Source: https://www.tkoilandgasupdate.com/page/2/
Timestamp: 2019-04-18 12:53:46+00:00

Document:
Parties to oil and gas leases on property that is, or may be, subject to a prior lease may want to take greater care when memorializing their intent with respect to the new lease’s effect on prior leases. The Texas Supreme Court heard arguments early this year in a case that has the court deciding whether an original lessee should have the burden of proving that a new lease, executed by the assignee of its rights under the original lease, was actually a top lease subject to the original lessee’s back-in rights, or whether the execution of the new lease “washed out” the back-in rights.
TRO-X L.P. leased property in Ward County in 2007 from five lessors, each with an undivided interest in the property, and entered into a participation agreement with a third party, under which TRO-X assigned its rights in the lease but retained a right to a five percent “back-in” once the project reached payout. The Participation Agreement also included an anti-washout provision that extended TRO-X’s back-in right to any renewals, extensions, or top leases. The third party conveyed its rights in the lease to Anadarko Petroleum Corp. subject to the Participation Agreement (including the back-in rights).
In 2011, one of the lessors sent Anadarko a demand letter alleging non-compliance with an Offset-Well provision contained in the original leases (“2007 Leases”). Anadarko subsequently entered into negotiations of, and eventually executed, new leases (“2011 Leases”) with the same subject property under substantially the same terms as the 2007 Leases.
TRO-X brought suit alleging that, pursuant to the anti-washout provision in the Participation Agreement, it was entitled to the five percent back-in under the 2011 Leases. The trial court agreed with TRO-X and found that the 2011 Leases were top leases and, pursuant to the anti-washout provision, were subject to the terms of the Participation Agreement. Anadarko appealed asserting insufficiency of evidence for the trial court’s finding. The Eighth Court of Appeals reversed and rendered judgement for Anadarko, finding that the trial court did not have legally sufficient evidence to discern the lessor’s intent that the 2011 Leases were top leases rather than a revocation of the 2007 Leases coupled with new and independent leases. Anadarko Petroleum Corp. v. TRO-X, L.P., 511 S.W.3d 778, 779 (Tex. App.—El Paso 2016, pet. granted).
TRO-X appealed the court of appeals’ ruling contending, among other arguments, that the court errantly placed the burden of proving that the 2011 Leases were top leases on TRO-X, and that the 2011 Leases were top leases as a matter of law.
Regardless of how the court rules, parties to oil and gas leases will find it prudent to memorialize their intent with respect to the effect of a new lease on prior leases to which the leased property may be subject. In addition, parties to participation agreements should carefully consider the wording of any anti-washout provision included in such agreements.
If this waiver were enforceable, the service companies could not file oil and gas mechanics liens pursuant to Chapter 56 of the Texas Property Code against the mineral interest. The operator filed bankruptcy and, in a case of first impression, objected to the enforceability of the liens on the basis of the advance waiver provision and other grounds.
However, it is Chapter 56 that governs oil and gas liens, and this Chapter does not include the same prohibition against waivers as that contained in Section 53.286. Although Chapter 56 incorporates certain provisions from Chapter 53 regarding enforcement, the Bankruptcy Court did not find that was broad enough to include the waiver prohibition in Chapter 53.
And when we go to 53.286. . . you can argue this particular provision one way or the other depending upon how you want to see it. You can look at it and say, well, this kind of expresses a legislative intent that waiver of statutory liens is - - void as against public policy. But you can also look at it and say, well, the fact that it exists in Chapter 53 but it doesn’t exist in Chapter 56 is an indication that the legislature didn’t intend for that to apply to Chapter 56. And we can ascribe all sorts of legislative intent to this if we want to. We can ascribe the fact that, gee, maybe the Texas legislature just didn’t think about it at the time that they amended Chapter 53, or we can say that maybe the oil and gas industry didn’t have as good a lobby as mechanics and materialmen. Or maybe we can just say, the legislature could just as easily have taken the same type of public policy and applied it to Chapter 56. I think that’s the real problem with looking through legislative history or legislative intent, because it can be twisted to make it whatever you want it to be.
But at the end of the day, all I’m left with is the statute itself, and there’s nothing in Chapter 56 that precludes waiver of these liens. And I think that the Texas Supreme Court has expressed its preference that the parties are free to contract. - - Texas is a big freedom of contract state in contracting around what would otherwise be statutory or, in some cases, constitutional rights.” Case 16-04065, Bankruptcy Court of Northern District of Texas, Doc 252, Entered 1/26/17, Transcript pp. 89-90 (edited for clarity).
In conclusion, this appears to be a close question. The only legal authority is an unreported opinion of one bankruptcy judge with limited precedential value. As a practical matter, however, until some court decides otherwise, operators and service companies should assume advance mineral contractor lien waivers in MSAs in Texas are valid and enforceable and prepare accordingly.
During the 2013 Texas Legislative Session, a colleague and I lobbied for an amendment to the Texas Environmental, Health, and Safety Audit Privilege Act (the “Audit Act”). In case that law isn’t a familiar one, here’s the gist: It provides immunity from civil and administrative penalties for environmental, health, and safety (“EHS”) violations that are identified during a compliance audit, voluntarily disclosed to the appropriate regulatory agency, and diligently corrected. Prior notice of the audit is required, as is notification to the agency upon completion of required corrective actions. The 2013 amendment to the Audit Act creates the opportunity for a new owner who identified EHS violations during due diligence to disclose the violations to the appropriate regulatory agency within 45 days after closing and also be eligible for immunity under the Audit Act, without the need for the otherwise required prior notice of audit to the agency.
The idea for the new owner amendment to the Audit Act occurred to us because we had a number of oil and gas exploration and production and midstream clients who at the time were users of the Audit Act for operations that they currently owned or operated but couldn’t use the Audit Act to mitigate the risk of enforcement penalties when they acquired new assets because the Audit Act only afforded protection to present owners and operators. Our clients were identifying EHS issues such as lack of air permitting, noncompliance with New Source Performance Standards (“NSPS”) for storage vessels (e.g., Subparts Kb and OOOO) and engines (e.g., Subpart JJJJ), unreclaimed drilling pits, and requirements for sites handling sour gas during their due diligence activities prior to closing. While they had every intention of correcting these issues post-closing, they had limited tools outside of the liability allocation measures in the deal documents to address the risk of enforcement penalties. In the meantime, the out-of-compliance assets remained at risk for agency enforcement. The 2013 new owner amendment to the Audit Act changed that. However, it became law in September 2013, just months before the oil price crash and the sharp reduction in transactions in the oil and gas industry, and it seems to only now be demonstrating its value to the industry it was in large part developed to assist.
As the price of oil has since stabilized somewhat and transaction activity in the industry has increased again, particularly transactions involving distressed assets where EHS compliance may not have been a priority, the risk management tool that the Audit Act’s new owner provisions provide has again become highly relevant. We’re seeing buyers raising the prospect of its use post-closing and sellers insisting on a buyer’s use of it to mitigate any potential environmental liability that seller might retain. Use of the Audit Act’s new owner provisions reduces regulatory penalty risks, risks that flow to both prior and current owners and operators, and, thus, makes sense for both sides of a transaction.
A buyer who identifies EHS compliance issues during due diligence activities must voluntarily disclose those violations to the appropriate state agency (e.g., Railroad Commission of Texas, Texas Commission on Environmental Quality) within 45 days after closing.
The new owner may continue the audit after closing that commenced as due diligence prior to closing by also giving notice to the appropriate agency within 45 days after closing. In such a case, the new owner has six months after the date of closing to complete the ongoing EHS audit. Any additional compliance issues identified during the audit must be “promptly” disclosed to preserve eligibility for immunity from civil and administrative penalties for those violations.
Disclosed violations must be diligently corrected, but typically on a (reasonable) schedule proposed by the new owner, rather than within timelines established by the agency.
The new owner must notify the agency once all corrective actions are completed.
The relevant agency will review the audit submittals, request additional information if needed, or, if all requirements of the Audit Act have been met, issue a “no further action” determination.
With the onslaught of new environmental regulations in the last few years, managing EHS compliance has become increasingly challenging. The Audit Act’s new owner provisions provide a risk management tool to address gaps in compliance due to, for example, neglected distressed assets, owners or operators that are unfamiliar with environmental regulation, or mere oversight. And it’s a tool that can benefit both sides of a transaction.
 Tex. Rev. Civ. Stat. Ann. art. 4447cc; see also Senate Bill 1300 (83rd Leg., R.S. (2013)).
 Tex. Rev. Civ. Stat. Ann. art. 4447cc § 10(b)(1)(B).
 Id. § 10(b)(1)(A) and (g-1).
On May 19, the Supreme Court of Texas issued its opinion in Lightning Oil Co. v. Anadarko E&P Onshore, LLC, No. 15-0190, 2017 WL 2200343 (Tex. 2017). In a unanimous opinion by Justice Johnson, the Court resolved a dispute about whether the right to grant permission to drill through the subsurface belongs to the surface-estate owner or the mineral-estate owner.
Anadarko signed a mineral lease covering lands located in a wildlife conservation area. The lease required Anadarko to use drilling locations outside the wildlife conservation area “when prudent and feasible.” To comply with this term of the lease, Anadarko approached the owner of the Briscoe Ranch, which adjoins the wildlife conservation area. The mineral estate under the Briscoe Ranch had been severed from the surface estate. The Briscoe Ranch, Inc. owns the surface estate and the minerals are leased to Lightning Oil. Anadarko signed an agreement with Briscoe Ranch, Inc. (the surface-estate owner) to build a drilling site on the Briscoe Ranch and drill five horizontal wells to reach the minerals in the wildlife conservation area. Although the wellbores would pass through mineral formations owned by Lightning, Anadarko disclaims any intention to produce any minerals from Lightning’s leasehold. Lightning objected to the agreement between Anadarko and Briscoe Ranch, Inc., and sued Anadarko for trespass and tortious interference with contract.
The Supreme Court noted that while Anadarko’s activities on the Briscoe Ranch might present some risk to Lightning’s rights, those rights could be protected (i) by the Railroad Commission’s rules regarding placement of wells and (ii) by the accommodation doctrine and the fact that Anadarko’s rights (because they are derived from the surface-estate owner) would be subject to Lightning’s rights as the owner of the dominant mineral estate.
The Court then considered whether Lightning could make a claim based on the fact that some quantum of Lightning’s minerals embedded in the subsurface materials were removed during drilling. The Court held that Lightning’s rights must be balanced against state policy of encouraging maximum recovery of minerals. In the balancing, the Court concluded that Lightning’s loss of some minerals through the drilling process was not a sufficient injury to support a claim for trespass. The Court also rejected Lightning’s claim for tortious interference with its lease, because nothing Anadarko planned to do interfered with Lightning’s contractual rights.
The use of independent contractors is prevalent in the oil and gas industry. Using such workers has certain advantages, including savings in employee benefits costs and payroll tax liabilities and additional flexibility to respond to shifting business needs. However, using such workers causes a business to run the risk of misclassifying individuals who should be treated as employees as independent contractors, which could result in significant wage, tax, and other liabilities. This risk has grown as oversight from governmental agencies has increased.
In recent years, businesses have faced enhanced enforcement efforts from the U.S. Department of Labor (DOL) and Internal Revenue Service (IRS) concerning the misclassification of employees as independent contractors. The DOL concluded that the oil and gas industry in particular is “ripe for noncompliance” with wage-hour laws due to the “fissured landscape” in which job sites that “used to be run by a single company can now have dozens of smaller contractors performing work.” Since 2012, the DOL has concluded more than 1,000 investigations and recovered more than $41,500,000 in back wages in an initiative focused on oil and gas related industries.
The DOL and IRS have pledged to share information and coordinate enforcement efforts to reduce the incidence of misclassification, reduce the tax gap, and improve compliance with federal tax and labor laws.
Businesses that classify workers as “independent contractors” (or other nonemployee workers) should ensure that their workers are properly classified. This is no simple task, as businesses that use such nonemployee workers must be able to justify such classification under all relevant laws, including the Fair Labor Standards Act, state wages and hour laws, workers’ compensation and unemployment compensation statutes, and state and federal tax codes.
Longstanding industry practice does not guarantee that a given classification decision will be upheld or insulate a business from liability for misclassification. Further, different but similar standards apply for determining whether a worker is an employee or an independent contractor under the various laws. Generally, these standards all depend on the degree of control the employer retains over the work performed and the amount of independence retained by the worker.
Often the best first step for an employer concerned about worker classification is to conduct an internal audit to help identify potential misclassification issues and develop a plan to address any potential deficiencies located in the audit. Particular care should be taken to ensure that like individuals are treated alike so that individuals performing the same job functions are not classified inconsistently. Members of Thompson & Knight’s Labor and Employment Practice Group and Tax Practice Group are available to assist employers with conducting audits and taking other steps to avoid misclassification issues and to help ensure compliance with applicable tax and employment laws.
 Press Release, U.S. Department of Labor Wage and Hour Division, Release No. 14-1883-PHI (Dec. 10, 2014).
 News Release, U.S. Department of Labor Wage and Hour Division, Release No. 16-1221-SAN (Sept. 8, 2016).
 Memorandum of Understanding between the Internal Revenue Service and the United States Department of Labor (Sept. 19, 2011).
After refusing to review denial of injunction, Texas Supreme Court to take up issue of denial of trespass claim in Lightning Oil v. Anadarko.
On Friday, January 20th, the Texas Supreme Court agreed to hear a case from the San Antonio Court of Appeals, involving Lightning Oil Company and Anadarko Petroleum Corporation. The dispute surrounds Lightning’s claim that Anadarko will trespass if it drills through Lightning’s leasehold estate to access an adjacent oil and gas block.
Lightning leased the minerals beneath the Briscoe Ranch in Dimmit, Texas. Anadarko’s Chaparral lease, which covers land directly south of Lightning’s leases, precluded use of the surface, so Anadarko entered into an agreement with the Briscoe Ranch owners to use the surface to drill horizontal wells beneath the Chaparral. Lightning filed suit, seeking to prevent Anadarko from drilling and sought a temporary injunction while the parties litigated whether Anadarko’s well would trespass Lightning’s mineral leasehold. The trial court denied Lightning’s application for temporary injunction, and Lightning appealed. In November 2014, the appeals court affirmed the trial court decision, holding that Lightning did not meet its temporary injunction request burden to prove probable, imminent, and irreparable injury if Anadarko is allowed to drill on the Briscoe Ranch surface. The Texas Supreme Court denied review of Lightning’s petition.
After losing a summary judgment battle at the trial level as to the trespass issue, Lightning appealed. In October 2015, the San Antonio Court of Appeals again ruled in favor of Anadarko, this time holding that the surface owner could grant Anadarko the right to drill through the subsurface. Lightning appealed to the Texas Supreme Court, and this time the Court granted review. The Court will be deciding whether Anadarko’s use of Briscoe Farm’s surface estate, to drill beneath its southward Chaparral leases, is a trespass to Lightning’s oil and gas leasehold estate beneath the Briscoe Farm acreage. This issue is a significant one to the industry, and the impact of the Court’s decision is likely to have reverberating effects, as the use of offsite drilling pads is commonplace, and the Court may clarify how an operator should proceed.
 Lightning Oil Co. v. Anadarko E & P Onshore, LLC, No. 04-14-00152-CV, 2014 WL 5463956, at *1 (Tex. App.—San Antonio Oct. 29, 2014, pet. denied) (mem. op.).
 Lightning Oil Co. v. Anadarko E & P Onshore LLC, 480 S.W.3d 628, 638 (Tex. App.—San Antonio 2015), review granted (Jan. 20, 2017).
The AAPL officially released its Form 610 – 2015 Model Form Operating Agreement (the “2015 JOA”) to the public last month via its proprietary online Contract Center. Intended to be a comprehensive update to address the realities of horizontal drilling, the 2015 JOA contains new and revised: definitions, well proposal and elections provisions, expanded forms of notice (i.e., email), among numerous other changes. Nevertheless, many of the form revisions contained in the new 2015 JOA will appear familiar to domestic industry participants who have negotiated an operating agreement in recent years. This is because most of the changes to the 2015 JOA echo the revisions and additions that had become market in shale-play operating agreements utilized in the Barnett, Haynesville, Eagle Ford, and Marcellus shales.
An important departure from the horizontally-oriented revisions contained in the 2015 JOA is the form’s overhauled approach to the operator’s rights and duties in Article V. These changes were prompted less by horizontal drilling practices than by state court rulings interpreting the applicability of the model form’s exculpatory clause. In particular, Article V.A. of the 2015 JOA provides that an operator shall have no liability to the non-operators “for losses sustained or liabilities incurred in connection with authorized or approved operations under this agreement except as may result from gross negligence or willful misconduct.” The addition of the italicized phrase is a direct response to the Texas Supreme Court’s ruling in Reeder v. Wood County, which held that the exculpatory clause should be applied broadly to relieve an operator of liability (even for breach of the operating agreement), except in cases where the operator’s conduct was grossly negligent or willfully bad. Arguably, the revision to this provision in the 2015 JOA is an expression of the spirit, if not the letter, of the reasonable operator protections contained in the AAPL’s previous model form operating agreements. That is, the reasonably prudent operator is authorized to execute its duties without the unwarranted second-guessing of its non-operators, but that authority (and protection from liability) is not unlimited.
Additional operator-related concepts include provisions for the engagement of a non-owning or contract operator pursuant to a discrete agreement (Art. V.A.). The obligations of the non-owning operator will be according to the terms of the 2015 JOA, unless otherwise set forth in the separate contract operator agreement. Further, the removal of a non-owning operator may be effected by majority ownership vote, without the requirement that good cause be shown (Art. V.B.5). And, in the case of an operator who owns an interest in the Contract Area, Article V.B.2 of the 2015 JOA allows the parties to select a minimum ownership percentage; if an operator’s ownership interest falls below this minimum threshold, such operator will be deemed to have resigned its operatorship.
The 2015 JOA contains additional operator-related revisions, the potential effects of which merit further analysis. We encourage the owners of working interests in oil and gas assets to seek competent legal counsel prior to executing a new 2015 JOA or any other form of operating agreement.
Oil and gas drillers across Texas had their hopes of a multi-million dollar tax break dashed this summer, as the Texas Supreme Court held in Southwest Royalties, Inc. v. Hegar, that downhole equipment such as casing and tubing was not exempt from state sales taxes. However, the court left the door open for future tax disputes involving more advanced extraction equipment and may offer opportunities for exploration, production, and processing companies seeking tax benefits under Texas law.
Midland-based Southwest Royalties filed its initial suit in 2009, seeking a refund for sales taxes paid on the casing, tubing, and pumps used by its oil and gas exploration division. The company cited Texas Tax Code § 151.318, which provides a tax exemption for equipment “used or consumed” in “the actual manufacturing, processing, or fabrication of tangible personal property for ultimate sale.” Southwest Royalties sought refunds of less than $500,000, but a win for the company could have forced the Comptroller to issue billions of dollars in refunds industry-wide.
The dispute centered largely on the meaning of “processing” in Texas Tax Code § 151.318. The court concluded that “processing” included any equipment used to “modify or change the characteristics of tangible personal property,” including hydrocarbons. The key question analyzed by the court was whether the casing, tubing, and pumps used by Southwest Royalties caused any physical or chemical change to minerals after they were extracted. While minerals undergo various phase changes during extraction, the court concluded that these phase changes were the result of natural shifts in pressure and temperature that occurred during the extraction process. Although equipment plays a vital role in transporting hydrocarbons to the surface, it is only a “conduit” by which the minerals moved from the reservoir and thus fails to qualify as processing under the exemption.
The ruling is not all bad news for the industry, however. The Texas Supreme Court rejected the Comptroller’s attempt to categorically exclude all extraction and processing equipment from sales tax exemptions, and the court’s detailed analysis of drilling operations offers a road-map for future, case-by-case disputes involving tax exemptions for other types of oilfield equipment. Thus, for example, oilfield extraction or production equipment that "processes" (i.e., changes the physical characteristics of) hydrocarbons now is potentially subject to the exemption in Texas Tax Code § 151.318. As a result, exploration and production companies looking to reduce their tax bill may find relief in this summer’s decision.
 No. 14-0743, 2016 WL 3382151 (Tex. June 17, 2016). The Texas Supreme Court issued a revised opinion on October 21, 2016, clarifying that in most cases “artificial means” are needed to move oil & gas from its reservoir into the wellbore. The revised opinion can be found here.
 Tex. Tax Code § 151.318(a)(2), (5), (10).
 Jim Malewitz, Texas Budget Spared in Court Ruling on Drilling Tax Case, Texas Tribune, June 17, 2016.
 Southwest Royalties, 2016 WL 3382151, at *5–6.

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