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Last March the San Antonio Court of Appeals handed down its decision in Bell v. Chesapeake Energy, No. 04-18-00129-CV. Chesapeake has asked the Texas Supreme Court to review the case. The facts bear a resemblance to Murphy v. Adams, decided by the Supreme Court last year. Both involve construction of an express offset clause in an oil and gas lease.

A typical express offset clause provides that, if a well is drilled within a certain distance from the lease boundary, the lessee must either drill an offset well or pay compensatory royalty based on the production from the adjacent well. The lessor is not required to show that the adjacent well is actually draining the leased premises. In Murphy v. Adams, the issue was what constitutes an “offset well.” The Supreme Court held (in a 5 to 4 decision) that, in the context of horizontal drilling in the Eagle Ford formation, any well drilled on the leased premises, regardless of its location, may satisfy the lessee’s obligation to drill an offset well.

In Bell v. Chesapeake, the issue is what amount of compensatory royalty Chesapeake must pay. The wells drilled on tracts adjacent to Chesapeake’s leases were not drilled parallel to the lease line, but a portion of the adjacent wells’ horizontal wellbore was within the minimum distance from the lease line to trigger the offset-well obligation. The lessors contend that Chesapeake must pay compensatory royalty based on 100% of the production from the adjacent well. Chesapeake argues that it should have to pay compensatory royalty only on the portion of the adjacent well’s production coming from perforations or “take points” that are within the minimum distance from the lease line specified in the lease.

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We’ve recently seen several requests for royalty owners to sign a production sharing agreement for a unit-line or lease-line allocation well. Such a well would be drilled along the boundary of two existing leases or pooled units.  So, unlike most allocation wells, production can’t be allocated based on the portion of the well’s productive lateral length on each lease or pooled unit. Instead, the production sharing agreement may propose to allocate production between the two leases or units in one of two ways – 50-50 to each unit, or based on acreage.

Allocating production between the two leases or units for such a well presents at least two problems:  first, the actual drilled wellbore cannot actually be drilled exactly down the boundary line between the two leases or units. The wellbore will deviate, sometimes significantly, from a straight line. Second, the well may not actually be drilled down the unit line, but might be on one side or the other of the unit line, but too close to the unit line to avoid drainage or a special Rule 37 spacing permit. In addition, the wellbore might extend beyond the boundary into another lease or unit. Wellbores are getting longer and longer.

So I think the better practice is to allocate production for a unit-line allocation well based on acreage. In effect, it is the same allocation that would result if a pooled unit were created for the well.

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I recently heard a presentation by Dr. Scott Tinker, head of the Bureau of Economic Geology at the University of Texas. He is the founder of the Switch Energy Alliance, about which I’ve written before. Switch Energy Alliance is “a 501(c)(3) dedicated to inspiring an energy-educated future that is objective, nonpartisan, and sensible.” It produced a documentary called Switch, and is working on another called Switch On. Switch can be viewed and downloaded on SEA’s website.

A premise of Dr. Tinker’s work is that rational decisions about energy and CO2 emissions and global warming can’t be made without understanding the role of energy in the world and the challenges facing efforts to wean ourselves of fossil fuels.

Here are just a few of the powerpoint slides from Dr. Tinker’s presentation (click on image to enlarge):

annual-energy-consumption

Sources and uses of energy in the US. Note the huge amount of “rejected energy” – wasted energy:

US-Energy-Consumption-2018

Global sources of energy:

Global-Energy-Mix

A look at electricity. Electricity generation by region (note Asia Pacific): Continue reading →

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In a short opinion, the Supreme Court of North Dakota decided a case brought by Newfield Exploration against the North Dakota Board of University and School Lands to determine how royalties on gas should be calculated under the State’s leases to Newfield. The case illustrates how post-production costs can sometimes be hidden in “percentage-of-proceeds” or “POP” contracts for the sale of gas. Newfield Exploration Company v. State of North Dakota, No. 2019088, 2019 WL 3024639, decided 7/11/2019.

Newfield sold its gas to Oneok. The opinion describes this contract as follows:

Title to the gas passes to Oneok when it receives the gas from Newfield, but payment to Newfield is delayed until after Oneok processes the gas into a marketable form and sells the marketable gas. The price Oneok pays to Newfield for the gas is calculated based on 70-80% of the amount received by Oneok when Oneok sells the marketable gas. The 20-30% reduction of the price for which the marketable gas is sold accounts for Oneok’s cost to process the gas into a marketable form and profit.

The lease royalty clauses provided:

Lessee agrees to pay lessor the royalty on any gas, produced and marketed, based on gross production or the market value thereof, at the option of the lessor, such value to be based on gross proceeds of sale where such sale constitutes and arm’s length transaction.

All royalties on … gas … shall be payable on an amount equal to the full value of all consideration for such products in whatever form or forms, which directly or indirectly compensates, credits, or benefits lessee. Continue reading →

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ConocoPhillips always seems to be getting into interesting scrapes.

In 1995, ConocoPhillips bought oil and gas leases from EOG covering 1,058 acres, the Las Piedras Ranch, in Zapata County. At the time there was one producing well on the leases.  The minerals belonged to the Ramirez family. One member of that family was Leonor, who died in 1990, owning a 1/4 mineral interest in the Ranch. Her will devised to her son Leon Oscar Sr. “all of my right, title and interest in and to Ranch Las Piedras … during term of his natural life,” and on his death “to his children then living in equal shares.” Leon Oscar Sr. signed an oil and gas lease on the Ranch, which was acquired by ConocoPhillips.

Leon Oscar Sr. died in 2006, survived by three children – Leon, Jr., Minerva and Rosalinda. In 2010 they sued ConocoPhillips and EOG for an accounting and to establish their title to 1/4 mineral interest in the Ranch. They alleged that the oil and gas lease signed by Leon Oscar Sr. was not binding on them as remaindermen following Leon Oscar’s life estate, and that EOG and ConocoPhillips owed them an accounting and payment for 1/4 of the net profits from oil and gas production from the Ranch, from the date of first production. They also sued for prejudgment interest and attorneys’ fees. The plaintiffs settled with EOG, and in 2015 the trial court signed a final judgment against ConocoPhillips awarding plaintiffs title to the minerals and $11.1 million for their share of net profits on production from the Ranch, plus $950,000 in prejudgment interest and $1,125,000 in attorneys’ fees. In 2017, the San Antonio Court of Appeals affirmed. 534 S.W.3d 490. In June of this year the Texas Supreme Court granted ConocoPhillips’ appeal. Oral argument is set for September 17. ConocoPhillips Company, et al. v. Ramirez, No. 17,0822

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Much has been written lately about flares of natural gas in the Permian Basin. A website called Skytruth provides a helpful interactive map allowing amazing satellite views of flares over time. Here’s a snapshot of flares in the Permian (click on image to enlarge):

Permian-flaresOne can zoom in on the map and locate each flare. This one is just east of US 285 southeast of Orla:

FlareSince the beginning of the boom in the Permian, the Texas Railroad Commission has never denied an operator’s application for a permit to flare. With low gas prices and lack of pipeline capacity, operators have turned to flaring gas in order to produce oil.

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Excellent article by Shannon L. Ferrell, Professor at the Department of Agricultural Economics at Oklahoma State University, on negotiating solar leases. You can download it here.

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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’.TexasBarToday_TopTen_Badge_Small

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. Continue reading →

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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.TexasBarToday_TopTen_Badge_Small

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. Continue reading →

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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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