Like wild mushrooms after a warm summer rain, and undaunted by the COVIDs, the fraudsters, the grifters, and the “the spawn of the Devil’s own strumpet”* were prolific before meeting the wrath of the courts and the regulators in 2021. This year features several potential lifetime achievement awards for recidivism.

Corruption Goes Nuclear

Perps: Former Ohio Speaker of the House Larry Householder and utility First Energy, beneficiary of a $1.3 billion state bailout of the state’s nuclear energy industry.

Crime: Householder was indicted on racketeering and conspiracy charges for taking bribes from FirstEnergy. Others were charged for crimes.

How they did it: The utility paid $56.6 million to an outfit called Generation Now who allegedly siphoned it off to Householder and the others. The money came from customers of First Energy’s distribution and transmission units.

Sentences: Plenty but none yet to the calaboose. Householder’s trial date is coming up. Republicans and Democrats together expelled him from the House; First Energy CEO Charles Jones was fired; two others pled guilty; a lobbyist committed suicide; First Energy was fined $230MM and entered into a deferred prosecution agreement.

The big picture: Forbes’ Ken Silverstein predicts that it will jar an industry that is perpetually trying to regain its balance after much bad publicity. Plus, high capital costs for construction and cheap shale gas have curtailed nuclear development, presenting a problem for the environment. Example: When Southern California Edison closed its San Onofre nuclear station in 2013 CO2 emissions jumped by 35% (That’s green California for you). Factoid: 96 nuclear reactors in 29 states supply about 20% of the country’s electricity and 55% of the carbon free power.

Don’t you know his mother was disappointed


Perp: Mark Plummer, host of the ironically-named Dallas radio show “Smart Oil and Gas”. Continue Reading 2021’s Bad Guys in Energy

Co-author Brittany Blakey

In 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 and gas leases. At the time the leases were executed the original lessors owned both surface and minerals. Each lease contains special surface covenants, including a requirement that the lessee to bury flowlines and pipelines to a certain depth at the lessor’s request.

Eventually, the mineral estates became severed from the surface. After purhasing the surface,  Henry et al requested that the lessees bury all flow lines pursuant to the covenants.

Lessees refused, taking the position that Henry et al could not enforce the covenants because the covenants had been detached from the surface estate through the mineral reservations (i.e, the covenants do not belong to the surface owners). Henry et al sued to enforce the covenants or, alternatively, recover damages for their breach.

The question

Were the surface covenants conveyed with the surface estates or reserved to the mineral estates (plural; at inception of the leases there were three different tracts).

The answer

Surface owners win. Because a pipeline burial covenant is “attached to the surface” it generally runs with the land and is conveyed through a deed. To deviate from the general rule, the deed must contain a reservation or exception that expressly reserves or detaches the burial covenant. The court will not infer a reservation by implication.

The court observed that the mineral reservations in the deeds from the previous owners to Henry et al did not mention the surface estates or surface covenants. And there were no express words revealing an intent by the grantors to detach the surface covenants from the surface estates. Therefore, because there was no reservation of the surface covenants, the deeds conveyed the covenants to Henry et al.  The trial court’s decision in favor of the lessees was reversed and the case remanded to the trial court.

The dead cow and injunctive relief

The surface owners alleged that the lessees’ actions constituted a nuisance, were negligent, and violated the Texas Natural Resources Code and the National Electric Code (who knew there was such a thing). The result was the electrocution of a cow, so innocent, not yet on its journey to the charnel house, and without doubt a prize cow and a credit to bovines everywhere.

The evidence was mixed. The standard for review of an injunction ruling is abuse of discretion. The appellate court declined to second-guess the trial court’s refusal to grant injunctive relief.

Sandra Jaffe, co-founder of Preservation Hall,  RIP.

Co-author Brittany Blakey

First, 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 the case of an oil and gas lease considered in Martin v. Rosetta Resources Operating, LP. The Texas Supreme Court has granted petition to review the decision.

The issue

Did the offset well clause impose a general duty on the lessee to protect against all drainage, even when the draining well itself did not trigger a duty?

The leases

The Martins entered into a series of leases, all of which had this provision:

“ …  in the event a well is drilled on or in a unit containing part of this acreage or is drilled on acreage adjoining this Lease, the Lessor [sic], or its agent(s) shall protect the Lessee’s [sic] undrilled acreage from drainage and in the opinions of reasonable and prudent operations, drainage is occurring on the un-drilled acreage, even though the draining well is located over three hundred thirty (330) feet from the un-drilled acreage, the Lessee shall spud an offset well on said un-drilled acreage or on a unit containing said acreage within twelve (12) months from the date the drainage began or release the acreage which is un-drilled or is not a part of a unit which is held by production.”

Lessee Rosetta and other operators formed a pooled unit containing a portion of the Martin acreage and drilled the Martin Well. Those parties later drilled the Simmons well 1.5 miles away on a separate, nonadjacent unit. The Martins sued Rosetta and others alleging several theories, including breach of contract for failing to protect the undrilled leased acreage from drainage by the Simmons well.

The result

The theory argued by the Martins at the trial court was that by drilling the Martin well (not the Simmons, read the clause), Rosetta triggered a general duty to protect against drainage, including from the Simmons well. The trial court ruled for Rosetta, holding that the Simmons well did not trigger a contractual duty to protect against drainage because the Simmons well was not on acreage adjoining the Martin lease.

The court of appeals reversed and remanded. A general duty to protect the Martins’ undrilled acreage against all drainage was triggered when Rosetta drilled the Martin well. There was no dispute that there was drainage, prompting the court to require Rosetta to spud an offset well or else release the undrilled acreage.

In its petition to the Supreme Court, Rosetta argues that the general duty to protect against all drainage as found by the court of appeals defied the lease’s offset production clause and imposed an “onerous burden” on the lessee. The duty to protect was limited to drainage caused by the well triggering the duty.

It will be interesting to see how our Supreme Court addresses the odd and illogical lease language in light of its policy to interpret agreements according to the words the parties actually said, not on what the parties could have said.

Trial lawyers, read pp 4-5 discussing why the Martins’ new argument was not barred by res judicata.

Your musical interludes. RIP Michael Nesmith (Gotcha! You were thinking Monkees) … and some Christmas.

Co-author Brittany Blakey

The Texas Supreme Court has granted petition for review of a 2019 decision in Dyer et al v. Texas Commission on Environmental Quality . At issue is whether rescission of a Railroad Commission no-harm letter before the TCEQ granted an injection-well permit rendered the permit void.

The Injection Well Act (Chapter 27 of the Texas Water Code) governs the permitting process for underground injection wells in Texas. The Act aims to maintain the quality of fresh water for the public and existing industries while trying to prevent injections that may pollute fresh water. Under the Act, a company seeking to construct and operate an injection well must apply to the TCEQ for a permit. The applicant must also provide a “no-harm” letter from the RRC stating that the injection well will not damage an existing oil or gas reservoir.

I’m an oil and gas guy. Why does this order concern me?

This case is about injection wells for industrial and municipal waste, not for oil and gas waste. But the court’s treatment of the Administrative Procedures Act and the effect of (dueling?) orders of state agencies could inform future actions and orders of both agencies.

The long and complicated timeline Continue Reading Texas Supreme Court to Review Approval of Injection Well Permit

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% of the minerals in Tracts 2, 3 and 4 in Scurry County, Texas. They do not own the executive rights in Tract 1. They signed the Robison lease in 2008. In 2015 the Williamses signed the Williams lease on Tract 1 with DEA. In 2016 the Robisons signed a lease with DEA for Tracts 2 and 3, and a lease with MEI in Tract 4. King/LaRoca drilled a producing well under the Robison lease on Tract 1. There were no operations on Tracts 2, 3 and 4.

DEA sued, claiming a superior right to title to the minerals in Tracts 2 and 3 on the basis that the Robison Lease had expired after the end of the primary term.  (MEI made the same claims to Tract 4).  DEA and MEI asserted that their leases were the valid leases on Tracts 2, 3 and 4. King/LaRoca counterclaimed alleging that Tracts 2, 3 and 4 were maintained by the well on Tract 1.

King/LaRoca acknowledged that the Robison lease failed to convey any interest in Tract 1 but that the term “leased premises” referred to the land within the described boundaries and not to the interest conveyed and that by including Tract 1 in the property description the Robison’s intended that production anywhere within the boundaries of the described land would be sufficient to hold all the land regardless of whether the Robisons actually conveyed any interest in a portion of the leased premises.

The result

Not so, said the court. King/LaRoca’s interpretation would require the court to construe “leased premises” to have different meanings in different parts of the lease. Specifically it would require “leased premises” to include Tract 1 for purposes of extending the primary term but not include Tract 1 for purposes of leasing the mineral interests in the Robison lease.

The court assumed that identical words used in different parts of the same instrument would generally be given the same meaning (“Leased premises” was used in at least six places in the lease).

Because the Robisons did not own the executive right in Tract 1, they did not have the right to lease those minerals so that the lessee could drill a well on that tract or to pool that tract with other lands.

The court discerned no intent by the parties that “leased premises” was not to be used consistently throughout the lease. The leased premises were those tracts in which the Robisons actually conveyed a leasehold interest:  Tracts 2, 3 and 4. Tract 1 was not covered by the Robison lease and therefore not part of the “leased premises”. The habendum clause applied only to Tracts 2, 3 and 4 and production on Tract 1 did not hold the lease as to Tracts 2, 3 and 4.

Attorney’s fees

The court considers the substance of a party’s pleading rather than its form to determine whether a claim sounds in trespass to try title. There was no question but that the claims of all parties were for trespass to try title. The trial court’s award of fees to DEA on the basis that it successfully defended King/Laroca’s declaratory judgment counterclaim was reversed.

Full disclosure: My firm and I represented King in the suit.

Your musical interlude.

Separator. Equipment for oil separation. Modular oil treatment unit. Bulite for separation

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.”


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.


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.


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)