Co-author Carolina Cuppetilli*Today we will skip our usual routine of explaining how court rulings on the question of the day might affect your interests. Instead we will discuss the fallout from abysmal document drafting. In Rosetta Resources Operating v. Martin, the Supreme Court of Texas cautioned that an express covenant to protect against
Co-author David LeonardIf perpetuation of a mineral lease beyond the primary term is contingent upon continuous operations, do traditional notions of “production in paying quantities” always matter? Spoiler: No.
In Thistle Creek Ranch, LLC v. Ironroc Energy Partners, LLC, an appellate court affirmed partial summary judgment in favor of lessee Ironroc Energy Partners under these odd clauses in the Kettler lease.
The habendum clause:
Unless sooner terminated … this lease shall remain in force for a term of three (3) years from the date hereof, hereinafter called “primary term,” and as long thereafter as operations, hereinafter defined, are conducted upon said land with no cessation for more than ninety (90) consecutive days.
The lease defined “operations” as:
“ … any of the following: drilling, testing, completing, reworking, recompleting, deepening, plugging back or repairing of a well in search for or in any endeavor to obtain production of oil [or] gas, … production of oil [or] gas, … whether or not in paying quantities.
The oddity, of course, is that the lease could be perpetuated by operations, whether or not there was production in paying quantities.
Continue Reading Lease Perpetuated Beyond Primary Term Without Production in Paying Quantities
Co-author Julia EdwardsThis “most-favored-nations” clause in three oil and gas leases on land in LaSalle County, Texas, was at issue in EP Energy E&P Co., L.P. v. Storey Minerals, Ltd.:
If … the lessee … acquires an Oil and Gas Lease [on certain lands] on such terms that the … bonus … [is] greater than th[at] provided to be paid to lessor hereunder, lessee … agrees that it will execute an amendment to this lease, effective as of the date of the third party lease on the leased premises, to provide that the lessor hereunder shall receive thereafter the same percentage (per net mineral acre) … bonus … as any subsequent lessor of the leased premises to the extent that such … bonus … [is] greater than those provided to be paid herein. … “
In the end, as a result of lessee EP’s subsequent leases lessors (MSP) were entitled to increased bonuses on leases from the time prior to execution of the triggering lease. Once again, a court applied the plain, ordinary, and generally accepted meaning of the contract.
Continue Reading Most-Favored-Nations Clause Costs Lessee
Co-author Brittany BlakeyZehentbauer Family Land, LP v. TotalEnergies E&P USA, Inc. is a story we’ve heard before: Royalty owners contend they are not getting a big enough slice of the hydrocarbon pie, which presents a question courts must answer: Where is the valuation point for royalty calculation?
Under the oil and gas leases at issue, royalties are to be paid:
“based upon the gross proceeds paid to Lessee for the gas marketed and used off the leased premises, including casinghead gas or other gaseous substance… computed at the wellhead from the sale of such gas substances so sold by Lessee.”
The midstream arrangements and the “netback method”
Chesapeake and Total sell their production at the wellhead to their respective midstream affiliates, CEMLLC and TGPNA, each of which sells the transported product to unaffiliated downstream companies. The affiliates account for the gas using the “netback” method, which “takes a weighted average of prices at which the midstream affiliates sell the oil and gas at various downstream locations and adjusts for the midstream company’s [various costs (including transportation)] to move the raw oil and gas from the wellhead to downstream resale locations.” The netback method accounts for these midstream (post-production) costs. The midstream affiliates pay this reduced amount to the producers, who use this netback price as the base for calculating the plaintiffs’ royalty payments.
Continue Reading Ohio Royalty Owners Burdened with Post-Production Costs
Co-author Brittany BlakeyIn Texas, what happens to an obligation to bury pipelines when, after creation of the obligation, the surface and minerals are severed? Henry v. Smith explains.
Henry et al own the surface estate of the Camp Creek Ranch, a 15,000-acre tract in Archer County. Smith et al are lessees in three oil
Co-author Brittany BlakeyFirst, a word for you scriveners: Preserve your reputation and the honor of your law school writing instructor by preparing clear and understandable contracts. Then your handiwork won’t be disparaged as “opaquely worded” “cryptic language”, suffering from “lack of accuracy and lack of clarity”, and “containing grammatical and logical errors”, as in
How many different meanings can parties attribute to a term in an oil and gas lease? Answer: As many as they want, but the court will only use one, says King Operating et al v. Double Eagle Andrews, LLC et al.
The facts
The Robisons own 50% of the minerals in Tract 1, and 100%
In resolving a dispute over post-production cost deductions from oil and gas royalties (PPC’s), the court in Shirlaine West Properties Ltd et al v. Jamestown Resources, LLC and Total E&P USA, Inc. opined that the case ” … is yet another episode in the endless struggle in the oil and gas context between lessors and lessees in the allocation of [PPC’s] in the calculation of royalty payments.”
Takeaway
Was the lessor’s gas royalty burdened by PPC’s? Yes. The market value royalty clause unambiguously fixed the wellhead as the valuation point for royalty calculation.
The royalty clause
The lessor did its best to be free of PPCs:
Continue Reading Another Post-Production Cost Decision in Texas
Co-author Brittany Blakey
When the form contract says one thing and the addendum says another, which one would you expect to prevail?
The central issue in Tier 1 Resources Partners v. Delaware Basin Resources, LLC was whether one tract that was subject to several identical leases automatically terminated at the end of the primary term. The answer to the question turned on the aforementioned choice.
The leases
The Bush lessors leased Sections 6 and 2, in Reeves County, Texas, to DBR. The leases were made of two parts: a 10-paragraph “Producers 88” form and an 11-paragraph addendum. The interplay between the Producers 88 and the addendum caused disagreement among the parties.
Paragraph 1 defined the land covered by the lease as “said land,” which expressly included Section 6 and Section 2. The habendum clause established a three-year primary term. Upon lease expiration, DBR’s interest would automatically terminate as to all lands and depths except those designated to be within a production unit. DBR could save the lease from automatic termination by conducting a continuous drilling program per the lease specifications.
The lessee’s problem
Continue Reading Addendum Prevails over Form … Again
In Emerald Land Corp. v. Trimont Energy (BL) LLC, a Louisiana federal court considered whether a lessee was required to remove flowlines buried beneath the surface and canal bottoms of property subject to mineral leases.
What the leases said
Each of three leases granted to lessee Chevron the exclusive right to construct lines, tanks, storage facilities, and other structures necessary “to produce, save, take, care of treat and transport” oil and gas products. All three had identical damages provisions: “Lessee shall pay all damages caused by its operations hereunder to the land, buildings and improvements presently existing… [.]” Chevron contended that the granting language included the express right to install buried flowlines in connection with its activities. No provision expressly required restoration of the land by removing buried flowlines or paying the cost of removal.
Addressing lease terms and Castex
Relying on the lease terms and Terrebonne Parish School Board v. Castex Energy, Inc., Chevron differentiated between buried flowlines (buried below “plow depth”, which here was at least three feet) from surface flowlines, alleging that buried lines did not cause damage to the land. Chevron admitted it had to remove the surface lines.
Emerald distinguished Castex arguing that, unlike the canals dredged on the property in that case, these flowlines were foreign equipment attached and buried on the property. Therefore, Chevron was obligated to remove the lines as part of its obligation to restore the land to its original condition minus normal “wear and tear.” Emerald also pointed to evidence showing that buried flowlines were exposed at the surface of the property and, presumably, created a hazard.
Continue Reading Louisiana Court Considers Buried and Surface Flowlines