2016 OIL AND GAS LAW UPDATE

Alex Ritchie Associate Professor, Leon Karelitz Chair in Oil and Gas Law University of New Mexico School of Law1

Contents

I. Introduction ...... 2 II. Texas Oil and Gas Regulations ...... 2 1. Commission Rule Amendments for Horizontal Development ...... 2 2. Surface Equipment Removal Requirements and Inactive Wells ...... 5 3. Deliverability Tests ...... 6 III. Texas Cases ...... 6 1. In re Sabine Oil and Gas Corp...... 6 2. Coyote Lake Ranch, LLC v. City of Lubbock ...... 10 3. Hysaw v. Dawkins ...... 12 4. Apache Deepwater, LLC v. McDaniel Partners, Ltd...... 13 5. Texas Railroad Commission v. Gulf Energy Exploration Corp...... 14 6. Crosstex North Texas Pipeline L.P. v. Gardiner (Tex.) ...... 16 7. North Shore Energy, L.L.C. v. Harkins ...... 18 8. Anadarko Petroleum Corp. v. TRO-X, L.P...... 19 9. Aery v. Hoskins, Inc...... 20 10. Adams v. Murphy Exploration & Production Co...... 21 11. Jackson v. Wildflower Production Co...... 22 12. Shell Western E&P, Inc. v. Pel-State Bulk Plant, LLC ...... 24 IV. Louisiana Cases ...... 25 1. Hayes Fund for First United Methodist Church v. Kerr-McGee Rocky Mountain, LLC ...... 25 2. Regions Bank v. Questar Exploration & Production Corp...... 27 3. St. Tammany Parish Government v. Welsh ...... 28 4. AIX Energy, LLC v. Bennett Properties, LP ...... 29 5. XXI Oil & Gas, LLC v. Hilcorp Energy Co...... 30 6. Amendments to Louisiana Risk Fee Statute ...... 31 V. Eastern Cases ...... 32 1. Dominion Resources Black Warror Trust v. Walter Energy, Inc. (Alabama) ...... 32 2. Corban v. Chesapeake Exploration, L.L.C. (Ohio) ...... 33 3. State ex rel. Claugus Family Farm, L.P. v. Seventh District Court of Appeals (Ohio) 36 4. Lutz v. Chesapeake Appalachia, L.L.C. (Ohio) ...... 38 5. Simmers v. City of North Royalton (Ohio) ...... 39 6. Shedden v. Anadarko E. & P. Co., L.P. (Pennsylvania) ...... 40 7. Robinson Township v. Commonwealth (Pennsylvania) ...... 41 8. Birdie Associates, L.P. v. CNX Gas Co. (Pennsylvania) ...... 43

1 BSBA (Accounting), Georgetown University, 1993; JD, University of Virginia School of Law, 1999. The author sincerely thanks Professor of Law Librarianship Ernesto Longa for his research assistance in preparing this paper. VI. Western Cases ...... 44 1. City of Kenai v. Cook Inlet Natural Gas Storage Alaska, LLC (Alaska) ...... 44 2. City of Longmont v. Colorado Oil & Gas Association (Colorado) ...... 45 3. Armstrong v. Bromley Quarry & Asphalt, Inc. (Kansas) ...... 46 4. Earthworks’ Oil & Gas Accountability Project v. New Mexico Oil Conservation Commission (New Mexico) ...... 48 5. T.H. McElvain Oil & Gas Limited Partnership v. Benson-Montin-Greer Drilling Corp. (New Mexico) ...... 49 6. Fleck v. Missouri River Royalty Corporation (North Dakota) ...... 49 7. Vogel v. Marathon Oil Company (North Dakota) ...... 50 8. American Natural Resources, LLC v. Eagle Rock Energy Partners, L.P. (Oklahoma) ...... 52

I. INTRODUCTION

After providing a brief discussion of recent Texas oil and gas regulatory changes, this paper summarizes and analyzes selected oil and gas cases from across the Nation that were decided during 2016. This summary is not exhaustive, but is necessarily limited to some of the more important oil and gas cases selected for discussion by the author.

II. TEXAS OIL AND GAS REGULATIONS

1. Commission Rule Amendments for Horizontal Development

On January 12, 2016, the Texas Railroad Commission adopted amendments, effective February 1, 2016, to Rules 5, 31, 38, 40, 45, 51, 52, and 86 to better allow for horizontal development.2

Unconventional Fracture Treated Fields

Amended Rule 86 provides for the designation of “unconventional fracture treated” fields (“UFT fields”), defined as a field in which horizontal drilling and hydraulic fracturing must be used in order to recover resources from the field.3

A field may be designated administratively as a UFT field if (1) the in situ permeability of a distinct producible interval within the field is 0.1 millidarcies or less before fracture treatment, and (2) for producing wells that were permitted before February 1, 2012 and were completed, either there are at least five such wells of which at least 65% were drilled horizontally and completed using hydraulic fracture treatment, or there are at least 25 such wells drilled horizontally and completed using hydraulic fracture treatment.4

2 41 TEX. REG. 785 (Jan. 29, 2016). For a more in depth discussion of the horizontal development rule changes, see Tim George, Railroad Commission Update, 42 ERNEST E. SMITH OIL, GAS AND MIN. L. INST. (2016). 3 16 TEX. ADMIN. CODE § 3.86(a)(13). 4 Id. § 3.86(i)(1)(A), (i)(2)(A). 2

UFT fields may alternatively be designated through an evidentiary hearing if an applicant demonstrates that the reservoir characteristics are such that horizontal drilling and hydraulic fracturing treatment must be used to recover resources from all or part of the field and UFT designation will promote orderly development of the field.5 Regardless of such a designation, special field rules for a UFT field prevail over conflicting provisions of the Rule.6

A benefit of UFT field designation is that “[a]creage assigned to horizontal wells shall not count against acreage assigned to vertical wells, and acreage assigned to vertical wells shall not count against acreage assigned to horizontal wells.”7 In other words, the same acreage may be assigned simultaneously to both vertical and horizontal wells. Horizontal wells and vertical wells must separately satisfy density exceptions applicable to each.

Another benefit is that a horizontal well in a UFT field will usually be entitled to a larger allowable than a horizontal well in a field that has not been designated a UFT field. The maximum daily allowable for a horizontal drainhole in a UFT field is 100 barrels of oil for each acre assigned to an oil well, or 600 Mcf of gas for each acre assigned to a gas well. For a horizontal well in a field that has not been designated a UFT field, the allowable is based on the applicable allowable for a vertical well in the field under applicable field rules.8

Density exceptions are also made easier in UFT fields. For a density exception, notice is required to operators, lessees of tracts with no designated operator, or unleased mineral owners within 600 feet from any take point on a horizontal well within the UFT field correlative interval. If no objection is filed within 21 days or the applicant files objection waivers, then the application for an exception may be approved administratively without filing supporting data. If an objection is filed, the applicant may show at a hearing that the exception is necessary to effectively drain an area of the UFT field.9 These requirements are significantly relaxed from the notice and evidentiary standards for exceptions under Rule 38.10

Horizontal Drainhole Displacement

Previously, Rule 86 defined the “horizontal drainhole displacement” as the displacement between the penetration point and the terminus. The amended Rule now defines the term “horizontal drainhole displacement” as the displacement between the first take point and the last take point.11 A “take point” is defined as a point where oil or gas can be produced from the correlative interval.12 Because the first and last take point will often be inside the penetration point and the terminus, for many horizontal wells the amendment will decrease the horizontal drainhole displacement.

5 Id. § 3.86(i)(1)(B), (i)(2)(B). 6 Id. § 3.86(j). 7 Id. § 3.40(e)(1). 8 Id. § 3.86(d)(5). 9 Id. § 3.86(k). 10 Id. § 3.38(g), (h). 11 Id. § 3.86(a)(4). 12 Id. § 3.86(a)(11). 3

This change could have the effect of decreasing the well allowable for some horizontal wells. Rule 86(d) allows the assignment of acreage to each horizontal drainhole well for the purpose of allocating allowable oil or gas production up to the amount specified for a vertical well plus additional acreage that may be assigned to the horizontal drainhole under Rule 86(d)(1).13 The smaller the horizontal drainhole displacement, the smaller the additional acreage that may be assigned to the well, therefore decreasing the allowable.

Drainhole Spacing

Just as the commission tied drainhole displacement to take points, it also tied spacing of horizontal wells to takepoints, allowing closer spacing in UFT fields. Previously, no point of the drainhole could be closer than 1,200 feet to another horizontal drainhole in another well or 467 feet from any property line, lease line, or subdivision line. Now, the 1,200 foot and 467 foot spacing requirements are measured from take points, such that no take point may be 1,200 feet from another horizontal drainhole or 467 feet from a property line, lease line, or subdivision line.14

In addition, amended Rule 86 now expressly provides for “nonperforation zones” or “NPZs,” defined as a portion of a horizontal drainhole well within the field between the first take point and the last take point that the operator has intentionally designated as containing no take points.15 In other words, designated portions of an interval that are not perforated are not counted towards the spacing rules.

These amendments also now expressly provide for offsite penetration points, if prior to the submission of the application to drill, an applicant gives notice to operators (or lessees or mineral owners where there is no operator) of any offsite tracts through which the proposed wellbore path will traverse from the point of penetration, allowing the notified party 21 days to object. Notice is not required, however, if written waivers are obtained and attached to the drilling permit. Even if an operator, lessee, or mineral owner objects, the applicant may request a hearing to show that the offsite penetration point is necessary to prevent waste or protect correlative rights.16

Amended Rule 86 also creates a safe harbor for compliance with spacing rules. A well complies with Rule 37 spacing rules if the take-points along the as-drilled location fall within a predetermined rectangle. The rectangle is parallel to the permitted drainhole and 50 feet on either side, or 10% of the minimum distance to any property line, lease line or subdivision line, whichever is greater, on either side of the drainhole. This regulatory rectangle begins at the first take point and ends at the last take point.17

13 Id. § 3.86(d)(5). 14 Id. § 3.86(b)(1), (2). 15 Id. § 3.86(a)(7). 16 Id. § 3.86(g)(1). See also id. § 3.86(g)(2)(B) (“A horizontal drainhole, as drilled, shall be considered reasonable with respect to the drainhole represented on the plat filed with the drilling permit application if the take points on the as-drilled plat comply with subsection (b)(4) and (5) of this section and with any applicable lease line spacing rules.”). 17 Id. § 3.86(b)(5). 4

Finally, Rule 86 creates special rules for stacked laterals that allow an operator at its discretion to consider stacked lateral wells as a single well for density and allowable purposes. To be considered a stacked lateral, the operator must designate one horizontal drainhole as the “record well.” The result is that all points from the first take point to the last take point of any other horizontal drainhole that is part of the stacked lateral need not be within the proration and drilling unit for the record well.18 In other words, an operator need not obtain separate density exceptions for each horizontal drainhole that comprises part of the stacked lateral.

To constitute a “stacked lateral,” (a) the horizontal drainhole wells must be on the same lease, pooled unit, or unitized tract at different depths within the same correlative interval, (b) the horizontal drainholes must be drilled from different surface locations, (c) all take points must be within a predetermined rectangle with a width of 660 feet, and a length of which is 1.2 times the distance between the first and last take points of the record well, (d) all drainholes must have the same classification (gas or oil), and (e) there must be only one operator for the stacked lateral.19

These rule changes should reduce administrative burdens that hinder horizontal development, better maximizing production, preventing waste, and protecting the correlative rights of owners and lessees. In essence, the rule changes make the best special field rules the default rules. The changes recognize that horizontal wells in unconventional reservoirs drain much differently than conventional wells and that horizontal and vertical wells can and should coexist in the same field.

2. Surface Equipment Removal Requirements and Inactive Wells

On November 15, 2016, the Texas Railroad Commission adopted a seemingly minor but important amendment to Rule 15 to be effective January 1, 2017.20 The amendment generally does not change requirements to plug inactive wells or remove equipment from inactive well sites, but it does change the definition of what constitutes an inactive well. As the rule has been amended, a well that has been inactive for 12 consecutive months may again be considered active when the well has reported production of at least five (reduced from 10) barrels of oil for oil wells or 50 (reduced from 100) Mcf of gas for gas wells in each month for three consecutive months. The amendment also adds a new clause that treats a well as active again if the well has reported production of at least one barrel of oil for oil wells or at least one Mcf of gas for gas wells each month for 12 consecutive months.21

This rule change should provide relief to Texas operators faced with low commodity prices, particularly small operators of marginal wells, by lessening the prospect of prematurely plugging and abandoning wells. Notably, the commission rejected comments from landowners and an environmental group that the rule change encourages noneconomic production and delay cleanup obligations.

18 Id. § 3.86(f). 19 Id. § 3.86(a)(10). 20 Tex. Railroad Comm’n, 16 TAC Chapter 3—Oil and Gas Div. § 3.15 (Nov. 15, 2016). 21 16 TEX. ADMIN. CODE § 3.15(a)(1). 5

3. Deliverability Tests

On November 15, 2016, the Texas Railroad Commission amended Rule 28, effective January 1, 2017, relating to deliverability tests for gas wells.22 Before the amendment, an operator of a gas well was required to report the results of an initial deliverability test within 10 days after the start of production, then semiannually for most nonassociated gas wells and annually for most associated gas wells. Under the amended rule, an operator must file its initial deliverability test report within 90 days after well completion, but may elect not to perform additional tests, in which case the commission shall deem deliverability to be the lesser of the results of the most recent deliverability test on file or the maximum daily production from any of the 12 months before the due date of the test.23 Despite the election, an operator must still perform deliverability tests at recompletion of the well into a different field, at reclassification of the well from oil to gas, when the well is inactive and the operator resumes production, when necessary to reinstate an allowable, or when required by commission order or special field rule. The commission estimates that the amendment will result in 70% fewer filed Form G-10s, the gas well status reports.24

III. TEXAS CASES

1. In re Sabine Oil & Gas Corp., 547 B.R. 66 (Bankr. S.D.N.Y. 2016); In re Sabine Oil & Gas Corp., 550 B.R. 59 (Bankr. S.D.N.Y. 2016).

In this era of low oil and gas prices and the prevalent bankruptcy of upstream oil and gas companies, the characterization of an obligation in a contract as a personal covenant or a covenant running with the land may determine whether the corresponding right will survive the bankruptcy of the obligor.

As a result of a combination with Forest Oil Corp., Sabine Oil and Gas Corporation (“Sabine”) became a party to two contracts with Nordheim Eagle Ford Gathering, LLC (Nordheim) and two contracts with HPIP Gonzales Holdings, LLC (HPIP). Under the agreements, Sabine agreed to “dedicate” to the “performance” of the agreements certain gas and liquid hydrocarbons. In exchange, Nordheim and HPIP agreed to construct gathering and treatment facilities, and to redeliver the gathered and treated products to Sabine. In the Nordheim agreement specifically, Sabine agreed to deed certain lands and easements to Nordheim to construct and operate its gathering equipment. Each of the agreements expressly provided that the agreements themselves were covenants that run with the land and were binding on successors and assigns.25

In July, 2015, Sabine filed for bankruptcy under chapter 11 of the Bankruptcy Code, and a few months later filed a motion as a debtor-in-possession to reject the gathering agreements

22 Tex. Railroad Comm’n, 16 TAC Chapter 3—Oil and Gas Div. § 3.28 (Nov. 15, 2016). 23 16 TEXAS ADMIN. CODE § 3.28(d). 24 Id. § 3.28(e). 25 In re: Sabine Oil & Gas Corp., 547 B.R. 66, 70-71 (Bankr. S.D.N.Y. Mar. 8, 2016) (hereinafter, “Bench Ruling”). 6 under section 365(a) of the Bankruptcy Code.26 HPIP and Nordheim argued that rejection of the agreements does not affect covenants to non-debtor parties that run with the land because such covenants are property interests rather than merely interests in executory contracts.27 In its bench ruling on the motion to reject, the court held that Sabine had properly considered the business and legal risks associated with rejecting the contracts. The court also analyzed whether the agreements run with the land, but held that it could not rule definitively on this substantive legal issue because under Orion Pictures Corp. v. Showtime Networks28a court may not decide a disputed issue in the context of a motion to assume or reject an executory contract where the court has not scheduled and conducted an adversarial proceeding to decide the contested issue.29 In a later decision, however, the court addressed the substantive issue more directly, holding that the covenants at issue in the case do not run with the land.30

Traditionally, American courts have distinguished between covenants that run with the land at law (also referred to as real covenants) and covenants that run with the land in equity (also referred to as equitable servitudes). Under the early common law, neither the rights nor the duties created by contract could be assigned. To relieve restrictions on assignment and bind future assigns, the 1583 decision in Spencer’s Case31 introduced covenants that run at law, and the 1834 decision in Tulk v. Moxhay32 introduced covenants that run in equity.33

For most American courts, a covenant runs with the land at law (a real covenant) when it (1) touches and concerns the land, (2) the original covenanting parties intended that the covenant run with the land, and (3) there is privity of estate. In contrast, a covenant that runs in equity (an equitable servitude) must satisfy the first two requirements, but rather than privity, only notice to the successor to the burden is required, such that a purchaser without actual, constructive, or inquiry notice of the covenant would not be subject to the burden. If there is no intent that the benefit or burden of a covenant run to successors, then the covenant is considered personal to the original parties and will not run with the land.34

For covenants that run with the land at law, there are two types of privity of estate— vertical privity and horizontal privity—and under the First Restatement of Property, both types must be present for the burden of a covenant to run at law.35 Traditionally, vertical privity required that a successor seeking to enforce a covenant must succeed to the same quantum of estate (e.g. fee simple to fee simple) held by the original covenantee, but this requirement has been relaxed in most jurisdictions. Modernly, to establish vertical privity the successor need only succeed to a portion of the original estate of the covenantee.36

26 Under Section 365(a) of the Bankruptcy Code, a debtor in possession, “subject to the court’s approval, may assume or reject any executory contract . . . of the debtor.” 11 U.S.C. § 365(a). 27 See Gouveia v. Tazbir, 37 F.3d 295, 298 (7th Cir. 1994); In re Bergt, 241 B.R. 17 (Bankr. D. Ak. 1999); In re Banning Lewis Ranch Co., LLC, 532 B.R. 335, 346 (Bankr. D. Colo. 2015). 28 4 F.3d 1095, 1098 (2d Cir. 1993). 29 Bench Ruling, 546 B.R. at 73. 30 In re: Sabine Oil & Gas Corp., 550 B.R. 59 (Bankr. S.D.N.Y. 2016) (hereinafter, “Substantive Ruling”). 31 5 Co. 15a, 77 Eng,. Rep. 72 (Q.B. 1583). 32 2 Phil 774, 41 Eng. Rep. 1143 (Ch. 1848). 33 9-60 POWELL ON REAL PROPERTY § 60.01[3], [4]. 34 Id. § 60.01[5]. 35 RESTATEMENT, PROPERTY §§ 534, 535. 36 9-60 POWELL ON REAL PROPERTY § 60.04[c][iv]. 7

Horizontal privity, however, is more difficult to establish in many cases. Horizontal privity generally means that the original parties had a simultaneous existing interest (referred to as mutual privity) or an interest as grantor and grantee when the covenant was created.37 Scholars overwhelmingly advocate for the abolition of horizontal privity;38 and, the Restatement (Third) of Property: Servitudes, issued in 2000, rejects the horizontal privity requirement, reasoning that the requirement “serves no necessary purpose and simply acts as a trap for the poorly represented.”39 Despite the American Law Institute’s best efforts, however, the requirement seems to persist. One commentator reported in 2013 that not a single reported case had rejected the horizontal privity requirement after the Restatement (Third)’s adoption in 2000.40

The courts that cling to horizontal privity arguably do so in part because they resort to concepts of equitable servitudes when such privity is lacking.41 Further, since the modern combination of courts of law and equity and due to extreme confusion of judges and practitioners as to the difference between covenants at law and covenants at equity, courts have over time muddied the waters and awarded whatever relief they feel is appropriate to remedy the breach of a covenant or servitude.42 Given the confusion, in the Restatement (Third) of Property: Servitudes, the American Law Institute dropped the distinction between real covenants and equitable servitudes entirely.43

Texas jurisprudence illustrates the muddling of the law of covenants and servitudes. Consider the Texas Supreme Court case of Westland Oil Development Corp. v. Gulf Oil Corp.44 There the court held that an unrecorded area of mutual interest agreement (AMI) contained in a letter agreement for the assignment by the farmee of its interest in a farmout agreement was a covenant running with the land. The court made no mention of the distinction between covenants that run at law and covenants that run in equity. And although the court stated that privity of estate was required, it did not distinguish between horizontal and vertical privity, merely stating that the requirement was satisfied because the sections subject to the AMI were assigned to the defendants.45

37 Mutual privity means that at the time the covenant was created, the covenantor and the covenantee owned a simultaneous existing interest in the same land, which might be satisfied by a landlord/tenant relationship or when the parties are the dominant and servient owners of an easement. Mutual privity, also referred to as “Massachusetts privity” may be required in a very small number of jurisdictions. See, e.g., Morse v. Aldrich, 35 Mass. 449 (1837). The First Restatement of Property requires vertical privity and either horizontal privity or mutual privity. Restatement, Property §§ 534, 535. As such, many court decisions lump together the concept of mutual privity and horizontal privity under a single heading referred to as “horizontal privity.” 38 See, e.g., Berger, A Policy Analysis of Promises Respecting the Use of Land, 55 MINN. L. REV. 167 (1970); Browder, Running Covenants and Public Policy, 77 MICH. L. REV. 12 (1978); Newman & Losey, Covenants Running with the Land and Equitable Servitudes; Two Concepts, or One?, 21 HASTINGS L.J. 1319 (1970); Stoebuck, Running Covenants: An Analytical Primer, 52 WASH. L. REV. 861 (1977). 39 RESTATEMENT (THIRD), PROPERTY: SERVITUDES § 2.4, cmt. b (2000). 40 Michael Lewyn, The Puzzling Persistence of Horizontal Privity, 27-JUN Prob. & Prop. 32 (May/June 2013). 41 See Leywn, supra note 40. 42 9-60 POWELL, supra note 33, § 60.07. 43 RESTATEMENT (THIRD), PROPERTY: SERVITUDES § 1.4, cmt. a. 44 637 S.W.2d 903 (Tex. 1982). 45 Id. at 910-11. 8

The Fifth Circuit, in Newco Energy v. Energytec, Inc. (In re Energytec, Inc.),46 noted that Texas case law contains variations on its covenant analyses, but accepted the following as the necessary elements for a covenant to run with the land: (1) the covenant must touch and concern the land, (2) the covenant must relate to a thing in existence or specifically bind the parties and their assigns, (3) the covenant must be intended by the original parties to run with the land, and (4) the successor to the burden must have notice.47 The court in Energytec then quoted an intermediate Texas court for the proposition that “[t]here must also be privity of estate between the parties when the covenant was made.”48

In Sabine, the parties argued as to whether Texas requires horizontal privity, but the court was not persuaded that it had been abandoned because some Texas courts have included horizontal privity in their analyses.49

So without actually concluding whether Texas requires horizontal privity, the bankruptcy court in Sabine found it lacking. Although Sabine had conveyed pipeline easements and other real property to Nordheim for its gathering system, this was not the same property that HPIP and Nordheim claimed was burdened by the dedication obligation. The alleged dedication covenant burdened the land of Sabine, which was separate and apart from any land or easements conveyed to Nordheim for its gathering equipment.

Nordheim also argued that its right to connect and take minerals created a real property interest, but the court retorted that neither HPIP nor Nordheim had the right under their agreements to go upon the land and connect their pipelines to the wells. Rather, Sabine was responsible for connecting its wells to certain receipt points. The court also thought it material that the “dedication” at issue did not include granting language sufficient to constitute a conveyance of real property. In fact, the agreements contained language expressly disclaiming a conveyance.50

Compare Energytec, where Party A conveyed a pipeline and rights-of-way to Party B, reserving the right to receive a transportation fee on the pipeline system that it simultaneously assigned to Party C.51 This was the type of “traditional paradigm for horizontal privity”—a conveyance of property that itself is burdened by the covenant—that the bankruptcy court found lacking in Sabine.52

Even more significant, the Sabine court concluded that the dedication covenant did not touch and concern the land. This finding is more significant because a covenant that does not touch and concern the land can be neither a covenant at law nor an equitable servitude. To determine whether the dedication touched and concerned Sabine’s land, the court referred to two tests: (1) whether the covenant affected the nature, quality, or value of the thing demised, “independent of collateral circumstances,” or the mode of enjoying it; or (2) whether the

46 739 F.3d 215 (5th Cir. 2013). 47 Id. at 221 (quoting Inwood N. Homeowners’ Ass’n, Inc. v. Harris, 736 S.W.2d 632, 635 (Tex. 1987)). 48 Id. (quoting Ehler v. B.T. Suppens Ltd., 74 S.W.3d 515, 521 (Tex. App.—Amarillo 2002). 49 Substantive Ruling, 550 B.R. at 65. 50 Id. at 69-70. 51 Energytec, 739 F.3d. at 217. 52 Substantive Ruling, 550 B.R. at 68. 9 promisor’s legal interest was rendered less valuable. It was not sufficient that the land was rendered less valuable by the covenant; the owner’s interest in the property or its use must also have been affected.53

The dedication requirement did not affect the land “independent of collateral circumstances” because dedication was triggered when the products were produced and saved and incident to the provision of services by HPIP and Nordheim, not a conveyance of real property. HPIP and Nordheim argued that a conveyance of oil and gas “produced and saved” is the creation of a royalty and thus a dedication of minerals in place, but the court disagreed under the facts of the case.54 The obligation to dedicate related only to extracted minerals, and under Texas law, minerals once extracted are personal property.55

In its touch and concern analysis, the Sabine court also highlighted that (1) Sabine reserved rights to operate its oil and gas properties without interference from HPIP and Nordheim, (2) HPIP and Nordheim connected at receipt points, not directly to Sabine’s wells, and (3) the gathering fee to Nordheim was triggered by receipt of gas, not extraction.56 The court distinguished the 1924 case of American Refining Co. v. Tidal Western Oil Corp.,57 where the Court of Civil Appeals of Texas in Amarillo found that a requirement to deliver casinghead gas under a casinghead gas contract was a covenant running with the land. In contrast to Sabine, the covenantor in American Refining had conveyed the gas in place; the covenantee was entitled to come upon the land to install its extensive plant and equipment; and to retrieve the gas, the covenantee was required to draw the gas out of the ground using its equipment.58

In conclusion, the structure of an agreement will be critical to the analysis whether a covenant thereunder runs with the land. Even without horizontal privity, a covenant may be held to be an equitable servitude if it touches and concerns the land, so the “touch and concern” element is the most important to consider. In the context of a gathering agreement, whether there has been an express grant of the minerals in place, the degree of control of the lessee, whether the connection occurs at the well or at another point, and whether the gathering fee is payable upon extraction or receipt, may all be factors that inform a court’s analysis.

2. Coyote Lake Ranch, LLC v. City of Lubbock, 498 S.W.3d 534 (Tex. 2016), reh’g denied (Sept. 23, 2016).

In the seminal case of Getty Oil Co. v. Jones,59 the Texas Supreme Court first announced the accommodation doctrine in the context of oil and gas operations to balance the respective interests of the dominant mineral interest owner and the servient surface estate owner. The court recently restated in Merriman v. CTO Energy, Inc.60 the elements that a plaintiff surface owner must show to obtain relief against the mineral owner for unreasonable use of the surface:

53 Bench Ruling, 547 B.R. at 77. 54 Substantive Ruling, 550 B.R. at 66. 55 See e.g., Sabine Prod. Co. v. Frost Nat. Bank of San Antonio, 596 S.W.2d 271, 276 (Tex.Civ.App. 1980). 56 Substantive Ruling, 550 B.R. at 67. 57 264 S.W. 335 (Tex.Civ.App.—Amarillo, 1924). 58 Id. at 338-40. 59 470 S.W.2d 618 (Tex. 1971). 60 407 S.W.3d 244 (Tex. 2013). 10

. . . [T]he surface owner has the burden to prove that (1) the lessee’s use completely precludes or substantially impairs the existing use, and (2) there is no reasonable alternative method available to the surface owner by which the existing use can be continued. If the surface owner carries that burden, he must further prove that given the particular circumstances, there are alternative reasonable, customary, and industry-accepted methods available to the lessee which will allow recovery of the minerals and also allow the surface owner to continue the existing use.61

In Coyote Lake Ranch, the Texas Supreme Court now considered whether the accommodation doctrine applies to the groundwater estate. The ranch at issue lies over the Ogallala Aquifer. In 1953, the City of Lubbock purchased the ranch’s groundwater, subject to a reservation by the ranch of water for domestic use, ranching operations, oil and gas production, and irrigation. The deed provided the city “the full . . . rights of ingress and egress in, over, and on [the ranch], so that the [city] may at any time and location drill water wells and test wells . . .” As to surface use, the city was granted the right to use as much of the ranch as was “necessary or incidental” for taking, producing, treating, and transmitting water.

In 2012, in need of additional water, the city informed the ranch that it planned to drill up to 20 new test wells and 60 additional wells on the ranch. The ranch objected to the drilling because of the potential harm to the surface and sued. The trial court granted the ranch a temporary injunction that prohibited damage to growing grass, proceeding with drilling wells without consulting with the Ranch, and erecting power lines to the proposed well fields. The court of appeals reversed and remanded and dissolved the injunction on the grounds that the deed clearly gave the city the power to pursue its plans. On appeal, the Texas Supreme Court affirmed the dissolution of the injunction, but gave new guidance to the trial court on remand.

Although the rule of capture was first applied to groundwater by the Texas Supreme Court in 1904,62 only recently in Edwards Aquifer Authority v Day did the Texas Supreme Court hold that groundwater is owned in place by the landowner like oil and gas.63 The ranch argued that the accommodation doctrine should also extend to groundwater so that the city would be required to take into account existing uses being made of the surface by the ranch. The Texas Supreme Court agreed.

After some exposition about the law of servitudes and the history of the accommodation doctrine, the court described the similarities between mineral and groundwater estates. Applying the analysis from Edwards – minerals and groundwater both exist in subterranean reservoirs and are fugacious; both can be severed; both include a right to use the surface; and both are protected from waste. The city argued that the better rule would imply a requirement of reasonable use into its deed, but the court found that the city already had both the implied right to reasonable use and an express right to do that which is necessary and incidental. The court stated that “[w]hat is

61 Id. at 240 (internal citations omitted). 62 See Houston & T.C. Railway v. East, 81 S.W. 279 (Tex. 1904). 63 369 S.W.3d 814 (Tex. 2012). 11 reasonable, necessary, or incidental for the severed estate cannot be determined in the abstract but must be measured against, and with due regard for, the rights of the surface estate.”64

In a concurring opinion joined by Justice Willett and Justice Lehrmann, Justice Boyd did not take issue with application of the accommodation doctrine. He pointed out, however, that when a deed or lease expressly describes the disputed rights, the courts must defer to the language of the instrument.65 Justice Boyd argued that the deed was not silent, but broadly gave the city the full right to drill wells at any time and location. He concedes, however, that other uses of the surface such as building access roads must under the terms of the deed be “necessary or incidental,” and for those uses the accommodation doctrine was appropriate.66

3. Hysaw v. Dawkins, 483 S.W.3d 1 (Tex. 2016).

This case concerned the familiar specter of the double fraction problem, where the Texas Supreme Court was invited but refused to embrace the mechanical mathematical approach to resolving such disputes.

In her will, Ethel Nichols Hysaw devised separate parcels to each of her three children, Howard, Dorothy, and Inez, in fee simple, subject to a reservation to each child of a non- participating royalty interest that “each of my children shall have and hold an undivided one- third (1/3) of an undivided one-eighth (1/8) of all oil, gas or other minerals in or under or that may be produced from any of said lands.” The will went on to clarify that the royalty holder would not participate in bonus or rentals or have any executive rights, “but that the said [named child] shall receive one-third of one-eighth royalty, provided there is no royalty sold or conveyed by me covering the lands so willed to [the child]. In the case of an inter vivos sale by the testatrix, the will stated that “should there be any royalty sold during my lifetime then [the three children], shall each receive one-third of the remainder of the unsold royalty.”

In fact, Ethel did convey equal royalty interests in the tracts that were devised to Howard, but did not convey royalty interests in the tract devised to Inez. After Inez’s successors executed a mineral lease that provided for a 1/5th royalty, Howard’s successors initiated a declaratory judgment action. Inez’s successors claimed Howard’s and Dorothy’s successors were each entitled to a fixed 1/24 royalty (i.e., 1/3 of 1/8) and that Inez’s successors were entitled to the excess royalties (i.e., 1/5 minus 2/24). Howard’s and Dorothy’s successors argued that each child’s successors were entitled to 1/3 of the entire 1/5 royalty provided in the lease.

In a double fraction case such as this, the parties usually dispute whether a grant or reservation of some fraction of “1/8” creates a fixed (or gross) royalty in the amount determined by multiplying the fractions, or whether “1/8” has been used as a proxy for the royalty payable under an oil and gas lease, entitling the holder to a floating royalty of whatever royalty fraction has been negotiated by the holder of the executive right. The trial court held that the will created a floating royalty, and the court of appeals reversed. The supreme court, however, agreed with the trial court.

64 493 S.W.3d at 63-64. 65 Id. at 66 (quoting Am. Mfrs. Mut. Ins. Co. v. Schaefer, 124 S.W.3d 154, 162 (Tex. 2003)). 66 Id. at 67. 12

After discussing the nature of mineral rights, the court described in some detail the problems associated with 1/8 royalties. At one time the 1/8 royalty was so common that courts took judicial notice that it was the standard and customary royalty.67 This led to the theory of “estate misconception,” which posits that lessors actually believed they conveyed 7/8 of the minerals and retained 1/8 of the minerals when they executed an oil and gas lease, rather than conveying a fee simple determinable and retaining a possibility of reverter and a royalty interest. If, for example, a landowner owned an undivided one-half of the minerals and had executed a lease, the landowner would then convey what he believed he owned, e.g., 1/2 of 1/8, resulting in the double fraction problem.68

Although the court acknowledged the simplicity and certainty inherent in a bright-line test, it decided to reaffirm its favored approach of gleaning the parties’ intent from the language of the instrument on a case by case basis. This holistic approach construes words and phrases in an instrument as a whole rather than examining particular language in isolation.69 Applying that approach to the language of Ethel’s will, the court found the estate-misconception theory and the historical use of 1/8 as informative. In particular, because the testatrix had granted a floating 1/3 royalty in the residuary royalty clause (that applied in the event of an inter vivos sale), and was otherwise careful to ensure each child was treated equally, she demonstrated her intent that 1/8 was shorthand for the entire royalty interest a lessor might retain under a mineral lease.70

4. Apache Deepwater, LLC v. McDaniel Partners, Ltd., 485 S.W.3d 900 (Tex. 2016), reh’g denied (May 6, 2016).

This case presented another double fraction (or more accurately, triple fraction) problem, but in the context of a production payment. In 1953, Ferguson assigned to Tyson its interests as a lessee in four oil and gas leases in Upton County, Texas. The four leases represented in the aggregate a 35/64 mineral interest in Surveys 36 and 37 as follows:

Cowden Lease, Survey 36: 32/64 Cowden Lease, Survey 37: 32/64 Peterman Lease: 1/64 of Surveys 36 and 37 Broudy Lease 2/64 of Surveys 36 and 37

This was simple enough, but the assignment also reserved to Ferguson a 1/16 production payment out of production from Surveys 36 and 37. Recognizing that the production payment was payable only from the lessee’s 7/8 working interest, the language in the assignment specifically reserved:

67 483 S.W.2d at 9-10. 68 Id. at 10-11 (citing Laura H. Burney, The Regrettable Rebirth of the Two-Grant Doctrine in Texas Deed Construction, 34 S. TEX. L. REV. 73, 89 (1993); PATRICK H. MARTIN & BRUCE M. KRAMER, WILLIAMS & MEYERS, OIL AND GAS LAW § 327.2, at 90-91 (2015); Laura H. Burney, Interpreting Mineral and Royalty Deeds: The Legacy of the One-Eighth Royalty and Other Stories, 33 ST. MARY’S L.J. 1, 24 (2001)). 69 483 S.W.2d at 13. 70 Id. at 15. 13

1/16th of 35/64ths of 7/8ths, being one-sixteenth of the entire interest in the production from said lands to which Assignor claims to be entitled under the terms of said respective oil and gas leases . . . 71

The production payment would continue until net proceeds amounted to $3.55 million and 1.42 million barrels. Twenty years later, the Cowden leases expired, and Apache thereafter acquired Tyson’s 3/64 interests under the Peterman and Broudy Leases. Because the Cowden leases had expired, Apache notified McDaniel, Fergusons’s successor-in-interest, that the production payment had been reduced to 1/16 of 3/64 of 7/8 and made a payment based on that revised calculation. McDaniel disagreed and sued. The trial court agreed with Apache and the court of appeals reversed, but the Texas Supreme Court agreed with the trial court and rendered a take nothing judgment against McDaniel.

The court of appeals had thought the production payment could not be reduced because of the absence of an express proportionate reduction clause. Per the supreme court, however, this interpretation failed to recognize the nature of a production payment. A production payment, a form of overriding royalty with a limited duration, terminates automatically when the underlying lease from which it was carved also terminates.72 The plaintiff’s interpretation ignored that the underlying reservation related to the leases that were actually owned and purportedly conveyed. The court was also moved by the use in the reservation of the term “respective,” meaning particular or separate.73 The reservation, although it did not contain a reduction clause, also did not provide that the burden would be allocated to the remaining leases after the expiration of a lease.74 So once again, the Texas Supreme Court eschewed a mechanical mathematical formulation in favor of the original parties’ perceived intent gleaned from a holistic review of the instrument.

5. Texas Railroad Commission v. Gulf Energy Exploration Corp., 482 S.W.3d 559 (Tex. 2016).

In 2008, the Texas Railroad Commission ordered American Coastal Enterprises (“ACE”) to plug a number of inactive offshore wells. ACE then declared bankruptcy and the commission took over that responsibility. The commission awarded Superior Energy Services (“Superior”) a contract to plug eight wells, including 08S-5. On May 19, 2008, Gulf Energy Exploration Corporation (“Gulf Energy”), the lessee of the area that included 708S-5, met with the commission and ACE. The parties reached an oral agreement that the commission would delay plugging four ACE wells, including 708S-5 to allow Gulf Energy to post a bond and apply to the commission to take over as operator of the four wells. After exchanging several drafts, the parties signed a formal agreement on June 9, 2008.

In the meantime, the commission accidentally plugged 708S-5. A commission employee had inadvertently transposed the coordinates for several wells, resulting in the photo and

71 485 S.W.3d at 907. 72 MARTIN AND KRAMER, 2 WILLIAMS & MEYERS, OIL AND GAS LAW, § 422 (2015); A.W. Walker, Jr., Oil Payments, 20 TEX. L. REV. 259, 288 (1942). 73 485 S.W.3d at 907-08. 74 Id. at 908. 14 coordinates for 708S-5 being labeled another well and vice versa. Gulf Energy then obtained consent from the legislature by resolution to sue the commission for no more than $2.5 million and sued both the commission and Superior. The jury found that the commission breached its agreement with Gulf Energy to postpone plugging the well, and also held the commission and Superior liable in negligence, with 65% attributable to Superior and 35% attributable to the commission. The court of appeals affirmed.

On appeal to the Texas Supreme Court, the commission raised a defense of good faith under Texas Natural Resources Code § 89.045, which provides that “[t]he commission and its employees and agents, the operator, and the nonoperator are not liable for any damages that may occur as a result of acts done or omitted to be done by them or each of them in a good-faith effort to carry out this chapter.” Although Gulf Energy argued that its legislative resolution precluded the commission from raising the good faith defense, the Texas Supreme Court disagreed. As required by statute, the resolution did not waive any defense of law or fact, only the defense of immunity from suit.75 The court also rejected Gulf Energy’s attempt to analogize the defense to the common law official immunity defense, which only applies to the performance of a discretionary duty.76 Further, the good faith defense was held to apply equally to the contract claim and the tort claim because of the broad use of the words “any damages” and “acts done or omitted” in Section 89.045.77

The parties also argued over the meaning of good faith. The commission argued for a subjective good faith standard, while Gulf Energy argued that good faith includes a component of objective reasonableness. After reviewing several dictionaries for the ordinary meaning of the term, the court agreed with the commission.78 The evidence did not conclusively establish, however, that the commission acted with subjective good faith because there was at least some evidence presented that the commission willfully ignored discrepancies between the well data and the well itself before actually plugging the well. As such, the court could not hold that the commission acted in good faith as a matter of law; but instead held that the commission should have received a jury instruction on its good faith defense.79

The parties also disagreed whether they had entered into a binding oral contract to defer plugging at the time the well was plugged or whether their first agreement as to the matter was the written agreement that was signed after the well was plugged. Under Foreca, S.A. v. GRD Development Co., the answer turned on whether “the contemplated formal document [was] a condition precedent to the formation of a contract or merely a memorial of an already enforceable contract.”80 The court found the evidence on this issue conflicting: some supported Gulf Energy’s contention that the formal agreement merely memorialized their written understanding; some supported the commission’s contention that the parties did not intend to be bound until the contract was signed. Because the trial court incorrectly decided the question as a

75 482 S.W.3d at 566; see also TEX. CIV. PRAC. & REM. CODE § 107.002(a)(7)-(8), (b). 76 482 S.W.3d at 567. 77 Id. at 575-76. 78 Id. at 568. 79 Id. at 571-72. 80 758 S.W.2d 744, 745 (Tex. 1988). 15 matter of law, the commission was entitled on remand to have the issue decided by a jury.81 Ultimately, the case was remanded for a new trial.

6. Crosstex North Texas Pipeline L.P. v. Gardiner, No. 15-009, 2016 WL 3483165 (Tex. June 24, 2016), reh’g denied (2 pets.) (Dec. 16, 2016).

Depending on whom one asks, this case is not strictly an oil and gas case, but it does involve a compressor station and will have important implications for the industry in the future. In its opinion, the Texas Supreme Court took the opportunity to clarify the law of private nuisance.

In 2006, the Gardiners granted Crosstex North Texas Pipeline, L.P. (“Crosstex”) an easement and right of way across their 95 acre ranch. Crosstex then constructed a compressor station on a 20-acre trace adjacent to the ranch that included four diesel engines “bigger than mobile homes.” After complaints, Crosstex constructed a three-sided building around the engines, sound blankets, and sound walls. The open side, however, faced the ranch and the Gardiners complained that it just funneled sound onto the ranch. In 2008, the Gardiners filed suit, prompting Crosstex to install additional measures. After a trial, the jury found that Crosstex negligently created a nuisance. It also found that the nuisance was permanent and caused the market value of the ranch to decline by over $2 million.

The court of appeals held that the evidence was legally sufficient but not factually sufficient to support the jury’s finding of a negligently created nuisance. But the court of appeals remanded the case for a new trial because it found the trial court should have submitted a jury question requested by the Gardiners that Crosstex created a nuisance by conduct that was “abnormal and out of place.” The Texas Supreme Court affirmed the remand for a new trial, but not based on the holding of the court of appeals. Instead, it remanded because the trial court did not have the benefit of its extensive clarification of the law of nuisance in Texas.82

First, the supreme court reaffirmed its definition of a nuisance as “a condition that substantially interferes with the use and enjoyment of land by causing unreasonable discomfort or annoyance to persons of ordinary sensibilities attempting to use and enjoy it.”83 But nuisance is not a cause of action, or a standard of conduct, or the damages that result from conduct – rather it is a type of legal injury that supports a claim or cause of action and may result in compensable damages.

In analyzing this definition, the court highlighted that the condition must have caused a substantial interference, not a “trifle” or “petty annoyance.” What is substantial depends on the particular facts, including how long the interference lasts and how often it occurred. Further, the interference must be unreasonable. This question focuses on the effect on the plaintiff, not on the conduct – which is a separate issue. Whether the interference is unreasonable is an objective test. A condition is not a nuisance if it interferes only with especially sensitive persons or uses; it must interfere with an ordinary person in a similar circumstance. What is unreasonable also

81 482 S.W.3d at 575. 82 2016 WL 3483165 at *26. 83 Id. at *6 (quoting Holubec v. Brandenberger, 111 S.W.3d 32, 37 (Tex. 2003). 16 requires balancing a host of factors depending on the circumstances of the case. As to these factors, the court provided an illustrative list. These factors generally relate to the gravity of the harm and the utility of the conduct, although the court did not use these terms.84

The court then clarified that for nuisance liability to attach, a plaintiff must show that a separate standard of care of culpable conduct has been breached. This conduct can be based on an intentional act, negligence, or strict liability.

For intentional conduct causing a nuisance, the defendant must either intend to cause interference or act with a belief that interference was substantially certain to result from the defendant’s conduct. Intent relates to the interference, not to the conduct itself. Note that the jury failed to find Crosstex “intentionally and unreasonably created a nuisance,” but the intentional conduct standard appeared relatively easy to satisfy in this case. Although intentional conduct is a subjective standard, the defendant need not believe that the interference was substantial; and the plaintiff need not show that the conduct itself was unreasonable.85 The mere intent to operate a compressor station would not be sufficient, but it should be enough under the court’s standard for the Gardiners to show that Crosstex believed an interference was substantially likely to occur.

In this regard, the author believes there is still an element of degree that must be shown to establish the requisite intent. The court states that the conduct itself need not be unreasonable, but the plaintiff must at least show that the defendant believed that an interference was substantially likely to result from the conduct. A whisper is noise, but it can barely be heard, so it would not be sufficient that the defendant believed any amount of noise would emit from the diesel engines. The plaintiff should have to show the defendant was substantially certain that the noise would interfere with the use and enjoyment of property, even if the defendant did not view the interference as substantial.

The court then stated, despite the views of Keeton,86 that negligence can serve as actionable conduct to make out a nuisance claim by proving the elements of ordinary negligence. A nuisance claim grounded in negligence thus requires the plaintiff to prove an additional element not required of an ordinary negligence claim not based in nuisance – the substantial interference that caused unreasonable discomfort or annoyance.87

Finally, the court clarified that strict liability can be the basis for a nuisance claim, but only if the conduct is an abnormally dangerous activity. The court rejected the notion that a claim may be based on use of land that is “abnormal and out of place in its surroundings,” disagreeing on this point with the court of appeals.88

84 Id. at *12. Here the court provides a non-exhaustive list of factors citing as one source the Restatement (Second) of Torts §§ 827, 828. Section 827 of the Restatement (Second) of Torts provides factors that relate to the gravity of harm, while Section 828 provides factors that relate to the utility of the conduct. A harm that is reasonably avoidable or conducted at an inappropriate location may be a nuisance regardless of its utility. Whether socially useful conduct should be taken into account may depend on the severity of the harm. See DAN B. DOBBS, PAUL T. HAYDEN, AND ELLEN M. BUBLICK, DOBBS’ LAW OF TORTS § 401 (2016 update). 85 2016 WL 3483165 at *17. 86 WILLIAM L. PROSSER AND W.P. KEETON, PROSSER AND KEETON ON TORTS, § 91, at 652-53 (5th ed. 1984). 87 2016 WL 3483165 at *17. 88 Id. at *19. 17

7. North Shore Energy, L.L.C. v. Harkins, 501 S.W.3d 598 (Tex. 2016).

In June 2009, Harkins granted North Shore Energy (“North Shore”) an exclusive option to lease land as described on “Exhibit A” attached to the agreement. The tract at issue, “Tract 2” was described in relevant part as follows:

Being 1,210.8224 acres of land, more or less, out of the 1673.69 acres out of the Caleb Bennet Survey, A-5, Goliad County, Texas and being the same land described in [the Export Lease]

The recorded memorandum of the “Export Lease” described 1273.54 acres in Goliad County and “being all of the 1673.69 acre tract described on Exhibit “A” attached hereto, SAVE AND EXCEPT a 400.15 acre tract” that was described in a separate lease to Hamman Oil & Refining (the “Hamman Lease”).

In September 2009, North Shore exercised its option to lease 169.9 acres and paid the consideration, but never signed a formal lease. The 169.9 acres included a large portion of the Hamman Lease tract. The Hamman Lease had since expired. North Shore drilled a well on this Hamman tract. After Dynamic Production (“Dynamic”) approached North Shore for a deal to allow it to shoot seismic across the optioned acreage, Dynamic determined that North Shore did not have the right to lease the land where its well was located. Dynamic then leased the land from Harkins and North Shore sued. The primary question addressed by the supreme court was whether the optioned acreage included the 400 acre Hamman tract excepted from the Export Lease.

North Shore argued the last antecedent doctrine, which provides that a qualifying phrase must be confined to the words and phrases immediately preceding it without impairing the meaning of the sentence.89 In other words, North Shore argued that the words “being the same land described in the [Export Lease]” qualified “1673.69 acres out of the Bennet Survey” in the option agreement, meaning that the parties were referring to the entire 1673.69 acres described in the Export Lease, but without reference to the excluded 400 acres. The court however, concluded this interpretation impaired the meaning of the sentence in the option agreement.

Rather, the court read the two phrases as correlative pairs. Put simply, the court read the description as “Being 1,210.8224 acres of land . . . and being the same land described in the [Export Lease]. To the court, it was immaterial that the Export Lease, after deducting the Hamman Lease land, granted 1273.54 acres, while the option agreement purported to option 1210 acres, “more or less.” Because, as the court stated, the call for acreage is the least reliable in a deed, the slight difference of 63 acres “in acreage when the description uses the phrase ‘more or less’ would not preclude an interpretation of the description to include the larger acreage.”90 Interpreting the description any other way would ignore the “save and except” clause in the Export Lease, which is a large portion of the description.

89 501 S.W.3d at 603 (citing City of Corsicana v. Willmann, 216 S.W.2d 175, 176 (1949)). 90 Id. at 604. 18

In a separate claim, North Shore alleged geophysical trespass because Dynamic had shot seismic across acreage that was subject to the option agreement. The court rejected this claim, however, because North Shore had no right to exclude Dynamic during the option period. The court found that the option agreement did not pass title or convey an interest in property. North Shore thus acquired neither possession nor title to the option land and had no standing to complain.91

8. Anadarko Petroleum Corp. v. TRO-X, L.P., No. 08-15-00158-CV, 2016 WL 1073046 (Tex. App.—El Paso Mar. 18, 2016, pet. filed) (mem. op.).

In 2007, the Coopers and Hills (collectively, the “Coopers”) executed five leases to TRO- X, L.P. (“TRO-X”) as the prime lessee. The prime leases contained an offset well provision that required TRO-X to drill an offset well within 180 days of the completion of a well on adjacent property that was within 660 feet of the leasehold border. The prime leases also required the lessee to surrender the lease as to the relevant portion upon demand of the lessor for breach of the offset well provision.

Later that same year, TRO-X executed a sublease entitled “Participation Agreement” that was later assigned to Anadarko. The sublease transferred all of TRO-X’s interest in the prime lease, except that once the sublessee reached project payout, TRO-X would have the option to receive a reversion of five percent of its prime lease working interests.92 The five percent back-in option extended to any renewals, extensions, or top leases taken within one year of termination of the underlying interests.

In 2008, Anadarko completed a well on non-leasehold property that triggered the offset well requirement, but did not drill an offset well under the terms of the prime lease. Two years later, the Coopers demanded a release of the prime leases from Anadarko. In 2011, Anadarko negotiated new leases with the Coopers covering all of the mineral interests covered by the 2007 prime leases. The new leases were executed without the knowledge or consent of TRO-X. The new leases were executed on June 17, 2011, and releases of the prime leases were executed by Anadarko on June 30, 2011.

TRO-X brought suit to try title and for breach of the Participation Agreement, claiming it was entitled to five percent of Anadarko’s interests in the new leases because they were top leases of the prime lease. Interestingly, the Participation Agreement back-in provision did not apply to new leases after a loss of title and reversion of the same land and Anadarko never argued that the new leases taken by Anadarko were either renewals or extensions of the prime leases, only that they were top leases.

The trial court rendered summary judgment for TRO-X, but the court of appeals reversed on the grounds that TRO-X failed to provide a scintilla of evidence to support its claim that the

91 Id. at 606. 92 An assignment transfers all of the lessee’s interest in the lease, whereas if the transferor retains a reversionary interest, the transfer is characterized as a sublease. Royalco Oil & Gas Corp. v. Stockhome Trading Corp., 361 S.W.3d 725, 731-32 (Tex.App.—Fort Worth 2012, no pet.). 19 new leases were top leases.93 The determination that the new leases were not top leases was dispositive, so the appellate court never reached TRO-X’s breach of contract claims.94

In Texas, which does not impose a contractual duty of good faith and fair dealing, working interest owners owe no duty to protect the interests of other working interest owners, absent a fiduciary relationship. This allows subsequent lessees to execute new leases that washout the interests of reversionary interest holders.95 TRO-X argued that the delay between the earlier execution of the new leases and the subsequent execution of the releases meant that the earlier leases remained in effect, such that the new leases were top leases. The court stated that resolution of the issue depended on the intent of the Coopers. Merely because the new leases were executed first was not sufficient evidence that the Coopers intended the new leases to be top leases. The court quotes Sasser v. Dantex Oil & Gas, Inc., where it was held “by signing a new lease with the intent to terminate a prior lease, a lessor waives strict compliance with a surrender clause and effectively terminates or releases the prior lease.”96 Here, the Coopers sought an extension of the original prime leases, but Anadarko made clear in negotiations that it was seeking new leases. Thereafter, the Coopers never took issue with characterization of the 2011 leases as new leases.97

9. Aery v. Hoskins, Inc., 493 S.W.3d 684 (Tex.App.—San Antonio Mar. 30, 2016, pet. filed).

In 1957 and 1963, Rose Quinn partitioned and conveyed separate portions of the surface estate of the Quinn Ranch to her three children: Hazel Hoskins (“Hoskins”), Sam Quinn (“Quinn”), and Frances Ray (“Ray”). Rose also conveyed to each child an undivided 1/3 mineral interest in the entire Ranch property. The children then entered into an agreement (the “Sibling Agreement”) where they partitioned the mineral estate into separate mineral tracts corresponding to the separate surface estate tracts owned by each child. Under the Sibling Agreement, the children then carved out the royalty interest from each of their individual mineral interests, and pooled their royalty interests. As a result of this pooling, each would be entitled to royalty on production anywhere on the Hoskins tract, the Quinn tract, or the Ray tract in the proportion that the number of acres of their mineral estate bore to the number of acres in the entire Ranch. To accomplish this pooling and apportionment, the children also each cross-conveyed the royalty interest attributable to their own tracts to each of the other children in such proportions.

In 1966, Quinn conveyed his tract by general warranty deed to James House “together with all and singular rights and appurtenances.” Three days later, Quinn conveyed his interest in the Hoskins tract and the Ray tract – ostensibly the pooled royalty interests he held in this tract by virtue of the Sibling Agreement – to his sister Hoskins and her husband. The plaintiffs (House and his successor-in-interest Aery) sued when they realized they were not receiving royalties from production on the Hoskins tract or the Ray tract.

93 2016 WL 1073046 at *6. 94 Id. at *5 95 See Stroud Production, L.L.C. v. Hosford, 405 S.W.3d 794, 804-06 (Tex.App.—Houston [1st Dist.] 2013, pet. denied). 96 906 S.W.2d 599, 603 (Tex.App.—San Antonio 1995, writ denied). 97 2016 WL 1073046 at *6. 20

The question was whether Quinn’s conveyance of his tract to House included his pooled royalty interests in the Hoskins tract and the Ray tract or whether those interests were conveyed three days later to Hoskins and her husband. The parties agreed that House acquired from Quinn the royalty interest of Quinn attributable to the Quinn tract mineral estate. But they disagreed whether the deed from Quinn to House also conveyed Quinn’s pooled royalty interests attributable to the Hoskins tract and the Ray tract.

The plaintiffs first argued that the children intended for the royalty interests in the pooled tracts to be retained as an undivided whole so that when House acquired Quinn’s royalty interest in the Quinn tract he also acquired Quinn’s interests in the Hoskins and Ray tracts. The court disagreed, noting that a royalty interest can be severed from the mineral estate and conveyed or reserved in a conveyance. The royalty interests here remained separate undivided interests in each tract and were not merged into an undivided royalty interest in the entire Ranch.98

The plaintiffs next argued that the royalty interests in the Hoskins and Ray tracts were appurtenant to the Quinn tract. Other courts have addressed similar fact situations. In McCall v. McCall, the First District Court of Appeals in Houston held that a property owner’s royalty interest that is appurtenant to property other than the one conveyed is not impliedly included in the conveyance of that owner’s property.99 In Avery v. Moore, relied upon in McCall, the West Virginia Supreme Court held that conveying a tract that has been partitioned conveys only the mineral estate under the devised tract, not the grantor’s royalty interests in other tracts.100 These cases could be distinguished because they did not involve pooled royalty interests, but the court nevertheless found them persuasive.

The court stated that “while a mineral estate can be separated from the surface estate and further separated from its attributes, all still remain attached to the land from which they originate and derive their source.”101 An appurtenant right or obligation must benefit or burden the property to which it is attached, such that an appurtenance automatically passes unless it is carved out from the conveyance. In contrast, a personal interest or interest in gross must be expressly granted. Here, the court found that Quinn’s royalty interest in the separate Hoskins and Ray tracts were not necessary for the use and enjoyment of the Quinn tract. They were separable and not appurtenant and did not pass to House.102

10. Adams v. Murphy Exploration & Production Co.-USA, 497 S.W.3d 510 (Tex. App.—San Antonio June 15, 2016, pet. filed).

This case serves as a warning to lessees that are willing to agree to an offset well provision to specifically define the term “offset well” and to avoid relying on traditional industry definitions established during the age of conventional vertical well development that may not accurately reflect drainage patterns in unconventional formations.

98 493 S.W.3d 684 at 697. 99 24 S.W.3d 508, 513-515 (Tex.App.—Houston [1st Dist.] 2000, pet. denied). 100 144 S.E.2d 434, 438 (W.Va. 1965). 101 493 S.W.3d 684 at 699. 102 Id. at 702. 21

Shirley and William leased their respective tracts, and the leases were assigned to Murphy Exploration & Production Co. (“Murphy”). Each lease contained an offset well clause that required Murphy to drill an offset well within 120 days of completion of a well on adjacent acreage that was within 467 feet of the leased premises. The clause alternatively allowed the lessee to pay royalties as if an offset well was drilled that was producing the same amount of production being produced from the adjacent well, or to release acreage. The parties agreed that the offset well clause was triggered when a well was drilled on an adjacent tract. To satisfy its obligations under the clause, Murphy drilled a well that ran parallel to the adjacent well, that bottomed in the same formation, and that was separated laterally by approximately 2,100 feet. The lessors did not believe the well satisfied the offset well provision, and sued Murphy for breach. Murphy was granted summary judgment by the trial court.

The primary issue was whether Murphy satisfied its obligation to drill an “offset well.” Murphy’s expert testified that “the conventional concept of drainage across lease lines has limited application in the [Eagle Ford Shale].” He also testified that an offset well is understood in the industry to mean a well drilled on an adjacent lease. The Lessors’ expert testified that to prevent or minimize drainage, an offset well must be drilled as close as possible to the offending well.103

The court noted that Williams and Meyers, Oil and Gas Law defines an offset well as “[a] well drilled on one tract of land to prevent the drainage of oil or gas to an adjoining tract of land, on which a well is being drilled or is already in production.”104 In Coastal Oil & Gas Corp. v. Garza Energy Trust, the Texas Supreme Court recognized that an offset well is one used “to offset drainage from [owner’s] property.”105 Reviewing this authority, the court concluded that to constitute an “offset well” the well must protect against drainage.

The court held that the testimony put forth by Murphy’s expert was not sufficient to conclusively prove that the well drilled by Murphy was an offset well because Murphy did not conclusively prove that the well prevented drainage from the offending well. As such, Murphy was not entitled to summary judgment and the court of appeals reversed and remanded for further proceedings. 106

11. Jackson v. Wildflower Production Co.,No. 07-15-00070-CV, 2016 WL 6024387 (Tex.App.—Amarillo Oct. 13, 2016, pet. filed) (mem. op.).

In this family dispute as to the priority of deeds and the status of a grantee as a bona fide purchaser, the Court of Appeals in Amarillo determined whether an instrument was a quitclaim deed.

103 497 S.W.3d at 516. 104 PATRICK H. MARTIN & BRUCE M. KRAMER, 8 WILLIAMS & MEYERS, OIL AND GAS LAW, MANUAL OF OIL AND GAS TERMS 684 (2014). 105 268 S.W.3d 1, 14 (Tex. 2008). 106 497 S.W.3d at 517. 22

Jane Fuller Jackson owned an undivided 1/12 mineral interest in two tracts in Wheeler County, Texas (the “Jackson Interest”). In 1990, Jackson and others executed a deed of trust to First National Bank at Lubbock secured by Jackson’s mineral interest and other property. In 1993, the Bank foreclosed and purchased the property in the foreclosure. Before the foreclosure, the Bank had agreed to sell the interest it had purchased in foreclosure to Jackson’s husband, Leete. It executed and delivered a quitclaim deed to Leete Jackson on November 23, 1993 which was recorded on December 3, 1993.

During this time period, the Bank also negotiated with Rex Fuller, Jackson’s brother, to sell to him certain properties that were also foreclosed. The Bank executed and delivered an instrument to Rex’s company, Wildflower Production Co. (“Wildflower”) on November 30, 1993, purporting to convey to Wildflower the same Jackson Interest that was previously conveyed by the Bank to Leete. This conveyance was executed and delivered after the conveyance to Leete, but before the Bank to Leete deed was recorded. The primary issue was whether this conveyance from the Bank to Wildflower was a quitclaim deed.

In 2010, a division order title opinion that was prepared by a lawyer for the operator of a unit that included the Jackson Interest raised the ownership interest for the first time. Wildflower filed suit for a declaratory judgment and Leete counter-claimed. The parties stipulated that the only issues were whether (1) Wildflower had actual or constructive notice of the Bank to Leete deed, and (2) Wildflower was a bona fide purchaser. The trial judge found that Wildflower had superior title and that Leete had waived her claim that the deed was a quitclaim deed because the stipulation included no mention of the issue.107

The court of appeals disagreed as to the waiver. Leete preserved his claim that Wildflower was not a bona fide purchaser, and that issue depended on the character of the deed at issue. A quitclaim deed only releases the grantor’s claims to the property to the grantee. In contrast, a deed is a conveyance of the property itself, rather than just the grantor’s interest. It has been settled in Texas since 1871 that a party receiving a quitclaim deed cannot be an innocent purchaser for value under the Texas recording statute because the grantee under a quitclaim deed is deemed to have constructive notice of all legal or equitable claims.108

There was conflicting evidence at trial whether Wildflower had actual notice of the prior deed, but the court focused on the construction of the instrument, which stated:

[The Bank] . . . does hereby grant, bargain, sell, convey, transfer, assign and deliver unto [Wildflower] . . . a portion of the Grantor’s right, title, interest, estate, and every claim and demand . . . in and to that part of the oil, gas and other minerals . . .

Although the court said that “if anything can be said with certainty, it would be that the instrument was poorly drafted,” the court found the instrument was a quitclaim deed. The court distinguished Bryan v. Thomas, where Justice Culver wrote in 1963 that “the grantee in a deed

107 2016 WL 6024387 at *10. 108 See Richardson v. Levi, 3 S.W. 444, 446 (1887) (citing Rodgers v. Burchard, 34 Tex. 441 (1871)). 23 which purports to convey all of the grantor’s undivided interest . . . , if otherwise entitled, will be accorded the protection of a bona fide purchaser.” 109

In analyzing Bryan, the court of appeals focused on the “if otherwise entitled” language at issue in the Bryan opinion, embracing the analysis of H. Martin Gibson. Gibson argued that the words “if otherwise entitled” does not simply mean that the grantee must satisfy the recording statute’s other requirements for bona fide purchaser status. Rather it means that when such language is used, the court must delve deeper to find other indicia of intent to quitclaim or intent to convey the land itself.110 In Bryan, the other indicia that caused the court to conclude that a conveyance of the property was intended included a warranty clause in the deed. In the instant case, the instrument conveyed only the grantor’s “right title and interest,” similar to the Bryan deed, but was titled “Mineral Deed Without Warranty,” and said nothing as to a warranty. The court also found material that the instrument lacked any express covenant of seisin or statement that the grantor owned what it purported to convey.111

For a comparison, see Enerlex, Inc. v. Amerada Hess, Inc.112 There, the grantor conveyed “all right, title and interest,” whereas in Jackson the grantor conveyed the “Grantor’s” right, title and interest. The deed in Enerlex also contained a general warranty, and yet the court still found it was a quitclaim deed because it lacked a representation concerning title. Although in Jackson, there was evidence that the grantee never thought it was receiving the Jackson Interest, grantees should be mindful when negotiating conveyances that, without careful attention to the deed/quitclaim deed distinction, a grantee may not be entitled to bona fide purchaser status.

12. Shell Western E&P, Inc. v. Pel-State Bulk Plant, LLC, No. 04-15-00750-CV, 2016 WL 6247007 (Tex.App.—San Antonio Oct. 26, 2016).

This case provides a lesson in the care required when drafting master services agreements. In 2011, Shell hired Green Field to perform fracking operations under a master services agreement. Green Field then subcontracted with Pel-State to provide bulk fuel, fuel equipment, and other services to assist Green Field with the fracking operations. In 2013, Pel- State sent Shell a lien claim notice under the Texas Property Code oil and gas statutory lien provisions because it had not been paid for its services. Rather than pay Pel-State, Shell filed a bond for 150% of the value of the lien claims under the Texas Property Code and Pel-State sued Shell and Green Field. Unfortunately, Green Field then filed for bankruptcy.

Pel-State alleged its lien amount was $3.2 million based on its unpaid invoices, but Shell claimed the lien amount was only $714 thousand. The dispute centered on two provisions of the Texas Property Code (the “Code”). First, under Section 56.006 of the Code, “[a]n owner of land or a leasehold owner may not be subjected to liability under this chapter greater than the amount agreed to be paid in the contract for furnishing material or performing labor.”113 Second, Section

109 365 S.W.2d 628, 630 (Tex. 1963). 110 2016 WL 6024387 at *8-*9 (citing H. Martin Gibson, The Perils of Quitclaims, 25-4 TEXAS OIL AND GAS L. J. 1 (2011)). 111 2016 WL 6024387 at *10. 112 302 S.W.3d 351, 355 (Tex. App. – Eastland 2009). Enerlex is criticized in PATRICK H. MARTIN AND BRUCE M. KRAMER, 1-2 WILLIAMS & MEYERS, OIL AND GAS LAW § 220 (2016). 113 TEX. PROP. CODE ANN. § 56.006 (emphasis added). 24

56.043 of the Code provides that the property owner is “not liable to the subcontractor for more than the amount that the owner owes the original contractor when the notice is received.”114

Shell argued that it entered into multiple contracts with Green Field because each “call- off” represented by a separate invoice for work was a separate contract. A master services agreement provides the terms and conditions for the work, but does not specify the particular work to be performed or the price.115 Shell therefore argued that the master services agreement itself was nothing more than an agreement to agree. On the day Shell received Pel-State’s notice of lien claim, Shell owed Green Field almost $11 million, much more than the amount of the total lien claim. But Shell claimed that it only owed Green Field $714 thousand under the individual “contracts” for which Pel-State provided its subcontracted labor. The remaining amounts claimed by Pel-State were for labor performed under other “contracts” that were already paid by Shell to Green Field. The court rejected this argument.

The court referred to the general rule that multiple documents pertaining to the same transaction will be construed together as one contract.116 The master services agreement repeatedly referred to itself as “the contract” and defined “contract” as this document. The agreement specifically stated that in the event of a conflict between any call-off and the agreement itself, the agreement would control. As such, the call-offs and the master services agreement were construed together as one contract.

Further, the Texas Legislature has instructed in separate statutes that “the singular includes the plural and the plural includes the singular” so that the word “contract” also means “contracts.”117 The Code also provides: “[a]ll material or services that a person furnished for the same land, leasehold interest, oil or gas pipeline, or oil or gas pipeline right-of-way are considered to be furnished under a single contract unless more than six months elapse between the dates the material or services are furnished.”118

Shell also argued that Pel-State’s lien was not worth $3.2 million because Green Field owed Shell $80 million under the financing portion of the agreement, allowing Shell to set-off the amount owed. The court rejected this argument because Shell failed to raise it in response to Pel-State’s summary judgment motion or in its own summary judgment motion.119

IV. LOUISIANA CASES

1. Hayes Fund for First United Methodist Church v. Kerr-McGee Rocky Mountain, LLC, 193 So.3d 1110 (La. 2015).

In this case, the defendant mineral lessees were sued by royalty owners for breach of contract, claiming that the defendants mismanaged and imprudently operated two oil and gas

114 Id. § 56.043. 115 2016 WL 6247007 at *3 (citing In re Helix Energy Solutions Group, Inc., 303 S.W.3d 386, 391 (Tex.App.— Houston [14th Dist.] 2010, orig. proceeding). 116 Id. at *4 (citing Jones v. Kelly, 614 S.W.2d 95, 98 (Tex. 1981)). 117 TEX. GOV’T CODE §§ 311.012(b), 312.003(b). 118 TEX. PROP. CODE ANN. §56.005(b). 119 2016 WL 6247007 at *7. 25 wells in violation of Mineral Code article 122,120 causing damage to the reservoirs beneath the two wells and the attendant loss of royalty income.

For one well, the Rice Well, the drill pipe became differentially stuck and could not be moved or removed, which plaintiffs claimed prevented defendants from cementing the hole, allowing water to enter the wellbore. Plaintiffs claimed this caused the entire reservoir to water out. The plaintiffs alleged that the second well, the Hayes Lumber well, sanded up because the defendants improperly used a triple permanent packer, resulting in the loss of the lower zones. After hearing twenty-five days of testimony over 11 months, the district court believed the defendants’ experts over the sole plaintiffs’ expert, concluding that the plaintiffs failed to prove by a preponderance of the evidence that defendants’ actions caused a loss of hydrocarbons.

The Third Circuit Court of Appeal reversed the district court,121 finding the defendants liable for more than $13 million in damages for lost royalties. In the course thereof, the court of appeal held that the district court impermissibly found that there were no damages to the remaining hydrocarbons that could be produced. The defendants had argued at the trial court that the boundaries of the reservoir were smaller than the dimensions of the reservoir set forth in the order of the Louisiana Commissioner of Conservation establishing the unit. The court of appeal held that this argument, which the plaintiffs asserted was the basis for the no damages finding, was an impermissible collateral attack under Louisiana Revised Statutes 30:12.122 In response, the defendants argued that “in the real world, gas and oil reserves are not rectangular-shaped as they are depicted on the plats in the present case.” The court of appeal disagreed, finding that a lawsuit against the Louisiana Office of Conservation was the exclusive way to challenge the reservoir boundaries.123

The intermediate appellate court also held that the trial court legally erred in ruling that plaintiffs had to prove its operations were imprudent, where the lease provided that “Lessee shall be responsible for all damages caused by Lessee’s operations.”124 The collateral attack and lease interpretation issues resulted in the filing of several amicus briefs in support of the defendants, but the Louisiana Supreme Court never reached these issues.

Rather, the supreme court acrimoniously reversed the court of appeal and reinstated the judgment of the district court based solely on the issue of causation. The supreme court stated that because it found the district court’s causation determination reasonable and dispositive of the case, “we pretermit discussion of the remaining assignments of error.”125

120 LA. REV. STAT. § 31.22. 121 Hayes Fund for the First United Methodist Church of Welsh, LLC v. Kerr-McGee Rocky Mountain, LLC, 149 So.3d 280 (La. App. 3 Cir. 10/1/14), rev’d, 193 So.3d 1110 (La. 2015). 122 LA. REV. STAT. § 30:12(A)(1) (exclusive remedy for any review of the Commissioner’s order is “a suit for injunction or judicial review against the assistant secretary” of the Office of Conservation); see also Trahan v. Superior Oil Co., 700 F.2d 1004, 1015-16 (5th Cir. 1983) (collateral attack applies to suits between private parties in which an order is an operative fact upon which the rights directly depends). 123 149 So.3d at 295. 124 The original version of the lease lined out the words “to timber and growing crops of Lessor.” Id. at 299. 125 193 So.3d at 1112, n. 1. 26

The sole question to the supreme court was whether the district court committed manifest error in ruling for the defendants because that court found the defendants’ experts more credible than the plaintiffs’ single expert. The court then tortuously reviewed the record to demonstrate to the court of appeal a proper manifest error review. The court stated that “the appellate court does not function as a choice-making court; the appellate court functions as an errors-correcting court. . . . ;”126 and that “[i]t is destructive to the manifest error analysis for a reviewing court to make its choice of the evidence rather than look for clear error in the reasonable basis found by the trier of fact.”127

2. Regions Bank v. Questar Exploration & Production Corp., 184 So.3d 260 (La. Ct. App. 2d Cir. 2016).

This case presented an issue of first impression in Louisiana involving a conflict between the Louisiana Civil Code and the Louisiana Mineral Code. The Louisiana Civil Code article 2679 provides that “[t]he duration of a term may not exceed ninety-nine years.”128 In contrast, the Louisiana Mineral Code provides:

The interest of a mineral lessee is not subject to the prescription of nonuse, but the lease must have a term. Except as provided in this Article, a lease shall not be continued for a period of more than ten years without drilling or mining operations or production.129

W.P. Stiles granted three mineral leases in 1907 in favor of three lessees that were assigned in 1908 by the lessees and assigned again in 1920 to Standard Oil Company. Standard became Exxon Mobil Corporation, and continued to operate the leases. The leases contained a habendum clause with a primary term of 10 years and a secondary term for “as much longer thereafter as gas or oil is found or produced in paying quantities . . . .”

There was no argument that the leases continued to produce. The plaintiffs, successors to the original lessor, claimed originally that the defendant breached its obligation to reasonably develop the leases below 6,000 feet. The plaintiffs’ thereafter amended their complaint for cancellation of the leases in their entirety by operation of the 99-year limitation in the Louisiana Civil Code. On this issue the trial court denied the plaintiffs’ motion for summary judgment and the plaintiffs appealed. After holding that the trial court’s ruling on this issue was a “final judgment” subject to appeal, the court of appeal addressed the apparent conflict between the Mineral Code and the Civil Code as to the permissible term of the lease.

The court of appeal found that plaintiffs’ assertion that a mineral lease is limited to 99 years was contrary to the universal understanding that a mineral lease continues for so long as minerals are produced in paying quantities. The general term limit applicable to leases could not apply to mineral leases because the Mineral Code specifies the maximum term of a mineral lease, which is a maximum ten year primary term. Because the Mineral Code states that a lease

126 Id. at 1112. 127 Id. at 1150. 128 LA. CIV. CODE art. 2679 (enacted 2005). 129 LA. REV. STAT. § 31:115(A). 27 may not continue for more than ten years without drilling operations or production, the court essentially holds that by implication the Mineral Code allows the converse -- a lease may continue indefinitely during the secondary so long as it is conditioned on drilling operations or production.130 As to the conflict between this interpretation and the Civil Code, the Mineral Code provides that “[i]n the event of a conflict between the provisions of the [Mineral] Code and those of the civil Code or other laws the provisions of this [Mineral] Code shall prevail.”131

3. St. Tammany Parish Government v. Welsh, 199 So.3d 3 (La. Ct. App., 1st Cir. 2016), cert. or review denied, 194 So. 3d 1109 (La. 2016) (mem. op.), recon. not cons’d, 195 So. 1204 (La. 2016) (mem. op.).

In 1998, St. Tammany Parish became a Louisiana home rule parish. In 2010, the parish adopted a master zoning plan that rezoned the unincorporated areas of the Parish. In 2014, the Commissioner of the Louisiana Office of Conservation issued an order creating a drilling and production unit and later granted a conditional drilling permit to Helis Oil to drill an exploratory well. The well location was in a residential suburban zoning district that prohibited the drilling of a well and was located over the Southern Hills Aquifer, the sole source of drinking water in the area. The parish sued the commissioner, and the trial court ruled on summary judgment that the parish’s zoning ordinances were preempted by general state law and thus unconstitutional. The trial court also held that the Office of Conservation had complied with a state law mandate that an agency consider a parish master development plan before undertaking any activity or action affecting the elements of the master plan. The court of appeal affirmed.

The Louisiana statutes contain a broad preemption provision that prohibits most interference by local governments in the regulation of oil and gas activity:

The issuance of the permit by the commissioner . . . shall be sufficient authorization to the holder of the permit to enter upon the property covered by the permit and to drill in search of minerals thereon. No other agency or political subdivision of the state shall have the authority, and they are hereby expressly forbidden, to prohibit or in any way interfere with the drilling of a well or test well in search of minerals by the holder of such a permit.132

It is not clear to the author how a statute that expressly preempts an area of law can also impliedly preempt the same area of law, or why a court needs to look for evidence of “legislative intent” for a statute that is so broad or so clear. Regardless, the court found this broad preemption provision, along with the pervasive conservation regulatory statute that addresses every aspect of oil and gas exploration and operations sufficiently demonstrated a legislative intent to both expressly preempt and impliedly preempt the area of the law in question.133

130 184 So.3d 260 at 265-66 (“The general lease provision . . . which provides that a maximum lease term is 99 years, cannot apply to mineral leases because mineral leases have their own maximum term as provided by the Mineral Code.”) 131 LA. REV. STAT. § 31.2. 132 LA. REV. STAT. § 30:28(F) (emphasis added). 133 199 So.3d at 8. 28

Although the parish argued that Louisiana Constitution, article VI, section 17, which bestows land use and zoning power on local governments, precluded the preemption finding, the court noted that provision was limited by article VI, section 9(B), which provides that “[n]ot withstanding any provision of this Article, the police power of the state shall never be abridged.”134 The police power includes the power of the commissioner to regulate oil and gas. The court also turned to Louisiana Constitution, article VI, section 5, which allows a home rule charter to contain provisions as to the exercise of powers and functions proper for the management of a local government’s affairs that are “not denied by general law.”135 The preemption provision is a general law, applicable to the entire state of Louisiana, which denies local government power.136

The court also rejected the parish’s argument that Louisiana Constitution, article IX, section 1, which requires the legislature to enact laws to protect the environment, also grants such a power to the local government that could not be superseded by the state. The state legislature enacted laws to protect the environment from oil and gas development and operations, and those laws included a preemption provision that prohibits local governments from interfering with the drilling of a permitted well.137 Finally, the court of appeal rejected the parish’s strained meaning of the word “consider” as meaning “give heed to” (or essentially, defer to) the parish, where under Louisiana law the commissioner is required to “consider” the parish’s master plan before creating a unit or issuing a drilling permit. The record established that the commissioner considered the parish’s arguments even though they were rejected.138

Perhaps most interesting about the case, the Louisiana Supreme Court denied certiorari or review, but three justices would have granted the writ, two of which assigned reasons. Justice Guidry reasoned that St. Tammany only sought enforcement of its zoning ordinances, not to regulate oil and gas, a matter sufficiently fundamental to self-governance to warrant review.139 Justice Knoll reasoned that, although the commissioner’s power to issue drilling permits is an exercise of police power that may not be abridged, so is the local government’s zoning power. Reminiscent of the 2014 opinion of the New York Court of Appeals in Wallach v. Town of Dryden,140 Justice Knoll also opined that he did not view this case as a matter that could be resolved based on preemption because the oilfield regulatory ordinances govern a different subject matter than land use ordinances which are concerned with local zoning.141

4. AIX Energy, LLC v. Bennett Properties, LP, Civ. Act. No. 13-cv-3304, 2016 WL 5395870 (W.D. La. Sept. 26, 2016) (mem. op.).

This case presented the question whether a mineral servitude was lost for nonuse by prescription, returning to the surface estate. Under Louisiana law, production on either the tract

134 LA. CONST. art. VI, § 9(B) (emphasis added). 135 LA. CONST. art. VI, § 5(E). 136 199 So. 3d at 9. 137 Id. at 10. 138 Id. at 11. 139 194 So.3d 1109, 1109 (La. 2016) (mem. op.), recon. not cons’d, 195 So. 1204 (La. 2016) (mem. op.). 140 16 N.E.3d 1188 (N.Y. 2014). 141 194 So.3d at 1110. 29 at issue or from a unit embracing all or part of the tract interrupts prescription.142 A subsequent purchaser of the surface argued that, as a third party purchaser without notice, it was not bound by the unit agreement creating the unit, but the federal district court disagreed.

The court applied Louisiana Civil Code article 3339, which provides in part that “a tacit acceptance” . . . “and a similar matter pertaining to rights and obligations evidenced by a recorded instrument are effective as to a third person although not evidenced of record.” The predecessor owner of the mineral servitude never executed the voluntary unit agreement, but signed division orders that included a ratification of the unit agreement and accepted royalties. The court held a ratification could be characterized as either a tacit acceptance or a similar matter. Because the unit agreement contained a ratification provision, a reasonable person would have known that it was possible the agreement had been ratified despite the absence of a signature of record.143

5. XXI Oil & Gas, LLC v. Hilcorp Energy Co., No. 2016-269, 2016 WL 5404650 (La. Ct. App. 3d Cir. Sept. 28, 2016).

This decision involved the implications of an interim decision of the United States District Court for the Western District of Louisiana. Under Louisiana Revised Statutes 30:103.1, an operator must issue to the owners of interests “by a sworn, detailed, itemized statement” (1) an initial report as to the costs of drilling, completing, and equipment the well within ninety calendar days from the date of completion, and (2) quarterly reports thereafter “after establishment of production from the unit well.”144 The harsh penalty for failure to issue the reports is forfeiture of the right to demand contribution.145 Section 103 is titled “operators and producers to report to owners of unleased oil and gas interests”; and, although the language of the reporting obligation is not expressly limited to unleased owners, later provisions of the statute state that “[r]eports shall be sent . . . to each owner of an unleased oil or gas interest” and the penalty provision on its face is limited to owners of unleased oil and gas interests.

After Hilcorp recompleted a well and began producing, XXI, a mineral lessee in the unit, requested an initial report from Hilcorp containing the costs of recompleting the well and quarterly reports as to production. Hilcorp sent XXI an AFE that included cost estimates and an invoice. XXI then elected to participate, but sent Hilcorp a letter that informed Hilcorp that it could not deduct XXI’s share of costs because Hilcorp had failed to timely provide XXI a “sworn, detailed statement of revenues and expenses.”146 XXI relied on a previous 2013 decision, where the same Third Circuit Court of Appeal mechanically applied the statute and held that the statement of costs was inadequate because it was not sworn, and that forfeiture was the clear remedy.147 Upon remand, the trial court calculated penalties in the amount of $357 thousand, and Hilcorp again appealed.

142 LA. REV. STAT. § 31:37. 143 2016 WL 5395870 at *4. 144 LA. REV. STAT. § 30:103.1. 145 Id. § 30:103.2. 146 For the facts of the case, see XXI Oil & Gas, LLC v. Hilcorp Energy Co., 124 So.3d 530 (La. App. 3d Cir. 2013). 147 Id. at 535. 30

This time, however, Hilcorp cited TDX Energy, LLC v. Chesapeake Operating, Inc.,148 an unpublished opinion issued in the interim wherein the United States District Court for the Western District of Louisiana held that the reporting and penalty statutes do not apply to mineral lessees, rejecting the plaintiff’s argument that the statute only excused the reporting obligations for interests that are not leased by the operator. The federal court held that the reporting requirement applies only to lands that are not leased at all, reasoning that the legislature might have viewed unleased mineral owners as less sophisticated. If the legislature intended the statute to apply “owners of oil and gas interests unleased by the operator,” it should have so stated.149

On appeal the second time in the Hilcorp case, the Third Circuit Court of Appeal rejected the recent federal court opinion with no discussion of its substance. Instead, the court turned to the law of the case doctrine, which precludes in part an appellate court from ordinarily considering its own rulings of law on a subsequent appeal in the same case. The court recited the rule that federal court decisions on state law are not binding on the state courts, and instead accepted the very argument that was rejected in TDX Energy – that “unleased” means “unleased by the operator.” The court of appeal thus maintained its position that the statute required the operator to send the reports to other mineral lessees.

A Louisiana court has discretion whether to apply the law of the case doctrine where a former appellate decision was clearly erroneous.150 Based on seemingly clear language of the statute, this would have been a fitting opportunity to apply that discretion.

In the TDX Energy case, the U.S. district court also had occasion to interpret Louisiana’s risk fee statute that governs drilling unit operations in the absence of a joint operating agreement. The district court agreed with TDX that Chesapeake could not invoke the statute and seek to impose the two hundred percent risk penalty because Chesapeake had not sent notice before completing the well.151 The statute had provided that an owner drilling or intending to drill a well must send notice to other owners in the unit before the actual spudding of the well.152 As discussed below, the Louisiana Legislature amended this statute in part in response to this holding.

6. Amendments to Louisiana Risk Fee Statute

On June 13, 2016, Louisiana enacted Senate Bill 388 as Act number 524153 to amend Louisiana’s risk fee statute. As noted above, before the amendment an owner drilling or intending to drill a well was required to send notice to other owners in the unit before the actual spudding of the well. Now any such owner drilling, intending to drill, or “who has drilled a unit well” may send the notice to other owners after the spudding of the well.

148 Civ. Act. No. 13-1242, 2016 WL 1179206 (W.D. La. 2016) (mem. op.). 149 Id. at *5 (emphasis in original). 150 Trans Louisiana Gas Co. v. Louisiana Ins. Guar. Ass’n, 693 So. 2d 893, 896 (La. App. 1st Cir. 1997). 151 2016 WL 1179206 at *11. 152 LA. REV. STAT. § 30.10A(2)(a)(i) (2015). 153 LA. S.B. 388 (enacted June 13, 2016) (amending LA. REV. STAT. §§ 30:10(A)(S)(a)(i), (b)(i), (c), (d)(i), and enacting LA. REV. STAT. § 30:10(A)(2)(i)). 31

The prior version of the law also required payment of drilling costs under an AFE within sixty days of spudding, while the amended statute now requires payment within sixty days of the later of spudding or receipt of the required notice. For units created around a well already drilled or drilling, the prior law required notice to the other owners within sixty days of the order creating the unit. The amendment eliminates the sixty day notice requirement. The amendment also provides that failure to send notice to an owner does not invalidate notices provided to other owners.

V. EASTERN CASES

1. Alabama – Dominion Resources Black Warrior Trust v. Walter Energy, Inc., No. 2:16-cv-00058-RDP, 2016 WL 3924227 (N.D. Ala. July 21, 2016) (mem. op.).

Walter Energy, Inc. and its subsidiaries, including Walter Black Warrior Basin, LLC (“WBWB”) filed bankruptcy as part of the largest Chapter 11 bankruptcy in Alabama history. WBWB held oil and gas leases in Tuscaloosa County. In 1994, WBWB entered into an overriding royalty agreement, a trust agreement, and an administrative services agreement with Dominion Resources Black Warrior Trust (“Dominion”), under which WBWB granted to Dominion an overriding royalty and Dominion paid WBWB an administrative services fee. The bankruptcy court rejected the agreements as burdensome and unprofitable executory contracts. Dominion argued that the royalty agreement was an interest in land that could not be rejected. The bankruptcy court reasoned that the characterization of the royalty turned on the characterization of WBWB’s underlying leasehold interest as real or personal property under Alabama law, and concluded that the leasehold interest was personal property.

On appeal, the United States District Court for the Northern District of Alabama applied the equitable mootness doctrine, concluding that the appeal was both statutorily and equitably moot.154 Equitable mootness applies in a bankruptcy proceeding when the appellate court cannot grant equitable relief because the “reorganization plan has been so substantially consummated that effective relief is no longer available.”155 Here, the bankrupt WBWB had transferred both real and personal property to a new entity (which had been issued new permits and licenses), granted lien releases, and obtained new funding and surety bonds.

Nevertheless, the district court addressed Dominion’s argument that its royalty interest was real property. Like the bankruptcy court, the district court cited NCNB Tex. Natl. Bank, N.A. v. West for the holding that Alabama recognizes the non-ownership theory when classifying the mineral interest in oil and gas.156 Both courts also cited the 1916 Alabama Supreme Court opinion in State v. Roden Coal Co. for the proposition that coal mineral rights held under a lease “convey[ed] no greater estate in the land or the minerals in place than a chattel interest . . . .” and that the “leasehold interest is property, a chattel real, . . . in the nature of personal property.”157 Accordingly, the court could not provide relief, and the appeal was considered moot.

154 2016 WL 3924227 at *6. 155 Id. at *4 (quoting In re Club Assocs., 956 F.2d 1065, 1069 (11th Cir. 1992)) (internal citation omitted)). 156 631 So.2d 212, 223 (Ala. 1993). 157 197 Ala. 407, 414 (1916). 32

However, these opinions upon which the court relied and the manner in which they were applied are not without question. As to the classification of mineral interests, at least one commentator has argued that Alabama consistently followed an ownership-in-place theory before NCNB, and that NCNB was based on a misinterpretation of Alabama case law.158 Although the classification of oil and gas leases and royalties in Alabama is uncertain, in Lake v. Sealy, decided 20 years after the Roden case, the Alabama Supreme Court suggested that mineral rights, oil and gas leases, and royalties thereon are “classified in the nomenclature of the law of real property as incorporeal hereditaments.”159 In a more recent case, the Alabama Supreme Court held that an unsigned oil and gas lease and a cover letter to the lessee signed by the lessor satisfied the statute of frauds, “assuming without deciding that an oil, gas, and mineral lease is a conveyance of an interest in real property within the purview of the statute of frauds.”160

An incorporeal interest, although non-possessory, is an interest in land and is often called a profit-à-prendre. A profit-à-prendre authorizes the holder to remove something of value from the land;161 but it does not necessarily follow that such an interest in land must be real property. At common law, an interest in land with a lesser duration than a freehold estate would be classified as personal property – a chattel real – as the court held in Roden. Arguably, however, Roden is based on a misunderstanding of the nature of a mineral lease.

If, concerning an interest in land, the primary factor distinguishing personal property from real property is the duration of the estate, then an oil and gas lease should be classified as real property. The habendum clause of an oil and gas lease typically makes the lease a conveyance of an estate in fee simple determinable, a type of defeasible fee of indefinite duration – a freehold estate. Some commentators have thus argued that the distinction between a deed and a lease of minerals is of little value, although courts appear to apply the distinction regularly.162 Similarly, an overriding royalty interest has an indefinite duration that typically lasts so long as the underlying lease remains in effect.

2. Ohio – The Dormant Mineral Act Cases – Corban v. Chesapeake Exploration, L.L.C., 2016-Ohio-5796, 2016 WL 4887428 (Sept. 15, 2016), and Its Progeny.

In 1961, the Ohio General Assembly enacted the Ohio Marketable Title Act, which provides that marketable record title—an unbroken chain of title to an interest in land for 40 years or more—extinguishes interests that depend on transactions that occurred before the effective date of the root of title unless a savings event appeared in the record chain of title.163 In 1973, the Marketable Title Act was amended to include mineral interests.164

158 Misha Ylette Mullins, Comment: Alabama Oil and Gas Law: Ownership or Nonownership After NCNB, 48 ALA. L. REV. 1065 (1997). 159 165 So. 399, 401 (Ala. 1936). 160 Borden v. Case, 118 So.2d 751, 753 (Ala. 1960). 161 PATRICK H. MARTIN AND BRUCE M. KRAMER, 8 WILLIAMS & MEYERS OIL AND GAS LAW, MANUAL OF OIL AND GAS TERMS, P (2016). 162 Id., v. 1-2, § 207. 163 OHIO REV. CODE §§ 5301.47 et seq. 164 135 OHIO LAWS, PT. I, 942-43. 33

In 1989, the Ohio General Assembly enacted the Ohio Dormant Mineral Act165 (the “1989 DMA”) to more efficiently clear title to mineral interests in response to a 1983 decision of the Ohio Supreme Court. The court, when interpreting the Marketable Title Act, had held that a recorded affidavit of transfer under a will broke the chain of title of an otherwise unbroken marketable record title even though the transfer at issue arose under an independent chain of title.166

The 1989 DMA provided that a mineral interest shall be “deemed abandoned and vested” in the owner of the surface unless one or more savings events occurred within the prior 20 years. Savings events included a “title transaction” that has been filed or recorded, and actual production from lands covered by a lease or lands pooled with the lease.

Then in 2006, the legislature amended the 1989 DMA to require the surface owner to give advance notice to the mineral rights holder (as amended, the “2006 DMA”).167 Under the 2006 DMA, the claimant of a mineral interest has an opportunity to respond to the notice within 60 days by filing a claim to preserve the mineral interest and an affidavit that describes a savings event. The mineral interests at issue are deemed abandoned and vested in the surface owner only if the mineral interest holder fails to timely respond and the surface owner takes certain additional procedural steps required by the statute.

In Corban v. Chesapeake Exploration, L.L.C., the Ohio Supreme Court answered two certified questions posed by the United States District Court for the Southern District of Ohio: (1) whether the 1989 DMA or the 2006 DMA should be a applied to a quiet title action that asserted the rights to minerals that were abandoned before 2006; and (2) whether the payment of delay rental was a title transaction that constituted a savings event.168

In Corban, an assignment of a lease of the mineral interest was recorded in 1985, but after that lease expired for lack of production, the next recorded transaction was the assignment of a separate lease in 2009, more than 20 years after the previous recorded transaction. In 2011, a well was drilled and began to produce. Thereafter, the plaintiff, Corban, filed a quiet title action seeking an injunction and claiming trespass and conversion, alleging that the defendants had abandoned their mineral interests by operation of law under the 1989 DMA before the enactment of the 2006 DMA.

As to the second certified question, the justices all agreed that payment of delay rental is not a title transaction or saving event under the DMA. A “title transaction” is defined in the statute as a transaction that affects title to an interest in land. In 2015, the Ohio Supreme Court determined that a recorded oil and gas lease is a title transaction that stops the 20-year term because the lessor effectively relinquishes her ownership interest in the oil and gas underlying the property, but that the unrecorded expiration of a lease is not a title transaction that restarts the

165 142 OHIO LAWS, PT. I, 981, 985-88. 166 Heifner v. Bradford, 446 N.E.2d 440 (Ohio 1983). 167 OHIO REV. CODE § 5301.56. 168 2016 WL 4887428 at *1. 34 clock.169 In this case, the court found that a delay rental does not affect title separate and apart from the oil and gas lease and occurs outside the record chain of title.170

The first certified question was more difficult. To answer whether the 2006 DMA applied to statutory abandonments alleged to have occurred before its enactment, the court first had to determine whether the 1989 DMA was self-executing, i.e. whether a mineral interest is automatically merged into the surface estate after the expiration of the statutory period. The majority focused on the word “deemed” in the 1989 Act, distinguishing the term from the word “extinguished.” Using the word “deemed” created the conclusive presumption that a mineral interest had been abandoned—a presumption that cannot be overcome by contrary proof. But the presumption was simply an evidentiary device to be employed in litigation to quiet title.171 The majority thus concluded that the 1989 DMA was not self-executing. The 1989 act required a quiet title action seeking a decree that the dormant mineral interests were “deemed” abandoned.

The law, however, changed in 2006, now prescribing specified procedures. These procedures, held the majority, applied equally to claims of mineral interest abandonment that were made both before and after the enactment of the 2006 DMA. The plaintiff argued that such a retroactive application violated the Retroactivity Clause of the Ohio Constitution, but the majority disagreed. The majority reasoned that clause only prohibits retroactive application of substantive laws, not procedural laws. In enacting the 2006 DMA, the legislature had done nothing more than modify the procedural requirements necessary to obtain marketable title to an abandoned interest.172

As to this first certified question, Justice Kennedy concurred in the judgment but not as to the majority’s reasoning. She agreed that the 1989 DMA was not self-executing and also agreed that the 2006 DMA applied to claims asserted after its effective date. Reasoning, however, that the term “abandon” had a common law meaning that was understood when the 1989 DMA was enacted, she would require the surface owner to show the intent of the mineral interest owner to abandon its interest, in addition to the absence of a statutory savings event.173

Joined by Justice O’Neill, recently retired Justice Pfeifer dissented as to this question. He stated that the 1989 DMA was a “bluntly efficient” means to vest the surface owner with record title to the underlying minerals by operation of law. He focused on the word “vested” as used in the statute rather than “deemed abandoned.” He argued that where property rights vested under the 1989 DMA before the enactment of the 2006 amendments, application of those amendments was nothing less than a taking and violated constitutional protections from retroactive legislation.174

Interestingly, both the 1989 DMA and the 2006 DMA use the terms “abandoned and vested in the owner of the surface.” The 2006 DMA, however, also contains the additional

169 Chesapeake Exploration, L.L.C. v. Buell, 45 N.E.2d 490 (Ohio 2015). 170 2016 WL 4887428 at *9. 171 Id. at *7. 172 Id. at *8-*9. 173 Id. at *22. 174 Id. at *28-*30. 35 language that if the procedures are followed by the surface owner, “the record of the mineral interest shall cease to be notice to the public of the existence of the mineral interest or any rights under it.” Apparently, this additional language was sufficient to the majority to transfer a mineral interest by operation of law under the 2006 DMA when its procedures are properly followed; whereas the majority would require a separate quiet title action under the 1989 DMA in the absence of this language.

Relying on Corban, the court on the same day decided Walker v. Shondrick-Nau,175 Albanese v. Batman,176 and 10 other cases that cite Corban and Walker as authority, denying claims of surface owners that relied on the now defunct “automatic merger” concept and who failed to meet the 2006 DMA’s notice and other procedural requirements.

Although the decision provides some certainty, it may raise significant title issues and other claims for parties and their title lawyers that operated under a belief that the 1989 DMA affected an automatic merger of the mineral and surface estate. A surface owner believing it acquired a mineral interest might have leased that interest, now resulting in breach of warranty claims. Mineral owners that may have been advised that their interests were abandoned (or who simply lost track) might now at the court house steps with new allegations of trespass and conversion.

3. Ohio – State ex rel. Claugus Family Farm, L.P. v. Seventh District Court of Appeals, 47 N.E.3d 836 (Ohio 2016).

In this class action lawsuit, plaintiffs sued Beck Energy Corporation (“Beck”) on behalf of themselves and 400 named plaintiff landowners in Monroe County alleging that the Form G & T (83) leases presented by Beck and signed by the landowners violated Ohio law. Under Ohio law, long-term mineral leases that do not require development are void as against public policy.177

After the trial court granted summary judgment, it certified the class. Beck appealed the class certification and the appellate court remanded. The trial court then expanded the class to include 200 to 300 unnamed plaintiff landowners in other counties, and applied its summary judgment to the expanded class. In July 2013, the trial court tolled the leases of only the named plaintiffs, but on appeal the court of appeals expanded the tolling order to also include the unnamed plaintiffs back to October 1, 2012, the date of Beck’s original motion to toll the leases. In September, 2014, the court of appeals reversed the trial court on the merits, and the parties stipulated to further toll the leases pending an appeal to the Ohio Supreme Court.

The form lease at issue provided as follows:

This lease shall continue in force . . . for a term of ten years and so much longer thereafter as oil and gas or their constituents are produced or are capable of being

175 2016-Ohio-5793, 2016 WL 4908788 (Ohio Sept. 15, 2016). 176 2016-Ohio-5814, 2016 WL 4894676 (Ohio Sept, 15, 2016). 177 Iunno v. Glen-Gery Corp., 443 N.E.2d 504, 508 (Ohio 1983). 36

produced on the premises in paying quantities, in the judgment of the Lessee, or as the premises shall be operated by the Lessee in search for oil or gas . . . .

This lease, however, shall become null and void and all rights of either party hereunder shall cease and terminate unless, within ___ months from the date hereof, a well shall be commenced on the premises, or unless the Lessee shall thereafter pay a delay rental of ___ Dollars each year . . . . 178

The class representative argued that these leases could be continued indefinitely by the lessee past the primary term without development if the lessee subjectively determined that oil and gas is capable of being produced. The Ohio Supreme Court, however, affirmed the decision of the court of appeals that the leases did not violate Ohio public policy. Under Ohio law, delay rentals may only keep a lease in effect without development during the primary term.179 Further, the court held that oil and gas is only “capable of being produced” when a well is present, and Beck acknowledged that it could only exercise its judgment that oil and gas is capable of being produced once a well had been drilled.180

The landowners also argued that a covenant to develop should be implied in the leases. When a lease does not require development within a specific period, Ohio courts will impose an implied covenant to reasonably develop.181 The court rejected the landowners’ argument, however, because the leases at issue required development within ten years and contained specific language in the leases that disclaimed any implied covenants.182

The most interesting aspect of the case related to the tolling of the leases, which was challenged by Claugus Family Farm, L.P. (“Claugus”), an absent and unnamed plaintiff. While the case was working its way through the courts, Claugus’s lease with Beck expired, but after the tolling order was effective. In anticipation of the lease expiration, Claugus negotiated a new lease with Gulfport subject only to title review. Upon hearing of the tolling order, Gulfport refused to lease, the tolling order being a title defect.

Even though Claugus was only notified of the tolling order after it was modified and expanded by the court of appeals, the supreme court held that Claugus found out about the case 11 months before the court of appeals issued its opinion on the merits, and could have moved to intervene during that time.183 Justice Pfeifer once again issued a lively dissent.

Claugus had argued that its lease was valid, but that it had simply expired. It wanted to avoid having its lease (and 100s of other similar leases) extended while the litigation played out. As Justice Pfeifer surmised the facts:

178 47 N.E.3d at 841-42 (emphasis added). 179 Id. at 842 (citing Brown v. Fowler, 63 N.E. 76 (1902)). 180 Id. at 842-43. 181 Iunno, 443 N.E.2d at 508. 182 47 N.E.3d at 843. 183 Id. at 844. 37

It is as if [the named lead plaintiff] and Beck Energy were part of a scheme to extend the Beck leases by subterfuge—by making a specious argument about the validity of the leases and tolling them—instead of extending the leases the old- fashioned way, by working the land that is the subject of the leases.184

And per Justice Pfeifer, the lead plaintiff did not appropriately represent the class. Claugus and who-knows-how-many-other unnamed plaintiffs without notice believed their leases were valid. As such, the class should never have been certified and the due process rights of Claugus and others were violated. Claugus lost its top lease with Gulfport, and the price of oil crashed during the pendency of the litigation, causing Claugus to “dream[] of what might have been, of what this court could and should have done.”185

4. Ohio – Lutz v. Chesapeake Appalachia, L.L.C., 2016-Ohio-7549, 2016 WL 6519011 (Ohio Nov. 2, 2016).

In a federal class action lawsuit against Chesapeake Appalachia, L.L.C. for underpayment of royalties, the United States District Court for the Northern District of Ohio certified a single question to the Ohio Supreme Court – whether Ohio follows the “at the well” rule and permits deduction of post-production costs from royalty payments under an oil and gas lease, or whether it follows the marketable product rule which limits deductions under certain circumstances. The leases at issue contained rather standard royalty provisions, providing that the royalty on gas sold or used off the lease would be one-eighth of the market value at the well of the gas sold or used, and that gas sold at the well would be one-eighth of the amount realized. The leases also contained an apparently conflicting provision that the lessor would be entitled to the field market price for gas marketed from the premises.

In an unsatisfying opinion, the majority declined to answer the question and dismissed the cause. The court reasoned that an oil and gas lease is simply a contract, and if the leases were not ambiguous, then the federal court should be able to interpret the contract without the court’s assistance. If the leases were ambiguous, then the court lacked the necessary extrinsic evidence to give effect to the parties’ intent.186

Two justices dissented. Justice Pfeifer (again dissenting) would have answered that Ohio follows the marketable product rule because the lessee is in complete control of postproduction costs, these costs can be manipulated, and lessees usually draft the lease.187

In contrast, Justice O’Neill would have answered that rights are determined by the written instrument. He would adopt the rule annunciated in Piney Woods County Life School v. Shell Oil Co., that market value at the well refers to gas in its natural state, allowing the lessee to deduct processing and transportation costs.188 He referred back to Claugus, where the court strictly

184 Id. at 845. 185 Id. at 846-46. 186 2016 WL 6519011 at *2. 187 Id. at *3. 188 Id. at *4. 38 adhered to the terms of the leases, refusing to impose an implied covenant to develop where the lease required development during the primary term and disclaimed any implied covenants.189

5. Ohio – Simmers v. City of North Royalton, 65 N.E.3d 257 (Ohio Ct. App. [10th Dist.] 2016).

This appellate court case is material because it offers unleased landowners a new avenue to challenge forced pooling applications based on environmental or safety concerns.

Cutter Oil (“Cutter”) had entered into a number of oil and gas leases with the City of North Royalton and had drilled 17 wells in the city, but the #8HD Well was different. This well would be the first horizontal well drilled in the city, and the first horizontal well drilled by Cutter. Cutter offered the city a lease, and pursuant to the Ohio Code, the city conducted a public meeting to consider the proposed lease agreement.190 In the interim, Cutter filed an application for mandatory pooling. Although the City Council eventually voted to reject the lease agreement, the Division of Oil & Gas Resources Management ordered mandatory pooling and issued a drilling permit for the well. The city appealed to the Ohio Oil and Gas Commission, which issued an order vacating the division’s pooling order. The Franklin County Court of Common Pleas affirmed, and the division appealed to the court of appeals, which affirmed the judgment of the court of common pleas.

The sole question was whether the commission improperly considered health, safety and welfare factors when it vacated the pooling order of the division. In Jerry Moore, Inc. v. State of Ohio, the Ohio Oil and Gas Board of Review (the predecessor to the commission) in 1996 held that under the Ohio Revised Code an applicant for mandatory pooling must show that (1) its tracts under lease are of an insufficient size and shape to meet the requirements for a unit and (2) it used “all reasonable efforts” to obtain a voluntary agreement on a “just and equitable basis.” This latter requirement contemplates both a reasonable offer and sufficient efforts to advise the other owners of the same. 191 If these showings are made, then the division must issue a permit if it is satisfied that pooling is necessary to protect correlative rights and to provide effective development, use, and conservation of oil and gas.192

In this case, the division considered only whether a reasonable monetary offer was made. It argued that safety considerations were not appropriate for mandatory pooling, but instead are considered at the drilling permit stage under the Code, which requires the division to deny a permit where it finds that operations will result in violations of the Code or “will present an imminent danger to public health or safety or damage to the environment.” Alternatively, the division may issue a permit subject to conditions that reasonably can be expected to prevent the violations. The court of appeals noted that the city had safety concerns that may not rise to the level of “imminent danger.” These considerations might never be considered at the drilling

189 See supra Part V.3. 190 OHIO REV. CODE ANN. § 1509.61 (“The legislative authority of a political subdivision shall conduct a public meeting concerning a proposed lease agreement for the development of oil and gas resources on land that is located in an urbanized area and that is owned by the political subdivision prior to entering into the lease agreement.”). 191 Ohio Oil and Gas Board of Review, Appeal No. 1, 19 (July 1, 1996). 192 OHIO REV. CODE ANN. § 1509.27. 39 permit stage. The drilling permit process is a ministerial process because a permit must be issued within 21 days of application unless it is denied by order.193

To interpret what is required for “just and equitable” efforts under the mandatory pooling statute, the court turned to its 1993 decision in Johnson v. Kell.194 There a landowner was offered a standard royalty rate for 1.4 acres of the 13 acres he had purchased at a significant premium to develop his oil and gas rights. He had drilled a well and the newly proposed well would offset his existing well. The Johnson court held that a factual finding regarding correlative rights must take into account the impact on the forced participant; and because of these facts and circumstances, the economic impact on this landowner could be significant.

The majority of the court of appeals in this case significantly expanded the holding of Johnson. The majority stated that under Johnson the “just and equitable” standard requires consideration of land not directly forced into the mandatory pool; and, that factors other than finances must be considered to understand the impact on affected landowners. Further, despite the ruling of the Ohio Supreme Court in State ex rel. Morrison v. Beck Energy Corp.,195 the court of appeals thought it made no sense to allow a municipality to voice its concerns and then have those concerns “brushed aside” by the division.196 The court also found that the division’s position conflicted with the public policy of the state to encourage extraction when it can be accomplished “without undue threat of harm to the health, safety and welfare of the citizens of Ohio.”197

In dissent, however, Judge Salder argued that the majority had misinterpreted Johnson. That case authorized the consideration of non-economic factors only to the extent those factors affected the value of the unwilling participant’s correlative rights.198 Judge Salder agreed with the position of the division that the commission lacked jurisdiction to consider safety issues. Safety is to be considered at the drilling permit stage, and the commission is without jurisdiction to consider an appeal from a decision granting a permit.199

6. Pennsylvania – Shedden v. Anadarko E. & P. Co., L.P., 136 A.3d 485 (Pa. 2016).

In 2006, the Sheddens leased 100% of the oil and gas rights on 62 acres to Anadarko, expressly warranting title to all of the oil and gas. Before Anadarko tendered its bonus payment, it discovered (unbeknownst to the lessors) that the lessors owned only an undivided 1/2 of the oil and gas rights because the remaining 1/2 interest had been reserved by their predecessors in an 1894 deed. As a result, Anadarko tendered a bonus on 31 net mineral acres. Thereafter, the lessors won a quiet title action to the remaining 1/2 mineral interest. The lease contained an extension clause, and in 2011 when Anadarko invoked the clause it tendered the extension payment on 100% of the net mineral acres. The lessors filed a declaratory judgment action

193 65 N.E.3d at 263. 194 626 N.E.2d 1002 (Ohio Ct. App. [10th Dist.] 1993). 195 37 N.E.3d 128, 137 (Ohio 2015) (Home Rule Amendment to Ohio Constitution does not apply a municipality to unfairly impede or obstruct oil and gas activities permitted by the state). 196 65 N.E.3d at 264. 197 Id. at 264-65 (citing Newbury Twp. Bd. of Twp. Trustees v. Lomak Petroleum, 583 N.E.2d 302 (Ohio 1992)). 198 Id. at 267-68. 199 See Chesapeake Exploration, L.L.C. v. Oil & Gas Comm., 985 N.E.2d 480, 484 (Ohio 2013). 40 contending that the lease only pertained to the 1/2 undivided interest that the lessors owned at the time the lease was granted.

The court first considered whether the lease was modified by Anadarko’s payment of bonus on only 1/2 of the net mineral acres. It was not, because under the express terms of the lease Anadarko was entitled to reduce its bonus payment to reflect what the lessors actually owned at the time the lease was granted.200 The court next considered whether the doctrine of estoppel by deed barred the lessors from denying that the lease granted to Anadarko covered 100% of the oil and gas rights. Under the doctrine of estoppel by deed:

[w]here one conveys with a general warranty land which he does not own at the time, but afterwards acquires the ownership of it, the principal of estoppel is that such acquisition inures to the benefit of the grantee, because the grantor is estopped to deny, against the terms of his warranty, that he had the title in question.201

The lessors argued that because the doctrine is equitable, Anadarko must show detrimental reliance, which it could not do because it paid bonus on only 1/2 of oil and gas rights in the land. The court disagreed. Distinguishing equitable estoppel, the court found that under Pennsylvania law detrimental reliance is not an element of estoppel by deed. Although rooted in equity, broader considerations were at stake, including the policy of making deeds final evidence of their contents.202

7. Pennsylvania – Robinson Township v. Commonwealth, 147 A.3d 536 (Pa. 2016).

In 2013, in Robinson Township v. Commonwealth,203 a plurality of the Pennsylvania Supreme Court struck down portions of Act 13,204 a sweeping law enacted in Pennsylvania in 2012 to regulate the oil and gas industry that amended and repealed the former Pennsylvania Oil and Gas Act of 1984.205 As amended and expanded by Act 13, Title 58 of the Pennsylvania Consolidated Statutes contained three preemption provisions: (1) Section 3302 from the former Oil and Gas Act, which prohibits local governments from adopting requirements that regulate the same features of oil and gas operations that are regulated by the state under Chapters 32 and 33 of the act; (2) Section 3303, which prohibited local governments from enacting or enforcing environmental legislation; and (3) Section 3304, which required local ordinances regulating oil and gas to be uniform and mandated that certain drilling and ancillary activities be allowed in every local zoning district.

In its 2013 opinion, the court struck down Sections 3303 and 3304 based on the Environmental Rights Amendment to the Pennsylvania Constitution,206 but left standing Section 3302 relating to technical operational activities. The court reasoned that the Environmental

200 136 A.3d at 490. 201 Jordan v. Chambers, 75 A. 956, 958 (1910). 202 136 A.3d at 492 (quoting 28 AM.JR.2D, ESTOPPEL BY DEED OF BOND, § 5). 203 83 A.3d 901 (Pa. 2013). 204 See 58 PA. CONSOL. STAT. §§ 2301-3504. 205 PA. ACT NO. 223 of 1984, PA. P.L. 1140 (effective April 18, 1985). 206 PA. CONST. art. I, § 27. 41

Rights Amendment requires the state and its subdivisions, including municipalities, to act as trustees of the environmental resources within the state that are both publicly and privately owned. The state legislature had no power to abrogate those trustee responsibilities on behalf of municipalities. The court then remanded to the commonwealth court to determine whether other provisions of Act 13 were severable to the extent they were valid.207 The remand thus required the commonwealth court to examine both the severability and validity of the remaining provisions that were challenged by the plaintiffs, a group made up of municipalities and others that the court refers to as the “Citizens.” The decisions made by the commonwealth court on remand were then appealed back to the Pennsylvania Supreme Court, which issued its opinion.

The majority first considered the severability of Sections 3305 through 3309 of Act 13. Section 3305 provided a mechanism for the Pennsylvania Public Utility Commission (the “PUC”) to determine whether a local ordinance violated the Pennsylvania Municipal Planning Code (the “MPC”) or Chapters 32 and 33 of the act and allowed “any person” who is aggrieved by a local ordinance to bring an action in court to invalidate or enjoin the ordinance. Sections 3307 and 3308 provided penalties for municipalities if their local ordinances didn’t comply with the MPC or Chapters 32 and 33, including the loss of “impact fees” that are assessed by the state and allocated to local governments. The court agreed with the commonwealth court that these provisions were not severable. The legislature enacted these provisions to allow the PUC to review compliance with the preemption provisions that the court previously struck down.208

The court then concluded that Sections 3222.1(b)(10) and (b)(11) of Act 13 did not violate the single subject mandate of the Pennsylvania Constitution, but did constitute “special laws” in violation of Article III, Section 32 of the Pennsylvania Constitution. Section 3222.1 of Act 13 requires chemical disclosure of fracking fluids, but exempts certain trades secrets and confidential information. The challenged subsections, (b)(10) and (b)(11), imposed restrictions on health care professionals’ access to information about these chemicals and disclosure as another means to protect proprietary information. The supreme court described the history of Article III, Section 32 of the Pennsylvania Constitution as preventing favoritism to specific corporations or industries, concluding that Sections 3222.1(b)(1) and (11) grant the oil and gas industry special protections for trade secrets that are not enjoyed by any other class of industry— the type of ill that the prohibition on “special laws” was intended to prevent.209

The Citizens’ then challenged Section 3218.1 of Act 13 as a special law because it required disclosure of spills to public drinking water facilities, but not to private well owners. The Department of Environmental Protection (the “DEP”) argued that it had never regulated private drinking wells; public drinking water sources serve more people then private wells; and it had no means to notify private well owners because such owners are not required to report to the DEP. Despite these arguments, the court held that the distinction did not have a fair and substantial relationship to the object of the legislation. Two of the purposes of Act 13 were aimed at protecting health and safety. As roughly a quarter of the population received drinking water from private wells, the court could not conceive how excluding them served these purposes. Due to separation of powers, however, the court could not simply rewrite the statute to

207 See Robinson T’ship v. Commonwealth, 96 A.3d 1104 (Pa. Comwlth. Ct. 2014). 208 147 A.3d at 565-66. 209 Id. at 575-76. 42 add private drinking water wells. So it struck the provision down in its entirety, but stayed its mandate by 180 days to allow the legislature to fix the problem.210

Finally, the court considered whether Section 3241 of Act 13 was unconstitutional because it conferred the eminent domain power on private corporations. Section 3241 conferred the power to condemn property for natural gas injection and storage on a corporation “empowered to transport, sell or store natural gas.” This definition was consistent with the definition of a “public utility” in the Public Utility Code, but the text of Section 3241 was not strictly limited to public utilities. Public utilities must produce light, heat or power for the public or transport natural gas for the public.211 A private corporation not selling to the public would be allowed to use Section 3241, and the public was not the primary and paramount beneficiary of this taking power. The state claimed that the public purpose of this takings power was to advance the development of infrastructure, but the court thought this purpose was speculative and incidental, not primary and paramount.212

8. Pennsylvania – Birdie Associates, L.P. v. CNX Gas Co., 149 A.3d 367 (Pa. Super. Ct. 2016), rearg. dismissed (Nov. 18, 2016).

In Pennsylvania, the Guaranteed Minimum Royalty Act (the “GMRA”) guarantees a lessor a minimum royalty of one-eighth of all gas removed from the property.213 And under Pennsylvania law, title to coal-bed methane (“CBM”) is vested in the owner of the coal.214

In 1984, two separate lessors leased to Consol Land Development Company (“Consol”) their undivided one-half interests “in and to all of the Pittsburgh seams or measures of coal and all constituent products of such coal in and underlying” certain lands in Pennsylvania. The original lease term was 20 years, subject to renewal for another 20 years upon payment of $100 per acre before the end of the original lease term. The leases provided for a royalty and minimum royalties on the production of coal, but were silent as to the treatment of CBM.

All minimum royalties were paid, but coal was never produced. Instead, Consol assigned its interests in the leases to CNX Gas Company, LLC (“CNX”), which drilled and produced CBM, but refused to pay royalties. CNX argued that despite the title of the underlying documents as “leases,” the agreements gave the grantee of the coal estate the right to produce CBM without payment of minimum royalties. The assignees of the original lessors, in contrast, argued that the documents were simply leases that were invalid under the GMRA.

Under what has become known as the “Pennsylvania Doctrine,” a “lease of coal in place with the right to mine and remove all of it for a stipulated royalty vests in the lessee a fee.”215

210 Id. at 582-83. 211 66 PA. CONSOL. STAT. § 102(1)(i); (v). 212 147 A.3d at 588. 213 58 PA. CONSOL. STAT. § 33.3 (“A lease or other such agreement conveying the right to remove or recover oil, natural gas or gas of any other designation from the lessor to the lessee shall not be valid if the lease does not guarantee the lessor at least one-eighth royalty of all oil, natural gas or gas of other designations removed or recovered from the subject real property.”). 214 U.S. Steel v. Hoge, 468 A.2d 1380 (Pa. 1983). 43

The lessor’s interest is a possibility of reverter that is personal property. The lessors argued that the Pennsylvania Doctrine was rejected as outdated in Olbum v. Old Home Manor, Inc. where the superior court found that a four year coal lease was not a sale.216 But in this case, the superior court rejected that argument, finding Olbum factually distinguishable. Although under Olbum a coal lease does not automatically convey a sale of the coal in place, in this case the leases were clearly conveyances of the coal estate because they conveyed all interests in the coal, “together with the right to mine and remove all of said coal;” they included a statement that the rights granted “are in enlargement and not in restriction of the rights to the mineral estate and ownership of said coal;” and the lessors warranted title.217 As the conveyance vested in Consol a fee simple interest in the coal in place, CNX owed no royalties under the GMRA.

VI. WESTERN CASES

1. Alaska – City of Kenai v. Cook Inlet Natural Gas Storage Alaska, LLC, 373 P.3d 476 (Alaska 2016)

In 2011, Cook Inlet Natural Gas Storage Alaska, LLC (“CINGSA”) entered into leases with the State of Alaska and Cook Inlet Region, Inc. (“CIRI”), to store non-native gas. CIRI and the state held the mineral rights in the Cannery Loop Sterling C Gas Reservoir, a depleted gas reservoir below the Kenai River. The City of Kenai owned approximately 576 acres in the surface estate overlying the reservoir. The city alleged that as the surface owner it owned the subsurface pore space, and CINGSA sued. The superior court granted summary judgment in favor of CINGSA, CIRI and the state, and the city appealed.

In an issue of first impression, the Alaska Supreme Court noted the lack of consensus among the courts and legal scholars as to pore space ownership. The city argued that the issue was a matter of deed interpretation, but in this case, the city received its surface acreage from the state by patent. The patent was subject to a reservation of the minerals in the state that was governed by state statute. The statutory language reserved to the state all minerals, and “generally all rights and power in, to, and over said land, whether herein expressed or not, reasonably necessary or convenient to render beneficial and efficient the complete enjoyment of the property and rights hereby expressly reserved.”218

Although the court acknowledged that pore space might be viewed, not as mineral, but as the absence of something, it found that it was “an inextricable part of the rock strata in which it is found . . . .”219 As porous rock are minerals, so too are the microscopic spaces within it. The court also found its interpretation consistent with the purpose of the Alaska Land Act to maximize revenue for the state, and that the surface owner’s ownership of the pore space was unnecessary for the enjoyment of the surface estate.220

215 Smith v. Glen Alden Coal Co., 32 A.2d 227, 233 (Pa. 1943); see also Shenandoah Borough v. Philadelphia, 79 A.2d 433, 436 (Pa. 1951), cert. denied, 342 U.S. 821 (1951); Hutchison v. Sunbeam Coal Corp., 519 A.2d 385, 387 (Pa. 1986); Kennedy v. Consol Energy, 116 A.3d 626, 633 (Pa. Super. Ct. 2015). 216 459 A.2d 757 (Pa. Super. Ct. 1983). 217 149 A.3d at 373-74. 218 ALASKA STAT. § 38.05.125(a). 219 373 P.3d at 481. 220 Id. at 482. 44

2. Colorado – City of Longmont v. Colorado Oil & Gas Association, 369 P.3d 573 (Colo. 2016).

In 2012, the residents of Longmont, Colorado voted to amend the city’s home-rule charter. The amendment prohibited fracking and the storage and disposal of fracking wastes. The Colorado Oil and Gas Association (“COGA”) sued, and environmental groups intervened on behalf of Longmont. The Colorado Oil and Gas Conservation Commission and an oil and gas company intervened on behalf of COGA. The district court granted summary judgment and an injunction to COGA that it stayed pending appeal. Longmont appealed and the court of appeals transferred the case to the Colorado Supreme Court.

In deciding the case, the court sought to explain and simplify its prior holdings on preemption. In Colorado, an imperio home rule state, a court must first decide whether the question at hand is a matter of statewide, local, or mixed state and local concern. In this opinion, the court clarified that this question is separate and distinct from the question whether a local law is preempted by state law.221 The factors considered in this initial inquiry include (1) the need for statewide uniformity, (2) the extraterritorial impact of the local regulation, (3) whether the local or state governments have traditionally regulated the matter, and (4) whether the Colorado Constitution commits the matter to the state or local government regulation. In matters of purely local concern, a home-rule ordinance supersedes conflicting state law. In matters of statewide or mixed state and local concern, state law will supersede a conflicting local ordinance.222

The court had previously found in Voss v. Lundvall Brothers, Inc.223 a great need for uniformity in the context of a complete ban on drilling because the boundaries of pools do not conform to jurisdictional boundaries; consequently, a complete ban results in irregular drilling patterns that in turn result in waste. The same analysis also applied to fracking because the process is used for virtually all oil and gas wells in Colorado. Extraterritorial impacts also favored a finding of statewide concern. If the ban were upheld then other municipalities may enact their own bans ultimately resulting in a de facto statewide ban. As to which level of government has traditionally regulated fracking, the court recognized that, while the state has regulated oil and gas development since 1915, local governments have broad authority to regulate land use. Under the final factor, the Constitution neither prohibits local regulation of fracking nor proscribes the state from regulating land use. Applying these factors, the court concluded the matter was one of mixed state and local concern and subject to preemption. 224 The court then turned to the second question—whether the local ban was preempted.

Colorado has recognized three forms of preemption: express, implied preemption by occupation of the entire field, and operational conflict preemption. No party argued that the Colorado Oil and Gas Conservation Act expressly preempted the ban, and the court’s prior cases

221 The court notes that its opinion in Voss v. Lundvall Brothers, Inc., 830 P.2d 1061 (Colo. 1992), erroneously conflated this inquiry. See id. at 1068. 222 369 P.3d at 580. 223 830 P.2d 1061, 1067 (Colo. 1992). 224 369 P.3d at 580-81. 45 already concluded that the Oil Conservation Act does not impliedly preempt the a local government’s authority to enact land use regulation.225

Turning to operational conflict preemption, the court recognized the inconsistencies of its prior holdings. In Voss, the court had stated that an operational conflict could arise when the local regulation would materially impede or destroy a state interest.226 In other cases the court had asked whether the local ordinance authorized what the state forbade or forbade what the state authorized.227 Here, the court reconciled the two tests. The proper test is whether the effectuation of the local interest will materially impede or destroy a state interest, but a statute that forbids what the state allows or vice versa will necessarily satisfy this standard.228

In this case, the commission had promulgated significant regulations governing the fracking process, including disclosure requirements, chemicals used, location of pits, and disposal of wastes. The ban rendered these regulations superfluous and thus materially impeded the application of state law.229

This decision, however, was not a complete victory for industry. In several instances the court reiterated that municipalities have a significant interest in regulating land use. Further, the court rejected COGA’s argument that the commission had the exclusive authority to regulate the technical operational aspects of drilling (such as downhole operations) because nothing in the Colorado Oil and Gas Conservation Act grants the commission this exclusive authority.230 This decision thus leaves abundant room for Colorado local governments to regulate oil and gas activity through land use ordinances or through operational performance standards—short of a complete ban on activities necessary for drilling, operations, and production.

3. Kansas – Armstrong v. Bromley Quarry & Asphalt, Inc., 378 P.3d 1090 (Kan. 2016).

This Kansas Supreme Court case involving an underground mine sought to clarify the interaction between trespass and conversion law and the law regarding limitations of actions with implications for the oil and gas industry.

Bromley Quarry & Asphalt, Inc. (“Bromley”) operated an underground limestone mine abutting the plaintiff’s property. In 1992, the plaintiff, Armstrong, sued Bromley for access to the mine to determine whether Bromley was trespassing. Although relief was not granted, the court ordered Bromley not to trespass and the parties agreed to dismiss the suit with prejudice by

225 Id. at 583 (citing Bd. of Cty. Comm’rs v. Bowen/Edwards Assocs., Inc., 830 P.2d 1045, 1059 (Colo. 1992); Voss, 830 P.2d at 1066). 226 Id. at 582 (citing Bowen/Edwards, 830 P.2d at 1059; Voss, 830 P.2d at 1068). 227 Id. (citing Webb v. City of Black Hawk, 295 P.3d 480, 492 (Colo. 2013)). 228 Id. at 583. Note that a drilling permit authorizes the drilling of a well in a particular location, which may be a location completely off limits under a traditional local zoning ordinance that establishes a residential district where industrial activity, including oil and gas drilling, is prohibited. The court does not address this thorny lingering issue, although it is clear from its prior holdings as reiterated in this case that the court recognizes the right of municipalities to conduct traditional zoning. 229 Id. at 585. 230 Id. at 584. 46 agreement in 1999. Under the agreement, Armstrong agreed that it could not prove any damages based on a survey map prepared by Bromley in 1992, and Bromley affirmed that the map was accurate reflecting the condition of the mine. In fact, the map was not accurate.

For several years after preparing its own maps of the mine for federal and state regulators, Bromley commissioned a new survey that was completed in 2011 that showed the mine had and was continuing to trespass on Armstrong’s land and that the limestone in the area of trespass was completely mined out.

Armstrong sued Bromley and Bromley admitted the trespass, but contended that most of the rock taken from the disputed area was removed before the applicable limitations period. The district court computed the damages as $127 thousand, representing the value of the rock taken during the two-year limitations period and after deducting the cost of removing the rock because Bromley was a good faith trespasser. A panel of the court of appeals disagreed that Bromley was a good faith trespasser but affirmed the trial court’s limitations analysis. Both parties appealed.

In Kansas, both trespass and conversion are subject to a two-year statute of limitations,231 but Kansas law also imposes a statute of repose. A statute of limitations may be tolled, but under the statute of repose no action may be commenced more than 10 years after the time of the act giving rise to the cause of action.232 This means that Armstrong was not entitled in any event to damages for any rock removed more than 10 years before the filing of the lawsuit.233

The statute of limitations in Kansas begins to run when the fact of injury becomes reasonably ascertainable to the injured party.234 In this case, the Kansas Supreme Court starts with the assumption that underground mining is not immediately apparent, without something more. Armstrong was suspicious that Bromley was trespassing and testified that his house had shaken from what he perceived to be blasting on his property. These suspicions may be the “something more” that triggered an obligation to reasonably investigate whether a trespass was occurring, but the supreme court disagreed with the trial court that the suspicions alone were enough to trigger the running of the limitations period.235

Materially, the supreme court was concerned there was little Armstrong could do to investigate. The court of appeals noted that Armstrong never obtained his own survey, had cores drilled, or turned to a regulatory agency for help. But to the supreme court, there was nothing in the record to indicate Armstrong acted unreasonably under the circumstances. Armstrong had sought an injunction in 1992 to obtain access to the mine and it was denied. Armstrong also had sought and obtained the previous mine maps filed with government agencies, but they were inaccurate. Based on the narrow record, the supreme court reversed and remanded as to whether the statute of limitations should have been tolled.236

231 KAN. STAT. ANN. § 60-513(a)(1), (2). 232 Id. § 60-513 (b). 233 378 P.3d at 1096. 234 KAN STAT. ANN. § 60-513 (b). 235 378 P.3d at 1099. 236 Id. at 1098-1100. 47

Armstrong also raised that in Kansas the statute of limitations does not begin to accrue for a continuing trespass until the continuing trespass is complete.237 But it was not clear that Armstrong had raised and preserved this argument before the trial court, an issue that could be decided on remand.238

After considering an evidentiary matter, the supreme court then turned to whether Bromley was a good faith trespasser. The court described the interrelationship between trespass and conversion in the mineral context. It explained that these are hybrid claims with a unique damages rule because the conversion claim stems from the trespass. A good faith trespasser is entitled to deduct its operating expenses for removing the minerals; whereas a bad faith trespasser is liable for enhanced value damages, meaning no expenses are deducted.239

The court adopted what appeared to be the reasoning of the Kansas Court of Appeals in Dexter v. Brake240 that good faith requires a mixed subjective and objective analysis, which is also a mixed question of law and fact.241 It also confirmed that the trespasser bears the burden of proof to show that its belief as to the superiority of its title was both honest and reasonable. In this case, Bromley failed to put forth evidence supporting an argument that it honestly believed it had superior title. The district court had erred when it considered Bromley’s excuses for its admitted trespass, rather than its honest and reasonable belief.242

4. New Mexico – Earthworks’ Oil & Gas Accountability Project v. New Mexico Oil Conservation Commission, 374 P.3d 710 (N.M. Ct. App. 2016).

In 2008, the New Mexico Oil Conservation Commission adopted a stringent new rule to regulate pits used in oil and gas production activities (the “Pit Rule”). Industry appealed the rule and the court of appeals stayed the proceedings. While the appeals were stayed, and after a change from a democratic to republican administration, the 2013 commission adopted a revised version of the Pit Rule acting on a petition from industry associations that relaxed, simplified, and clarified certain requirements. The revised rule was appealed by environmental organizations by writ of certiorari to the New Mexico Court of Appeals because the New Mexico Oil and Gas Act does not provide a statutory right to appeal rulemakings.243

On appeal, the appellate court held that the pending appeals regarding the 2008 Pit Rule did not prevent the commission from adopting a new version of the rule. Although an appeal might divest a tribunal of jurisdiction where it is acting in an adjudicatory capacity, the 2013 Pit Rule was the result of a rulemaking, not adjudication. The doctrine of separation of powers prevents the judicial branch from acting to stop a rulemaking before the rule is final, regardless that a prior version of the rule had been appealed. To the extent of any difference between the 2008 Pit Rule and the 2013 Pit Rule, the former rule has been repealed by implication.244

237 Id. at 1102 (citing Sullivan v. Davis, 29 Kan. 28 (1992); Dexter v. Brake, 269 P.2d 846 (Kan.App. 2012)). 238 Id. 239 Id. at 1095-96. 240 269 P.2d at 861. 241 378 P.3d at 1106. 242 Id. at 1106-07. 243 See N.M. STAT. ANN. § 70-2-25. 244 374 P.3d at 714-15. 48

The court also refused to take judicial notice of the record in the 2008 rulemaking proceeding because administrative appeals are limited to the record before the agency.245 The fact that the 2013 Pit Rule was different than the 2008 rule did not automatically render the new rule arbitrary and capricious. The commission had provided adequate reasoning to support the new rule and did not impermissibly apply economic considerations. The Oil and Gas Act allowed the commission to include economic considerations, and there was no indication that the economic considerations were the primary consideration for the new rule.246

5. New Mexico – T.H. McElvain Oil & Gas Limited Partnership v. Benson-Montin- Greer Drilling Corp., No. S-1-SC-34993, 2016 WL 6123936 (N.M. Oct. 20, 2016)

In this case, the successors to the grantors of a warranty deed collaterally challenged a 1948 quiet title action that negated the grantors’ oil and gas reservation. The reservation was held in a joint tenancy. After the district court ruled for the successors to the grantees, the court of appeals reversed. To the consternation of title lawyers across the state, the court of appeals held that the successor to the grantee that brought the 1948 quiet title action failed to exercise diligence and good faith to notify the surviving joint tenant, Mabel Wilson. This lack of notice violated Ms. Wilson’s due process rights by depriving her of her property.247

The New Mexico Supreme Court disagreed and reversed the court of appeals. As indicated on the face of the 1948 district court quiet title decision, the 1948 court had a verified complaint and sheriff’s return which indicated that the plaintiffs’ predecessors could not be located. Ms. Wilson’s address was not in any of the original deeds; she had changed her name and moved to San Diego; and she had not exercised any rights to ownership. Publication in a Farmington, New Mexico newspaper was therefore sufficient. The court stated, “Without evidence on the face of the quiet title judgment that the district court lacked jurisdiction, that judgment must be accorded finality in accordance with the reliance interests created as a consequence of the quieting of the title in its owner.”248

6. North Dakota – Fleck v. Missouri River Royalty Corporation, 872 N.W.2d 329 (N.D. 2015).

In this opinion issued in December, 2015, the North Dakota Supreme Court specifically addressed for the first time how production in paying quantities should be determined. In 1972, Fleck’s predecessors-in-interest executed an oil and gas lease with a ten year primary term and secondary term for so long thereafter as oil and gas was produced. The lease also included a cessation of production clause that provided the lease would not expire upon the cessation of production if the lessee resumed operations for drilling of a well or restored production within 90 days so long as production resulted. If these conditions were satisfied, then the clause would

245 Id. at 717. 246 Id. at 720-21. 247 See T.H. McElvain Oil & Gas Ltd. P’ship v. Benson-Montin-Greer Drilling Corp., 340 P.3d 1277 (N.M. Ct. App. 2015). 248 2016 WL 6123936 at *11. 49 continue the lease so long thereafter as production continued. Fleck presented evidence that the well posted a net loss of over $200 thousand from July 2010 through 2013.

In interpreting the lease, the district court did not require production in paying quantities or attempt to determine whether the well was producing in paying quantities. Instead, the district court granted summary judgment to the defendant lessees because the well consistently produced an average of a few barrels per day and any cessation of production was temporary. The North Dakota Supreme Court has held in the past that the term “production” in an oil and gas lease means “production in paying quantities,”249 so the district court clearly misapplied the law.250

The North Dakota Supreme Court has also held in the past that production in paying quantities is not determined by a simple analysis of profits and losses over a specific period of time, but that a reasonable time must be examined.251 After examining the relevant authority from other jurisdictions, the court adopted the test from the Texas case of Clifton v. Koontz,252 whereby a court must consider first, whether the well yielded a profit over operating costs over a reasonable period of time, and second, whether a reasonable and prudent operator would continue to operate the well in the manner in which the well was operated based on the facts and circumstances.253

Finally, the court concluded that the district court also erred in interpreting the cessation of production clause because the term “production” as used in that clause also means “production in paying quantities.” For the lease to remain in effect after operations for the drilling of a well or to restore production, if production results, it must continue in paying quantities. Because these were genuine issues of material fact, summary judgment was not appropriate, and the case was remanded to the district court for further proceedings.254

7. North Dakota – Vogel v. Marathon Oil Company, 879 N.W.2d 471 (N.D. 2016).

Vogel brought claims against Marathon Oil Company (“Marathon”) for failing to pay royalties on associated gas that was flared by Marathon in violation of Section 38-08-06.4 of the North Dakota Century Code. That statute allows flaring of gas produced from an oil well for only one year from first production unless an exemption is obtained from the North Dakota Industrial Commission. The statute also requires a producer to pay royalties on gas flared in violation of the section. The commission may enforce the section and determine the royalties owed, and the section specifically states that the commission’s determination is final.255

To bring these claims, Vogel argued that Chapter 38-08 provided Vogel an implied private right of action, or alternatively, that she could bring her action under the North Dakota Environmental Law Enforcement Act of 1975,256 or that she made out common law claims of

249 See Tank v. Citation Oil & Gas Corp., 848 N.W.2d 691 (N.D. 2014). 250 872 N.W.2d at 333. 251 Sorum v. Schwartz, 411 N.W.2d 652, 654 (N.D. 1987). 252 325 S.W.2d 684, 690-91 (Tex. 1959). 253 872 N.W.2d at 335. 254 Id. at 335-36. 255 N.D. CENT. CODE § 38-08-06.4. 256 Id., ch. 32-40. 50 conversion and waste. The district court dismissed her claims without prejudice and the North Dakota Supreme Court affirmed.

Chapter 38-08 itself implied no private right of action. Although the plaintiff arguably was in the class of persons for whose benefit the statute was enacted, there was nothing in the language of the chapter indicating the legislature intended a right of action for damages. A royalty owner may petition the commission for a determination of royalties on gas flared. The commission must then set a date for a hearing and enter an order within thirty days after the hearing.257 This comprehensive regulatory scheme was strong evidence that the legislature did not intend to provide private remedies for damages because it provided administrative remedies.258 The statute also provides for injunctive relief if the commission fails to act, another indicator that the legislature did not intend to provide a private right of action for damages.259

In its first interpretation of the North Dakota Environmental Law Enforcement Act of 1975 (the “ELEA”),260 the majority also held that the ELEA did not allow Vogel to circumvent the commission by bringing her claims directly in court. The ELEA expressly states that “any person . . . aggrieved by the violation of any environmental statute . . . may bring an action in the appropriate district court . . . to enforce such statute.”261 The majority agreed that Section 38-08- 06.4, the flaring statute, was an environmental statute. It also agreed that the ELEA remedies were cumulative and did not replace statutory or common law remedies, but it nevertheless held that these “cumulative” remedies may not be pursued unless the commission failed or refused to act.262

The majority also held that the district court properly dismissed Vogel’s common law claims. As Section 38-08-06.4 created a statutory right to royalties, it replaced common law claims for royalties on flared gas. The court noted that the statute only mandated royalties on flared gas after the first year, potentially conflicting with any right a royalty owner might have had to royalties on flared gas under the common law. Because two contradictory rules of law on the same subject are precluded, the majority reasoned that the statute alone governed claims for royalties on flared gas.263 Ultimately, the majority held that Vogel was required to exhaust her administrative remedies before the commission before she could pursue her claims in court.264

Chief Justice Vande Walle filed a concurring opinion, concurring in the result but questioning the implications of the majority opinion. As Justice Vande Walle pointed out, royalties are a matter of contract under the lease between the lessor and the lessee. Nothing in the record indicated whether Vogel was a mineral lessee of Anadarko, but if an obligation could be shown under a lease to pay royalties, Justice Vande Walle would not require a plaintiff to go through the commission before bringing a claim in court for breach of the lease. Further, Section 38-08-06.4 states that the determination of the commission is final, but the majority never

257 N.D. CENT. CODE § 38-08-11(4). 258 879 N.W.2d at 478. 259 Id. (citing N.D. CENT. CODE § 38-08-17(2)). 260 N.D. CENT. CODE ch. 32-40. 261 Id. § 32-40-06. 262 879 N.W.2d at 481-82. 263 Id. at 482-83. 264 Id. at 495. 51 explains what determination is final—the value of the flared gas for payment of royalty or the decision of the commission to enforce the Section?265

Finally, Justice Kapsner dissented, focusing on the ELEA. The ELEA was enacted to ensure enforcement of environmental laws even when agencies do not act. As she explained, “It makes little sense under the ELEA to require the party aggrieved by such dereliction of duty to first exhaust remedies before the agency that may have allowed a violation to persist, especially when that agency may be the agency the plaintiff is suing.”266 She also questioned the majority’s understanding of the nature of a cumulative remedy, which is a remedy in addition to another available remedy, rather than a remedy that may be pursued only after other remedies are exhausted.267 The ELEA was intended to give a private enforcement mechanism to citizens where agencies lack resources for enforcement, and this is just the type of case that the ELEA was intended to address.

8. Oklahoma – American Natural Resources, LLC v. Eagle Rock Energy Partners, L.P., 374 P.3d 766 (Okla. 2016).

In 2005, the predecessor in interest of the defendants entered into a letter agreement regarding the development of an area of mutual interest (“AMI”) with American Natural Resources, LLC (“ANR”). The AMI granted ANR the right to participate with a twenty-five percent working interest in all future wells within the AMI. After the defendants drilled and completed 17 wells in the AMI without allowing ANR to participate, ANR sued. The district court agreed with the defendants that the AMI violated the rule against perpetuities and granted defendants’ motion to dismiss. The court of appeals reversed in part, and the defendants filed a petition for certiorari.

Article II, Section 32 of the Oklahoma Constitution provides that perpetuities shall never be allowed,268 which the Oklahoma Supreme Court has interpreted as adopting the common law rule against perpetuities. 269 ANR argued that the rule was inapplicable under the court’s decision in Producers Oil Co. v. Gore,270 while the defendants argued that the court’s earlier decision in Melcher v. Camp271 required the rule’s application.

Producers Oil involved a preemptive rights provision in a joint operating agreement (“JOA”), whereas Melcher involved a separate right of first refusal agreement that gave a lessee the option to acquire on the same terms any lease that was offered to the lessor. In Producers Oil, the court distinguished the option in Melcher. In Melcher, the right applied to previously unleased property that might in the future be leased by the lessee, and only one party held a preemptive right. By contrast, in Producers Oil, the preemptive right lasted only so long as the JOA remained in effect, which would terminate when the lease underlying the operating agreement terminated.

265 Id. at 485-86. 266 Id. at 489. 267 Id. at 489-90. 268 OKLA. CONST., art. II, § 32. 269 Melcher v. Camp, 435 P.2d 107, 111 (Okla. 1967). 270 610 P.2d 772 (Okla. 1980). 271 435 P.2d 107 (Okla. 1967). 52

In the instant case, the court determined the option was more akin to the Melcher option than the Producers option. The court thought it material that the option was part of a separate agreement and not part of a JOA, and that the option did not expire when an existing lease expired, but continued in perpetuity when new leases were executed with new wells drilled thereon.272

In the author’s view, the rule should not apply to commercial transactions at all consistent with the reasoning in dicta of the Colorado Supreme Court in Atlantic Richfield Company v. Whiting Oil and Gas Corporation.273 The rule was designed to restrict donative family transfers, not commercial transactions. Further, the term “lives in being” has no application to commercial transactions involving entities. The Restatement (Third) of Property: Servitudes also takes the view that commercial options and rights of first refusal should not be subject to the draconian rule,274 as does the Uniform Statutory Rule Against Perpetuities, because it “is a wholly inappropriate instrument of social policy to use as a control over such arrangements.” 275

ANR further argued that as a limited liability company it could be a life in being for purposes of the rule, but the court disagreed. Although a corporation can be a “person,” it was not a life in being under the common law rule. On this point, the court followed Melcher that where there is no measurable life in being, the only definite period is a term not exceeding 21 years.276

272 374 P.3d at 770. 273 320 P.3d 1179, 1185-1186 (Colo. 2014). 274 RESTATEMENT (THIRD), PROP: SERVITUDES § 3.3 (200). 275 UNIF. STATUTORY RULE AGAINST PERPETUITIES § 4, 8B U.L.A. 279, 280 cmt. A (2001). 276 3745 P.3d at 771 (quoting Melcher, 435 P.2d at 111). 53