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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:

  • Royalty on gas was 25% of “ … market value at the point of sale, use or other disposition …
  • … to be determined “ … at the specified location and by reference to the gross heating value …”.
  • “The market value used in the calculation … shall never be less than the total proceeds received by Lessee in connection with a sale, use or other disposition … “.
  • Royalty “ … shall be free and clear of all costs and expenses whatsoever, except ad valorem and production taxes.”
  • … [N]otwithstanding any language herein to the contrary, all oil, gas or other proceeds accruing to Lessor … shall be without deduction for [PPC’s] …  and costs resulting in enhancing the value could be deducted ” … but in no event would Lessor receive a price lower than or more than the price received by Lessee.”
  • If Lessee realized proceeds after deduction for PPC’s “ … the proportionate part of such deductions shall be added to the total proceeds received by Lessee … . “.
  • Heritage Resources v. NationsBank would have no application.

Continue Reading Another Post-Production Cost Decision in Texas

Co-author Brittany Blakey

Ammonite Oil and Gas Corporation v. Railroad Commission of Texas illustrates the difficulties faced by lessees attempting to force-pool a tract under the Mineral Interest Pooling Act.  In this case, the applicant Ammonite failed to make a “fair and reasonable offer” to voluntarily pool before applying to the Railroad Commission.

Facts

Ammonite held a lease from the State of Texas covering riverbed acreage in the Eagle Ford Shale. EOG drilled 16 wells on adjacent tracts on both sides of Ammonite’s tract. Ammonite offered to voluntarily pool its acreage with EOG’s. EOG rejected the offer, and Ammonite applied to the Commission to force-pool its tract pursuant to the Mineral Interest Pooling Act.

The Commission dismissed Ammonite’s applications based on several findings of fact and conclusions of law, but the primary conclusion at issue was that Ammonite failed to make a “fair and reasonable offer” to voluntarily pool as required by the MIPA.

Question: Were Ammonite’s voluntary pooling offers fair and reasonable?

Answer: No.

Reasoning:

For the Commission to approve a MIPA application, the mineral owner must meet one of the three statutory requirements by establishing that proposed force-pooled units would:

  • avoid the drilling of unnecessary wells,
  • protect correlative rights, or
  • prevent waste.

The “fair and reasonable offer” test

A “fair and reasonable offer” is a precondition to any forced-pooling application under MIPA. If the applicant fails to meet that test, the Commission lacks jurisdiction over the application and must dismiss it. Because the MIPA does not define “fair and reasonable” the Commission is given great deference and discretion in interpreting that standard in each case. The fairness and reasonableness of the pooling offer is judged from the viewpoint of the party being asked to pool.

The Commission’s dismissal of the application was based on its factual findings that:

  • Ammonite failed to provide survey data or a metes and bounds description to establish the precise acreage to be pooled;
  • None of the 16 EOG wells produce from or drain Ammonite’s riverbed tracts; and
  • Ammonite’s proposed 10 percent charge for risk was unreasonably low because a large resource play like the Eagle Ford requires an investment in large amounts of acreage and the drilling of a significant number of wells in order to be commercially successful, not just drilling one well in a single unit. Expert testimony, which was accepted, explained that a 100 percent charge for risk would be appropriate.

Your musical interlude.

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

Co-author Brittany Blakey

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

Co-author Brittany Blakey

Here we go  again, in Gary and Theresa Poenisch Family Ltd. P’Ship v. TMH Land Servs., Inc., learning that a purported Texas land transaction will not be enforced if the parties fail to comply with the Statute of Frauds.

Poenisch and TMH, among others, jointly owned an overriding royalty interest in the Wiatrek oil and gas lease. The lease became the subject of a lawsuit, and litigant GulfTex could settle if all of the overriding royalty owners agreed it could buy down their overrides. Poenisch was the only holdout. Poenisch did not want its override to decrease and sought to acquire TMH’s share.

TMH was open to the deal, and the following email correspondence ensued:

  • President of TMH emails to selling overriding royalty owners’ attorney Butler: “Pursuant to my conversation with [override owners’ spokesperson], I will sell my retained ORR in the Gulftex proposed 300+ acre unit for $20,000.” (emphasis added).
  • Butler via email to Poenisch: Asks for confirmation of the agreement.
  • Poenisch’s attorney to Butler: “We have a deal.”
  • Poenisch’s attorney to Butler: [I] “will draft up the Ellerbe assignment of [override] and send your way for review.”

Poenisch’s attorney never sends the draft, and no further steps are taken to consummate the transaction.

A year later Poenisch sends a letter to TMH seeking to enforce the email chain as a binding contract and asks TMH to sell its override for $20,000. TMH refuses, and Poenisch sues for specific performance. The trial court determines that the contract did not contain a legal property description sufficient to satisfy the Statute of Frauds. The court of appeals affirms the trial court’s Judgment.

Why did the suit fail?

In Texas, the Statute of Frauds requires a contract for the sale of real property (such as an overriding royalty) to be:

  • in writing,
  • signed by the person to be charged, and
  • a sufficient legal property description, such as the lease from which the override stems. The described property must be identified with “reasonable certainty”.

The only description of the property in the alleged contract was the bold portion of the email. Poenisch argued that the property described in the email could be identified with reasonable certainty when read with extrinsic evidence. The court disagreed.

  • The “descriptive language used in this email is vitally lacking in definitiveness.”
  • There must be a “key or nucleus” property description before extrinsic evidence can be introduced to identify the property with reasonable certainty.
  • Extrinsic evidence may be used only for the purpose of identifying the property with reasonable certainty from the data contained in the contract, not for the purpose of supplying the location or description of the property.

The purported contract contained an inadequate property description and the Statute of Frauds precluded Poenisch’s claims as a matter of law.

Your rmusical interlude (George was always undervalued)

Coauthors Sahrish K. Soleja and Lydia Webb

If you are a royalty owner and have questions about how your claim is likely to be treated when your lessee/operator goes into bankruptcy in Delaware, In re MTE Holdings LLC is a significant case.

Historically, royalty claims have been treated as funds placed in trust because they are not the property of the debtor’s bankruptcy estate – meaning royalty claims are not subject to the bankruptcy claims process altogether. However, in this recent decision a Delaware bankruptcy court, applying Texas law, held that royalty claims were in fact subject to the bankruptcy claims process and moreover, should be classified as unsecured, not secured, claims.

The dispute

In MTE, the debtors, operators of oil and gas wells, were lessees in several hundred oil and gas leases in Texas.  Under the leases the lessee would sell the production and distribute to each royalty owner its share of the proceeds.  Here, the debtors refused to pay proceeds to royalty owners in the ordinary course during the bankruptcy, the typical treatment for trust funds, because they lacked the funds to do so. This left the royalty owners with no choice but to assert the right to payment from the bankruptcy estate, secured by their interest in the oil and gas in place.  The question before the court was whether the royalty owner claims should be classified as secured or unsecured.  The answer means the difference between receiving payment in full (for secured claims) vs. pennies on the dollar (for unsecured claims).

The First Purchaser Statute

Looking at the statutory language of Section 9.343(a) of the Texas Business and Commerce Code, commonly referred to as the Texas First Purchaser Statute, the court held that the statutory lien created by Section 9.343(a) secures only an obligation to pay the first purchaser of produced oil and gas.  Meaning, a statutory lien was created for royalty claimants who took their production in-kind and turned around and sold it.  On the contrary, royalty owners who receive payment in cash do not receive the benefit of Section 9.343(a).  In MTE, none of the royalty claimants had exercised their option to receive payment in kind and thus could not claim secured status. This is, of course, the case with virtually all Texas royalty owners.  Because there was little to no money to pay unsecured claims, the royalty claims were effectively rendered worthless by the Delaware bankruptcy court.

Help has arrived

Some help for Texas royalty owners (but too late for the  MTE claimants) is on the way. Section 9.343(a) was repealed by the 2021 Texas legislature and replaced by a new statute, Section 67.002(a)-(c), effective Sept. 1, 2021, the Texas First Purchaser Lien Act. The new statute creates a real prooperty lien on hydrocarbons before they are extracted from the land. Whether royalty owners elect to take payment in kind or in cash, they will have a valid and enforceable lien against the debtor/operator.  But the larger concern is the Delaware bankruptcy court’s willingness to look past whether royalty claims should be subject to the bankruptcy process at all.

Your musical interlude.

Co-author Brittany Blakey

Let’s begin with a question: Master service agreements (“MSA’s” in the trade), once agreed upon, often remain in force for years. As time passes and circumstances change, the parties amend, sometimes losing sight of the original details. Was Stingray Pressure Pumping, LLC v. In re Gulfport Energy Corporation the result of forgetfulness or merely a Hail-Mary to avoid liability?

The MSA and amendments

Stingray Pressure Pumping and Gulfport Energy entered into an MSA for oilfield fracing services in 2013. The parties amended the MSA in January and July 2016, adding Gulfport Buckeye (now Gulfport Appalachia) as a party in the July amendment. The MSA was amended for the third time in 2018 to extend the term until the end of 2021.  That amendment was only signed by the original parties, not Gulfport Appalachia.

The litigation

In December 2019, Gulfport Energy sued Stingray in Delaware state court for breach of contract. Stingray countersued. In November 2020 Gulfport Energy and its wholly owned subsidiarie Gulfport Appalachia filed for bankruptcy in the Southern District of Texas. A dispute arose about whether Gulfport Appalachia remained a party to the MSA after the 2018 amendment. After reviewing the original agreement and the three amendments, the bankruptcy court held that Gulfport Appalachia was not liable under the MSA after September 30, 2018, the day the agreement would have ended without the 2018 amendment. Stingray appealed to the district court.

Gulfport Energy argued that Gulfport Appalachia was not liable after September 2018 because it was not a party to the July 2018 amendment that extended the MSA. Among other facts, it pointed out that the amendment did not explicitly include Gulfport Appalachia in the identification of the parties, and there was no signature block for Gulfport Appalachia.

The district court reverses

The district court disagreed. There was only one MSA – one that incorporated all of its amendments. The July 2016 amendment explicitly added Gulfport Appalachia to the definition of “Company” – as was required by the agreement in order to amend. Beyond that date, Gulfport Energy and Gulfport Appalachia both represented the “Company” as a party to the agreement. Without an explicit amendment in the 2018 amendment removing Gulfport Appalachia from the definition of the “Company”, it remained as a party to the agreement and was bound by the 2018 amendment. Additionally, the MSA did not require that all entities sign—just a signature for the “Company” and a signature for the “Contractor”. The 2018 amendment was signed by a “Company” representative and a “Contractor” representative, so it bound all.

Practice tip: Was the amendment flawed or was the challenge made on 4th and 25?

It’s a trick question. The answer can’t be discerned with certainty from the two-page opinion. The point for scriveners: Don’t forget the original terms when amending an old agreement.

Your musical interlude

Co-author Brittany Blakey

Sometimes writing too many alternatives into an oil and gas lease invites confusion … which provokes litigation … which results in disappointment for somebody … or everybody.

For example, the central issue in Vermillion FC, LP v. 1776 Energy Partners, LLC was the effect of a well-tract designation pursuant to a retained acreage provision. The parties entered into an oil and gas lease covering approximately 1100 acres in Zavala County Lessee 1776 Energy commenced drilling a horizontal oil well, the Byrd Ranch No. 1H, and began production, designated a 320-acre well tract, and notified Vermillion.

The parties spent the next three years fighting over whether 1776 Energy breached the lease by, among other things, retaining excess acreage in the well tract and untimely releasing non-retained acreage.

Vermillion sued for breach of contract and other claims. Both parties moved for partial summary judgment. Vermillion argued that the 1776 Energy’s 320-acre well tract should have been 40 acres and that the lease terminated as to all other acreage.  Specifically, Vermillion argued that the retained acreage clause required the well tract to have as few acres as possible for actual production.

The trial court granted Vermillion’s motion and denied 1776 Energy’s.

The clause (we are paraphrasing) defined the well tract as the “minimum number of acres” “producing in paying quantities”, but was qualified by

  • … which pursuant to the applicable field rules provides or permits for creation of an allowable sufficient to cover actual production;
  • … but was expressly limited of 80 acres plus the length of the horizontal well bore plus 330 feet on either side thereof; and
  • … notwithstanding the above, to the extent the Railroad Commission’s field rules provided for additional acreage, the rules would control.

After examining the field rules and the express language of the lease, the court of appeals concluded that 1776 Energy was entitled to retain 280 acres with respect to the well—not 40 acres as Vermillion argued or the 320 acres 1776 Energy wanted. The court distinguished this case from Endeavor Energy Resources v. Discovery Operating and XOG Operating v. Chesapeake Exploration by emphasizing the Supreme Court’s holdings that a retained acreage clause must be construed on its own language under governing principles of contract interpretation. Also, Endeavor and XOG involved vertical wells, not horizontals.

Concluding that the Byrd Ranch No. 1H Well retained 280 acres rather than 320, the court reversed and remanded. The additional 40 acres automatically terminated at the end of the primary term.  1776 Energy breached the lease by failing to release the 40 acres.

Your musical interlude.

Coach Eaux congratulates the Tigers for reading Energy and the Law

Resistance was futile for defendants opposing a temporary injunction sought by a party armed with a FERC Certificate of Public Convenience and Necessity that includes condemnation rights under the Natural Gas Act. In Venture Global Gator Express v. Land et al., Venture Global sought to condemn land in Plaquemines Parish, Louisiana, and a preliminary injunction for immediate possession of the property.

The NGA requires that the party seeking to condemn be unable to acquire the property by contract or unable to agree on compensation to be paid. Defendants, Capt. Zack’s Myrtle Grove Properties and ESB Louisiana Opportunities (who held an Option to acquire certain rights) challenged the characterization of a portion of the proposed servitude as temporary instead of permanent and accused Venture Global of not negotiating in good faith.

The right to condemn Continue Reading Louisiana Federal Court Allows Injunctive Relief Under FERC Certificate of Public Convenience and Necessity

Co-author Marcus Fettinger

Under the Fair Labor Standards Act, what is required for an employee to be exempt from overtime pay? Ordinarily, it’s a guaranteed minimum salary. As the Department of Labor has explained, being paid on a “salary basis” means an employee regularly receives a predetermined amount of compensation each pay period on a weekly, or less frequent, basis. The predetermined salary cannot be reduced because of variations in the quality or quantity of the employee’s work.

That seems straightforward, but it took the Fifth Circuit three rounds of deliberations to nail it down. The entire panel of the Court recently reconsidered a 2020 opinion in Hewitt v. Helix Energy Solutions Group, Inc. In its majority opinion, 12 of the 18 judges held that a daily rate can qualify as a salary if, and only if, the employer pays a minimum of $684 per week regardless of the amount that the employee works and a “reasonable relationship” exists between the minimum salary and the total amount paid. Continue Reading Fifth Circuit Tells the Oil Patch That a Day Rate is Not a Salary