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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.
2
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).
3
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).
4
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).
5
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).
6
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”).
7
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 Networks28
a 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].
8
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.
9
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.
10
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).
11
. . . [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).
12
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.
13
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.
14
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.
15
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).
16
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).
17
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.
18
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.
19
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.).
20
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.
21
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.
22
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.
23
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)).
24
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).
25
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.
26
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.
27
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).
28
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.
29
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.
30
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.
31
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)).
32
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).
33
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.
34
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.
35
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.
36
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).
37
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.
38
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.
39
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.
40
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).
41
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.
42
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.
43
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).
44
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.
45
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.
46
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.
47
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.
48
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.
49
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.
50
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.
51
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.
52
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).
53
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).
