment of more than four days, dissolution or prorogation), the OGA may issue the revised strategy; and
  • OGA can determine when the revised strategy comes into force (the earliest date being the date of issue).
_________________________    [1]   Pathway to a Net-Zero Basin: Production Emissions Targets, OIL & GAS UK (June 16, 2020), https://oilandgasuk.cld.bz/OGUK-Pathway-to-a-Net-Zero-Basin-Production-Emissions-Targets-Report-2020 (p.4).    [2]   UK offshore oil and gas industry outlines plan to cut emissions as talks on transformational sector deal formally begin, OIL & GAS UK, https://oilandgasuk.co.uk/category/press-release/.    [3]   In addition, under the Energy Act 2016 (s.8), the OGA is required to have regard, when exercising its functions, to “collaboration”, i.e. the need to work collaboratively with the Government and with persons who carry on, or wish to carry on, relevant activities.    [4]   Letter from the CMA to the Department of Energy and Climate Change (December 3, 2015), see paras 5 to 13, here.

Gibson Dunn’s lawyers are available to assist with any questions you may have regarding these developments. For additional information, please contact the Gibson Dunn lawyer with whom you usually work, any member of the firm's Oil and Gas practice group, or the following authors:

Anna P. Howell - London (+44 (0)20 7071 4241, ahowell@gibsondunn.com) Mitasha Chandok - London (+44 (0)20 7071 4167, mchandok@gibsondunn.com) Kelly Powers - London (+44 (0)20 7071 4147, kpowers@gibsondunn.com) Ade Adesiyan - London (+44 (0)20 7071 4251, aadesiyan@gibsondunn.com)

© 2020 Gibson, Dunn & Crutcher LLP Attorney Advertising:  The enclosed materials have been prepared for general informational purposes only and are not intended as legal advice.

June 30, 2020 |
En Banc D.C. Circuit Overturns Long-Standing FERC Practice of Issuing Tolling Orders for Rehearing Requests

Click for PDF An en banc decision by D.C. Circuit today likely ends the Federal Energy Regulatory Commission’s (“FERC’s”) practice of issuing tolling orders for the purpose of allowing additional time for consideration. In Allegheny Defense Project v. FERC, No. 17-1098 (June 30, 2020), the D.C. Circuit on rehearing en banc found that FERC’s routine practice of issuing an order to allow additional time for consideration of a rehearing request is inconsistent with the plain language of the Natural Gas Act (“NGA”). Although this case concerned the hearing provisions of the NGA, this order can be expected to end the practice of rehearing tolling orders under the Federal Power Act (“FPA”) as well. The NGA requires a party aggrieved by a FERC order to first obtain an order on rehearing from FERC before proceeding to judicial review.[1] The NGA also states that a rehearing request may be deemed denied if FERC does not act upon it within thirty days.[2] The question in Allegheny Defense was whether FERC “granting rehearing” simply to allow additional time for consideration qualified as “acting upon” the rehearing request. The D.C. Circuit concluded it does not. The court found that Congress had identified four actions that FERC may take to “act upon” a rehearing request within the meaning of the statute: (i) grant it, (ii) deny it, (iii) abrogate its order without further hearing, or (iv) modify its order without further hearing.[3] The court found FERC’s tolling orders did not qualify as any of the foregoing. Accordingly, the court concluded that FERC cannot escape the consequence of its inaction by “kicking the can down the road” with a non-substantive tolling order.[4] The court held that tolling orders would be treated “deemed denials” that allow the aggrieved party to proceed with judicial review.[5] The court, however, did stop short of requiring that FERC decide all rehearing requests within thirty days, leaving open the possibility that something short of a substantive decision on rehearing may be sufficient.[6]

RULING’S IMPACT

This decision will have immediate and broad consequences for a range of FERC matters. First, with respect to pipeline construction cases, this decision in combination with FERC’s recently issued rule on construction during rehearing will prevent pipeline construction from starting while the rehearing process plays out, but provide additional timing certainty for that process. Indeed, there should now be less uncertainty for both pipelines and landowners in how the rehearing process plays out. Second, this decision will likely change the calculation on pipeline opponents pursuing stays of construction in the court of appeals because judicial review will always be available at the time construction begins. Third, while we expect landowners spurred by plaintiff’s lawyers to argue that the D.C. Circuit’s decision in combination with the new FERC rule should cause certain district courts to hold eminent domain cases in abeyance while the rehearing process plays out, the Court today was very careful to not create new law on this point and the prevailing law remains in place.[7] However, it should be noted that the concurring opinion by Judges Griffith, Katsas, and Rao called out allowing construction and eminent domain suits to go forward despite FERC granting rehearing for further consideration. Finally, more broadly, going forward this order will place additional demands on FERC and its Staff since the long standing tolling practice is no longer available under the NGA or FPA. Given how often rehearing papers are filed, and the complexity of many rehearing requests, FERC would be more than justified in seeking additional resources to handle what is now a cramped rehearing time frame.

No Pipeline Construction During Rehearing

On June 9, 2020, FERC issued Order No. 871 and will no longer allow pipeline construction to proceed before it decides requests for rehearing on a certificate order.[8] In Order No. 871, FERC announced that it will no longer authorize construction of an approved natural gas project under sections 3 or 7 of NGA, until either FERC acts on the merits of any timely-filed request for rehearing or the time for filing such a request has passed.[9] At the time this decision was announced, that meant construction could be delayed for an indefinite period of time (months or possibly years) while FERC considered timely filed rehearing requests.[10] Now Order No. 871 in combination with the Allegheny Defense decision, mean that construction typically should be delayed only during the thirty day period permitted for an aggrieved party to seek rehearing and then the additional thirty days for FERC to act on the request (i.e., a total of sixty days). The court made clear that even after a petition for review is filed with the court, FERC retains concurrent jurisdiction to modify or set aside a challenged order until the administrative record is filed with the court, which typically happens forty days after the petition is served on FERC.[11] Therefore, in certain cases, the time period where construction could not move forward under Order No. 871 could extend an additional hundred days or longer (the up to sixty days for a party to petition for review and the forty days to file the administrative record, which could be extended with leave from the court). This, however, still provides a more definite end point in terms of timing than under FERC’s prior tolling practice. Thus, the Allegheny Defense decision removes timing uncertainty for both proponents and opponents to new pipeline construction.

Implications for Stays

Prior to the Allegheny Defense decision, it was challenging for opponents of gas construction projects to obtain a stay while rehearing was pending because, absent a final order on rehearing, the only readily available forum for such a request was FERC itself.[12] Now that the beginning of construction will coincide with the availability of judicial review, more litigants may pursue stays in the court of appeals. FERC has had a relatively good track record in fending off stays, and it will be interesting to see how the rule change and Opinion today change the frequency and velocity of stay requests.

Pending Tolled Actions

Although Allegheny Defense was an NGA case, the implications of this decision are not limited to the NGA, as FERC routinely uses tolling orders under parallel provisions of the FPA.[13] Indeed, the Allegheny Defense court noted that matters beyond pipeline cases have “met a similar fate, with open-ended tolling orders leaving applicants awaiting action for a year or more.”[14] Given that the NGA and the FPA are generally interpreted in parallel, it is likely that the D.C. Circuit would similarly find FERC’s use of tolling orders impermissible under the parallel provisions of the FPA. Accordingly, any request for rehearing under the NGA or FPA that is pending under a tolling order may now be fair game to proceed to the court of appeals for judicial review. __________________________    [1]   15 U.S.C. § 717r(a) (“No proceeding to review any order of the Commission shall be brought by any person unless such person shall have made application to the Commission for a rehearing thereon.”).    [2]   Id.    [3]   Slip Op at 22 (explaining that FERC is given four options under the statute to “act on” rehearing requests: “the Commission can (i) ‘grant * * * rehearing,’ (ii) ‘deny rehearing,’ (iii) ‘abrogate * * * its order without further hearing,’ or (iv) ‘modify its order without further hearing[.]”).    [4]   Id. at 24.    [5]   Id. at 27.    [6]   Id. at 29-30 (“[W]e need not decide whether or how Section 717r(a), the ripeness doctrine, or exhaustion principles might apply if the Commission were to grant rehearing for the express purpose of revisiting and substantively reconsidering a prior decision, and needed additional time to allow for supplemental briefing or further hearing processes.”).    [7]   Id. at 18 n.2 (explaining that FERC adopted Order 871 after oral argument, but that rule does not prevent courts from moving forward with eminent domain proceedings); id. at 30 n.4 (noting that the court was not deciding what the implications of a grant of merits rehearing might mean for reliance in eminent domain proceedings); see also, e.g., Transcon. Gas Pipe Line Co. v. Permanent Easements for 2.14 Acres & Temp. Easements for 3.59 Acres in Conestoga Township, Lancaster County, Pa., Tax Parcel No. 1201606900000, 2017 WL 3624250, at *3-4 (E.D. Pa. Aug. 23, 2017); Steckman Ridge GP, LLC v, An Exclusive Nat. Gas Storage Easement Beneath 11.078 Acres, 2008 WL 4346405 at *4 (W.D. Pa. Sept. 19, 2008).    [8]   Limiting Authorizations to Proceed with Construction Activities, Order No. 871, 171 FERC ¶ 61,201 (2020).    [9]   Id. at P 1. [10]   Id. at PP 8-9. [11]   Slip Op. at 30. [12]   Certain litigants pursued extraordinary relief in the court of appeals as a work-around in this circumstance, but that is not done frequently. See, e.g., Emergency Petition for a Writ of Prohibition, New York Dept. of Enviro. Conservation v. FERC, (2nd Cir. filed Nov. 14, 2017) available at https://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=15000152. [13]   See Slip Op. at 26-27; 16 U.S.C. § 825l(a) (“Any person, electric utility, State, municipality, or State commission aggrieved by an order issued by the Commission in a proceeding under this chapter to which such person, electric utility, State, municipality, or State commission is a party may apply for a rehearing within thirty days after the issuance of such order. . . . Unless the Commission acts upon the application for rehearing within thirty days after it is filed, such application may be deemed to have been denied. No proceeding to review any order of the Commission shall be brought by any entity unless such entity shall have made application to the Commission for a rehearing thereon.”). [14]   Slip Op. at 26 (citing a challenge under the Federal Power Act where it took FERC twenty two months to act on a rehearing request).

Gibson Dunn’s Energy, Regulation and Litigation lawyers are available to assist in addressing any questions you may have regarding the developments discussed above.  To learn more about these issues, please contact the Gibson Dunn lawyer with whom you usually work, or the authors:

William S. Scherman – Washington, D.C. (+1 202-887-3510, wscherman@gibsondunn.com) Ruth M. Porter – Washington, D.C. (+1 202-887-3666, rporter@gibsondunn.com) Jeffrey M. Jakubiak – New York (+1 212-351-2498, jjakubiak@gibsondunn.com) © 2020 Gibson, Dunn & Crutcher LLP Attorney Advertising:  The enclosed materials have been prepared for general informational purposes only and are not intended as legal advice.

May 27, 2020 |
Texas Supreme Court Rules That “Anti-Washout” Clause Purporting to Extend Overriding Royalty Interests to a “New Lease” Violates Rule Against Perpetuities

Click for PDF On May 15, 2020, the Texas Supreme Court held that a broad “anti-washout” provision extending overriding royalty interests to a new lease for the same assets was invalid under Texas’s “rule against perpetuities,” though such a provision is subject to judicial reformation under Texas property laws. As we noted in our October 24, 2019 alert when the Texas Supreme Court agreed to hear Yowell v. Granite Operating Co., No. 18-0841 (Tex. 2020), overriding royalty interests are “carved out” of an oil and gas lease. They entitle the interest holder to some portion of a leased asset’s production without subjecting the interest holder to the expense of developing, operating, or maintaining the leased asset. Absent specific language to the contrary, these interests are “limited in duration to the leasehold interest’s life” and terminate with the lease. Sunac Petroleum Corp. v. Parkes, 416 S.W.2d 798, 804 (Tex. 1967). Interest holders thus often include “anti-washout” clauses in the instrument creating the overriding royalty interest to prevent the interest from lapsing when a lease is renewed or extended, and some seek to prevent the interests from lapsing even when the lessee enters into an entirely new lease on different terms. For decades, Texas courts confirmed that these anti-washout provisions are valid and enforceable as applied to lease extensions and renewals but did not address their validity as applied to “new leases.” That changed on May 15, 2020, when the Texas Supreme Court considered and held for the first time that an anti-washout provision could not extend an existing overriding royalty interest to new leases when it was not clear that the interest would vest within a certain period of time. In Yowell, the Court reviewed the validity of an anti-washout provision that purported to cover any “extension, renewal, or new lease” executed by the mineral interest holder for the same assets. The Court confirmed that the “extension” and “renewal” provisions were valid, but concluded that the “new lease” provision violated the Texas Constitution because, at the time of execution, there was uncertainty as to when (or whether) the purported interest in a theoretical “new lease” would vest. The Court rested its decision on a principle of property law called the “rule against perpetuities.” Under this rule, “no interest is valid unless it must vest, if at all, within twenty-one years after the death of some life or lives in being at the time of the conveyance.” BP Am. Prod. Co. v. Laddex, Ltd., 513 S.W.3d 476, 479 (Tex. 2017). The Court first concluded that the overriding royalty interest did not vest at the time of creation because it provided no “immediate, fixed right of present or future enjoyment as to new leases because those leases were not yet in existence.” The Court then noted that it was possible for the interest to vest outside the timeframe allowed by the rule against perpetuities. Specifically, the holder’s interest in a “new lease” was contingent on events that may not occur, including that (1) the existing lease must terminate, (2) the mineral interest owner must execute a new lease, and (3) the new lease must be obtained by the same lessee or its successor. In light of these contingencies, the overriding royalty interest would vest, if at all, after an indeterminate amount of time. The Supreme Court thus held that the provision was invalid as written. Nonetheless, the Court also held that the anti-washout provision should be “reformed” under section 5.043 of the Texas Property Code to “reflect the creator’s intent.” This statute provides that “[w]ithin the limits of the rule against perpetuities, a court shall reform or construe an interest in real property that violates the rule to effect the ascertainable general intent of the creator of the interest.” Tex. Pro. Code § 5.043(a). The Court concluded that the reformation statute applied to corporate conveyances of property interests, including anti-washout provisions, and remanded the case for further proceedings related to reformation of the specific clause at issue. After Yowell, it is unclear whether anti-washout provisions that purport to cover “new leases” are simply void pursuant to the rule against perpetuities, or whether adding time limits and specifying other contingencies can save such clauses. Similarly, it remains to be seen whether and how Texas trial and intermediate courts will reform anti-washout provisions that purport to cover “new leases” to comply with the rule. In the meantime, lessees and overriding royalty interest holders who wish to include anti-washout provisions covering “new leases” should carefully and clearly draft such provisions so that the interest vests with certainty within the limited time period proscribed by the rule, or risk that such a provision will be void or subject to judicial intervention and reformation. Gibson Dunn stands ready to advise our clients in drafting these provisions and otherwise advise our clients on the extent to which the Court’s decision may impact existing oil and gas leases.


The following Gibson Dunn lawyers assisted in preparing this client update: Mike Raiff, Mike Darden, Allyson Ho, Christine Demana and Collin Ray. Gibson Dunn’s lawyers are available to assist in addressing any questions you may have regarding these developments. Please contact the Gibson Dunn lawyer with whom you usually work or any of the following members of the firm’s Oil and Gas or Appellate and Constitutional Law practice groups: Michael P. Darden – Houston (+1 346-718-6789, mpdarden@gibsondunn.com) Allyson N. Ho – Dallas (+1 214.698.3233, aho@gibsondunn.com) Tull Florey – Houston (+1 346-718-6767, tflorey@gibsondunn.com) Hillary H. Holmes – Houston (+1 346-718-6602, hholmes@gibsondunn.com) Shalla Prichard – Houston (+1 346-718-6644, sprichard@gibsondunn.com) Mike Raiff – Dallas (+1 214-698-3350, mraiff@gibsondunn.com) Doug Rayburn – Dallas (+1 214-698-3442, drayburn@gibsondunn.com) Gerry Spedale – Houston (+1 346-718-6888, gspedale@gibsondunn.com) © 2020 Gibson, Dunn & Crutcher LLP Attorney Advertising:  The enclosed materials have been prepared for general informational purposes only and are not intended as legal advice.

May 7, 2020 |
Webcast: Maintenance of Oil and Gas Leases in These Troubled Times

In the current distressed environment of the oil and gas industry, there has been a great deal of discussion about, consideration of, and even implementation planning for, significantly reducing or even “shutting in” production. Join the Chair of Gibson Dunn’s Oil & Gas Practice Group, Michael P. Darden, as he discusses how and why this reduction or shut-in of production may occur and the consequences thereof, and provides a comprehensive examination of potential pitfalls and suggested courses of action. View Slides (PDF)



PANELISTS: Michael P. Darden is Partner-in-Charge of the Houston office of Gibson, Dunn & Crutcher, chair of the firm’s Oil & Gas practice group, and a member of the firm’s Energy and Infrastructure and Mergers and Acquisitions practice groups. Before joining Gibson Dunn, Mr. Darden served as the global chair of the oil and gas transactions practice and co-chair of the global oil and gas industry team at Latham & Watkins as well as the firmwide chair of the global oil and gas practice at Baker Botts. Mr. Darden is Board Certified in Oil and Gas Law by the Texas Board of Legal Specialization.
MCLE INFORMATION: This program has been approved for credit in accordance with the requirements of the New York State Continuing Legal Education Board for a maximum of 1.0 credit hour, of which 1.0 credit hour may be applied toward the areas of professional practice requirement.  This course is approved for transitional/non-transitional credit. Attorneys seeking New York credit must obtain an Affirmation Form prior to watching the archived version of this webcast. Please contact Victoria Chan (Attorney Training Manager) at vchan@gibsondunn.com to request the MCLE form. Gibson, Dunn & Crutcher LLP certifies that this activity has been approved for MCLE credit by the State Bar of California in the amount of 1.0 hour. California attorneys may claim “self-study” credit for viewing the archived version of this webcast.  No certificate of attendance is required for California “self-study” credit.

April 30, 2020 |
Colorado’s Sweeping Oil and Gas Law: One Year Later

Click for PDF A year ago, Colorado ushered in a new era of oil gas regulation when Governor Jared Polis signed Senate Bill 19-181 (“SB-181”) into law.[1] For opponents of oil and gas development, SB-181 represented a significant victory—and a reversal of fortune. Over the course of the previous year, Colorado voters had soundly defeated Proposition 112, a statewide initiative that would have mandated aggressive setback rules for new wells,[2] and the Colorado Supreme Court issued its unanimous decision in Martinez v. Colorado Oil and Gas Conservation Commission, which upheld a decade’s worth of rulemaking by the Colorado Oil and Gas Conservation Commission (“COGCC”) under the state’s prior regulatory regime.[3] In response to these developments, newly elected Governor Polis, with the support of a Democratic majority in both houses of the Colorado General Assembly, vowed to push for legislation to “reform” the COGCC and “make sure health and safety are prioritized.”[4] The result was SB-181, which was touted as a solution to the long-simmering “oil and gas wars” between environmental activists and industry groups in the state.[5] A year has now passed since the signing of SB-181. In that time, the COGCC and other state regulators have begun the process of implementing the law. It has become clear, however, that the “oil and gas wars” are not over. Rulemaking at the COGCC remains contentious, and local governments continue to flex their muscles and threaten to significantly restrict oil and gas development within their borders. Meanwhile, legal challenges to these regulations are likely on the horizon, and voters may once again be asked to decide whether to impose new regulations on the industry when they head to the ballot box for this year’s election. While the current COVID-19 crisis and the related turmoil in global markets have recently dominated concerns about the future of oil and gas development in Colorado, determining the state’s long-term regulatory scheme remains a top priority for both the proponents and opponents of Colorado’s oil and gas industry.

A Recap of SB-181’s Major Changes

SB-181 made fundamental changes to Colorado’s regulatory structure for the oil and gas industry, in some cases reversing assumptions that had been a part of state law for decades. First, SB-181 granted local governments power to regulate future oil and gas development within their jurisdictions, including the power to preempt less restrictive statewide regulations promulgated by the COGCC.[6] This decentralization of authority was a dramatic shift in Colorado’s regulatory approach. In the decades before SB-181, lawmakers had been hesitant to grant local governments significant control over the industry. Doing so, they feared, would lead to an impractical patchwork of regulations across the state.[7] SB-181 was an about-face: a local government may now impose oil and gas regulations that are stricter than those promulgated by the COGCC, and those stricter rules will govern oil and gas development within the local government’s jurisdiction.[8] SB-181’s only limitations on local regulatory powers are that these powers must be exercised in a “reasonable manner” and any regulations imposed on the industry must be “necessary and reasonable” to protect public health and the environment—limitations that are undefined and have yet to be tested by the courts.[9] Second, SB-181 altered the overall mission of state regulators. Previously, the COGCC was charged with a statutory mandate to “foster” development of oil and gas resources to achieve the “maximum efficient rate of production.”[10] Protection of public health and the environment was a significant goal, but the COGCC pursued that goal in tandem with oil and gas development. Now, under SB-181, the COGCC is required to “regulate”—not “foster”—oil and gas development in Colorado, and it must do so “in a manner that protects” public health and the environment.[11] In effect, SB-181 required the COGCC to reevaluate its regulatory approach while deemphasizing full utilization of state oil and gas reserves. Consistent with this “mission change,” the COGCC is required to collaborate with the Colorado Department of Public Health and Environment (“CDPHE”) to address the “cumulative impact” of oil and gas development. Third, SB-181 called for the restructuring and professionalization of the COGCC.[12] Previously, the COGCC was composed of nine members. Seven were unpaid volunteers, three of whom were required to have substantial experience in the oil and gas industry.[13] By July 1, 2020, however, membership will be reduced by two commissioners, and each of the seven will be paid, full-time government employees. Five will be newly appointed by the Governor, only one of which is required to have industry experience. The remaining two are the Executive Directors of the Colorado Department of Natural Resources and CDPHE, who will serve as ex officio non-voting members.[14] SB-181 mandates that the newly appointed commissioners be free from conflicts of interest, which are defined to include working as a registered lobbyist at the state or local levels, serving in the Colorado General Assembly within the past three years, or serving in an official capacity with an entity that advocates for or against oil and gas activity.[15] The COGCC began accepting applications for the full-time commissioner positions in January 2020, but Governor Polis has not yet announced his nominations.[16]

Delays in the Statewide Rulemaking Process

To implement its wide-reaching reforms, SB-181 required the COGCC to undertake major rulemaking initiatives on a range of subjects, including (1) updates to the COGCC’s hearing procedures (the so-called “500 Series” rules); (2) public disclosure of flowline locations; (3) criteria for the selection of drilling sites, including consideration of alternative locations; (4) wellbore integrity; (5) minimizing the cumulative impact of oil and gas development (in consultation with the CDPHE); and (6) the overall “mission change” of the COGCC.[17] In addition, SB-181 instructed CDPHE to establish rules to minimize air and water pollution generated from exploration and development activities.[18] All of these rules were initially scheduled to be finalized by July 1, 2020, before the transition in the COGCC’s structure and membership.[19] But the rulemaking process has proved more contentious than expected and has been plagued by delays. As a result, the COGCC has acknowledged that meeting the July deadline is unlikely.[20] The COGCC attempted to ease into the rulemaking process in June 2019, just after SB-181 went into effect, tackling a subject thought to be relatively uncontroversial—the so-called 500 Series, which would amend existing procedural rules.[21] Instead, public rulemaking hearings became a battleground, with environmental groups demanding a moratorium on new drilling permits until a full suite of updated health and safety regulations could be drafted, approved, and implemented.[22] The COGCC eventually adopted updated 500 Series rules in July 2019 and new flowline rules in November 2019,[23] but delays continue to affect the COGCC’s other rulemaking proceedings. The COVID-19 crisis has exacerbated these delays. Rulemaking hearings to address the “mission change” of the COGCC, cumulative impacts of oil and gas development, and drilling site criteria were delayed by several months.[24] Hearings to consider rules governing wellbore integrity were rescheduled from February 2020 to April 2020[25] and were rescheduled again to June 2020.[26] While the COGCC recently began holding hearings via videoconference to continue the rulemaking process, it has recognized the inadequacy of these virtual meetings for public testimony and open discussion with respect to especially controversial rulemakings, such as the mission change rules.[27] As a result, the COGCC has opted to reschedule public hearings on the mission change rules until August 24 through September 24, when the COGCC hopes to be able to hold in-person hearings, though it currently plans to proceed with the June 2020 public hearings on wellbore integrity rules, likely by videoconference.[28] Accordingly, the COGCC will not meet its July 1st goal of completing all of the rulemaking required by SB-181. While the current commissioners may be able to complete the wellbore integrity regulations before July 1st, the ongoing rulemaking process will be completed by the newly constituted COGCC, not the current commissioners.[29] It remains to be seen whether shifting the balance of the rulemaking proceedings to the new COGCC commissioners will further delay adoption of final rules or affect their content. Meanwhile, CDPHE has been engaged in separate rulemaking proceedings through two of its divisions, the Air Quality Control Commission (“AQCC”) and the Water Quality Control Commission (“WQCC”). In December 2019, the AQCC adopted rules imposing increased leak detection and repair requirements on producing wells, comprehensive annual emissions reports, and more stringent controls on emissions from storage tanks—all of which will increase operation costs substantially, particularly for small producers.[30] At the same time, AQCC also adopted regulations requiring oil and gas producers to obtain air-quality permits (in addition to the permit to drill required by the COGCC) before they can begin exploration and production activities, eliminating a 90-day grace period under previous rules.[31] In a future rulemaking, the AQCC will consider rules intended to reduce emissions of hydrofluorocarbons and rules requiring oil and gas producers to track and report greenhouse gases emissions.[32] Separately, the WQCC is finalizing tighter regulations governing surface and ground water, which will affect injection wells, waste disposal, and other oil and gas operations.

Local Regulation: Renewed Drilling Moratoriums and a Patchwork Approach

Soon after the passage of SB-181, a number of cities and counties in the Denver-Julesburg Basin enacted moratoriums on new applications for local drilling permits, including Adams and Boulder counties and the cities of Berthoud, Broomfield, Lafayette, Superior, and Timnath. The stated intent of these moratoriums was to pause oil and gas development while the COGCC and local governments updated their regulations.[33] Given the delays plaguing the rulemaking process at the COGCC, however, some of these moratoriums have effectively banned new oil and gas development for as much as a year.[34] The legality of these moratoriums is unclear. Under the pre-SB-181 framework, a number of cities and counties in Colorado attempted to impose lengthy moratoriums on oil and gas activity. But the courts struck them down, and the Colorado Supreme Court confirmed that local governments did not have the power to halt oil and gas development within their borders.[35] SB-181, however, granted local governments new powers—including, perhaps, the power to ban oil and gas activities. In the coming months, this question may soon be decided by a trial court in Boulder County. A group of anti-industry activists has asked for a ruling that would confirm the legality of the city’s ban on hydraulic fracturing under SB-181.[36] In the meantime, local governments have proceeded to consider and impose new regulations for the oil and gas industry. One of the industry’s primary criticisms of SB-181 was that it would enable and even encourage a patchwork of local regulations across the state, something that lawmakers in Colorado had long attempted to avoid through preemptive state rules. As the opponents of SB-181 explained, neighboring localities might adopt wildly different—and perhaps inconsistent—regulations.[37] Operating under this kind of jurisdiction-by-jurisdiction patchwork would be difficult and expensive, if not impossible, for producers. These fears appear to be well-founded.[38] The neighboring counties of Boulder and Weld are taking diametrically opposed regulatory approaches. Boulder commissioners are seeking the “toughest regulations [they] can get” and will likely adopt some of the most restrictive rules in the state.[39] Its proposed rules would impose more stringent restrictions on oil and gas exploration and production, and will at the same time add additional restrictions on noise, vibration, odor, and seismic testing.[40] In stark contrast, Weld county—home to nearly half of Colorado’s active wells—rejected a permitting moratorium and has taken steps to facilitate, rather than restrict, new oil and gas development. For example, local officials designated unincorporated portions of the county as “mineral resource areas of state interest,” prompting an agreement with the COGCC to address the backlog of permits affecting oil and gas development in the county.[41] While these two counties represent extreme approaches, they highlight the difficulties facing the industry. Mineral rights, leasehold interests, and wells may all span more than one jurisdiction, and producers will now have to grapple simultaneously with several sets of different local rules and regulations—not to mention new state-level rules—increasing the cost and complexity of their operations.

Statewide Permitting Slows and New Ballot Initiatives Loom

One of the primary effects of SB-181 has been a steep decline in the approval of new well locations and drilling permits, which were down nearly 57% and 58%, respectively, in the six months after SB-181 was enacted.[42] While some of this decline can be attributed to local government moratoriums, the COGCC has also indicated that the permitting slowdown is “a reflection of the new emphasis on health, safety and the protection of the environment” created by SB-181.[43] Indeed, shortly after SB-181 was passed, the COGCC adopted interim permitting criteria requiring additional analysis of some drilling permit applications “to ensure the protection of public health, safety, welfare, the environment, or wildlife resources.”[44] The recent decline in permitting has exacerbated an existing backlog, increasing operators’ uncertainty, interrupting drilling programs, and decreasing overall production.[45] Critics of SB-181 have long predicted that the new law could contribute to a slowdown in Colorado’s oil and gas industry.[46] This prediction was echoed by the University of Colorado’s Leeds School of Business, which warned in December 2019 that “economic and regulatory uncertainties could very well slow development in 2020.”[47] The delayed and uncertain regulatory outlook, when coupled with the COVID-19 crisis and the turmoil in global oil markets, have forced the industry to take dramatic steps, such as slashing capital expenditures, reducing or eliminating dividends, and furloughing or laying off employees. Such measures directly impact adjacent industries, including oilfield services companies, investors, and employees. So far, no major lawsuits have been filed to challenge state or local regulations promulgated under SB-181. As the Leeds School of Business explained, however, “the possibility of legal challenges” is “persistently looming” given the high stakes.[48] In the meantime, citizen initiatives seeking further changes to Colorado’s regulatory framework may reach the ballot for the upcoming 2020 presidential-year election. The proponent of Proposition 112, the setback initiative that was voted down in 2018, is pursuing six separate initiatives this year. Five of them would impose well setbacks similar to those found in Proposition 112; another would require oil and gas companies to post a far more expensive bond for new wells. If any of these initiatives make the ballot—which is anything but certain, given the difficulty of obtaining petition signatures during the COVID-19 pandemic—the industry could face another expensive campaign season. In 2018, industry groups spent nearly $40 million defeating Proposition 112.[49] A similar political fight in the midst of a presidential campaign may be even more expensive.

Conclusion

The implementation of SB-181 over the past year has been a difficult endeavor. The COGCC’s rulemaking process has been contentious, leading to repeated delays in the adoption of new regulations. Many local governments enacted moratoriums on new drilling applications, some of which have been extended due to the delays at the COGCC. These local governments have also taken different approaches to oil and gas regulation, creating a patchwork of rules across the state. With legal challenges to the implementation of SB-181 forthcoming and several new ballot initiatives on the horizon, SB-181 appears to have increased, not decreased, the clashes between proponents and opponents of oil and gas production in Colorado. Unfortunately for all involved, the end of the “oil and gas wars” in Colorado is a long way off. ______________________    [1]   https://www.denverpost.com/2019/04/16/colorado-oil-gas-bill-signed-gov-jared-polis/.    [2]   https://www.sos.state.co.us/pubs/elections/Initiatives/titleBoard/filings/2017-2018/97Final.pdf.    [3]   Martinez v. Colo. Oil & Gas Conservation Comm’n, No. 17SC297 (available at http://blogs2.law.columbia.edu/climate-change-litigation/wp-content/uploads/sites/16/case-documents/2019/20190114_docket-17-SC-297_opinion.pdf).    [4]   https://www.denverpost.com/2019/01/14/colorado-supreme-court-oil-gas-martinez-decision/.    [5]   https://www.denverpost.com/2019/04/16/colorado-oil-gas-bill-signed-gov-jared-polis/.    [6]   Senate Bill 19-181 §4.    [7]   City of Longmont v. Colo. Oil & Gas Ass’n, 369 P.3d 573, 585 (Colo. 2016) (“The Oil and Gas Conservation Act and the Commission’s pervasive rules and regulations, which evince state control over numerous aspects of fracking, from the chemicals used to the location of waste pits, convince us that the state’s interest in the efficient and responsible development of oil and gas resources includes a strong interest in the uniform regulation of fracking.”).    [8]   Senate Bill 19-181 §4; https://www.denverpost.com/2019/05/06/colorado-oil-and-gas-local-regulations-181/.    [9]   Senate Bill 19-181 §4. [10]   C.R.S. 34-60-102 (2017). [11]   Senate Bill 19-181 §5. [12]   Senate Bill 19-181 §§8-9. [13]   C.R.S. 34-60-104 (2017). [14]   Senate Bill 19-181 §9. [15]   Senate Bill 19-181 §9(d). [16]   https://www.coloradopolitics.com/news/cogcc-solicits-application-for-full-time-commissioners/article_0c6e349a-42d3-11ea-b401-f3cbf6062c82.html. [17]   Senate Bill 19-181 §12. [18]   Senate Bill 19-181 §11. [19]   https://coloradosun.com/2020/04/24/zoom-colorado-oil-and-gas-rule-meeting/. [20]   Id. [21]   https://www.gjsentinel.com/breaking/cogcc-delays-action-on-first-sb-181-rules/article_7d09abd8-922c-11e9-b04d-6305eb780f5e.html. [22]   https://www.westword.com/news/colorado-oil-and-gas-environmental-groups-clash-in-first-round-of-sb-181-rulemaking-11384760. [23]   The 500 Series regulations and flowline regulations are available at 2 Code Colo. Regs. § 404-1-500 and 2 Code Colo. Regs § 404-1-1100, respectively. Both sets of regulations may be found online at: https://www.sos.state.co.us/CCR/GenerateRulePdf.do?ruleVersionId=8521&fileName=2%20CCR%20404-1. [24]   https://cogcc.state.co.us/documents/sb19181/Overview/SB_19_181_Rulemaking_Update_20190801.pdf; https://cogcc.state.co.us/sb19181_calendar.html#/rulemaking_mission_change. [25]   https://cogcc.state.co.us/documents/media/Press_Release_SB_19_181_Rulemaking_Updates_20200316.pdf. [26]   https://cogcc.state.co.us/sb19181_calendar.html#/rulemaking_wellbore_integrity. [27]   https://www.bizjournals.com/denver/news/2020/04/29/colorado-oil-and-gasregulator-puts-off-hearings.html ?ana=e_ae_prem&j=90506159&t=Afternoon&mkt_tok=eyJpIjoiTWpWbFlXSmxaR1JrTldZ MyIsInQiOiI2bk9PeE1GN3JIbnZ5K1pUcE8yMlJHdGh1cGJ3dFozTW9TcjhBd3JMdzBJeldrbE11 WkJhZjNBYU5ZcVwvNFMwcGpkelpkMjVialhLclBMWDFabVUxQWpqelVUblZIV0ZhN3BEODF sUmlONVRSQ1ZrVWQ4MG1YaTNuSmVkWFJrcTZmUnZnMDZcL1BxNjNcL0NQa3BhbUZ0SFE9PSJ9. [28]   https://cogcc.state.co.us/documents/media/Press_Release_RM_&_PC_Update_April_Hearing_20200429.pdf. [29]   https://coloradosun.com/2020/04/24/zoom-colorado-oil-and-gas-rule-meeting/. [30]   5 Code Colo. Regs. § 1001-9; https://www.colorado.gov/pacific/cdphe/news/oil-and-gas-rulemaking. [31]   5 Code Colo. Regs. § 1001-9; https://www.colorado.gov/pacific/cdphe/news/oil-and-gas-rulemaking; https://www.denverpost.com/2019/12/17/colorado-oil-gas-regulations-air-quality/. [32]   https://www.colorado.gov/pacific/cdphe/news/climate-change-actions. [33]   https://www.coloradopolitics.com/news/boulder-county-commissioners-extend-oil-gas-moratorium/article_61dd130a-5d7d-11ea-995b-27efc3ba5399.html; https://www.denverpost.com/2019/06/28/boulder-county-oil-gas-moratorium/. [34]   https://www.bouldercounty.org/news/boulder-county-commissioners-extend-oil-and-gas-moratorium-to-july-31-2020/. [35]   City of Fort Collins v. Colo. Oil & Gas Ass’n, 369 P.3d 586 (Colo. 2016); City of Longmont v. Colo. Oil & Gas Ass’n, 369 P.3d 573 (Colo. 2016). [36]   Our Health, Our Future, Our Longmont v. Colorado, 2020cv30033 (Dist. Ct., Boulder Cty.). [37]   https://www.coga.org/uploads/1/2/2/4/122414962/sb19-181_summary_3-15-19.pdf. [38]   https://coloradosun.com/2019/08/05/colorado-oil-gas-rules-patchwork-sb181/. [39]   https://news.kgnu.org/2017/03/new-boulder-county-oil-gas-regulations-called-toughest-in-the-state/; https://www.denverpost.com/2017/03/24/new-boulder-county-oil-and-gas-rules/. [40]   https://assets.bouldercounty.org/wp-content/uploads/2020/03/dc-19-0002-summary-and-draft-text-amendments-20200306.pdf. [41]   https://www.cpr.org/2019/08/30/colorados-oil-and-gas-regulators-will-be-on-the-clock-to-review-weld-countys-permits/. [42]   https://www.bizjournals.com/denver/news/2019/11/08/colorado-oil-and-gas-well-permitting-post-reform.html. [43]   Id. [44]   https://cogcc.state.co.us/documents/sb19181/Guidance/SB_19_181_Guidance_20190529.pdf; https://www.ogj.com/general-interest/article/17279237/cogcc-issues-interim-guidelines-as-it-develops-new-regulations. [45]   Id. [46]   https://www.bizjournals.com/denver/news/2019/11/08/colorado-oil-and-gas-well-permitting-post-reform.html; https://www.bizjournals.com/denver/news/2019/04/12/big-changes-ahead-for-oil-but-a-slowdown-isnt-one.html. [47]   https://www.colorado.edu/business/sites/default/files/attached-files/2020_colo_business_econ_outlook.pdf. [48]   Id. [49]   https://www.cpr.org/2020/01/07/despite-prop-112s-loss-colorados-fracking-foes-are-back-with-6-new-ballot-measures/.
Gibson Dunn’s lawyers are available to assist in addressing any questions you may have regarding these developments. Please contact the Gibson Dunn lawyer with whom you usually work, any member of the firm's Oil and Gas practice group, or the following authors: Beau Stark - Denver (+1 303-298-5922, bstark@gibsondunn.com) Fred Yarger - Denver (+1 303-298-5706, fyarger@gibsondunn.com) Graham Valenta - Houston (+1 346-718-6645, gvalenta@gibsondunn.com) Please also feel free to contact any of the following in the firm's Oil and Gas group: Michael P. Darden - Houston (+1 346-718-6789, mpdarden@gibsondunn.com) Tull Florey - Houston (+1 346-718-6767, tflorey@gibsondunn.com) Hillary H. Holmes - Houston (+1 346-718-6602, hholmes@gibsondunn.com) Shalla Prichard - Houston (+1 346-718-6644, sprichard@gibsondunn.com) Doug Rayburn - Dallas (+1 214-698-3442, drayburn@gibsondunn.com) Gerry Spedale - Houston (+1 346-718-6888, gspedale@gibsondunn.com) © 2020 Gibson, Dunn & Crutcher LLP Attorney Advertising:  The enclosed materials have been prepared for general informational purposes only and are not intended as legal advice.

April 24, 2020 |
Gibson Dunn Earns 84 Top-Tier Rankings in Chambers USA 2020

In its 2020 edition, Chambers USA: America’s Leading Lawyers for Business awarded Gibson Dunn 84 first-tier rankings, of which 31 were firm practice group rankings and 53 were individual lawyer rankings. Overall, the firm earned 302 rankings – 84 firm practice group rankings and 218 individual lawyer rankings. Gibson Dunn earned top-tier rankings in the following practice group categories: National – Antitrust National – Antitrust: Cartel National – Appellate Law National – Corporate Crime & Investigations National – FCPA National – Outsourcing National – Product Liability: Consumer Class Actions National – Real Estate National – Retail: Corporate & Transactional National – Securities: Regulation CA – Antitrust CA – IT & Outsourcing CA – Litigation: Appellate CA – Litigation: General Commercial CA – Litigation: Securities CA – Litigation: White-Collar Crime & Government Investigations CA – Real Estate: Zoning/Land Use CA (Los Angeles & Surrounds) – Employee Benefits & Executive Compensation CA – Real Estate: Northern California CA – Real Estate: Southern California CO – Litigation: White-Collar Crime & Government Investigations CO – Natural Resources & Energy DC – Corporate/M&A & Private Equity DC – Labor & Employment DC – Litigation: General Commercial DC – Litigation: White-Collar Crime & Government Investigations NY – Litigation: General Commercial: The Elite NY – Real Estate: Mainly Corporate & Finance NY – Technology & Outsourcing TX – Antitrust This year, 156 Gibson Dunn attorneys were identified as leading lawyers in their respective practice areas, with some ranked in more than one category. The following lawyers achieved top-tier rankings:  D. Jarrett Arp, Michael Bopp, Theodore Boutrous, Jessica Brown, Jeffrey Chapman, Linda Curtis, Michael P. Darden, Patrick Dennis, Mark Director, Thomas Dupree, Scott Edelman, Miguel Estrada, Stephen Fackler, Sean Feller, Eric Feuerstein, Amy Forbes, Stephen Glover, Richard Grime, Peter Hanlon, Hillary Holmes, Daniel Kolkey, Brian Lane, Jonathan Layne, Ray Ludwiszewski, Karen Manos, Randy Mastro, Cromwell Montgomery, Stephen Nordahl, Theodore Olson, Richard Parker, William Peters, Tomer Pinkusiewicz, Jesse Sharf, Orin Snyder, George Stamas, Beau Stark, Charles Stevens, Daniel Swanson, Steven Talley, Helgi Walker, Robert Walters, F. Joseph Warin, Debra Wong Yang, and Meryl Young.

April 22, 2020 |
Webcast: Public Energy Company Briefing: Considerations for First Quarter 2020 Reports and Board Meetings

As oil and gas companies enter the first quarterly reporting cycle in the current industry downturn, please join members of Gibson Dunn’s Securities Regulation and Corporate Governance, Capital Markets, Business Restructuring and Oil and Gas Practice Groups as they provide both practical advice and information about the latest legal developments. Specifically, the panelists discuss:

  • Disclosure considerations for your first quarter earnings release and Form 10-Q
  • Navigating securities laws and good governance during a crisis
  • Planning for hostile bids, shareholder activism and related defenses
  • Fulfilling fiduciary duties in the challenging environment
View Slides (PDF)

PANELISTS: Hillary H. Holmes is a partner in the Houston office of Gibson, Dunn & Crutcher, Co-Chair of the firm’s Capital Markets practice group, and a member of the firm’s Securities Regulation and Corporate Governance, Oil and Gas, M&A and Private Equity practice groups. Ms. Holmes advises companies in all sectors of the energy industry on long-term and strategic capital planning, disclosure and reporting obligations under U.S. federal securities laws and corporate governance issues. She represents issuers, underwriters, MLPs, private investors, management teams and private equity firms in all forms of capital markets transactions. She also advises boards of directors, special committees and financial advisors in transactions and situations involving complex issues and conflicts of interest. James J. Moloney is a partner in the Orange County office of Gibson Dunn and serves as Co-Chair of the firm’s Securities Regulation and Corporate Governance Practice Group.  His practice focuses primarily on securities offerings, mergers & acquisitions, friendly and hostile tender offers, proxy contests, going-private transactions and other corporate matters. Mr. Moloney was with the SEC in Washington, D.C. for six years before joining Gibson Dunn.  He served his last three years at the Commission as Special Counsel in the Office of Mergers & Acquisitions in the Division of Corporation Finance.  In addition to reviewing merger transactions, Mr. Moloney was the principal draftsman of Regulation M-A, the comprehensive set of rules relating to takeovers and shareholder communications.  He advises a wide range of public companies on reporting and other obligations under the securities laws, the establishment of corporate compliance programs, and continued compliance with corporate governance standards under the securities laws and stock exchange rules. Ronald Mueller is a partner in the Washington, D.C. office of Gibson Dunn and a founding member of the firm’s Securities Regulation and Corporate Governance practice group. He advises public companies on a broad range of SEC disclosure and regulatory matters, executive and equity-based compensation issues, and corporate governance and compliance issues and practices. He advises some of the largest U.S. public companies on SEC reporting, proxy disclosures and proxy contests, shareholder engagement and shareholder proposals, and insider trading and Section 16 reporting and compliance. He also advises on many corporate governance matters, including governing documents for companies, boards, and board committees, such as bylaws and committee charters, director independence and related party transaction issues, and corporate social responsibility. Michael A. Rosenthal is a partner in the New York office of Gibson, Dunn & Crutcher and Co-Chair of Gibson Dunn’s Business Restructuring and Reorganization Practice Group.  Mr. Rosenthal has extensive experience in reorganizing distressed businesses and related corporate reorganization and debt restructuring matters.  He has represented complex, financially distressed companies, both in out-of-court restructurings and in pre-packaged, pre-negotiated and freefall chapter 11 cases, acquirors of distressed assets and investors in distressed businesses.  Mr. Rosenthal’s representations have spanned a variety of business sectors, including investment banking, private equity, energy, retail, shipping, manufacturing, real estate, engineering, construction, medical, airlines, media, telecommunications and banking. Gerry Spedale is a partner in the Houston office of Gibson, Dunn & Crutcher.  He has a broad corporate practice, advising on mergers and acquisitions, joint ventures, capital markets transactions and corporate governance. He has extensive experience advising public companies, private companies, investment banks and private equity groups actively engaging or investing in the energy industry. His over 20 years of experience covers a broad range of the energy industry, including upstream, midstream, downstream, oilfield services and utilities.
MCLE INFORMATION: This program has been approved for credit in accordance with the requirements of the New York State Continuing Legal Education Board for a maximum of 0.5 credit hour, of which 0.5 credit hour may be applied toward the areas of professional practice requirement.  This course is approved for transitional/non-transitional credit. Attorneys seeking New York credit must obtain an Affirmation Form prior to watching the archived version of this webcast. Please contact Victoria Chan (Attorney Training Manager) at vchan@gibsondunn.com to request the MCLE form. Gibson, Dunn & Crutcher LLP certifies that this activity has been approved for MCLE credit by the State Bar of California in the amount of 0.75 hour. California attorneys may claim “self-study” credit for viewing the archived version of this webcast.  No certificate of attendance is required for California “self-study” credit.

April 14, 2020 |
Force Majeure Primer and Flowchart for Oil and Gas Leases

Click for PDF Within the oil and gas industry, force majeure clauses are often (but not always) included in oil and gas leases where they play an important role.[1]  These clauses provide generally that, under certain circumstances, a lessee may be relieved from the consequences of a failure to comply with the terms of the lease due to the occurrence of an unforeseen event, even where the resulting liability might otherwise include damages or the forfeiture of the lease. Assessing the applicability and enforceability of such clauses in oil and gas leases requires a highly fact-specific analysis.  To assist clients in identifying issues they should evaluate in connection with their lease obligations in the face of the pandemic, we have prepared the following five-step analysis and flowchart to assist in the review and assessment of force majeure clauses in your oil and gas leases. STEP 1: Does COVID-19 trigger the force majeure clause? As an initial matter, the application of a force majeure clause depends on the specific language of such clause in the lease, which can vary considerably from lease to lease.  Therefore, the precise words of your force majeure clause should first be closely reviewed to determine whether one or more of the categories included within the enumerated causes could cover the current pandemic, its effects or responses to it.[2] In some general commercial contracts, the force majeure clause will reference an “epidemic,” “pandemic,” “disease outbreak” or even “public health crisis” as a triggering event giving rise to a force majeure.  However, in our experience, the inclusion of such terms in oil and gas leases are rare.  More commonly, force majeure clauses in oil and gas leases specifically refer to triggering events like “acts of civil or military authority” or “government orders or regulations,” both of which may be relevant under the current climate.  In an effort to “flatten the curve” and slow the spread of COVID-19, several states and jurisdictions have issued shelter-in-place or other stay-home orders to employees of nonessential businesses, which may in some cases include employees of oil and gas companies and associated contractors.  Therefore, when analyzing whether the force majeure clause in an oil and gas lease has been triggered, clients should evaluate any newly enacted restrictions to understand what, if any, impact they may have on the ability to comply with lease terms.  Another example of government orders which have been accepted as a force majeure event includes an interruption in operations caused by bankruptcy proceedings.[3]  Therefore, to the extent the lessee’s bankruptcy proceedings are hindering its drilling or production operations, the lessee may be able to seek relief under a force majeure claim.[4] STEP 2: Did COVID-19 effectively prevent performance by the lessee? Many force majeure clauses explicitly incorporate a performance standard that requires performance of contractual obligations be “prevented,” “delayed,” “interrupted” or made “impossible” as a result of the force majeure event before performance will be excused.  In this context, courts are reluctant to accept claims of a force majeure event when such event merely made performance more expensive or inconvenient, especially where the clause expressly requires performance to be made impossible.[5]  Under the same performance standard, a Texas court rejected a force majeure claim during an industry-wide scarcity of materials where the lessee nevertheless used its limited materials in its inventory to drill other leases but not the lease at issue in the dispute.[6]  Therefore, while COVID-19 may have resulted in supply chain disruptions which make it more difficult for lessees to obtain replacement parts in their drilling or production operations, it is necessary to evaluate whether performance really is impossible unless the force majeure clause in question contains a lesser performance standard. STEP 3: Does the force majeure clause contain any additional requirements (e.g., knowledge, control, due diligence)? If not, does your jurisdiction impose any additional requirements? Many force majeure clauses explicitly set forth additional requirements in order for lessees to be able to claim a force majeure event and obtain contractual relief from the consequences of the event. Three common additional requirements include that the force majeure event cannot have been foreseeable, must have been out of the lessee’s reasonable control and the lessee shall have exercised due diligence to overcome the condition claimed to be a force majeure event.  In some jurisdictions, courts will impose one or more of these requirements regardless of whether the lease expressly includes such a requirement. First, the unforeseeability requirement is often framed as a requirement that the force majeure event not have been within the lessee’s actual or presumed knowledge or reasonably expectable by the lessee.  And in the absence of express contractual language addressing knowledge, some courts have adopted an implicit requirement of unforeseeability.[7]  Thus, while it has been held that a government order postdating the execution of a lease may constitute a force majeure event,[8] a government order predating the lease execution is unlikely to constitute a force majeure event because it was knowable at the time of contracting.[9]  Therefore, to the extent a lease has been entered into since the outbreak of the virus, in certain jurisdictions, you may find it more challenging to allege that the effects of COVID-19 (including the resulting government regulations) were not reasonably expected at the time of entry into the lease.  Further, this unforseeability requirement is often cited by courts in rejecting claims that mere changes in commodity prices or reduction in demand constitute a force majeure event.[10]  As stated by a Texas appellate court, “fluctuations in the oil and gas markets are foreseeable as a matter of law.”[11]  Therefore, in order to obtain relief, the lessee must identify a permitted force majeure event (e.g., the pandemic) and prove that such permitted event and its consequences (which include a reduction in commodity prices and demand) resulted in the lessee’s inability to perform. Second, the requirement that the event have been beyond the reasonable control of the parties has led to  a division in the case law in terms of whether courts will impose such requirement in the absence of express contractual language.  Thus, some courts have adopted an implicit requirement that the condition alleged to constitute a force majeure event must be beyond the lessee’s reasonable control (with the lessee’s fault or negligence negatively affecting its claim to entitlement of relief).[12]  However, at least one Texas appellate court has held that a reasonable control requirement should not be implied in oil and gas leases in the absence of express language to that effect.[13] Third, the requirement that a party seeking to invoke force majeure exercise due diligence or explore all available options to overcome the condition prior to declaring an event a force majeure event is intended to be a “proximate cause” requirement.[14]  However, in the absence of express contractual language imposing such a requirement, at least one Texas appellate court has held that due diligence requirement should not be imposed on oil and gas leases absent express contractual language.[15] STEP 4: Is the obligation or performance in question covered by the force majeure clause? Upon establishing the occurrence of the force majeure event, the next step is examining the lease to determine the precise obligation or performance to be consequently excused.  The force majeure clause may explicitly suspend or excuse all of the lessee’s obligations,[16] or, more commonly, excuse only certain of the lessee’s obligations (e.g., the lessee’s obligation to drill or produce) while requiring the lessee to comply with certain other obligations (e.g., the lessee’s obligation to make certain payments to the lessor).[17]  Similarly, the lease may explicitly set forth which portion of the habendum clause that the force majeure event applies.  In these cases, where the provisions are explicit, the analysis is often relatively straightforward.  In other cases, the application of the force majeure clause is unclear, in which case legal analysis will need to be conducted to determine exactly what is being suspended or excused, and to what term of the habendum clause the force majeure event will apply.  For example, one court has held that to the extent (i) the habendum clause in the lease does not incorporate the force majeure clause by reference or contain any language expressly subjecting it to the other lease terms and (ii) the force majeure clause does not refer to the habendum clause with specificity (i.e., “anything in this lease to the contrary notwithstanding” being insufficient), the force majeure clause would not apply to extend the primary term.[18] Leases vary in either fixing the period of time for which the obligations are suspended or excused (e.g., one month, one year) or excuse performance for so long as the force majeure event inhibits performance (with or without a period of time within which the lessee must resume its obligations following the end of the event).  If your lease contains the latter provision, you should be particularly diligent in determining whether the circumstances have changed whereby the force majeure savings provision would no longer apply.[19] Finally, notwithstanding the foregoing, in an attempt to reconcile competing provisions of the lease and fulfill the intent of the contracting parties, courts will generally refuse to excuse performance under the force majeure clause if another clause is applicable, such as excusing production by the payment of shut-in royalties[20] or if the lease obligates the lessee to commence drilling or reworking operations within a certain amount of time following cessation of production and the force majeure event did not prevent the commencement of drilling or reworking operations.[21]  Therefore, the lease should be read holistically to determine the interaction of the force majeure clause with the other provisions of the lease. STEP 5: Are there contractual notice requirements? Force majeure clauses generally may require either (i) a minimum amount of notice ahead of an event contemplated by the lease or (ii) notice within a certain number of days of the triggering event.  Force majeure clauses in oil and gas leases are no exception.  Failure to provide timely notice may prohibit a lessee from obtaining the benefit of a force majeure clause in the agreement even when a triggering event is otherwise covered by the lease’s force majeure clause.[22]  Notice provisions may specify the form of the notice, to whom it must be sent, and the manner in which it must be sent.  Additionally, many agreements will require that notices given thereunder must provide sufficient specificity to make clear why the relevant triggering event applies to a given provision. Given the current work-from-home orders, it may be difficult to comply with all formal notice requirements in a contract, and clients may wish to propose alternative methods of providing notice with contract counterparties for so long as the current climate persists.  Gibson Dunn may also be able to assist clients with mailings—either notices required to be given or responses to notices received—especially where the client does not have an operational mailroom. ____________________________ Step 1. Does COVID-19 trigger the force majeure clause?[23]

Does the force majeure clause specifically reference an “epidemic,” “pandemic,” “disease outbreak,” or “public health crisis”? No ☐ Yes ☐ If yes, proceed to Step 2.
Does the force majeure clause refer specifically to “acts of civil or military authority” or “government order or regulation”? No ☐ Yes ☐ If yes, proceed to Step 2.
Does the force majeure clause have a catchall provision that covers “any other cause whatsoever beyond the control of the respective party” (or similar) and contains an enumeration of specific events that otherwise do not cover the current situation? No ☐ Yes ☐ If yes, the force majeure clause may not have been triggered because courts generally interpret force majeure clauses narrowly and will not construe a general catch-all provision to cover externalities that are unlike those specifically enumerated in the balance of the clause. But depending on the jurisdiction, if the failure to perform is caused by forces beyond the lessee’s control, a court may take into account traditional equitable principles in construing the lease provision in question or in applying some exception to it.
Step 2. Did COVID-19 effectively prevent performance by the lessee?
Does the force majeure clause require performance of obligations to be “prevented”, “delayed”, interrupted” or made “impossible” before contractual obligations are excused? No ☐ Yes ☐ If yes, the force majeure clause may have been triggered if the current government regulations specifically prohibit the fulfillment of contractual obligations.  Merely making performance more expensive or inconvenient, especially where the clause expressly requires performance to be made impossible, is likely insufficient. Proceed to Step 3.
Step 3. Does the force majeure clause contain any additional requirements (e.g., knowledge, control, due diligence)? If not, does your jurisdiction impose any additional requirements?
If the lease or applicable jurisdiction requires the force majeure event to not be within the lessee’s actual or presumed knowledge or reasonably expectable by the lessee, is this requirement satisfied? No ☐ Yes ☐ If yes, and the answers to the other questions in Step 3 are yes, proceed to Step 4.
If the lease or applicable jurisdiction requires the condition alleged to constitute a force majeure event be beyond the lessee’s reasonable control, is this requirement satisfied? No ☐ Yes ☐ If yes, and the answers to the other questions in Step 3 are yes, proceed to Step 4.
If the lease or applicable jurisdiction requires the lessee to exercise due diligence or explore all available options to overcome the condition prior to declaring an event a force majeure event, is this requirement satisfied? No ☐ Yes ☐ If yes, and the answers to the other questions in Step 3 are yes, proceed to Step 4.
Step 4. Is the obligation or performance in question covered by the force majeure clause?
Is the obligation or performance in question covered by the force majeure clause? No ☐ Yes ☐ If yes, and the answer to the other question in Step 4 is no, proceed to Step 5.
Is the obligation or performance in question covered another clause of the lease? No ☐ Yes ☐ If yes, courts will generally refuse to excuse performance under the force majeure clause, and you will be expected to comply with the obligation or performance requirement set forth in the other clause of the lease. If no, and the answer to the other question in Step 4 is yes, proceed to Step 5.
Step 5. Are there contractual notice requirements?
Does the lease require notice? No ☐ Yes ☐ If yes, timely notice must be provided in accordance with the notice provision, or termination may not be available even though a triggering event has occurred.  Some notice provisions required notice in advance of performance due.  Others required notice within a certain number of days of the triggering event.
Does the contract contain specific provisions for the method of notice? No ☐ Yes ☐ If yes, notice provisions may specify the form of the notice, to whom it must be sent, and the manner in which it must be sent.  Specific notice language may also be required.
Does the contract require specific language to give notice of a force majeure event? No ☐ Yes ☐ If yes, determine whether required wording is present in any notice.  Some leases may even have form of notices attached as exhibits to the contract.
Does the contract specify a specific method for delivery of such notice? No ☐ Yes ☐ If yes, notice may be required by email, priority mail, or through use of a particular form addressed to specific people.
____________________    [1]   Whether or not the lease contains a force majeure clause, if the failure to perform is caused by forces beyond the lessee’s control, a court may take into account traditional equitable principles in construing the lease provision in question or in applying some exception to it.  See 4 Kuntz, Law of Oil and Gas § 53.5 (2019).    [2]   See, e.g., Sun Operating Ltd. Partnership v. Holt, 984 S.W.2d 277, 283 (Tex. App. Amarillo 1988) (“[The] scope and application [of a force majeure clause], for the most part, is utterly dependent upon the terms of the contract in which it appears.”).    [3]   See, e.g., Gilbert v. Smedley, 612 S.W.2d 270 (Tex. Civ. App. Fort Worth 1981).    [4]   If the force majeure clause references “pricing fluctuation” or “market conditions”, then the lessee may be able to claim a force majeure event.  See In Kodiak 1981 Drilling Partnership v. Delhi Gas Pipeline Corp., 736 S.W.2d 715, 721 (Tex. App.—San Antonio 1987) (holding that a force majeure clause that included “partial or total loss of gas supply or market” excused performance due to “an unprecedented combination of factors—a general economic recession, a plummeting crude oil price, weather conditions ….”).  However, in our experience, the inclusion of such terms in oil and gas leases are rare.    [5]   See, e.g., Logan v. Blaxton, 71 So.2d 675 (La. Ct. App. 1954); San Mateo Community College Dist. v. Half Moon Bay Ltd. Partnership, 65 Cal. Rptr. 2d 287 (Cal. App. 1st Dist. 1998).    [6]   See Gilbert v. Smedley, 612 S.W.2d 270 (Tex. Civ. App. Fort Worth 1981).    [7]   See, e.g., TEC Olmos, LLC v. ConocoPhillips Company, 555 S.W.3d 176, 185 (Tx. Ct. App. 2018) (“a ‘catch-all’ provision [in the force majeure clause] generally requires a showing of unforeseeability”); Gulf Oil Corp. v. Federal Energy Regulatory Comm., 706 F.2d 444, 454 (3d Cir. 1983) (“Even presuming that [the lessee’s] routine mechanical repairs were within the ambit of the force majeure clause, their frequent, almost predictable, occurrence takes them outside of a force majeure excuse to nonperformance.”); Baldwin v. Kubetz, 307 P.2d 1005 (Cal. Ct. Appeals 1957) (the lessee “acquired [the lease] with knowledge of the necessity of procuring a [drilling permit]” and “his failure to perform this obligation does not justify his falling back” on utilizing the force majeure clause).    [8]   See, e.g., Frost National Bank v. Matthews, 713 S.W.2d 365 (Tex. App. Texarkana 1986); Gordon v. Crown Cent. Petroleum Co., 679 S.W.2d 192 (Ark. 1984).    [9]   See, e.g., Goldstein v. Lindner, 648 N.W.2d 892 (Wis. Ct. App. 2002) (holding that parties to an oil and gas lease are presumed to know what laws and regulations will affect the lessee’s ability to win permits); Hughes v. Cantwell, 540 S.W.2d 742 (Tex. Civ. App. El Paso 1976) (holding that the force majeure clause did not operate to extend the lease where the railroad commission’s spacing rules for gas wells were presumably known to the parties at the time they entered into the lease). [10]   See, e.g., Valero Transmission Co. v. Mitchell Energy Co., 743 S.W.2d 658 (Tex. App. Houston 1987); Langham Hill Petroleum, Inc. v. S Fuels Co., 813 F.2d 1327 (4th Cir. 1987). [11]   See TEC Olmos, LLC v. ConocoPhillips Company, 555 S.W.3d 176, 184 (Tx. App. Houston 2018). [12]   See, e.g.,  Perlman v. Pioneer Ltd. Partnership, 918 F.2d 1244 (5th Cir. 1990) (holding that, notwithstanding new regulations by the state, the lessee made no effort whatsoever to take actions necessary to comply with state’s requirements); Atkinson Gas Co. v. Albrecht, 878 S.W.2d 236 (Tex. App. Corpus Christi 1994) (holding that the lessee was not relieved of its duty to produce by virtue of the force majeure clause of the lease where the lessee’s own conduct in failing to timely file production reports with the railroad commission caused it to order the well sealed). [13]   See Sun Operating Ltd. Partnership v. Holt, 984 S.W.2d 277, 285 (Tex. App. Amarillo 1998) (holding that whether the occurrence of the listed force majeure event must be beyond the reasonable control of the lessee depends upon the language of the applicable force majeure clause). [14]   See, e.g., Wilson v Talbert, 535 S.W.2d 807 (Ark. 1976); Logan v. Blaxton, 71 So.2d 675 (La. App. 2d Cir. 1954); Woods v. Ratliff, 407 So.2d 1375 (La. App. 3d Cir. 1981). [15]   See Moore v. Jet Stream Investments, Ltd., 261 S.W.3d 412 (Tex. App. Texarkana 2008). [16]   See, e.g., Baldwin v. Kubetz, 307 P.2d 1005 (Cal. App. 2d. 1957). [17]   See, e.g., Hunter v. Vaughn, 46 So.2d. 735 (La. 1950); Illinois Mid-Continent Co. v. Tennis, 102 N.E.2d 390 (Ind. App. 1951); Huhn v. Marshall Exploration, Inc., 337 So.2d. 561 (La. App. 2d Cir. 1976). [18]   See Beardslee v. Inflection Energy, LLC, 31 N.E.3d 80 (N.Y.3d 2015).  See also Illinois Mid-Continent Co. v. Tennis, 102 NE(2d) 390 (1951) (holding that a force majeure clause which specifically related to “drilling obligations” did not serve to extend the primary term of the lease where drilling was frustrated in the last year of the lease). [19]   See, e.g., Wilson v Talbert, 535 S.W.2d 807 (Ark. 1976) (holding that, notwithstanding the force majeure clause providing that the lease will not terminate as a result of a temporary cessation of production because a breakdown of equipment, the lease nevertheless terminated because the lessee failed to make the necessary repairs and restore production within a reasonable time). [20]   See Welsch v. Trivestco Energy Co., 221 P.3d 609 (Kan. App. 2009) (the unavailability of purchasing and transportation services did not prevent the lessee from paying shut-in royalties and the force majeure clause was therefore not triggered). [21]   See Trinidad Petroleum Corp. v. Pioneer Natural Gas Co., 416 So.2d 290 (La. Ct. App. 1982). [22]   See Toyomenka Pac. Petroleum, Inc. v. Hess Oil Virgin Is. Corp., 771 F. Supp. 63, 67–68 (S.D.N.Y. 1991) (noting that a force majeure notification outside the limits of a notice period may waive the applicability of the force majeure clause if the parties intended the notice period as a condition precedent to the clause). [23]   As noted above, if the lease does not have a force majeure clause, an analysis using traditional equitable principles, depending on the jurisdiction, may be warranted.
Gibson Dunn’s lawyers are available to assist with questions you may have regarding developments related to the COVID-19 outbreak.  We regularly counsel clients on issues raised by this pandemic in the commercial context, including in the oil and gas industry.  For additional information, please contact any member of the firm’s Coronavirus (COVID-19) Response Team, the Oil & Gas Team, the Gibson Dunn attorney with whom you work, or the following authors: Authors:  Shireen Barday, Michael Darden, Hillary Holmes, Louis Matthews and Nathan Strauss © 2020 Gibson, Dunn & Crutcher LLP Attorney Advertising:  The enclosed materials have been prepared for general informational purposes only and are not intended as legal advice.

April 13, 2020 |
Best Lawyers in Singapore 2021 Recognizes Five Gibson Dunn Attorneys

Best Lawyers in Singapore 2021 has recognized five Gibson Dunn attorneys as leading lawyers in their respective practice areas: Troy Doyle – Insolvency and Reorganization Law; Jai Pathak – Banking and Finance and Mergers and Acquisitions Law; Brad Roach– Energy Law and Mergers and Acquisitions Law; Saptak SantraBanking and Finance and Energy Law; and Jamie Thomas – Banking and Finance. The guide was published April 9, 2020.

April 3, 2020 |
Gibson Dunn Deal Receives Honorable Mention in Asian-Mena Counsel Magazine

Asian-mena Counsel recognized Murphy Oil’s $2.127 billion divestment of its entire Malaysian operations to PTT Exploration and Production Company Limited (PTTEP), the publicly listed subsidiary of Thailand’s national oil company, PTT, with an honorable mention in its Deals of the Year for 2019. Gibson Dunn represented Murphy Oil on this deal.  The transaction was the largest oil and gas M&A transaction in Southeast Asia in the past 5 years, and the largest oil and gas M&A transaction in Malaysia’s history. The feature was published on April 2, 2020. The Gibson Dunn team was led by Singapore partner Brad Roach, and the corporate transactional team included Singapore associate Alexandra Jones, London partner James Howe, London associates Amar Madhani and Mitasha Chandok, Denver associates Melissa Persons and Graham Valenta, Houston partner Gerry Spedale and Hong Kong associate Winson Chu. London partner Sandy Bhogal and London associate Panayiota Burquier provided assistance on tax matters.  Washington, D.C. partner Michael Collins provided assistance on employment matters.

Oil and Gas Restructuring Support Team

Gibson Dunn lawyers have deep roots in the oil and gas industry, one of the premier U.S. corporate restructuring and reorganization practices and the nation’s leading litigation practice. The Business Restructuring and Reorganization group was named one of Law360’s top bankruptcy practice groups, the Oil and Gas group has been named practice group of the year, and members of both groups have been widely recognized by top industry publications, including Chambers, Legal 500 and The Guide to the World’s Leading Insolvency Lawyers.  Dubbed the “rescue squad” by The American Lawyer, our litigators are deeply skilled in prosecuting and defending the broad range of disputes that arise during the course of a bankruptcy case.  Our litigation practice was named The American Lawyer's Litigation Department of the Year 4 times out of the last 6 years. Our restructuring lawyers are at the center of work outs, in and out of court, of companies with highly complex, multibillion-dollar capital debt stacks. These lawyers regularly represent companies in financial distress or seeking options during challenging financial circumstances, their creditors (ad hoc lender and bondholder groups and official creditor committees) and investors  in the largest and most complex out-of-court restructurings and Chapter 11 bankruptcy cases in the US and around the world.  In oil and gas restructuring, efforts to build consensus can be supplemented by Gibson Dunn’s extraordinary bankruptcy litigators when a negotiated resolution cannot be reached.  Working with our firm’s Mergers and Acquisitions group, we represent both acquirers and companies seeking to be acquired or to spin off assets, both in and out of bankruptcy court. Gibson Dunn is recognized for excelling in the use of innovative ideas and adaptive strategies, including in advance of any actual restructuring needs. Our Oil and Gas lawyers have extensive experience advising clients on a comprehensive range of matters across the entire oil and gas value chain – from well‐head to LNG, refining and petrochemicals – including acquisitions, divestitures, financings, reorganizations and project work in the upstream, midstream, downstream, LNG and oilfield services segments of the business. This makes Gibson Dunn one of the rare global law firms with a true oil and gas practice capable of providing the full array of legal services needed by any company debtor, creditor group or investor, in any challenging or distressed situation.


Oil and Gas Restructuring Support Core Team Members:

Oil & Gas Business Restructuring and Reorganization Restructuring Litigation
Michael P. Darden David M. Feldman Shireen A. Barday
Hillary Holmes Scott J. Greenberg Jennifer L. Conn
Tull Florey Jeffrey A. Chapman Mitchell Karlan
Anna Howell James Chenoweth Marshall R. King
Elizabeth A. Ising Matthew K. Kelsey Mark A. Kirsch
Robert B. Little Jeffrey C. Krause Randy M. Mastro
Ronald O. Mueller Robert Klyman Matthew D. McGill
Robert L. Nelson Jr. Keith R. Martorana Robert Weigel
Shalla Prichard Michael A. Rosenthal
Gerald Spedale Matt J. Williams
Beau Stark
Steven Talley
Jonathan Whalen
Robyn Zolman

March 4, 2020 |
Webcast: Current Developments in Capital Markets Transactions in the Oil and Gas Industry

Please join our panel as they discuss current developments in capital markets in the oil and gas industry. Specifically, the panelists will provide insights, updates and practical guidance regarding market conditions, preferred equity, high-yield bonds, and SPACs. They also explore developing approaches to raising capital in the industry such as rights offerings and direct listings. View Slides (PDF)



PANELISTS: Michael Casey is a Partner and Managing Director in the Houston office of Goldman Sachs & Co. He has over 20 years of energy investment banking experience and has advised on a variety of capital raising and strategic transactions. Michael has broad capital raising and financing experience across equity and debt markets, both public and private, as well as joint ventures and private equity investments. In addition to his financing transaction experience, Michael has significant experience in M&A, having advised on numerous public company mergers, as well as advising both sellers and buyers on private company and asset transactions. Hillary H. Holmes is a partner in the Houston office of Gibson, Dunn & Crutcher and Co-Chair of the firm’s Capital Markets practice group. Ms. Holmes advises companies in all sectors of the energy industry on long-term and strategic capital planning, disclosure and reporting obligations under U.S. federal securities laws, corporate governance and M&A transactions. She represents issuers, underwriters, MLPs, financial advisors, private investors, management teams and private equity firms in all forms of capital markets transactions. Her experience comprises IPOs, registered offerings of debt and equity securities, private placements of debt and equity securities, structured preferred equity, joint ventures and private equity investments. She frequently advises boards of directors, special committees, and financial advisors in M&A transactions involving conflicts of interest or unique complexities. Doug Rayburn is a partner in the Dallas and Houston offices of Gibson, Dunn & Crutcher. His principal areas of concentration are securities offerings, mergers and acquisitions and general corporate matters. He has represented issuers and underwriters in over 200 public offerings and private placements, including initial public offerings, high yield offerings, investment grade and convertible note offerings, offerings by MLPs, and offerings of preferred and hybrid securities. Additionally, Mr. Rayburn represents purchasers and sellers in connection with mergers and acquisitions involving both public and private companies, including private equity investments and joint ventures. His practice also encompasses corporate governance and other general corporate concerns. Gerry Spedale is a partner in the Houston office of Gibson, Dunn & Crutcher. He has a broad corporate practice, advising on mergers and acquisitions, joint ventures, capital markets transactions and corporate governance. He has extensive experience advising public companies, private companies, investment banks and private equity groups actively engaging or investing in the energy industry. His over 20 years of experience covers a broad range of the energy industry, including upstream, midstream, downstream, oilfield services and utilities.
MCLE CREDIT INFORMATION: This program has been approved for credit in accordance with the requirements of the New York State Continuing Legal Education Board for a maximum of 1.0 credit hour, of which 1.0 credit hour may be applied toward the areas of professional practice requirement.  This course is approved for transitional/non-transitional credit. Attorneys seeking New York credit must obtain an Affirmation Form prior to watching the archived version of this webcast. Please contact Victoria Chan (Attorney Training Manager) at vchan@gibsondunn.com to request the MCLE form. Gibson, Dunn & Crutcher LLP certifies that this activity has been approved for MCLE credit by the State Bar of California in the amount of 1.0 hour. California attorneys may claim “self-study” credit for viewing the archived version of this webcast.  No certificate of attendance is required for California “self-study” credit.