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August 15, 2019 |
Gibson Dunn Lawyers Recognized in the Best Lawyers in America® 2020

The Best Lawyers in America® 2020 has recognized 158 Gibson Dunn attorneys in 54 practice areas. Additionally, 48 lawyers were recognized in Best Lawyers International in Belgium, Brazil, France, Germany, Singapore, United Arab Emirates and United Kingdom.

June 25, 2019 |
In the Pipeline: Understanding Post-Sabine Midstream Contract Rejection Risk

Click for PDF After a significant wave in 2015 and 2016, bankruptcy filings in the exploration and production (“E&P”) sector of the oil and gas industry temporarily leveled off. With sustained volatility in energy prices and a trend of increased leverage among borrowers, stakeholders in the sector would be well advised to prepare for the potential risks of any further E&P distress. The landmark decisions in the chapter 11 case of Sabine Oil & Gas Corporation established both a substantive precedent and a procedural template regarding bankrupt E&P debtors’ attempts to reject burdensome contracts with midstream services providers. Understanding both the applicable legal framework and procedural considerations that will govern future rejection disputes will be critical to strategic positioning ahead of the next wave of distress in the E&P sector. Background: Rejection of Executory Contracts and Midstream Services Agreements The Bankruptcy Code provides a mechanism for debtors to reject executory contracts, relieving the debtor from its future performance obligations thereunder and leaving the contractual counterparty with a prepetition claim against the debtor for breach of contract. Section 365(a) of the Bankruptcy Code allows a debtor in possession, “subject to the court’s approval,” to “assume or reject any executory contract.”[1] While the Bankruptcy Code does not define “executory contract,” most courts use the definition of a contract under which both parties have unperformed obligations where the failure of either party to complete performance would constitute a material breach excusing the performance of the other party.[2] In determining whether to approve a motion to assume or reject such a contract, courts evaluate whether the proposed assumption or rejection is a reasonable exercise of the debtor’s business judgment. Absent the involvement of certain types of contractual counterparties that receive special Bankruptcy Code protections, “the interests of the debtor and its estate are paramount; adverse effects on the non-debtor contract party arising from the decision to assume or reject are irrelevant.”[3] Given the significant volatility in oil and gas prices and the structure of midstream services contracts—which typically require the producing company to either deliver a minimum production volume or pay a deficiency payment—the ability to reject contracts is a critical tool for an E&P debtor seeking to use chapter 11 of the Bankruptcy Code to restructure burdensome obligations. From midstream providers’ perspective, rejection is inappropriate because the agreements at issue provide them with not only contractual promises of payment, but also dedications of underlying oil and gas mineral rights and associated acreage; in other words, the agreements convey real property interests. Courts have generally held that real property interests cannot be rejected because they do not involve future material, reciprocal obligations.[4] Thus, midstream providers, which generally incur substantial up-front costs through infrastructure investments in connection with their contracts, argue that permitting rejection upsets their (and their secured lenders’) business expectations that their dedications will remain in place and bind any successors to the subject mineral interests, even if the counterparty is reorganized under chapter 11 of the Bankruptcy Code. During the 2015-16 wave of oil and gas bankruptcies, disputes frequently arose over whether midstream services contracts are executory contracts that can be rejected, or contracts containing real property covenants that “run with the land,” rendering the contract ineligible for rejection.[5] A series of decisions in the Sabine bankruptcy addressed this issue on the merits and the federal courts, applying their interpretation of Texas law, concluded that a group of midstream contracts did not include rights in favor of the service-prover that ran with the land, and therefore could be rejected.[6] The Sabine Decisions The rejection dispute in Sabine involved several contracts between the debtor, a Texas-based onshore oil and gas exploration and production company, and two midstream gathering service providers: Nordheim Eagle Ford Gathering, LLC (“Nordheim”) and HPIP Gonzalez Holdings, LLC (“HPIP”). Under each contract, Sabine agreed to deliver all gas and condensate that it produced in certain “dedicated” areas to Nordheim and HPIP, respectively, for gathering, transportation, and processing. Under each contract, Sabine paid monthly gathering fees and was further required to make deficiency payments to the extent that it failed to deliver certain minimum amounts of gas and condensate on an annual basis. In seeking to reject the contracts, the debtors argued that because of the substantial and sustained decline in gas prices, it was no longer financially viable to deliver the minimum amounts under the contracts, and the resulting deficiency obligations would impose a considerable and unnecessary drain on the estate’s resources. As a threshold matter, the bankruptcy court found the decision to reject was a reasonable exercise of the debtors’ business judgment.[7] However, both Nordheim and HPIP argued that certain covenants under the agreement, including Sabine’s dedication of the specified production areas, “ran with the land” and thus could not be rejected. Each of the agreements was governed by Texas law. Under Texas law, in order for a covenant to “run with the land”, it must, among other things, “touch and concern the land.”[8] While the issue is not clearly settled, some Texas courts have also imposed a further requirement of “horizontal privity of estate,” which generally requires “simultaneous existing interests or mutual privity between the original covenanting parties as either landlord and tenant or grantor and grantee.”[9] Because the midstream providers did not identify any governing authority rejecting the horizontal privity requirement, the Sabine bankruptcy court analyzed the issue and concluded that such privity was absent because the covenants at issue did not reserve any interest in the subject real property.[10] The bankruptcy court further held that the covenants did not “run with the land,” finding that the covenants did not “touch and concern the land”. Citing Fifth Circuit precedent, the court explained that it is not enough for a covenant to “affect the value of the land,” and that it must “‘affect the owner’s interest in the property or its use in order to be a real covenant.’”[11] The court further noted that under Texas law, minerals cease to be real property and instead become personal property once they are extracted from the ground.[12] Because the covenants concerned only Sabine’s interest in personal property—i.e., the extracted gas and condensate—and did not affect its interest in the relevant real property—i.e., the “dedicated” land—the court held that the contractual dedication did not burden Sabine’s property interest in the land, but rather identified personal property that was subject to the agreements. The bankruptcy court also focused on the fact that the dedication covenants were triggered not by any action on the dedicated land, but rather by the receipt or storage of the subject products by the midstream providers.[13] This distinguished the case from Energytec, where the Fifth Circuit concluded that certain covenants in an agreement relating to a pipeline system did run with the land, such that the debtors could not sell the pipeline free and clear of a creditor’s interest.[14] In Energytec, the obligation to pay a monthly transportation fee was triggered by the flow of gas through a pipeline on the subject property.[15] There, the agreement gave the contractual counterparty consent rights over any assignments—a clear burden on the producer’s interest—and provided that the contractual transportation fee was secured by a lien on the pipeline system. By contrast, the agreements in Sabine did not give consent rights to the midstream counterparties, and the fees payable thereunder were unsecured; in fact, the dedicated properties were separately pledged to the debtors’ secured lenders.[16] These diverging results illustrate the critical importance of the precise language employed in midstream services contracts; it is unclear whether the bankruptcy court in Sabine would have reached a different conclusion had the contracts at issue contained more specific dedication language. The district court affirmed, basing its ruling on a finding that the covenants did not “touch and concern” the land and expressly declining to decide whether a real covenant under Texas law requires horizontal privity.[17] By contrast, the Second Circuit upheld the lower courts’ rulings that the covenants at issue did not “run with the land”, but based its holding on a lack of horizontal privity between the parties to the agreements rather than on whether the contracts “touched and concerned” the land.[18] After concluding that horizontal privity was a requirement of a Texas real covenant based on a lack of authority to the contrary, the appellate court held that such privity was absent because the real property involved in the contract—i.e., the land that was the subject of the dedicated leases—was not conveyed by the contracts or otherwise.[19] The court observed that it is not enough if the subject contract merely “involves” land; rather, horizontal privity must exist with respect to the specific land burdened by the covenant at issue.[20] Thus, it was of no moment that two of the contractual arrangements involved the conveyance of separate land adjacent to the dedicated land.[21] Post-Sabine Developments As of this writing, the substantive holding of Sabine has not been tested in any reported decision. Both shortly before and after the initial Sabine decision, midstream rejection disputes arose in numerous other E&P companies’ chapter 11 cases. While arising in different contexts, each dispute was settled before the nature of the underlying midstream contracts was adjudicated. In Sandridge Energy, the bankruptcy court expressed skepticism regarding the Sabine holding; however, in announcing a settled resolution of the dispute, the debtors’ counsel explained that the amount at issue did not justify the expected cost of litigation.[22] In Quicksilver Resources, the issue arose in connection with a sale of the debtors’ assets under section 363 of the Bankruptcy Code, as the debtors’ success on a motion to reject certain midstream contracts governed by Texas law was a condition precedent to closing the sale.[23] The initial Sabine decision was issued several days after oral argument on the Quicksilver rejection motion, and the parties settled shortly thereafter. The debtors withdrew the rejection motion, and the purchaser agreed to enter into replacement midstream agreements with a corresponding reduction of the agreed purchase price by $2.5 million. In several other cases, debtors resolved pending midstream rejection disputes by agreeing to assume the subject contracts on modified economic terms, while providing consideration for any prepetition deficiency or unpaid fee claims through an allowed general unsecured claim.[24] Critically, the issues in Sabine were governed by Texas law pursuant to choice-of-law provisions in the contracts, and even in Texas these issues have not been settled by the Texas Supreme Court. Midstream contracts providing for the application of another state’s law will require analysis of real covenants and equitable servitudes under such state’s law. For example, the chapter 11 case of Triangle USA Petroleum, LLC, an exploration and production company operating primarily in the Williston Basin of North Dakota and Montana, involved a dispute over certain midstream contracts governed by North Dakota law.[25] In contrast to Texas, where real covenant disputes are guided by common law principles, North Dakota statutes provide specific guidance on the requirements for a finding that a covenant “runs with the land.”[26] Procedural Considerations While its substantive result has generated debate, Sabine established a clear procedural roadmap for midstream contract rejection disputes that has served as a template in numerous cases. Before reaching the covenant issue, the Sabine court concluded that it could not “decide substantive legal issues, including whether the covenants at issue run with the land, in the context of a motion to reject, unless such motion is scheduled simultaneously with an adversary proceeding or contested matter to determine the merits of the substantive legal disputes related to the motion.”[27] Although rejection proceedings are designated as contested matters under the Federal Rules of Bankruptcy Procedure, the court held that these are summary proceedings intended to efficiently review the debtor’s decision to reject, and are inappropriate for resolving a lengthy trial with disputed issues.[28] Following Sabine, debtors seeking to reject midstream agreements have generally simultaneously filed a motion to reject and commenced an adversary proceeding seeking a declaratory judgment establishing that the relevant covenants do not “run with the land.”[29] Like any potentially fact-intensive litigation, the resolution of an adversary proceeding seeking a declaratory judgment (or a similar state court suit) can take an extended period of time.[30] However, debtors may be able to ensure that such litigation does not slow the overall progress of their restructuring by pursuing plan confirmation in parallel with rejection and including a plan provision contemplating a conditional rejection based on the outcome of litigation still pending at the time of confirmation. The TUSA case involved such a provision, referred to as a “toggle”.[31] In TUSA, the debtors sought to reject certain midstream services contracts with Caliber Midstream Partners, L.P. (“Caliber”). Prior to the petition date, Caliber commenced litigation in North Dakota state court seeking a declaratory judgment establishing that its contracts contained covenants that “ran with the land” and thus could not be rejected.[32] The “toggle” provision in the debtors’ plan of reorganization provided that the Caliber contracts would be deemed rejected as of the effective date of the plan, conditional on (i) the debtors prevailing in the North Dakota declaratory judgment action, and (ii) the bankruptcy court determining or estimating the allowed amount of Caliber’s rejection damages claim at less than $75 million.[33] The failure of either condition to occur would result in the assumption of the Caliber contracts and payment of associated cure amounts. The plan further allowed Caliber to vote its potential rejection claim and participate in the rights offering contemplated under the plan. Caliber objected to the plan, arguing that the conditional rejection provision allowed the debtors to indefinitely delay their decision to assume or reject, and that such decision could not be delayed past confirmation. In a bench ruling, the bankruptcy court sided with the debtors and confirmed the plan, noting that while the debtors were “asking for something that has never been done before,” this did not mean that the requested relief was prohibited. The court explained that the language of sections 365(d)(2) and 1123 of the Bankruptcy Code was permissive and not indicative of an absolute deadline for assumption or rejection.[34] Finding the conditions to be “simply a recognition that the debtor is not in a position to reject without knowing the effect of that rejection,” the court upheld the provision and confirmed the plan.[35] Practical Advice The result in Sabine and the subsequent resolutions of midstream contract disputes in other chapter 11 cases provide several important lessons to guide future expectations. First, the issue of whether a particular midstream agreement can be rejected is a fact-specific question of state law.  The principles of property and contract law guiding the inquiry, which vary from state to state, are uniformly complex and, in some cases, unsettled. Second, the prevailing procedural approach for such disputes established in Sabine and upheld by other bankruptcy courts requires a formal and potentially protracted litigation in the form of a declaratory judgment action asserted through an adversary complaint in bankruptcy court or a separate state court litigation. To the extent that litigation is pursued in the bankruptcy case, questions regarding bankruptcy courts’ statutory and constitutional authority to adjudicate these disputes create further potential for delay and uncertainty of venue. Third, notwithstanding these potential procedural delays, debtors may take advantage of Bankruptcy Code mechanisms, including claims estimation and the potential to confirm a “toggle” plan with a delayed conditional rejection provision, to ensure that their chapter 11 cases proceed expeditiously despite the pendency of rejection-related litigation. This represents a significant potential downside for midstream counterparties, who bear the burden of prolonged uncertainty as to the ongoing viability of their contracts even as the producer-debtor is able to consummate a restructuring or sale. These considerations make it essential for stakeholders to clearly understand the cost-benefit calculus of litigating the rejection of a midstream contract well in advance of a producer’s financial distress, and to frequently update such analysis as the dispute progresses. The parties must balance the significant legal and procedural uncertainty, including the potential for protracted and costly litigation, against the alternative cost of a consensual resolution that may involve modification of the agreement’s economic terms and satisfaction of prepetition amounts at a discount to their face value. In the 2015-16 cycle, this cost-benefit analysis, combined with the recovery in oil and gas prices, likely drove many of the post-Sabine settlements. It remains to be seen whether economic circumstances in any future cycles of E&P distress will ultimately result in judicial decisions that shed more light on the underlying substantive issues. __________________________    [1]   11 U.S.C. § 365(a).    [2]   See, e.g., Sharon Steel Corp. v. National Fuel Gas Distrib. Corp., 872 F.2d 36, 39 (3d Cir. 1989).    [3]   In re Sabine Oil and Gas Corp., 547 B.R. 66, 71 (Bankr. S.D.N.Y. 2016) (“Sabine”) (citing Orion Pictures Corp. v. Showtime Networks (In re Orion Pictures Corp.), 4 F.3d 1095, 1099 (2d Cir. 1993)).    [4]   See, e.g., Glosser v. Maysville Reg’l Water Dist., 174 Fed. App’x 34, 38-39 (3d Cir. 2009) (holding that an easement could not be assumed and assigned under section 365 of the Bankruptcy Code because outstanding duties under the easement were “not material” and “ministerial” in nature); In re Copper Creek Estates-Grand Island LLC, No. BK11-40496-TJM, 2011 WL 2681224 (Bankr. D. Neb. Jul. 8, 2011) (builder that placed restrictive covenant on vacant lots in exchange for providing financing to landowner had no ongoing obligations under agreement, which was not executory in nature; thus, covenant ran with the land and could not be rejected).    [5]   Midstream providers have also argued in the alternative that such covenants constitute equitable servitudes under applicable state law. See, e.g., Sabine at 79. Under Texas law, “a covenant that does not technically run with the land can still bind successors to the burdened land as an equitable servitude if: (1) the successor to the burdened land took its interest with notice of the restriction, (2) the covenant limits the use of the burdened land, and (3) the covenant benefits the land of the party seeking to enforce it.” Reagan Nat’l Advert. of Austin, Inc. v. Capital Outdoors, Inc., 96 S.W.3d 490, 495 (Tex. Ct. App. 2002) (internal citations omitted).    [6]   There is no controlling Texas Supreme Court decision on point. Accordingly, the Bankruptcy Court predicted how Texas law would interpret the contracts at issue. If and when the Texas Supreme Court addresses this issue, a different result may ensue.    [7]   Sabine at 74.    [8]   Sabine at 75-76 (citing Inwood North Homeowners’ Ass’n, Inc. v. Harris, 736 S.W. 2d 632, 635 (Tex. 1987). In addition, the covenant must relate to a thing in existence or specifically bind the parties and their assigns and be intended to run with the land by the parties, and the successor to the burden of the covenant must have notice. Id. Because it concluded that the covenant did not “touch and concern the land”, the Sabine court did not specifically analyze these other elements.    [9]   Id. at 76 (citing Westland Oil Dev. Corp. v. Gulf Oil Corp., 637 S.W. 903, 910-11 (Tex. 1982); Newco Energy v. Energytec, Inc. (In re Energytec, Inc.), 739 F.3d 215, 222 (5th Cir. 2013) (internal quotations omitted)). [10]   Id. [11]   Id. at 77 (quoting El Paso Refinery, LP v. TRMI Holdings, Inc. (In re El Paso Refinery, LP), 302 F.3d 343, 356 (5th Cir. 2002)). [12]   Id. [13]   Id. at 78. [14]   739 F.3d at 222. [15]   Sabine at 79. [16]   Id. at 78-79. [17]   HPIP Gonzales Holdings, LLC v. Sabine Oil & Gas Corp. (In re Sabine Oil & Gas Corp.), 567 B.R. 869, 877 n.5 (S.D.N.Y. 2017). [18]   Sabine Oil & Gas Corp. v. Nordheim Eagle Ford Gathering, LLC (In re Sabine Oil & Gas Corp.), 734 Fed. Appx. 64, 67 (2d Cir. 2018) (summary order). [19]   Id. at 66-67. The panel applied the same reasoning as the bankruptcy court, stating that “[i]t would be improper for us to read a traditional requirement of real covenants out of Texas state law when there is no Texas law instructing courts to do so.” Id. To the extent that the Texas Supreme Court rules on the issue—for instance, if that court accepts a certified question from a federal court—this aspect of the Sabine holding could potentially be overturned. In connection with the midstream contract dispute in In re Quicksilver Resources, a Texas law expert advocating for the midstream providers observed that “[t]he Texas Supreme Court has had the opportunity to include horizontal privity as a requirement of a covenant running with the land, but it has not done so, and indeed, has found that covenants that would not otherwise meet the horizontal privity “requirement” were in fact covenants running with the land.” No. 15-10585-LSS, Dkt. No. 1189-1 at ¶ 61 (Bankr. D. Del. Feb. 29, 2016) (citing Inwood N. Homeowners’ Ass’n, Inc. v. Harris, 736 S.W.2d 632, 635 (Tex. 1987); Westland Oil Dev. Corp. v. Gulf Oil Corp., 637 S.W.2d 903, 910-11 (Tex. 1982)). [20]   Id. at 67. [21]   Id. Each of the Sabine courts further rejected the alternative argument that the midstream contracts constituted “equitable servitudes,” primarily because the agreements did not provide any benefit to any real property of the midstream providers. Id. at 68. [22]   In re Sandridge Energy, Inc., No. 16-32488 (DRJ), Dkt. No. 460 at 13 (Bankr. S.D. Tex. Jul. 4, 2016) (court stating that it had “been looking for an opportunity to correct the State of New York” regarding a disputed issue of whether certain covenants “ran with the land”). [23]   The midstream providers argued that the contractual dedications of the total volume of gas owned or controlled by the debtors in the Barnett Shale were covenants that ran with the land under Texas law, and thus could not be rejected. No. 15-10585-LSS, Dkt. No. 1189 (Feb. 2, 2016). [24]   See In re Penn Virginia Corp., No. 16-32395 (KLP), Dkt. No. 524 (Bankr. E.D. Va. Aug. 5, 2016) (order approving settlement of rejection dispute contemplating assumption of midstream agreements with amended fee and minimum production terms and providing midstream counterparty with, among other things, $25 million allowed general unsecured claim and ability to participate in debtors’ rights offering based on 50% of such claim); In re Emerald Oil, Inc., No. 16-10704 (KG), Dkt. No. 754 (Bankr. D. Del. Sep. 28, 2016) (joint notice of global settlement providing that debtors will assume midstream contract with modified economic terms and provide counterparty with, among other consideration, 50% of crude sale proceeds, $2 million cash payment, and allowed unsecured damages claim for $10 million); In re Magnum Hunter Res. Corp., No. 15-12533 (KG), Dkt. Nos. 983, 1166, 1131, and 1214 (Bankr. D. Del.) (debtors reached separate settlement arrangements with four midstream providers, agreeing to assume two of the contracts on modified economic terms, reject a third in exchange for an allowed general unsecured claim of $15 million, and reject a fourth while withdrawing the related adversary complaint against the counterparty without prejudice). [25]   In re Triangle USA Petroleum, LLC, , Case No. 16-11566 (MFW) (Bankr. D. Del.) (“TUSA”). [26]   See N.D. Cent. C. § 47-04-25 (“The only covenants which run with the land are those specified in this chapter and those which are incidental thereto.”); id. § 47-04-26 (setting forth requirements for a covenant to run with the land and providing examples). [27]   Sabine at 73. [28]   Id. (citing Orion Pictures Corp. v. Showtime Networks (In re Orion Pictures Corp.), 4 F.3d 1095, 1098-99 (2d Cir. 1993); In re The Great Atlantic & Pacific Tea Co., 544 B.R. 43, 48 (Bankr. S.D.N.Y. 2016)). [29]   See, e.g., In re Penn Virginia Corp., No. 16-32395 (KLP) (Bankr. E.D. Va.), Dkt. No. 320 (motion to reject filed contemporaneously with complaint commencing declaratory judgment adversary proceeding); In re Triangle USA Petroleum Corp., No. 16-11566 (MFW) (Bankr. D. Del.), Dkt. No. 67 (same); In re Magnum Hunter Res. Corp., No. 15-12533 (KG) (Bankr. D. Del.), Dkt. No. 1062 (order directing debtors to commence an adversary proceeding to determine state law contract issues). [30]   Eureka Hunter, a midstream service provider in the Magnum Hunter chapter 11 case, raised additional procedural issues regarding bankruptcy court authority that have the potential to further delay the covenant determination. Eureka first argued that because its underlying contract claims did not invoke substantive rights provided by the Bankruptcy Code, they were “non-core” under the Bankruptcy Code, meaning that a bankruptcy court would only have the statutory authority to enter proposed findings of fact and conclusions of law subject to review by a district court. Eureka further argued that one aspect of its contract claims had to be adjudicated by an Article III court pursuant to the requirements of Stern v. Marshall and related Supreme Court decisions. 131 S. Ct. 2594, 2620 (2011). While Eureka’s claims were settled, these arguments could be raised in nearly any contractual rejection dispute, inserting another layer of procedural uncertainty and potential delay into the proceedings. [31]   Gibson Dunn represented an ad hoc group of TUSA’s senior unsecured noteholders. [32]   TUSA attempted to commence a declaratory judgment adversary proceeding in bankruptcy court and dismiss the state court action, but the bankruptcy court deferred to the first-filed state court action. [33]   Section 502(c) of the Bankruptcy Code provides for estimation for the purpose of allowance “any contingent or unliquidated claim, the fixing or liquidation of which, as the case may be, would unduly delay the administration of the case.” 11 U.S.C. § 502(c). The TUSA debtors requested that the court estimate the maximum amount of the potential rejection damages claim, establishing a cap on potential liability in order to facilitate plan negotiations that included a new money investment not conditioned on the final resolution of the Caliber litigation. [34]   Tr. of Hearing, Case No. 16-11566 (MFW) (Bankr. D. Del. Mar. 10, 2017), at 112; see also Findings of Fact, Conclusions of Law, And Order Confirming Third Amended Joint Chapter 11 Plan of Reorganization of Triangle USA Petroleum Corp. And Its Subsidiary Debtors, Case. No. 16-11566 (MFW) (Bankr. D. Del. Mar. 10, 2017), Dkt. No. 825, at 22. See 11 U.S.C. § 365(d)(2) (“[T]he court, on the request of any party to [an executory] contract . . ., may order the [debtor] to determine within a specified period of time whether to assume or reject such contract . . . .” (emphasis added)); 11 U.S.C. § 1123(b) (“[A] plan may . . . provide for the assumption, rejection, or assignment of any executory contract . . . of the debtor not previously rejected . . . .”). [35]   The Caliber litigation was ultimately settled; the parties agreed to renegotiate the midstream contracts before the North Dakota state court adjudicated the declaratory judgment action. In re Triangle USA Petroleum Corporation, No. 16-11566 (MFW), Dkt. No. 1007. Gibson, Dunn & Crutcher’s lawyers are available to assist with any questions you may have regarding these issues.  For further information, please contact the Gibson Dunn lawyer with whom you usually work, any member of the firm’s Business Restructuring and Reorganization or Oil and Gas practice groups, or any of the following: Matthew K. Kelsey – New York (+1 212-351-2615, mkelsey@gibsondunn.com) Matthew P. Porcelli – New York (+1 212-351-3803, mporcelli@gibsondunn.com) Julia Philips Roth – Los Angeles (+1 213-229-7978, jroth@gibsondunn.com) Please also feel free to contact the following practice group leaders: Business Restructuring and Reorganization Group: David M. Feldman – New York (+1 212-351-2366, dfeldman@gibsondunn.com) Robert A. Klyman – Los Angeles (+1 213-229-7562, rklyman@gibsondunn.com) Jeffrey C. Krause – Los Angeles (+1 213-229-7995, jkrause@gibsondunn.com) Michael A. Rosenthal – New York (+1 212-351-3969, mrosenthal@gibsondunn.com) Oil and Gas Group: Michael P. Darden – Houston (+1 346-718-6789, mpdarden@gibsondunn.com)   © 2019 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 30, 2019 |
PT Medco Energi Internasional Tbk.’s US$500 Million Secured RBL Facility (Project Gajah) as 2019 Indonesian Oil and Gas Deal of the Year

The Asset has named PT Medco Energi Internasional Tbk.’s (MedcoEnergi) US$500 million six-year secured revolving reserve-based lending (RBL) facility as the “Oil and Gas Deal of the Year – Indonesia” at its Asset Triple A Asia Infrastructure Awards 2019. Gibson Dunn advised MedcoEnergi subsidiaries, PT Medco E&P Malaka and PT Medco E&P Tomori Sulawesi as borrowers, and MedcoEnergi as sponsor on the deal, which was the largest reserve-based financing closed in Asia in 2018. The Gibson Dunn team was led by Jamie Thomas and assisted by U-Shaun Lim. The winners were announced on May 30, 2019. Medco Energi is a rapidly expanding oil and gas player, headquartered in Indonesia and we are honored to have represented the Medco Energi group on this US$500 million six-year secured revolving reserve-based lending (RBL) facility arranged by the mandated lead arrangers and bookrunners Australia and New Zealand Banking Group, ING Bank and Société Générale.  The transaction had to be structured carefully to fit and work around Medco Energi’s high yield notes and the structural impediments recently thrown by the laws of Indonesia, including government intervention with respect to the distribution of offtake to third parties (e.g. under the Ministry of Energy and Mineral Resources Regulation No. 42 of 2018 on Priority of Petroleum Utilization for the Fulfillment of Domestic Need) amongst other things and there was the added complexity of having  both pre- and post-completion tranches which detailed various parameters for utilization, depending on whether such financing was for exploration, expansion or post completion of an asset. There were protracted negotiations on the inputs and assumptions which determine the borrowing base amount at any point in time and we negotiated for our client a unique level of flexibility.  Thankfully, we were working with a sophisticated group of lenders and their legal counsels and we were pleased to see that the financing was very well received in the primary syndication market by a large number of international lenders. We thank everyone on the deal for their effort and support.

April 25, 2019 |
Colorado Passes Sweeping New Law to Alter the State’s Oil and Gas Regulatory Framework

Click for PDF On April 16, 2019, the Governor of Colorado signed Senate Bill 19-181 (“SB-181”) into law, making sweeping changes to Colorado’s framework for oil and gas regulation.[1]  SB-181 marks the latest attempt to manage growing tensions between Colorado’s oil and gas operators, who have seen crude oil production quadruple since 2010,[2] and fast-growing population centers along the Front Range, which includes suburbs of Denver along the I-25 corridor.[3] SB-181 was enacted after last year’s unsuccessful ballot campaign for Proposition 112, which if approved by voters would have significantly curtailed oil and gas development in Colorado.  Proposition 112 was a ballot initiative that would have required new oil and gas development to be subject to a 2,500-foot setback from occupied buildings and “vulnerable” areas, broadly defined to include water bodies and public spaces.[4]  According to an impact assessment of Proposition 112 conducted by the Colorado Oil and Gas Conservation Commission (the “COGCC”), the state’s oil and gas regulatory arm, approximately 85% of the non-federal land in Colorado would have been unavailable for oil and gas production had Proposition 112 passed.[5]  The oil and gas industry raised a record-setting $38 million to help defeat the initiative, nearly doubling the previous fundraising record for a single group in a ballot initiative.[6]  Ultimately, Colorado voters rejected Proposition 112 by a 56.1% vote.[7]  At the same time, however, the 2018 election saw a so-called “blue wave” crash into Colorado, with Democrats taking control of the state Senate, expanding control of the state House, and sweeping every statewide election, including the races for governor, secretary of state, and attorney general.[8] In the shadow of Proposition 112’s defeat by Colorado voters, the state’s newly elected lawmakers and legislative leaders pushed for an overhaul of oil and gas regulation in Colorado, culminating in Governor Jared Polis’s signing of SB-181 last week.[9]  While SB-181 mandates a host of changes to oil and gas regulation in Colorado, three changes in particular may have a significant impact on future oil and gas development, each of which is discussed below.  First, SB-181 grants local governments new power to regulate oil and gas development, including enhanced authority over surface activities.  Second, SB-181 requires the COGCC to prioritize and emphasize the protection of public health, safety, and the environment in its regulations, which could lead to an adjustment of the balanced approach to regulation that the COGCC had been implementing over the past decade. Third, SB-181 alters Colorado’s mandatory pooling rules to make it more difficult to pool nonconsenting mineral interest owners into a drilling unit. Increased Local Control of Oil and Gas Sites Prior to the passage of SB-181, Colorado law explicitly limited the ability of local governments to regulate oil and gas development, and the Colorado Supreme Court had recognized the primacy of state regulation over oil and gas operations.[10] SB-181 grants local governments significant new power to regulate the surface impacts of oil and gas development.  Local governments that elect to regulate oil and gas operations can now control where oil and gas wells are located to minimize adverse impacts to public health, safety, and the environment.[11] The bill requires all operators to first file applications to approve well sites with local governments which opt into the local regulatory scheme and to include such applications with their drilling permit applications to the COGCC (or, if a local government opts out of the local regulatory scheme, to include proof that the local government does not regulate the siting of oil and gas wells).[12]  Both local governments and oil and gas operators may ask the COGCC to appoint a technical review board to assess a local government’s preliminary or final determination (or lack thereof) regarding an operator’s well locations, but, notably, local governments are not required to consider the findings of a technical review board in making their final determinations.[13]  Local governments can also inspect oil and gas facilities; impose fines for leaks, spills, and emissions; impose fees on operators to cover the costs of permitting, regulation, and inspection; and enforce operators’ compliance with local noise ordinances.[14] The authority granted to local governments by SB-181 could therefore significantly affect the balance in Colorado between statewide and local regulatory control of oil and gas operations.  At the other end of the spectrum is Texas, where a local government’s power to regulate oil and gas operations is expressly preempted by statute, except in limited circumstances.[15]  Colorado’s shift toward additional local control of oil and gas development may significantly increase local government oversight of oil and gas operators and may prompt some localities to explore ways to use their new authority to substantially limit, and perhaps effectively ban, drilling operations. Shifts in Regulatory Priority Prior to the passage of SB-181, the COGCC was tasked with ensuring that the efficient development of oil and gas resources in the state was balanced with other regulatory objectives.  Colorado’s Oil and Gas Conservation Act (the “Act”) required the COGCC to “foster the responsible, balanced development, production, and utilization” of oil and gas resources to achieve the “maximum efficient rate of production” and to prevent “waste” of oil and gas.[16]  The Act required that such development occur “in a manner consistent with protection of public health, safety, and welfare, including the protection of the environment and wildlife resources,” but the Act also prioritized the controlled development of oil and gas in Colorado so as to maximize production.[17]  Health and environmental impacts were an important consideration under existing legislation, but they were to be weighed against effective resource management. SB-181 alters the COGCC’s objectives, deemphasizing its role in promoting oil and gas development.  The bill amends the Act to state that the COGCC’s mission is to “regulate,” not “foster,” the efficient development of oil and gas “in a manner that protects public health, safety, and welfare, including the protection of the environment and wildlife resources.”[18]  While the COGCC may still pursue maximally efficient production, that goal is now “subject to” the protection of public health, safety, and the environment.[19]  Further, SB-181 alters the definition of “waste” to specifically exclude the nonproduction of oil and gas if such nonproduction is necessary to protect public health, safety, and the environment.[20] These shifts in regulatory priority could have a dramatic effect on the mission of the COGCC.  By making the development of oil and gas resources subject to the protection of public health, safety, and the environment, SB-181 potentially requires the COGCC to adjust its balanced approach to regulation, through which it currently considers the efficient extraction of oil and gas weighed against other objectives.  After SB-181, the COGCC may perceive its top priority to be the protection of public health, safety, and the environment.[21] Under SB-181, the COGCC must exercise its regulatory authority “in a reasonable manner to protect and minimize adverse impacts” to public health, safety, and the environment.[22]   Furthermore, the changes to the definition of “waste” suggest that the COGCC may consider requiring nonproduction in some circumstances to fulfill its new regulatory focus.[23] Changes in Mandatory Pooling Orders Prior to the adoption of SB-181, Colorado law allowed “any interested person” to file an application with the COGCC to pool oil and gas resources within a particular drilling unit.[24]  Colorado did not require a specific percentage of mineral interest owners to join in a pooling application; rather, any person with a mineral interest could seek a mandatory pooling order, including operators with lease or royalty interests. If the COGCC approved the interested person’s pooling application, mineral interest owners who did not consent to pooling were entitled to a 1/8th royalty from oil or gas production until cost recovery was achieved.[25]  In addition, prior law did not restrict the operator from using the surface land of such nonconsenting owners for oil and gas operations.[26] SB-181 makes it significantly more difficult for operators to obtain a mandatory pooling order and increases the burden on operators if a mandatory pooling order is granted.  Colorado now joins several other oil and gas producing states in requiring a minimum percentage of the mineral interest owners to join a pooling application, requiring the consent of owners of 45% of the relevant mineral interests.[27]  If a mandatory pooling order is granted, nonconsenting owners are entitled to a 13% royalty from gas wells and a 16% royalty from oil wells until cost recovery is achieved.[28] Finally, operators are specifically prohibited from using the surface land of a nonconsenting owner for oil and gas operations.[29]  Given the often bitter debates among mineral interest owners in or near large metropolitan areas in Colorado, under these changes operators could find mandatory pooling orders more difficult to obtain. Implementation Issues and Other Changes Implementation provisions in the initial drafts of SB-181 caused significant alarm in the oil and gas industry. Early drafts of the bill allowed the COGCC to refrain from issuing any new oil and gas permits until the COGCC promulgated and implemented every new or revised rule required by SB-181.[30]  Many in the oil and gas industry argued that this allowed the COGCC to establish a moratorium on drilling lasting for months.[31]  A later version of the bill removed COGCC’s ability to delay all new permits, however.  The final version of the bill signed by Governor Polis allows the COGCC to delay its final determination regarding a permit application only if the COGCC determines pursuant to “objective criteria” that the permit application requires additional analysis to ensure the protection of public health, safety, and the environment.[32]  The COGCC must make these criteria available for public comment within 30 days and, following the public comment period, the criteria will become effective.[33] SB-181 makes several other important changes to oil and gas regulation in Colorado.  The bill requires the COGCC to establish rules to minimize emissions of methane, volatile organic compounds, and nitrogen oxides and to consider adopting more stringent rules regarding emissions controls.[34] Previously, the COGCC had worked with state’s air quality regulator to establish emissions limits for the oil and gas industry.  SB-181 also mandates changes in the composition of the COGCC itself.  Prior to the bill’s passage, the COGCC consisted of nine members, three of whom were required to have substantial experience in the oil and gas industry.[35]  Under the new law, the number of COGCC members who must have significant industry experience is lowered from three to one.[36] In addition, no later than July 1, 2020, the COGCC will be restructured to consist of seven members, none of whom may have “an immediate conflict of interest or who may not be able to make balanced decisions about oil and gas regulation in Colorado.”[37]  Previously, all COGCC members on a part-time basis; now, five of the seven will serve on the Commission full time.[38] Conclusion SB-181 makes large-scale changes to the oil and gas regulatory landscape in Colorado.  The bill shifts the state’s regulatory priorities away from fostering the efficient, balanced development of oil and gas; provides local governments with new and significant regulatory powers; and makes mandatory pooling orders significantly more difficult to obtain.  As a consequence, the industry will be required to focus keenly on local politics in the areas in which they operate.  The debate is not over, however.  Ballot initiatives have already been proposed to repeal some or all of the new legislation, including some sponsored by resource-friendly local governments whose economies depend heavily on the oil and gas industry.  Operators will also be closely monitoring the promulgation of new and revised state-level regulations required by SB-181 in an effort to anticipate and address some of its potentially strict effects.  In the meantime, SB-181 provides oil and gas opponents significant new regulatory tools that could potentially slow oil and gas development in Colorado, especially near its major cities and suburban areas.    [1]   https://www.denverpost.com/2019/04/16/colorado-oil-gas-bill-signed-gov-jared-polis/    [2]   https://www.eia.gov/state/analysis.php?sid=CO#21    [3]   https://www.nytimes.com/2018/05/31/us/colorado-fracking-debates.html    [4]   https://www.sos.state.co.us/pubs/elections/Initiatives/titleBoard/filings/2017-2018/97Final.pdf    [5]   https://cogcc.state.co.us/documents/library/Technical/Miscellaneous/COGCC_2018_Prop_112_Init_97_GIS_Assessment_20180702.pdf    [6]   https://www.cpr.org/news/story/record-breaking-political-spending-swamps-colorado    [7]   https://elections.denverpost.com/results/county-break-down/?Prop-112/7618    [8]   https://www.5280.com/2018/11/a-blue-wave-crashes-into-colorado-in-the-2018-midterms/    [9]   https://www.denverpost.com/2019/04/16/colorado-oil-gas-bill-signed-gov-jared-polis/ [10]   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.”). [11]   Senate Bill 19-181 §4. [12]   Senate Bill 19-181 §12. [13]   Senate Bill 19-181 §12. [14]   Senate Bill 19-181 §4. [15]   Tex. Nat. Res. Code Ann. § 81.0523 (“The authority of a municipality or other political subdivision to regulate an oil and gas operation is expressly preempted, except that a municipality may enact, amend, or enforce an ordinance or other measure that: (1) regulates only above-ground activity … (2) is commercially reasonable; (3) does not effectively prohibit an oil and gas operation … and (4) is not otherwise preempted by state or federal law.”). [16]   Colo. Rev. Stat. §34-60-102(1)(a)–(b) [17]   Id. (emphasis added); see also https://www.denverpost.com/2019/04/16/colorado-oil-gas-bill-signed-gov-jared-polis/ [18]   Senate Bill 19-181 §6. [19]   Id.; see also https://leg.colorado.gov/bills/sb19-181 [20]   Senate Bill 19-181 §6. [21]   See  https://coloradosun.com/2019/04/16/senate-bill-181-oil-gas-law-colorado-signed/; see also https://www.law360.com/publicpolicy/articles/1150786/colo-law-expanding-oil-gas-rules-gets-gov-s-signature [22]   Senate Bill 19-181 §18. [23]   Senate Bill 19-181 §6. [24]   Colo. Rev. Stat. §34-60-116(6) [25]   Colo. Rev. Stat. §34-60-116(7)(c) [26]   Senate Bill 19-181 adds this restriction. [27]   Senate Bill 19-181 §14. [28]   Id. [29]   Id. [30]   https://www.natlawreview.com/article/know-primer-colorado-s-senate-bill-181 [31]   Id. [32]   Senate Bill 19-181 §12. [33]   Senate Bill 19-181 §12. [34]   Senate Bill 19-181 §3. [35]   Colo. Rev. Stat. §34-60-104(2)(a)(I) [36]   Senate Bill 19-181 §8. [37]   Senate Bill 19-181 §9. [38]   Id. 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) Justin T. Stolte -Houston (+1 346-718-6800, jstolte@gibsondunn.com) © 2019 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 3, 2019 |
U.S. EPA Finalizes New Owner Clean Air Act Audit Program Tailored for the Oil and Natural Gas Sector

Click for PDF On March 29, 2019, the U.S. Environmental Protection Agency finalized the New Owner Clean Air Act Audit Program (the “Program”) for the oil and natural gas sector. Under the Program, new owners of upstream exploration and production sites can seek complete civil penalty mitigation in exchange for auditing their sites for Clean Air Act violations, disclosing any violations, and correcting those violations on an agreed timeline.[1] Opting into the Program. New owners of upstream sites seeking to participate in the program must notify EPA within nine months after acquiring new facilities. Buyers then must consult with the EPA to determine the scope of the audit, including the number of facilities covered. Although EPA strongly encourages new owners to conduct a comprehensive Clean Air Act audit of all applicable statutory and regulatory requirements, the agency has expressed a willingness to entertain proposals for more targeted Clean Air Act compliance audits.[2] Terms of the Program. In announcing the program, EPA provided a template audit agreement outlining the audit process. The template agreement requires, for example, participating new owners to follow an EPA-designed systematic process for estimating vapor control system pressures and vapor flow rates to control devices, and to correct any violations discovered during this process within 180 days of each respective violation’s discovery.[3] Violations discovered outside of the scope of the predesigned process for vapor control systems must be corrected within 60 days of their discovery. Benefits of the Program. Taken as a whole, the requirements of the template audit process may, unlike previous audit policies, require participating new owners to go beyond the requirements of applicable regulations in order to mitigate emissions from storage tanks.[4] Significantly, however, new owners that enter into, and fulfill, all obligations under the template agreement are provided with complete relief from civil penalties. In taking this approach, EPA acknowledged that it was providing for penalty mitigation over and beyond the approach used in preexisting audit guidance (which only allows for mitigation of the “gravity” component of a civil penalty, not the entire civil penalty). Risk Mitigation. EPA’s new audit program provides the upstream oil and gas sector with an option to mitigate enforcement risk by proactively addressing vapor control design issues targeted by a recent EPA enforcement initiative. EPA’s FY19 enforcement goals include an initiative specifically aimed at reducing emissions from storage vessels at upstream sites allegedly resulting from insufficient vapor controls. Under this initiative, EPA already has settled enforcement cases at facilities in Colorado, Oklahoma, Ohio, West Virginia, and Pennsylvania. In one case, the estimated cost of upgrades to vapor control systems and storage vessels resulting from EPA’s efforts was $60 million. Given the potential for substantial civil penalties, the Program may still be an attractive option for new owners seeking to avoid civil penalties or enforcement in spite of the Program’s emissions mitigation requirements.    [1]   The Program is distinct from, and does not alter, preexisting EPA policies incentivizing industry actors to self-audit their potential pollution (e.g., EPA’s Incentives for Self-Policing: Discovery, Disclosure, Correction and Prevention of Violations, 65 Fed. Reg. 19,618 (Apr. 11, 2000)). Industry members that prefer the incentive schemes of prior audit policies may still avail themselves of such policies.    [2]   EPA, Oil and Gas New Owner Program Questions and Answers (Mar. 29, 2019), available at https://www.epa.gov/compliance/oil-and-gas-new-owner-program-questions-and-answers.    [3]   Id.    [4]   Dawn Reeves, Lacking Fixes, Oil & Gas Sector Unlikely to Use EPA Penalty Relief Policy, Inside EPA (April 2, 2019), available at https://insideepa.com/daily-news/lacking-fixes-oil-gas-sector-unlikely-use-epa-penalty-relief-policy. 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 Environmental Litigation and Mass Tort or Oil and Gas practice groups, or the authors: Peter S. Modlin – San Francisco (+1 415-393-8392, pmodlin@gibsondunn.com) Michael K. Murphy – Washington, D.C. (+1 202-955-8238, mmurphy@gibsondunn.com) Stacie B. Fletcher – Washington, D.C. (+1 202-887-3627, sfletcher@gibsondunn.com) Kyle Neema Guest – Washington, D.C. (+1 202-887-3673, kguest@gibsondunn.com) Environmental and Mass Tort Group: Washington, D.C. Stacie B. Fletcher (+1 202-887-3627, sfletcher@gibsondunn.com) Raymond B. Ludwiszewski (+1 202-955-8665, rludwiszewski@gibsondunn.com) Michael K. Murphy (+1 202-955-8238, mmurphy@gibsondunn.com) Daniel W. Nelson – (+1 202-887-3687, dnelson@gibsondunn.com) Peter E. Seley – (+1 202-887-3689, pseley@gibsondunn.com) Los Angeles Patrick W. Dennis (+1 213-229-7568, pdennis@gibsondunn.com) Matthew Hoffman (+1 213-229-7584, mhoffman@gibsondunn.com) Thomas Manakides (+1 949-451-4060, tmanakides@gibsondunn.com) New York Andrea E. Neuman (+1 212-351-3883, aneuman@gibsondunn.com) Anne M. Champion (+1 212-351-5361, achampion@gibsondunn.com) San Francisco Peter S. Modlin (+1 415-393-8392, pmodlin@gibsondunn.com) 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) Justin T. Stolte -Houston (+1 346-718-6800, jstolte@gibsondunn.com) © 2019 Gibson, Dunn & Crutcher LLP Attorney Advertising:  The enclosed materials have been prepared for general informational purposes only and are not intended as legal advice.

March 28, 2019 |
Bridging The Divide

Houston partner Justin Stolte and associates James Robertson and Jordan Silverman are the authors of “Bridging The Divide” [PDF] published in the April 2019 issue of Oil and Gas Investor.

February 26, 2019 |
Webcast: IPOs and Capital Markets Developments in the Oil and Gas Industry

Please join members of Gibson Dunn’s Capital Markets and Oil and Gas Practice Groups as they discuss capital markets transactions that are currently popular in the oil and gas industry. They explore issues, considerations and recommendations regarding preparation, planning, structuring, disclosure and governance in connection with these transactions. Specifically, the panelists provide insights and practical guidance regarding: IPO Planning and Execution Preferred Equity and High-Yield Trends Special Purpose Acquisition Companies (SPACs) Tax Considerations in These Transactions View Slides (PDF) PANELISTS: Hillary H. Holmes will explain and provide guidance on the IPO process and preparation. As a Partner in the Houston office and Co-Chair of the firm’s Capital Markets practice group, Hillary represents public companies, private companies, master limited partnerships and investment banks in all forms of capital raising transactions, including IPOs, registered offerings of debt and equity securities, private placements of debt and equity securities, joint ventures, preferred equity investments, spin-offs and special purpose acquisition companies. In addition, she focuses on securities offerings and SEC and governance counseling for master limited partnerships and corporations in all sectors of the oil & gas energy industry. Hillary also advises boards of directors, conflicts committees, and financial advisors of energy companies in complex transactions. Doug Rayburn will discuss Preferred Equity and High-Yield Trends. Doug is a Partner in the Dallas and Houston offices of Gibson, Dunn & Crutcher and a member of the firm’s Capital Markets group. 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 master limited partnerships and offerings of preferred and hybrid securities. Additionally, Doug represents purchasers and sellers in connection with mergers and acquisitions involving both public and private companies, including private equity investments and joint ventures. Gerry Spedale will discuss SPACs – an alternative route to the public markets. He is a Partner in the Houston office and focuses on capital markets, mergers and acquisitions, joint ventures and corporate governance matters for companies in the energy industry, including master limited partnerships. He has extensive experience representing issuers and investment banks in both public and private debt and equity offerings, including initial public offerings, convertible note offerings and offerings of preferred securities. Gerry also has substantial experience in public and private company acquisitions and dispositions and board committee representations. James Chenoweth will provide insight into the tax implications of all three of these transactions. James is a Partner in the Houston office and a member of the firm’s Tax group. He counsels clients regarding tax-efficient structuring of partnership and corporate transactions, including transactions involving publicly traded partnerships, special purpose acquisition companies, IPOs and follow-on offerings, as well as acquisitions and dispositions, taxable sales and the formation of joint ventures. 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 Jeanine McKeown (National Training Administrator), at 213-229-7140 or jmckeown@gibsondunn.com to request the MCLE form. This program has been approved for credit in accordance with the requirements of the Texas State Bar for a maximum of 1.0 credit hour, of which 1.0 credit hour may be applied toward the area of accredited general requirement. Attorneys seeking Texas credit must obtain an Affirmation Form prior to watching the archived version of this webcast. Please contact Jeanine McKeown (National Training Administrator), at 213-229-7140 or jmckeown@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.

February 1, 2019 |
Law360 Names Gibson Dunn Among Its Energy 2018 Practice Groups of the Year

Law360 named Gibson Dunn one of its five Energy Groups Of The Year [PDF] for 2018. The practice group was recognized for securing deals in the renewable energy space and handling a range of complex financial transactions and litigation. The firm’s Energy practice was profiled on February 1, 2019. Gibson Dunn’s Energy and Infrastructure Practice Group advises clients in every stage of the development, construction, financing, acquisition, ownership and operation of energy and infrastructure projects and in connection with a wide variety of M&A, financing, investment, joint venture and other transactions involving energy and infrastructure companies of all types. Our group has substantial practical experience, knowledge and capabilities in all aspects and phases of: utility, power, pipeline and other oil and gas M&A, investment, joint venture and financing transactions, including master limited partnership (MLP), YieldCo, tax equity, hedging and other complex transactions; conventional power projects, including natural gas, combined cycle, coal, oil and nuclear facilities; renewable power projects, including solar, wind, geothermal, biomass and hydroelectric; electric energy transmission, interconnection and distribution; toll roads, water facilities, ports, airports, bridges, tunnels and other infrastructure projects; oil and gas (upstream, midstream and downstream), including E&P projects, pipelines, storage facilities, liquid natural gas (LNG) and other import/export facilities; power marketing, trading and hedging; mining; and petrochemical facilities, including fertilizer, polyethelene and LNG. Our internationally recognized Oil & Gas team brings multidisciplinary, multijurisdictional knowledge and experience to a full spectrum of oil and gas assignments.  We offer seamless advice and counseling, technical excellence, creativity, market knowledge, and unique insight on the most sophisticated matters, including: energy M&A (both private and public company-level and asset-level acquisition and divestitures); oil and gas transactional matters (including sophisticated joint ventures, farmouts, carry and earning agreements, and drillcos); capital markets (including public and private debt and equity, and MLPs, YieldCos and UpCs); resource fund formation; private equity (including sponsor-level, management team, and portfolio company engagements); asset-level finance (including reserve-based lending, acquisition finance, project finance, and hedging); restructuring; project development; infrastructure projects; and tax (including oil and gas and partnership; net profits structures, MLPs, YieldCos and UpCs).

January 24, 2019 |
Webcast: The Current (and Future) State of Oil and Gas M&A (2019)

Notwithstanding the recent (and precipitous) decline in commodity prices, the prior 12 months proved to be a relatively robust year for transactional activity in the oil and gas sector. Corporate consolidation, opportunistic acquisitions/divestitures, infrastructure development, and alternative financing arrangements have kept – and continue to keep – many of us busy. But will this continue, particularly in a (continued) volatile price environment? Join members of Gibson Dunn’s Mergers and Acquisitions and Oil and Gas Practice Groups for a 60 minute presentation to share their views on this question, as well as to (1) discuss the current state of mergers and acquisitions at the corporate level (“M&A”) and acquisitions and divestitures at the asset level (“A&D”) in the oil and gas sector; (2) identify trends in M&A and A&D in the sector; and (3) use their crystal balls to attempt to foresee what the future holds for M&A and A&D in the sector in 2019. 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. His practice focuses on international and U.S. oil and gas ventures, including LNG, deep-water, and unconventional resource development projects, international and U.S. infrastructure projects, asset acquisitions and divestitures, and energy-based financings, including project financings, reserve-based loans, and production payments. Justin T. Stolte is a partner in the Houston office of Gibson, Dunn & Crutcher, and a member of the firm’s Mergers and Acquisitions and Energy and Infrastructure practice groups. He represents exploration and production companies, midstream companies, private equity groups, and other financial institutions in complex transactions across the energy sector, with a particular focus on acquisitions, divestitures, and joint ventures involving upstream (onshore and offshore), midstream (gathering, processing, transportation, fractionation, and storage), liquefied natural gas (LNG), and downstream (petrochemicals and refining) assets. MODERATOR: Jeffrey A. Chapman is Co-Chair of Gibson Dunn’s Global Mergers and Acquisitions Practice Group. He maintains an active M&A practice representing private equity firms and public and private companies in diverse cross-border and domestic transactions in a broad range of industries. 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 Jeanine McKeown (National Training Administrator), at 213-229-7140 or jmckeown@gibsondunn.com to request the MCLE form. This program has been approved for credit in accordance with the requirements of the Texas State Bar for a maximum of 1.0 credit hour, of which 1.0 credit hour may be applied toward the area of accredited general requirement. Attorneys seeking Texas credit must obtain an Affirmation Form prior to watching the archived version of this webcast. Please contact Jeanine McKeown (National Training Administrator), at 213-229-7140 or jmckeown@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.

November 26, 2018 |
FERC Issues Proposed Rule on Return of Excess ADITs by Electric Utilities

Click for PDF On November 15, 2018, the Federal Energy Regulatory Commission (“FERC”) issued a Notice of Proposed Rulemaking (“NOPR”) addressing how electric utilities are to modify their cost-based rates to account for the impact of the Tax Cuts and Jobs Act of 2017 on accumulated deferred income taxes (“ADITs”).  FERC’s prior orders related to tax reform had deferred action on how to treat ADITs. FERC-jurisdictional transmission providers have billions of dollars of ADITs recorded on their books and the return of excess ADITs resulting from the Tax Act could return billions of dollars to ratepayers in coming years.  FERC’s rulemaking proceeding should provide guidance on how utilities are to address these ADITs, but the details will likely only be decided in company-specific proceedings initiated in the next year or so. ADITs are values recorded on the books of utilities that arise from the differences between the accelerated rates of depreciation used to calculate federal corporate income taxes and straight-line depreciation used to calculate FERC jurisdictional cost-based rates.  ADITs are generally liabilities that reflect money that will need to be paid to the IRS in the future and are based on an assumption that current income tax rates will remain the same. If federal corporate income tax rates fall, however, the amount the utility will actually need to pay to the IRS in the future is less than what was assumed.  And, as a result, the utility will be viewed as having over-collected from customers in the past.  In accounting parlance, the utility will be considered to have recovered “excess ADITs” through rates that, in the view of many, will need to be returned to customers, lest the utility enjoy a windfall from the tax cut that is not shared with customers. Indeed, this is the view taken by FERC in its NOPR.  It proposes to require utilities with formula transmission rates to adjust their rates to reflect the impact of the Tax Act on ADITs, whether that means returning excess ADITs to ratepayers or collecting deficient ADITs from ratepayers (though the former is likely to eclipse the latter for most utilities). Specifically, FERC proposes requiring such utilities to include a mechanism in their formula transmission rates that deducts any excess ADITs from rate base (or adds any deficient ADITs to rate base).  Notably, FERC states in the NOPR that it does not intend to adopt a “one size fits all” approach.  Instead, it intends to “allow public utilities to propose any necessary changes to their formula rates on an individual basis.” FERC also proposes that these utilities include a mechanism to decrease (or increase) any income tax allowances—i.e., a mechanism that provides for the return to or collection of excess or deficient ADITs from ratepayers over time.  In keeping with its approach of allowing flexibility, FERC does not propose any specific period of time but, instead, states that a “case-by-case approach to amortizing excess or deficient unprotected ADIT remains appropriate.”  Following this case-by-case approach, shortly before the NOPR issued, FERC approved a proposal by Emera Maine to return unprotected excess ADITs to customers over a period of 10 years. For utilities with stated transmission rates, however, FERC does not propose to require rate base adjustments prior to their next rate case.  But it does propose to require that such utilities determine their excess and deficient ADITs and propose in compliance filings a manner to return or recover these amounts from ratepayers. FERC-regulated transmission providers appear to have billions of dollars of ADITs recorded on their books.  Assuming FERC’s final rule generally follows its proposal, these utilities will likely need to return billions of dollars in excess ADITs.  But the precise manner in which this is done—and importantly the period of time over which excess ADITs will be returned—will likely be resolved only in company specific proceedings in the future. These proceedings are likely to be contentious at times, as customers will generally push for a faster return, but at the same time will need to balance that speed against future rate shock once the amortization is complete.  FERC recently approved Emera Maine’s request to return unprotected excess ADITs over 10 years, finding that doing so “balances passing through the benefits of the Tax Cuts and Jobs Act to ratepayers in a timely manner with avoiding rate shock.”  Whether other utilities will propose similar or different periods, and how FERC will respond, remains to be seen. The deadline for comments on the NOPR (issued in Docket No. RM19-5-000) is December 24, 2018.  FERC proposes that compliance filings be due within 90 days of the date of any Final Rule. *   *   *   * Gibson Dunn was counsel to Emera Maine in the matter noted above. 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) Jeffrey M. Jakubiak – New York (+1 212-351-2498, jjakubiak@gibsondunn.com) Jennifer C. Mansh – Washington, D.C. (+1 202-955-8590, jmansh@gibsondunn.com) © 2018 Gibson, Dunn & Crutcher LLP Attorney Advertising:  The enclosed materials have been prepared for general informational purposes only and are not intended as legal advice.

November 1, 2018 |
U.S. News – Best Lawyers® Awards Gibson Dunn 132 Top-Tier Rankings

U.S. News – Best Lawyers® awarded Gibson Dunn Tier 1 rankings in 132 practice area categories in its 2019 “Best Law Firms” [PDF] survey. Overall, the firm earned 169 rankings in nine metropolitan areas and nationally. Additionally, Gibson Dunn was recognized as “Law Firm of the Year” for Litigation – Antitrust and Litigation – Securities. Firms are recognized for “professional excellence with persistently impressive ratings from clients and peers.” The recognition was announced on November 1, 2018.

October 8, 2018 |
Four Questions To Ask Before An IPO

Houston partners Hillary Holmes, Gerry Spedale and James Chenoweth are the authors of “Four Questions To Ask Before An IPO,” [PDF] published in the October 2018 issue of Midstream Business.

October 1, 2018 |
Congress Clarifies Statutory Thresholds for FERC Merger Approvals

Click for PDF On September 28, 2018, President Trump signed into law amendments to Section 203 of the Federal Power Act that, among other things, narrow the scope of transactions that require prior approval from the Federal Energy Regulatory Commission (“FERC”).  The changes become effective on March 27, 2019. Presently, FERC prior approval is required anytime a public utility or an affiliate of a public utility acquires facilities subject to FERC’s jurisdiction (i.e., it engages in a “utility merger”)—regardless of value.  The new law establishes a $10 million threshold for such transactions and also requires after-the-fact reporting of such transactions involving assets valued between $1 million and $10 million. This amendment fixes inconsistencies in the Federal Power Act and eases significantly the regulatory burden associated with the purchase of smaller and/or lower value, FERC-jurisdictional assets.  Under the Energy Policy Act of 2005, Congress eliminated entirely any clear monetary threshold for utility merger approvals while at the same time increasing the threshold from $50,000 to $10 million for all other types of sales and purchases requiring FERC approval.  Since the statute was silent regarding any sort of de minimis threshold utility merger approvals, FERC interpreted its authority to extend to all such mergers regardless of the value of the facilities.  This has led to numerous applications to FERC for approval of transactions involving minimally valued assets (some as low as $1), frustration on the part of some utilities, and some entities incurring fines from the FERC Office of Enforcement due to erroneous reading of a $10 million threshold into the statute. The amended Section 203(a)(1) will also significantly ease the regulatory burden associated with the sales of lower value, FERC-jurisdictional assets.  Applications to FERC under Section 203 are burdensome to compile and it can often take months before the Commission issues an order on the request.  This amendment will help to encourage sales of less valuable FERC-jurisdictional assets while also freeing up the Commission to focus on other matters. Starting on March 27, 2019, entities wishing to engage in transactions involving FERC-jurisdictional assets of more than $10 million must continue to request FERC approval for consummating the transaction.  Entities wishing to engage in transactions involving FERC-jurisdictional assets between $1 million and $10 million do not need to seek FERC pre-approval, and instead must only notify FERC of the transaction within one month of the closing.  Transactions involving FERC-jurisdictional assets below the $1 million threshold do not need to be reported. 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) Jeffrey M. Jakubiak – New York (+1 212-351-2498, jjakubiak@gibsondunn.com) Jennifer C. Mansh – Washington, D.C. (+1 202-955-8590, jmansh@gibsondunn.com) © 2018 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 31, 2018 |
EPA Amendments to the Coal Ash Rule

Click on PDF On July 30, 2018, the Environmental Protection Agency (“EPA”) published a final rule amending the national minimum criteria for existing and new landfills and surface impoundments that contain coal combustion residuals (“CCR”), also known as coal ash.[1]  This rule, which directly affects over four hundred coal-fired electricity generating plants nationwide, is the first in a series of anticipated amendments altering regulations promulgated under the Obama Administration to address the disposal of coal ash in landfills and surface impoundments.  This first phase of regulatory changes has three key elements: It adopts two alternative performance standards that either participating state directors or the EPA may apply to owners and operators of CCR units; It revises groundwater protection standards (“GWPS”) for four regulated constituents which do not have an established maximum contaminant level under the Safe Drinking Water Act; and It extends certain deadlines by which facilities must cease the placement of waste in CCR units that are closing. I.   Background and Context Coal ash is produced from the burning of coal in coal-fired power plants.  According to the American Coal Ash Association, approximately 110 million tons of coal ash are generated every year, making it one of the most-generated forms of industrial waste in the United States.  While over one-third of all coal ash produced in the United States is recycled into construction materials, such as concrete or wallboard, a significant amount must be disposed of each year.  Coal ash contains contaminants like mercury, cadmium, and arsenic, which can pose environmental and health risks if not properly managed or disposed of. On April 17, 2015, the Obama Administration promulgated regulations setting federal standards for the disposal of coal ash pursuant to its authority under the Resource Conservation and Recovery Act, notably regulating such waste as a solid waste pursuant to Subtitle D, rather than as a hazardous waste pursuant to Subtitle C.[2]  The regulations addressed the risks associated with disposal, including leaking of contaminants into ground water, blowing into the air as dust, and catastrophic failure of coal ash surface impoundments.  EPA set certain minimum criteria consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action requirements, closure and post-closure care requirements, and record keeping, notification, and internet posting requirements. It also required unlined CCR surface impoundments contaminating groundwater above certain protection standards to stop receiving wastes and either retrofit or close, except in certain circumstances. Congress subsequently passed the Water Infrastructure for Improvements to the Nation (“WIIN”) Act, signed into law on December 16, 2016, which authorized EPA-approved state permitting programs to regulate coal ash disposal.[3]  Under the WIIN Act’s Section 2301, states may develop and operate their own permitting programs that adhere to, or are at least as protective as, the EPA’s standards.  On June 18, 2018, Oklahoma became the first (and so far only) state to have its permit program approved for the management of coal ash.  The EPA regulates coal ash disposal in states that choose not to implement permitting programs or that have inadequate programs that fail to meet federal standards. II.   Amendments to the 2015 Regulations On September 13, 2017, the EPA granted petitions from certain industry groups requesting reconsideration of certain provisions of the 2015 regulations in light of the WIIN Act and other factors.  EPA announced that it anticipates completing reconsideration of all provisions in two phases:  a first phase, which includes these amendments, to be finalized no later than June 2019, and a second phase to be proposed by September 30, 2018 and finalized by December 2019. The recently signed Amendments constituting phase one, part one, make three major changes to the prior regulations governing coal ash management and disposal.  First, EPA adopted two alternative performance standards that either participating state directors in states with approved CCR permit programs, or EPA where it is the permitting authority, may apply to owners and operators of CCR units:  (1) the suspension of groundwater monitoring requirements if there is evidence that there is no potential for migration of hazardous constituents to the uppermost aquifer during the active life of the unit and post-closure care; and (2) the issuance of technical certifications in lieu of the current requirement to have professional engineers issue certifications. Second, the Amendments revise the GWPSs for the four constituents[4] which do not have established maximum contaminant levels under the Safe Drinking Water Act, in place of the background levels under 40 CFR § 257.95(h)(2).  This revision adopts national criteria as health-based standards available to facilities to use to compare against monitored groundwater concentrations and to develop cleanup goals. Finally, the Amendments extend the deadline for when CCR units closing for cause must initiate closure under two circumstances:  (1) where the facility has detected a statistically significant increase from an unlined surface impoundment above a GWPS; and (2) where the unit is unable to comply with the aquifer location restriction.  With respect to unlined surface impoundments, the Amendments extend the 90-day period in which the owner or operator is to perform the required analysis and demonstrations by 18 months, until October 31, 2020.  With respect to aquifer location restrictions, the revision extends the timeframes during which facilities may continue to use the units by the same period, until October 31, 2020.  The EPA states that this extension allows facilities time to adjust their operations and better coordinate engineering, financial, and permitting activities. Generally speaking, these changes reduce the compliance obligations for facilities managing coal ash surface impoundments and provide increased flexibility in the management of coal ash.  They also grant the industry more time for compliance with the 2015 regulations, addressing concerns about feasibility of compliance within the original deadlines. These regulations are subject to challenge, even as EPA considers additional rulemakings to address other aspects of the 2015 coal ash rule.  In addition, EPA is currently scheduled to propose revisions to the Clean Water Act’s Effluent Limitation Guidelines applicable to steam electric power generators in December 2018, potentially posing added challenges relating to overlapping compliance schedules relevant to the management and disposal of coal ash.  In light of the ongoing complexities of the regulatory landscape, owners or operators of coal ash disposal facilities should evaluate how these proposed changes will impact their operations, costs, and investments.    [1]   See Hazardous and Solid Waste Management System:  Disposal of Coal Combustion Residuals from Electric Utilities; Amendments to the National Minimum Criteria (Phase One, Part One); Final Rule (83 Fed. Reg. 36435, July 30, 2018) (hereinafter, the “Amendments”).    [2]   40 C.F.R. § 257 pt. D.    [3]   Water Infrastructure for Improvements to the Nation Act, Pub. L. No. 114-322, 130 Stat. 1628 (2016).    [4]   These four constituents are cobalt, lithium, molybdenum, and lead. The following Gibson Dunn lawyers assisted in the preparation of this client alert: Avi Garbow and Courtney Aasen. Gibson Dunn’s lawyers are available to assist with any questions you may have regarding these issues.  For additional information about this regulatory change and other regulations affecting the management and disposal of coal ash, or related litigation, please contact the Gibson Dunn lawyer with whom you usually work or the following leaders of the firm’s Environmental Litigation and Mass Tort practice group: Avi S. Garbow (+1 202-955-8558, agarbow@gibsondunn.com) Daniel W. Nelson (+1 202-887-3687, dnelson@gibsondunn.com) Peter E. Seley (+1 202-887-3689, pseley@gibsondunn.com) © 2018 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 2, 2018 |
Who’s Who Legal Recognizes Five Gibson Dunn Partners in Energy

Five Gibson Dunn partners were recognized in Who’s Who Legal’s Energy 2018 guide:  Houston partners Michael Darden and Hillary Holmes, London partner Anna Howell, Singapore partner Brad Roach, and Washington, D.C. partner William Scherman. Additionally, Brad Roach was recognized as a Thought Leader in energy. The guide recognizes lawyers based on their “experience advising on some of the world’s most significant and cutting-edge legal matters.” The list was published July 2, 2018.

June 1, 2018 |
Houston Business Journal Names Justin Stolte to its 40 under 40

Justin Stolte has been named to Houston Business Journal’s 40 Under 40 Class of 2018, featuring “aspirational young professionals” selected for “leadership, overcoming challenges and community involvement.” His profile ran June 1, 2018.  

May 25, 2018 |
Gibson Dunn Receives Chambers USA Excellence Award

At its annual USA Excellence Awards, Chambers and Partners named Gibson Dunn the winner in the Corporate Crime & Government Investigations category. The awards “reflect notable achievements over the past 12 months, including outstanding work, impressive strategic growth and excellence in client service.” This year the firm was also shortlisted in nine other categories: Antitrust, Energy/Projects: Oil & Gas, Energy/Projects: Power (including Renewables), Intellectual Property (including Patent, Copyright & Trademark), Labor & Employment, Real Estate, Securities and Financial Services Regulation and Tax team categories. Debra Wong Yang was also shortlisted in the individual category of Litigation: White Collar Crime & Government Investigations. The awards were presented on May 24, 2018.  

April 13, 2018 |
The Indonesian PSC: the end of an era

In early 2017, Indonesia established a new form of production sharing contract (‘PSC’), the Gross-Split PSC, which abolished the cost recovery system first pioneered by Indonesia in 1966. Our article explores the history of the production sharing contract and some of the tensions associated with the traditional cost recovery system which contributed to the development of the Gross-Split PSC. We analyse the provisions of the new Gross-Split PSC and the issues that need to be considered by investors as a result of its introduction. To access a copy of our article, please click here: Our article was published in the Journal of World Energy Law and Business (JWELB) by Oxford University Press on behalf of the Association of International Petroleum Negotiators (AIPN) (Journal of World Energy Law and Business, 2018, 11, 116-135), which can be accessed at the following link: https://academic.oup.com/jwelb/article/11/2/116/4958804?guestAccessKey=a1fc1de5-422e-4abc-98bc-9e2f22303c2a Gibson, Dunn & Crutcher’s lawyers are available to assist in addressing any questions you may have regarding these issues. For further details, please contact the Gibson Dunn lawyer with whom you usually work or the authors in the firm’s Singapore office: Brad Roach Partner +65 6507 3685 broach@gibsondunn.com Alistair Dunstan Senior Associate +65 6507 3635 adunstan@gibsondunn.com

March 19, 2018 |
FERC Takes Aim at Income Tax Over Recovery in Pipelines’ Regulated Rates

Click for PDF Last week, on March 15, 2018, the Federal Energy Regulatory Commission (FERC) issued a number of orders aimed at addressing potential over-recovery of income tax in pipelines’ regulated rates.  First, in the wake of a loss in the D.C. Circuit, FERC reversed course on its long-standing policy of allowing master limited partnerships (MLPs) to include an income-tax allowance in their cost-of-service rates.  Second, FERC announced various initiatives to address potential over-recovery of taxes through cost-of-service rates that may result from the reduction in the corporate tax rate from 35% to 21%.  Although the markets initially reacted quite negatively, the actual impact will not be immediate and will vary considerably from company to company. Indeed, many companies have already announced that the FERC orders will not have a material impact on their revenue. Reversal of Income Tax Policy for MLPs[1] In the wake of the unfavorable United Airlines v. FERC[2] decision, the FERC reversed its long-standing policy of allowing MLPs to include an income-tax allowance in their cost-of-service rates.  FERC issued a policy statement that found such an allowance results in an impermissible double-recovery of costs in combination with the discounted cash flow (DCF) methodology for calculating return on equity.  FERC concluded that because the DCF methodology used to calculate the return necessary to attract capital is done on a pre-tax basis, investors’ tax liability is already reflected in calculated return on equity.  Thus, FERC concluded that any allowance for income tax with respect to an MLP would result in double-recovery of those costs. A few important points to keep in mind regarding the impact of this policy change: This only impacts FERC cost-of-service rates: Oil Pipelines: For oil pipelines, market-based rates and settlement rates will be unaffected.  With respect to indexed rates, there is no automatic immediate impact.  FERC will, however, address this issue in the next reassessment of the index in 2020. Gas Pipelines:  For interstate gas pipelines negotiated rates, market-based rates, and settlement rates are not affected.  Discount rates could be impacted, but only to the extent recourse rates are reduced below the discount-rate level as a result of the implementation of this policy. The policy statement does not actually change any pipeline’s rates. Oil Pipelines:  For oil pipelines, it announces a new policy that the pipelines may no longer include an income tax allowance in their cost of service on the annual Form 6 reporting.  Once this cost-of-service data is made publically available, it certainly could lead to FERC or shippers filing a complaint pursuant to Section 13(1) of the Interstate Commerce Act to reduce rates.  In addition, FERC intends to address the impact of the tax reduction in the five year review of the oil pipeline index in 2020.  Thus, in theory, FERC could require a reduction in rates for any pipelines whose rates are set at the ceiling by setting a negative index at that time. Gas Pipelines:  For gas pipelines, FERC is proposing a one-time reporting requirement to obtain data about the impact of this policy and the reduction in the corporate tax rate on each pipeline’s cost of service as discussed in more detail below.  Again, once this cost-of-service data is made public, FERC or shippers could initiate a proceeding to reduce rates pursuant to Section 5 of the Natural Gas Act.  This result is not automatic, however. The policy statement did not decide whether other non-pass through entities (e.g., limited partnerships, LLCs, etc.) would also no longer be permitted to recover a tax allowance in their rates.  Instead, FERC deferred those issues to consideration in future rate proceedings, but made clear that the issue of double-recovery would need to be addressed in those instances.  FERC’s Order on Remand in the United Airlines case[3] seems to leave little room for FERC to reach a contrary finding or other pass-through entities, as FERC reasoned that “MLPs and similar pass-through entities do not incur income tax at the entity level” and therefore the ROE offered under the DCF methodology must be sufficient to cover the investor’s tax liability. Notice of Proposed Rulemaking on Federal Income Tax Rate Reductions for Gas Pipelines[4] FERC issued a notice of proposed rulemaking that seeks require natural gas pipelines to do a one-time informational filing of an “abbreviated cost and revenue study” to provide information to allow FERC to determine whether gas pipelines are over-recovering for taxes in light of the reduction in the corporate tax rate.  FERC proposed to use the same form that FERC has attached to its orders initiating Section 5 rate investigations in recent years for this informational filing.  FERC then proposes several options to address over-recoveries, including some intended to encourage pipelines to voluntarily reduce rates: Limited Section 4 Filings:  Although FERC typically does not allow pipelines to file a limited rate case to adjust individual components of rates, FERC proposed to allow pipelines to file a limited Section 4 rate case to reduce their rates by the percentage reduction in the cost of service from the decrease in the federal corporate income tax rate and the elimination of the income tax allowance for MLPs. File a Statement Explaining Why an Adjustment is Not Necessary:  If a pipeline’s reduction in cost of service from the tax cuts and elimination of income tax allowance are offset by increases in costs elsewhere or if the pipeline is overall not recovering its cost of service despite the tax decease, a pipeline can file a statement explaining why no decrease in rates is appropriate despite the income tax reduction. Commit to File a General Section 4 Rate Case (or an Uncontested Settlement):  In lieu of a limited Section 4 rate case, pipelines can commit to file a general Section 4 rate case and indicate an approximate time-frame for making such a filing.  FERC proposes that if a pipeline commits to make such a filing by December 31, 2018, FERC will not initiate a Section 5 investigation of the pipeline’s rates prior to that time. File the Information Required and Do Nothing Else:  FERC, in a somewhat disingenuous acknowledgement that it cannot legally force pipelines to file a Section 4 rate case, notes that a pipeline may simply file the required information with FERC, take no further action, and wait to see if FERC initiates a Section 5 investigation.  FERC proposes, however, to open a rate proceeding docket for each filing and issue a public notice inviting interventions and protests on the filing.  FERC will then decide whether to initiate a Section 5 proceeding based on the public comments and protests.  In sum, these procedures are strikingly similar to requiring a Section 4 rate filing. With respect to intrastate Hinshaw and Section 311 pipelines, FERC found that its existing policies are generally sufficient to address potential over-recovery resulting from the Tax Cuts and Jobs Act.  However, FERC does propose to require that if a pipeline adjusts its state-jurisdictional rates as a result of the Act, then the pipeline must file a new rate election within 30 days after the reduced intrastate rate becomes effective. Notice of Inquiry Regarding the Effect of Tax Cuts and Jobs Act[5] Finally, FERC opened an inquiry to solicit comments on the impacts of other aspects of tax reform on jurisdictional rates, such as the treatment of accumulated deferred income taxes and the new 100% bonus depreciation regime which applies to oil pipelines.  In this regard, FERC is particularly interested how to treat accumulated deferred income tax going forward in light of the reduction in future tax liability.  FERC is soliciting comments on various topics related to ADIT, including: How to ensure rate base continues to be treated in a manner similar to that prior to the Tax Cuts and Jobs Act until excess and deficient ADIT is fully settled. Whether and how adjustments should be made so that rate base may be appropriately adjusted by excess and deficient ADIT. How tax allowance or expense in cost of service will be implemented to reflect the amortization of excess and deficient plant-based ADIT. FERC is also soliciting comments on the effect of the bonus depreciation change under the Tax Cuts and Jobs Act, which increases the bonus depreciation allowance from 50% to 100% for qualified property placed into service after September 1, 2017 and before January 1, 2023. Comments are due 60 days after publication of the notice in Federal Register.    [1]   Revised Policy Statement on Treatment of Income Taxes, 162 FERC ¶ 61,227 (2018).    [2]   827 F.3d 122 (D.C. Cir. 2016).    [3]   SFPP, L.P., 162 FERC ¶ 61,228 at P 22 (2018).    [4]   Interstate and Intrastate Natural Gas Pipelines; Rate Changes Relating to Federal Income Tax Rate, 162 FERC ¶ 61,226 (2018).    [5]   Inquiry Regarding the Effect of the Tax Cuts and Jobs Act on Commission Jurisdictional Rates, 162 FERC ¶ 61,223 (2018). Gibson Dunn’s Energy, Regulation and Litigation lawyers are available to assist in addressing any questions you may have regarding the developments discussed above.  Please contact the Gibson Dunn lawyer with whom you usually work, or the following: 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) © 2018 Gibson, Dunn & Crutcher LLP, 333 South Grand Avenue, Los Angeles, CA 90071 Attorney Advertising:  The enclosed materials have been prepared for general informational purposes only and are not intended as legal advice.

March 1, 2018 |
Drilling Down on DrillCos

Houston partner Michael Darden is the author of “Drilling Down on DrillCos,” [PDF] published by Oil & Gas Investor in March 2018.