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Three recent cases illustrate a little known aspect of Texas law – administrative law and how it works, and doesn’t work. Although the cases don’t directly affect mineral owners, they show how different the Texas Railroad Commission’s administrative process is from other agencies’.

Many disputes in Texas are resolved not in trial courts but by administrative hearings. In many cases, the law that governs those hearings is the Administrative Procedure Act, found at Chapter 2001 of Texas’ Government Code. The hearings are held before an administrative law judge (ALJ) who works for the State Office of Administrative Hearings (SOAH). If two parties get into a dispute in which the law requires adjudication by an administrative hearing, an evidentiary hearing is held before an ALJ who hears testimony, takes evidence, and prepares a Proposal for Decision (PFD). The PFD then goes before the board of the responsible agency, which either adopts the PFD or makes changes, and issues a final order. That order can then be appealed to a state district court in Travis County. The district court acts as an appellate body, and must uphold the decision if it is supported by “substantial evidence” in the record from the administrative hearing and otherwise complies with the governing law.

The APA limits the grounds on which an agency can change a PFD and requires the agency to explain its reasons for doing so. APA section 2001.058(e) provides:

A state agency may change a finding of fact or conclusion of law made by the administrative law judge, or may vacate or modify an order issued by the administrative judge, only if the agency determines:

(1) that the administrative law judge did not properly apply or interpret applicable law, agency rules, written policies provided under Subsection (c), or prior administrative decisions;

(2) that a prior administrative decision on which the administrative law judge relied is incorrect or should be changed; or

(3) that a technical error in a finding of fact should be changed.

The agency shall state in writing the specific reason and legal basis for a change made under this subsection.

Two cases, both from the Austin Court of Appeals, are appeals of orders by administrative agencies. Hyundai Motor America v. New World Car Imports San Antonio, Inc., No. 03-17-00761-CV, is an appeal of a decision by the Board of the Texas Department of Motor Vehicles. The case involves the obscure laws that govern the relationships between car manufacturers and their dealers.

In Hyundai, the Board of the Texas Department of Motor Vehicles did not accept the PFD of the ALJ, but made changes in the PFD, modifying certain findings and conclusions. Its decision favored New World Car. Hyundai appealed, arguing that the TDMV Board violated APA Section 2001.058(e) by changing findings of fact that were not merely “technical errors,” and by failing to justify in writing the reasons and legal basis for its changes.

The Court of Appeals held that the TDMV Board had violated Section 2001.058(e):

An ALJ is a “disinterested hearings officer” to whom the legislature has delegated the duty of basic fact-finding. … An agency cannot frustrate the delegation of the fact-finding role by ignoring an ALJ’s “findings with which it disagrees and substitut[ing] its own additional findings.”

The other recent Austin Court of Appeals case is Dyer v. Texas Commission on Environmental Quality, No. 03-17-00499-CV, an appeal of a decision made by the TCEQ on a contested application by TexCom Gulf Disposal for a permit to drill and operate injection control wells for the disposal of non-hazardous industrial waste in Montgomery County. The permit was opposed by Montgomery County, the City of Conroe, and several individuals, who contended that the wells would jeopardize groundwater, and by Denbury Onshore, LLC who operated oil and gas wells in the area and argued that the disposal wells would interfere with its production of oil and gas. The hearing before the ALJ was held in December 2007. The ALJ’s PFD proposed to deny the requested permit, but the TCEQ in 2011 approved TexCom’s application, substantially modifying the ALJ’s proposed findings of fact and conclusions of law.

On appeal, the permit’s opponents argued that the TCEQ had violated APA section 2001.058(e) in modifying the PFD. But TexCom argued that TCEQ’s right to modify the PFD was governed by a different statute that specifically addresses hearings for the TCEQ, Section 2003.047, which provides: “The commission my amend the proposal for decision, including any finding of fact, but any such amendment thereto and order shall be based solely on the record made before the administrative law judge. Such amendment by the commission shall be accompanied by an explanation of the basis of the amendment.” The Court of Appeals held that this statute controlled, and that the TCEQ had complied with its less onerous provisions in modifying the PFD.  The dissent argued that the requirements of section 2001.058(e) do apply to the TCEQ:

In granting the permits, the TCEQ essentially disregarded the ALJs’ findings without providing any meaningful reasoning for its decision, a decision the trial court affirmed. The majority upholds the TCEQ’s actions only by jettisoning some of the requirements that the TCEQ must follow in changing an ALJ’s fining of fact or conclusion of law.”

The Texas Railroad Commission also conducts administrative hearings on disputes that come before it. But unlike other agencies, its hearings are not conducted before ALJs at SOAH, but by ALJs who are employees of the RRC. So a RRC ALJ is not a “disinterested hearings officer,” but an employee of the agency whose responsibility it is to enforce the laws that are the subject of the administrative hearings. Also, the RRC is not subject to section 2001.058(e) of the Administrative Procedure Act. So its commissioners can change findings of fact and conclusions of law in a PFD without providing any reasoned justification for those changes. Although efforts have been made in the past to amend the law so that RRC administrative hearings are conducted by SOAH, those efforts have been unsuccessful. In my opinion, these differences greatly affect the decisions made by the RRC.

The third recent case, from the U.S. District Court, Southern District of Texas, Judge Kenneth Hoyt, is San Antonio Bay Estuarine Waterkeeper v. Formosa Plastics Corp., Civil Action No. 6:17-CV-0047. Plaintiffs sued claiming that Formosa Plastics’ plant illegally discharged plastic pellets and PVC power into Lavaca Bay in violation of the Clean Water Act. The case is not an appeal of an administrative order but does shed light on how environmental laws are enforced (or not) by a Texas state agency.

The Clean Water Act requires any company discharging a pollutant into waters of the US to obtain a discharge permit that meets the requirements of the Act. The Act provides that the Environmental Protection Agency can delegate the responsibility for issuing and enforcing discharge permits to a state that creates a system for granting and enforcing permits in compliance with the Act. That authority in Texas was granted to the Texas Commission on Environmental Quality (TCEQ). The TCEQ granted a discharge permit to Formosa Plastics beginning in 1993; the permit had to be renewed every ten years. Waterkeeper’s suit claims that Formosa has continually violated its permit and seeks monetary damages, attorneys’ fees and injunctive relief. In the court’s order of June 27, it found after an evidentiary hearing that Formosa had indeed continually violated its permit by discharging substantial amounts of plastic pellets and PVC powder into the bay. Later hearings will determine the relief to be granted.

In January 2019 Formosa and TCEQ signed an agreed order adjudicating certain violations of Formosa’s permit. Formosa agreed to a penalty of $121,875. Before Judge Hoyt Formosa argued that the agreed order resolved Waterkeeper’s complaints and made the case moot. Judge Hoyt disagreed:

The violations adjudicated in the Agreed Order, represented six violation events between April 4, 2017 to May 17, 2017. These violations are comprised of two events at each of three outfalls … Based on the overwhelming evidence, the TCEQ’s findings and assessment merely shows the difficulty or inability of the TCEQ to bring Formosa into compliance with its Permit restrictions.

Judge Hoyt concluded that Formosa is a “serial offender,” violating its permit from January 31, 2016 through March 24, 2018 – some 1,149 days of violations. Waterkeeper seeks $184 million in fines for Formosa’s violations, to be paid to the federal government.

It is not widely known that the EPA delegates most of its enforcement responsibilities to states. TCEQ is one of the largest state agencies in the country responsible for enforcing federal environmental laws. Some of EPA’s enforcement responsibilities under the Clean Water Act are delegated not to the TCEQ, but to the RRC. Violations resulting in pollution of surface and groundwater by oil and gas production operations are the responsibility of the RRC.

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Herein of a case that will probably be of interest only to law professors and title attorneys.

Leo Trial had six brothers and sisters. They inherited 237 acres in Karnes County. In 1983 Leo gave his wife Ruth one-half of his 1/7th interest in the property. In 1992, Leo and his siblings sold the land to the Dragons, reserving the minerals for a term of 15 years. But Leo’s wife Ruth did not join in the deed. The deed included a general warranty of title. The Dragons did not get a title policy and did not investigate the title.

Leo Trial died in 1996 and willed his estate to a trust for Ruth’s life and then to their two sons, Joseph and Michael. Ruth died in 2010, and Ruth’s 1/14th interest in the 237 acres passed to her sons.

The Trials’ 15-year term mineral interest expired in 2008. At the time there was production from the property, and the Dragons contacted the operator to transfer all royalties to them. The operator did so, not realizing that Ruth still had an interest in the property, a fact was not discovered until 2014. The operator then put Ruth’s interest in suspense, and the Dragons filed suit against the Trial sons, seeking to acquire their 1/14th interest in the property under the Duhig doctrine and the doctrine of estoppel by deed.

The rule of estoppel by deed says that “all parties to a deed are bound by the recitals therein, which operate as an estoppel, working on the interest in the land if it be by deed of conveyance, and binding both parties and privies; privies in blood, privies in estate, and privies in law.” The origin of the doctrine and of the phrase “privies in blood, privies in estate, and privies in law” comes from Carver v. Jackson, 29 U.S. (4 Pet.) 1 (1830), opinion by Justice Story. The doctrine was applied by the Texas Supreme Court in Duhig v. Peavy-Moore Lumber Co., 144 S.W.2d 878 (Tex. 1940). In that case, Duhig owned land, subject to a 1/2 mineral reservation by a previous owner. He sold the land and in the deed reserved a 1/2 mineral interest – but the deed was not made subject to the prior reservation of 1/2 of the minerals. The court held that, under the doctrine of estoppel by deed, Duhig’s 1/2 mineral interest passed to his purchaser and Duhig retained no mineral interest. Duhig was estopped from claiming a mineral interest because his deed purported to convey a 1/2 mineral interest, which was all Duhig owned.

The estoppel-by-deed theory also applies to after-acquired title. If, in Duhig, Duhig had signed his deed while owning no mineral interest and had later acquired a 1/2 mineral interest in the property, under this doctrine the interest he acquired would automatically pass to his purchaser. Because he purported to convey a 1/2 mineral interest to his purchaser, Duhig would be estopped from claiming the mineral interest he later acquired.

The Supreme Court held in Trial that these doctrines did not apply to the Dragons’ case. The Trial sons did not acquire their mother’s interest from their father but from their mother, and their mother did not sign the deed to the Dragons: “estoppel by deed does not bind individuals who are not a party to the reciting deed, nor does it bind those who claim title independently from the subject deed in question.” In a footnote, the court said that, if the Trial sons had obtained their title from their father, the outcome might have been different: “We need not and do not decide whether, in other circumstances, Duhig might apply to estop the Trial sons from asserting their ownership interest in the property.”

The court remanded to the trial court to consider the Dragons’ breach of warranty claim. But the court ended with an enigmatic footnote:

This is not to say that a grantee such as the Dragons could recover [damages?] only under a breach of warranty theory. We express no opinion as to whether such a grantee might prevail on causes of action such as unjust enrichment or money had and received, as such claims were not brought in the trial court and are not before us in this appeal.

More fodder for law review articles.

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Last week MineralSoft published a webinar in which I was interviewed by Jay Snodgrass, VP of MineralSoft, about royalty underpayments. You can listen to it here.

I met Jay when MineralSoft was just getting started. It is a software company providing solutions for royalty owners to manage their interests. MineralSoft was recently acquired by Drillinginfo. MineralSoft also has a good blog addressing issues of interest to royalty owners.

In my experience it is getting more and more difficult for royalty owners to understand their check skirts. Multiple adjustments for previous months, different formats for reporting, and more complex marketing arrangements by producers make it harder for royalty owners to tell whether their lessees are properly making and reporting royalty payments in compliance with their lease. Companies like MineralSoft are addressing that problem.

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Oil and Gas Lawyer Blog by John Mcfarland - 1M ago

Last Saturday our firm participated in the annual Austin parade celebrating Juneteenth, the day in 1864 it was announced in Texas that all slaves were free. The parade is the biggest in Austin, a celebration of freedom that has become a state holiday in Texas and 44 other states. June 19 also is my mother’s birthday.


Lincoln’s Emancipation Proclamation was issued on September 22, 1862, with an effective date of January 1, 1863. It declared that all slaves in the Confederate States would be free – excluding the five border states not in rebellion, and excluding the three zones then under Union occupation – Tennessee, lower Louisiana and Southeast Virginia.

Lee surrendered at Appomattox on April 9, 1864, but the Army of the Trans-Mississippi did not surrender until June 2. Union Army General Gordon Granger arrived on Galveston Island with 2,000 federal troops on June 18, to occupy Texas. The following day, from the balcony of Galveston’s Ashton Villa (see photo), Granger read aloud General Order No. 3:

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A reader alerted me to a Texas Supreme Court mandamus proceeding about unpaid royalties, In Re The Estate of Ebbie Edward Allen, Jr., No. 19-0027. Lawyers for the Relator asked the court to require the Texas Comptroller to audit Chesapeake and require it to deposit royalties not paid to Mr. Allen’s estate into the state’s unclaimed properties fund. The Supreme Court refused to take the case. The facts illustrate a little-known aspect of what can happen when royalties owed are not paid.

According to the petition, Ebbie Allen was an elderly man who lived alone on his 705-acre property in Brazos County and who signed an oil and gas lease in 1993, which was assigned to Chesapeake. In 1994, Chesapeake completed a horizontal well on the property and produced it until 2009, when it sold the lease to Envervest. Chesapeake produced 26,000 barrels and 2 Bcf of gas from the well. It sent a division order to Mr. Allen but he refused to sign it because he disagreed with the royalty decimal on the division order. Mr. Allen made attempts to resolve the royalty issue but never succeeded, and he subsequently passed away. Neither he nor his estate ever received any royalties on Chesapeake’s production. (After Enervest purchased the lease, the royalty issue was resolved and Mr. Allen’s estate received royalties from Enervest’s production, including some $15,000 in royalties that Enervest had deposited to the Comptroller’s unpaid properties fund.)

Chesapeake refused the Estate’s demands for payment, based on the four-year statute of limitations for royalty claims. Chesapeake also failed to deposit any of the royalties with the Comptroller. The Comptroller refused the Estate’s request that it audit Chesapeake’s records for unclaimed royalties that by law must be remitted to the Comptroller. In response to the Estate’s mandamus petition, the Comptroller responded that it had complete discretion whether and when to conduct audits and so could not be compelled to do so.

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The Texas Supreme Court has denied motion for rehearing of its opinion in Burlington Resources Oil & Gas Company v. Texas Crude Energy, No. 17-0266. The case addresses deductibility of post-production costs in the context of an overriding royalty. The case may, however, have implications for post-production-cost deductions in oil and gas royalty clauses.

Texas Crude acquired oil and gas leases in Live Oak, Karnes and Bee Counties, and entered into an agreement with Burlington to develop those leases. The parties agreed that any oil and gas lease acquired by either party within the designated area would be part of the development agreement, and that Texas Crude would receive an overriding royalty interest in all leases within the development area. Texas Crude subsequently sued Burlington over various alleged breaches of the development agreement, including the deduction of post-production costs from Texas Crude’s overriding royalties. The parties filed summary judgment motions asking the trial court to construe the language in the assignments of overriding royalty, and the trial court ruled that post-production costs were not deductible.  The parties agreed to seek an interlocutory appeal of this issue, which the court granted. The Corpus Christi Court of Appeals agreed to hear the case, and it affirmed the judgment of the trial court.  516 S.W.3d 638. Burlington then appealed to the Texas Supreme Court, which reversed and remanded, holding that the language of the overriding royalty assignments permits deduction of (some?) post-production costs.

The pertinent language of all of the overriding royalty assignments is identical:

The overriding royalty interest share of production shall be delivered to ASSIGNEE or to its credit into the pipeline, tank or other receptacle to which any well or wells on such lands may be connected, free and clear of all royalties and other burdens and all costs and expenses except the taxes thereon or attributable thereto, or ASSIGNOR, at ASSIGNEE’S election, shall pay to ASSIGNEE, for ASSIGNEE’S overriding royalty oil, gas or other minerals, the applicable percentage of the value of the oil, gas or other minerals, as applicable, produced and saved under the leases. “Value”, as used in this Assignment, shall refer to (i) in the event of an arm’s length sale on the leases, the amount realized from such sale of such production and any products thereof, (ii) in the event of an arm’s length sale off of the leases, the amount realized for the sale of such production and any products thereof, and (iii) in all other cases, the market value at the wells.

The unanimous decision, opinion by Justice Blacklock, held that the controlling language of the assignments is “delivered to ASSIGNEE or to its credit into the pipeline, tank or other receptacle to which any well or wells on such lands may be connected …” Texas Crude argued that the controlling language was in the definition of “Value”: “the amount realized from such sale of such production and any products thereof.” Texas Crude contended that under the court’s prior opinion in Chesapeake v. Hyder, 483 S.W.3d 870 (2016), a royalty based on the “amount realized,” without more, is free of post-production costs, and that the “into-the-pipeline” language would not be relevant unless Texas Crude elected to take its royalty share of production in kind.

Justice Blacklock said Texas Crude’s construction of the clause would lead to “strange results”:

If, as Texas Crude contends, the references in the Granting and Valuation Clauses to delivery “into the pipelines, tanks or other receptacles” only cover in-kind transfers, then an in-kind distribution would give Texas Crude its royalty percentage of production at the well. But an arms-length sale off the lease would give Texas Crude a higher royalty based on the downstream price after post-production enhancements. Under this construction, Burlington would be penalized for marketing Texas Crude’s share of production, finding a third-party buyer, transporting the product, and performing other post-production enhancements. It is difficult to fathom why either party would have intended such a result.

There are several troubling aspects to this statement. First, it seems to conflate “into the pipeline” with “at the well.” Second, Justice Blacklock considers that requiring Burlington to bear all post-production costs would “penalize” Burlington. Third, the opinion seems to be construing the language in a way that would reach a result the court deems reasonable, rather than enforcing the language as written. The clause clearly provides that Texas Crude may take its royalty in kind, or may require Burlington to pay royalty based on the “Value” of the production, the “amount realized” from its sale. Yet because the court considers this to be a “strange result,” it concludes that Burlington may deduct post-production costs from the “amount realized.”

“Into the pipeline” and “at the well” are not equivalent. Even if the “valuation point” for measuring the “amount realized” for purposes of calculating the amount due Texas Crude for its royalty were at the point where the production enters “into the pipeline, tank or other receptacle” to which the well is connected, that point is not “at the well.” No appellate case has heretofore addressed the meaning of “into the pipeline” language in the context of a royalty clause.

When the “at the well” and “into the pipeline” language was first used in oil and gas lease royalty clauses, almost all oil and gas production was sold by the producer at or near the well. Gas pipelines were purchasers. The separation of the gas transportation and gas purchase function had not yet occurred. Likewise, if the well was connected to an oil pipeline, the pipeline company was also the purchaser and the point of sale was when the oil was delivered “into the pipeline.”

Here is the royalty clause in a commonly used oil and gas lease form first published in 1950:

The royalties to be paid by Lessee are: (a) on oil, one-eighth of that produced and saved from said land, the same to be delivered at the wells or to the credit of Lessor into the pipe line to which the wells may be connected: Lessee may from time to time purchase any royalty oil in its possession, paying the market price therefore prevailing for the field where produced on the date of purchase; (b) on gas, including casinghead gas or other gaseous substance, produced from said land and sold or used off the premises or for the extraction of gasoline or other product therefrom, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at the wells the royalty shall be one-eighth of the amount realized from such sale.

This same language, with some variation, appears in lease forms used today. Under these typical clauses, the lessor’s oil royalty is an in-kind royalty, but the lessee may purchase the lessor’s royalty oil at a specified price. The lessor’s gas royalty is only a right to money, a share of proceeds from the sale of the gas or products extracted therefrom. The phrase “into the pipeline” appears only in the in-kind oil royalty provision. The gas royalty is based on the “amount realized” from the sale. So “into the pipeline” relates to in-kind royalty, and “amount realized” relates to royalty taken as a share of proceeds of sale.

The phrase “into the pipeline” has become more problematic as methods of gathering, treating, processing and selling oil and gas have become more sophisticated. Today, an operator may have an extensive gathering system for its production, and oil and gas may be treated before being delivered to the purchaser.  If “into the pipeline” is synonymous with “at the point where production is delivered to the purchaser,” then the costs incurred to gather and treat production before sale would not be chargeable to the royalty owner. As A.W. Walker (a prominent oil and gas attorney who wrote extensively on the development of oil and gas law) wrote more than 50 years ago, the phrase “into the pipeline” in a royalty clause was intended to make the royalty free of any cost incurred to get the production “into the pipeline” – at that time the point of sale:

When the royalty upon oil is payable in kind it is usually stipulated that the royalty oil shall be delivered, free of cost, in the pipe line to which the lessee may connect the wells. The lessor by his division order contract with the pipe line company provides for its receipt at that point and for the time and manner of payment by the purchaser. This clause obviates the necessity of any expenditures by the lessor in connection with the storage, treatment, and transportation of his royalty oil to his purchaser, and requires these expenses, sometimes of considerable proportions, to be borne by the lessee. It is, therefore, a vitally important provision from the standpoint of the lessor.

Why does this matter to royalty owners?  The court’s opinion in Heritage Resources v. NationsBank, 939 S.W.2 118 (1996), its first foray into the construction of royalty clauses and post-production costs, held that, when a lease provides for royalties payable “at the well,” any later language attempting to prohibit deduction of post-production costs is “surplusage”. Likewise, the court’s opinion in this case may be construed to hold the same for “into the pipeline”; whenever that phrase appears in a royalty clause, any later language regarding post-production costs may also be “surplusage.” And “into the pipeline” may be equated with “at the well,” even if the pipeline into which production is delivered is many miles from the well.

Finally, this case appears to me to be a second example of how the court strays from the language of the contract to reach a result the court deems “reasonable.” The most recent example prior to this case is Murphy v. Adams, decided last year.

Our firm assisted Texas Crude’s counsel in the Supreme Court briefing of this case.

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Senate Bill 421, reforming how pipelines exercise the power of eminent domain to condemn right-of-way, died at the end of the Texas legislative session after Rep. Tom Craddick sought to make amendments opposed by its author, Sen. Lois Kolkhorst. Kolkhorst said Craddick “seized the legislation” from its house sponsor and severely weakened the bill. The bill would have prevented low first-time offers for easements, improved easement terms and set mandatory meetings with property owners to explain the eminent domain process.

“The language of the House version would have turned back the clock for landowners and greatly harmed them,” Kolkhorst said in a statement Sunday. “I cannot agree to the Craddick proposal, which would do the opposite of what we set to do: help level the playing field for landowners in the taking of their property.”

This is the third legislative session in which Kolkhorst’s efforts to reform eminent domain have failed. Kolkhorst said she isn’t giving up. “This issue will and must remain a top state legislative priority,” she said.

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Oil and Gas Lawyer Blog by John Mcfarland - 1M ago

A couple of years ago I wrote about the history of Texas Pacific Land Trust (TPLT), one of the largest landowners in Texas.  The trust was formed out of the bankruptcy of Texas Pacific Railroad, which received 3.5 million acres of land in West Texas in consideration for building the T&P Railway across the state. It went into bankruptcy in 1888, and its land was put in a trust to sell of to pay the railroad’s bondholders. Those certificates of trust were later listed on the New York Stock Exchange, where they trade under the ticker TPL. Its shares closed today at $786.44 per share, a market cap of $6.2 billion.

TPLT now owns some 888,000 acres of land. The minerals under its land were spun off into a separate company and acquired by Texaco, now Chevron – now one of the largest mineral owners in the Permian. TPLT has royalty interests under about 500,000 of those acres, in El Paso, Hudspeth, Culberson, Reeves, Pecos, Winkler, Ector, Midland and Glasscock Counties. In addition to collecting royalties the trust makes money granting easements and collecting damages from oil companies operating on its land, and has recently begun a business supplying water to the industry.

Since its founding the trust has been managed by a three-member board of trustees. When a trustee dies or resigns, the remaining board members name his replacement, subject to shareholder approval. But now some investors want to change that, modernizing its management and converting it to a corporation. One of its trustees died in March, and those investors want to elect their own member rather than the nominee chosen by the other trustees.

The New York investment firm Horizon Kinetics, leading the dissident group, owns more than 23 percent of the trust shares and has nominated its own candidate for trustee.  The trust’s nominee is Donald Cook, a retired Air Force four-star general who was a commander of Randolph Air Force Base near San Antonio. He has served on boards of major corporations such as Burlington Northern Santa Fe railroad and the USAA Federal Savings Bank.

TPLT has postponed the shareholder meeting scheduled to elect its new trustee. It also filed a lawsuit in federal court in Dallas, accusing Eric Oliver, the nominee of the dissident shareholders, of violating securities laws.

Another chapter in the history of the T&P Railway.

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Hays County and the City of Kyle, and private landowners, have sued Kinder Morgan, the Texas Railroad Commission and its commissioners over the route for Kinder Morgan’s Permian Highway Pipeline, a gas pipeline 42 inches in diameter, set to cross through the Texas hill country and Hays County.  The suit claims that the RRC has failed to establish regulations that implement the Legislature’s requirement, imposed by Section 121.052 of the Texas Utilities Code, to “establish fair and equitable rules for the full control and supervision of the pipelines … in all their relations to the public” and to “prescribe and enforce rules for the government and control of pipelines … in respect to transporting … facilities.”  The petition explains that, to obtain the right to condemn a pipeline easement, the pipeline company only needs to file a form T-4 with the RRC. The Commission “conducts no investigation, evaluates no alternative routes, entertains no adversarial inquiry, provides no notice, allows no hearing, and considers no evidence.” “The pipeline’s chosen route crosses some of the most sensitive environmental features in Central Texas and the Texas Hill Country, including the recharge zones of the Edwards and Edwards-Trinity Aquifers (which provide the drinking water supply for towns and cities such as Fredericksburg and Blanco) and endangered species habitat.”

The suit asks the court to find that the RRC has unconstitutionally delegated to Kinder Morgan the legislative and constitutional requirement that a government entity review and determine the necessity for the pipeline route, and enjoining Kinder Morgan from proceeding with condemnation until that has been accomplished.

Plaintiffs are represented by Richards Rodriguez & Skeith, LLP and Renea Hicks. The suit is No. D-1-GN-19-002161, in the 345, District Court of Travis County. A copy of the petition can be seen here:  01-OrigPet-Sansom

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Rystad Energy has released an analysis of gas flaring in the Permian Basin. Operators flared 533 million cubic feed per day during the fourth quarter of 2018 – more than some states use in a year.The flared volumes represented an average of less than 5% of all gas produced. But results varied greatly by operator. (click to enlarge)

According to a report by the Environmental Integrity Project, a result of the increased volumes of flared gas and emissions, excessive emissions of sulfure dioxide and hydrogen sulfide have increased pollution levels in Ector County above standards set by the EPA.

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