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Last week I presented a paper at the Texas State Bar Advanced Real Estate CLE Conference for attorneys in San Antonio. I was asked to write a paper giving real estate attorneys a basic introduction to negotiating oil and gas leases. It might seem odd that real estate attorneys would want a primer on oil and gas leases; most people would assume that an attorney practicing real estate law in Texas would know about oil and gas leasing. And that used to be true, when the majority of attorneys had a rural general practice. General practitioners in Texas knew the basics of real estate and oil and gas law and often helped their landowner clients negotiate leases. Today, most real estate attorneys have little to do with oil and gas matters, and as practices have become more specialized the oil and gas specialty has diverged from the real estate specialty.

I was given thirty minutes to make my presentation – hardly enough time to do justice to the subject of oil and gas leases. The exercise of preparing my remarks caused me to focus on some basic concepts that I’ve not recently thought about, and I decided they would make a good topic for discussion here.

The oil and gas lease is in many ways a unique form of contract. It is the foundation of the oil and gas industry in the U.S. Because most minerals in the U.S. — unlike most of the world — are privately owned, some way had to be found for those willing to risk capital to exploit oil and gas to obtain rights to those resources. The oil and gas lease was the result. In its basic form, the oil and gas lease has remained unchanged since the early days of the industry.

The concept is simple: the mineral owner conveys the mineral estate in her land to the company that wants to exploit the minerals, for a term — a “primary term” of years, and a “secondary term,” for as long thereafter as oil or gas is produced. In that conveyance, the mineral owner reserves a cost-free interest in production – a royalty interest. The landowner thus transfers the risk and cost of development to the grantee, and retains a risk-free royalty interest in production.

The oil and gas lease is both a conveyance and a contract, and the law that has developed around the lease reflects both concepts. Its character as a conveyance has important consequences, and it is important for the landowner to understand those consequences, especially if the landowner owns both the surface and mineral estates. The mineral estate is the “dominant” estate, meaning that the owner of the mineral estate has the right, without compensation, to use so much of the surface estate as is reasonably necessary to explore for and produce oil and gas from the property. This basic idea is subsumed within the lease. The grantee in the lease acquires not only the mineral estate but also the right to use the surface estate for mineral development. This includes the right to build roads, lay pipelines, install production facilities, conduct seismic surveys, etc. And it includes the right to use groundwater for oil and gas exploration and production and the right to dispose of produced water and associated waste by drilling and operating injection wells on the property. All of these rights are implied in the grant of the mineral estate, and need not be specifically mentioned in the lease. If the landowner wants to restrict the lessee’s right of surface use in any way, those restrictions must be provided for in the lease. Absent such express contractual restrictions, the right of surface use is part of the bundle of rights granted to the lessee as part of the mineral estate.

An oil and gas lease is also a contract and enforceable as such. As the case law interpreting oil and gas leases began to develop, courts began to imply certain provisions into the lease, as a matter of contract interpretation. Courts considered that the lease imposed certain obligations on the lessee that were not expressed in the contract but were necessary in order for the parties to have the benefit of their bargain. These implied obligations are now well-recognized, and include the obligation to reasonably develop the lease and the obligation to protect the lease against drainage by wells on adjacent lands. Courts also created rules for construction of certain lease provisions. For example, leases remain in effect for a term of years and “as long thereafter as oil or gas is produced.” But what if there is a temporary cessation of production? Does the lease terminate? Faced with this question, courts developed the rule of “temporary cessation.” A lease will not terminate because of temporary lapses in production if the lessee acts diligently to restore production.

A body of law also developed around the construction of the royalty reservation in oil and gas leases. The royalty reserved in a lease is both an interest in the land – a real property interest that can be conveyed, devised, or gifted – and a contractual obligation of the lessee to make payments to the lessor. What does it mean that the royalty is “cost-free”? In Texas, courts have generally concluded that royalties are free of the costs of exploration and production but must bear their share of “post-production costs.” Again, this interpretation applies unless the parties provide otherwise in the lease agreement. How and when the royalty is calculated and paid is a source of much contention in the courts, largely because of the parties’ failure to adequately address the issue in the lease itself.

The law surrounding oil and gas leases continues to be a fascinating subject. As the technology of the exploration industry changes, new issues continue to arise and conflicts continue to result. But without this document, the oil and gas industry in the U.S. might never have been born.

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There has been a lot of discussion lately about the demand on groundwater from its use to hydraulically fracture wells, and possible contamination of wells by hydraulic fracturing and improper completion of wells.

Air Products and Chemicals is promoting the use of nitrogen foam instead of water in fracking in shallower formations. 

http://www.cryogas.com/pdf/Link_Nitrogen%20Fracs_Water_Air%20Products.pdf

A second study of wells in the Marcellus Shale led by Rob Jackson of Duke Universty, published in the Prodceedings of the National Academy of Sciences, found increased methane in water wells located close to recent shale wells. “Overall, our data suggest that some homeowners living < 1 km from gas wells have drinking water contaminated with stray gases," Jackson's team concluded. The study does not directly link the methane to the Marcellus wells because of the lack of data on the quality of the groundwater before the wells were drilled.

http://www.scientificamerican.com/article.cfm?id=methane-in-pennsylvania-duke-study

The EPA has abandoned its investigation into possible contamination of groundwater by fracking in Pavillion, Wyoming, saying that it would instead support the state’s investigation.  EPA released a draft report in 2011 that found frac fluids present in groundwater; its report was heavily criticized by the industry.

http://www.eenews.net/stories/1059983265

Scarcity of groundwater in the Permian Basin in West Texas has caused operators to turn to water recylcing and use of brackish (non-potable) groundwater. A recent study by UT Austin estimated that 20% of the frac water used in that area came from recycled or brackish water. The study found that in Dimmit, Webb and LaSalle Counties – all in the Eagle Ford Shale — more than 50% of total water use comes from mining, which includes fracking.

http://stateimpact.npr.org/texas/2013/03/28/drilling-boom-spurs-a-rush-to-harness-brackish-water/ 

http://ecowatch.com/2013/fracking-industry-reacts-water-scarcity/

Barnhart, a small town in Irion County in West Texas, has run out of water. It’s well has run dry. The Texas Commission on Environmental Quality has listed 30 communities statewide that could run out of water by the end of the year. 

http://www.texastribune.org/2013/06/06/west-texas-oilfield-town-runs-out-water/

http://www.tceq.texas.gov/drinkingwater/trot/droughtw.html

A report by the Texas Water Development Board showed groundwater levels dropped significantly in Texas aquifers. In South Texas’ Carrizo-Wilcox aquifer, the principal source for frac water in the Eagle Ford, median groundwater levels dropped 4.4 feet in monitoring wells, and the average drop was 17.1 feet. One monitoring well in LaSalle County ropped some 136 feet.

http://www.texastribune.org/2013/05/07/texas-groundwater-dropped-sharply-amid-droughtstud/

http://www.twdb.state.tx.us/groundwater/data/waterlevel.asp

Here is a good article on the relation between water resources and hydraulic fracturing:

http://www.martenlaw.com/newsletter/20130422-hydraulic-fracturing-and-water?utm_source=Marten+Law+News&utm_campaign=319bfd5c5e-Marten_Law_News_May_6_2013&utm_medium=email&utm_term=0_ff00f67215-319bfd5c5e-222334753

Ceres, an environmental non-profit, has published a paper analyzing water use in fracking operations and efforts being made by industry to use alternatives to potable groundwater. It found that more than half of the wells drilled in Texas in 2011 were in areas with high or exremely high “water stress.”

 

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Colleen Schreiber has written an excellent article in the June 13 edition of Livestock Weekly, “Landowners Hold Off Oil and Gas Lobby on Common Carrier Bills,” describing the blow-by-blow negotiations and lobbying in the pipeline industry’s efforts to “solve” the problems created by the Texas Supreme Court’s decision in Tex. Rice Land Partners, Ltd. v. Denbury Green Pipeline-Tex., LLC, 363 S.W.3d 192, 198 (Tex. 2012).

Lined up on one side:  pipeline lobbyists supporting bills by Rep. Tryon Lewis, R. Odessa, in the House, and Robert Duncan, R. Lubbock, in the Senate, including the powerful Koch brothers, owners of Koch Enterprises.

On the other side:  Texas and Southwestern Cattle Raisers Association, Texas Farm Bureau, Texas Land and Mineral Owners’ Association, the Bass family, and plaintiffs’ lawyers.

Ultimately, all bills failed. The pipeline industry asked the Governor to add their issue to the special session but, so far at least, pipelines have been overshadowed by abortion bills and financing of higher education projects.

In Denbury, the Supreme Court surprised the pipeline industry by holding that they actually have to prove their proposed line will be a “common carrier” before they can use the power of eminent domain to condemn right-of-way. This left the pipelines, in their view, subject to interminable delays and suits by landowners unhappy with the pipeline routes, the terms of their proposed easements and the compensation being offered.

To “fix” the problem, the pipelines proposed that a pipeline’s common-carrier status be determined once for each pipeline, at a hearing held before the Texas Railroad Commission. Landowner lobbyists agreed to negotiate and agreed to consider the concept of a single hearing that would determine common-carrier status for a pipeline; but they wanted the hearing to be before the State Office of Administrative Hearings (SOAH), rather than the RRC; they wanted to be sure all landowners likely to be affected got notice of the hearing; and they wanted strict standards to determine whether a pipeline qualifies as a common carrier. In the end, the biggest sticking point was whether the hearings would be before the RRC or SOAH. Pipelines obviously favored the RRC; the landowners, believing that the RRC would not protect their interests, favored SOAH.  (Most administrative hearings related to state agencies in Texas are held before administrative judges at SOAH. The RRC is one of the few agencies that has kept the right to have hearings before its own administrative judges, called hearings examiners.)

A bill might have been hammered out, but late in the game plaintiffs’ lawyers, led by Wayne Reaud, a lawyer who made a fortune suing tobacco companies, weighed in and refused to compromise. Reaud at the time was fighting a condemnation action brought by CrossTex for a pipeline that would cross lands he owns in Jefferson County. Reaud claimed that CrossTex should not have the right to survey on his land until it proved that it is a common carrier. He sought and obtained a temporary injunction to keep CrossTex off his property. CrossTex appealed that injunction to the 9th Court of Appeals in Beaumont, and the appeal was pending when the pipeline bills were being considered. (The Beaumont court has since issued its opinion affirming the trial court’s decision to grant the injunction. The opinion can be viewed here.) The end result was that the pipeline bills died in committee and never came up for a vote in either the Senate or the House.

Underlying the debate over the pipeline legislation is the perception by those representing landowners’ interests that the RRC is not the place to have hearings on the qualifications of pipelines to exercise eminent domain, and the insistence by the pipeline interests that the RRC be the judge. The RRC has jurisdiction to enforce other laws affecting landowners’ interests, and their experience has been that the RRC is not an agency friendly to landowners’ complaints.

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The examiners who heard the Klotzmans’ protest of EOG Resources’ application for an allocation well permit have issued their Proposal for Decision in the case. A copy of the PFD can be viewed here:  2013-06-25 PFD EOG Klotzman (2).pdf  Our firm represents the protestants in the case. For my prior discussion of the case and allocation well permits, see here and here and here. The parties now have until July 10 to file exceptions to the proposal, and replies to exceptions are due within 10 days thereafter. After that, if no changes to the PFD are made, it will go before the Railroad Commissioners for their decision.

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Last Friday, the Texas Supreme Court affirmed judgment in favor of XTO in its battle with Homer Merriman over whether XTO’s well should have been moved so as to accommodate his cattle-working operation.

I wrote about this case when the Supreme Court decided to hear it. Mr. Merriman owns 40 acres in Limestone County. When he bought the land, the seller reserved the mineral estate and the land was then subject to an oil and gas lease. Merriman built his home on the land. Although he works full-time as a pharmacist, Merriman also runs cattle. He leases land in Limestone County for grazing, and once a year he uses his 40 acres to round up and work his cattle, with portable pens that are assembled for the operation and then taken down. The rest of the year he grazes cattle on the 40 acres, where he also lives.

In 2007, XTO Energy approached Mr. Merriman and told him it intended to drill a well on his tract. Merriman objected to the proposed well location, arguing that it would prevent him from using the 40 acres for his cattle working operations. XTO discussed with Merriman moving the location to the southwest corner of his tract, where Merriman said it would be acceptable, but XTO ultimately decided not to accommodate Merriman’s request. Merriman then sued XTO seeking an injunction to prevent the drilling of the well at its chosen location. Despite the suit, XTO drilled the well. The trial court granted summary judgment for XTO, and the Waco Court of Appeals affirmed, holding that Merriman “has alternative uses of his land that are not impracticable or unreasonable. Merriman further has alternative methods of conducting his cattle operation [on other lands] that are not impracticable or unreasonable.”

The Supreme Court’s opinion concluded that the court of appeals reached the right result, but it disagreed with that court’s reasoning. It first re-stated the accommodation doctrine:

To obtain relief on a claim that the mineral lessee has failed to accommodate an existing use of the surface, the surface owner has the burden to prove that (1) the lessee’s use completely precludes or substantially impairs the existing use, and (2) there is no reasonable alternative method available to the surface owner by which the existing use can be continued. 

If the surface owner carries that burden, he must further prove that given the particular circumstances, there are alternative reasonable, customary, and industry-accepted methods available to the lessee which will allow recovery of the minerals and also allow the surface owner to continue the existing use. … [A] surface owner’s burden to prove that his existing use cannot be maintained by some reasonable alternative method is not met by evidence that the alternative method is merely more inconvenient or less economically beneficial than the existing method. … Rather, the surface owner has the burden to prove that the inconvenience or financial burden of continuing the existing use by the alternative method is so great as to make the alternative method unreasonable.

The court of appeals had said that Merriman could have conducted his cattle-working operations on other lands nearby that he leased for cattle operations, which was a “reasonable alternative” under the accommodation doctrine. The Supreme Court disagreed. It said that “the court of appeals improperly considered the land leased by Merriman in detrmining whether he produced evidence that he had no reasonable alternatives to continue his cattle operations.” The question was whether he had a reasonable alternative on the 40-acre tract.

The court of appeals also said that Merriman could have used his 40 acres for other agricultural uses. The Supreme Court said that this was not the test. Rather, the test was whether Merriman had any “reasonable alternatives for conducting his cattle operations on the tract, not whether he produced evidence that he had no reasonable alternatives for general agricultural uses.”

Finally, the Supreme Court considered whether Merriman “met his burden to produce evidence that he did not have any reasonable alternatives for continuing his cattle operation, including [roundup, sorting, working and loading of the cattle] on the tract.” It held that he did not. Merriman’s evidence “did not explain why corrals and pens could not be constructed and used somewhere else on the tract; and if they reasonably could be, then his existing use was not precluded.” Merely because his existing use of the tract made working his cattle “easier,” or “works the best” for him, or was more expensive, was not enough. The Court said that Merriman’s evidence was

evidence only that XTO’s well precludes or substantially impairs the use of his existing corrals and pens, creates an inconvenience to him, and will result in some amount of additional expense and reduced profitability because to continue his cattle operation he will have to build new corrals or conduct his operations in more phases. Evidence that the mineral lessee’s operations result in inconvenience and some unquantified amount of additional expense to the surface owner does not rise to the level of evidence that the surface owner has no reasonable alternative method to maintain the existing use.

Thus, Merriman did not produce evidence sufficient to raise a material fact issue as to part of the initial element on which he had the burden of proof: that he had no reasonable alternative means of maintaining his cattle operations on the 40-acre tract.

The Court’s requirement that the landowner prove that he has “no reasonable alternative” to continue his existing use is a difficult burden to meet. But Mr. Merriman did not present a very convincing case that he could not have conducted his cattle operations on the tract because of XTO’s well.

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Terrence Henry, a writer for StateImpact Texas, has written a recent article, “Why Oil and Gas Lobbyists Were Big Spenders in Texas.” He analyzes two reports on spending on lobbyists and campaigns compiled by Texans for Public Justice. Lobbyists for energy and natural resources companies spent between $31.4 million and $62.5 million on lobbyists during the most recent legislative session, according to the report, 19% of the total of between $155 million and $328 million spent on the session. Incredible numbers. There are no limits on such spending in Texas.

Texas Railroad Commissioners were big beneficiaries of both campaign contributions and lobbying by oil and gas interests. Sunset-recommended reforms of the Commission, opposed by the Commissioners, failed to pass once again. The only RRC-related reform that did pass (but which the Governor has vetoed) was a requirement that a commissioner resign if he/she decides to run for another office.  Andrew Wheat, a researcher at Texans for Public Justice, says that’s because the oil and gas industry supported that measure:  “The [oil and gas industry] is interested in paying their bills while they’re commissioners. But they don’t want to pony up huge amounts of money every time one of these people wants to run for higher office.”

One important bill supported by the energy industry did not pass. It would have limited public participation in hearings at the Texas Commission on Environmental Quality in applications for emissions permits. The bill was opposed by communities and environmental groups. And pipeline companies’ bills to make it easier for them to exercise the power of eminent domain to condemn pipeline easements also failed to pass.

 

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A friend recently made me aware of a publication by the Real Estate Center at Texas A&M called “Mineral Law West of the Pecos,” written by Judon Fambrough, a lawyer who is with the Center. Judon has written much good stuff about land and mineral law in Texas, and this publication is no exception. (The Center has many good articles and publications on its website of interest to land and mineral owners.) Judon’s article contains a good summary of the history of land grants in West Texas, mineral reservations, the Relinquishment Act and “mineral-classified” land, what constitutes a “mineral,” and recent litigation over State ownership of minerals in West Texas. His article is well written and informative and should be in every oil and gas lawyer’s library. The law of Texas land grants in West Texas (and South Texas) is complex and fascinating.

Judon provides this link to maps online at the Texas General Land Office, which show tracts in West Texas subject to any mineral classification or reservation by the State:

http://gisweb.glo.texas.gov/glomap/index.html

Another good resource.

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The session is over, and the Texas legislature has failed once again to pass sunset legislation for the Texas Railroad Commission. The legislature instead authorized continuation of the RRC for another four years, with sunset review to be repeated in the 2017 legislative session.

Under Texas sunset act, every state agency must go through a comprehensive review of its functions and performance every twelve years by the Sunset Advisory Commission, a 12-member commission appointed by the Lieutenant Governor and the Speaker of the House. The RRC underwent sunset review in 2010; the report of the Sunset Advisory Commission at that time criticized the agency for failing to vigorously enforce its rules and assess penalties for rule violations, and recommended structural reforms of the agency, including replacement of the three elected commissioners with a single appointed commissioner.  But the legislature failed to pass any legislation recommended by the Commission, instead requiring that sunset review be repeated for its 2013 session.

The 2012 Sunset Commission report no longer recommended replacing the three elected commissioners with an appointed commissioner. Instead, it recommended ethics reforms, including limiting the time when commissioners could solicit campaign contributions and prohibiting commissioners from accepting contributions from any company with a contested case pending before the RRC. It also required a commissioner running for a different elective office to resign from the RRC. The commissioners vigorously opposed these recommendations and the legislation introduced to enact the reforms.

The legislation continuing the RRC does provide that the next sunset review of the RRC must consider how to dismantle the agency and assign its responsibilities to other state agencies if sunset legislation fails to pass again in four years.

Rep. Dennis Bonnen, R-Angleton, author of the interim legislation continuing the RRC, expressed his frustration at the failure of the process: “I don’t see how they can go through a third time — through sunset and no bill passes — and we continue that agency. You just can’t keep doing that. We need to have the opportunity to have a strategic, orderly plan to dismantle the agency if that’s the choice they make. It’s the obvious thing to do.” Bonnen blamed the agency’s commissioners for the failure. “I’ll be candid. All of he commissioners were against any changes for ethics. I think that’s one of our biggest obstacles. The industry’s afraid to agree with the legislators on any policy changes we’re making because they don’t want to offend the Railroad Commissioners. It’s a very bad situation.”

Rep. Bonnen claims that Commissioner Barry Smitherman plans to run for Attorney General in 2014, a claim that Smitherman does not deny or confirm. But Smitherman expressed his relief that the RRC won’t have to go through sunset review for another four years.

Meanwhile, the RRC finally passed its overhaul of oil and gas well construction rules, Statewide Rule 13, a rulemaking that has been in the works for many months. Industry and environmental advocates — in particular the Environmental Defense Fund — worked together on the rule changes, and both expressed satisfication with the result.  Scott Anderson, senior policy advisor at EDF, said that “the rule marks a huge turning point in state regulation of the safety and environmental integrity of oil and gas wells. Texas has moved back into the leadership position on regulation of oil and gas well construction. Agencies around the country, including the federal Bureau of Land Management, are likely to learn a lot from studying these rules as well as similar rules adopted last year in Ohio.” But Anderson cautioned that one big improvement is still ndeed. “For reasons we don’t understand, the commission is allowing operators to leave less space around the pipes in the lower parts of wells than experts recommend. Having enough space around these pipes is important in order to get adequate cement jobs, which are needed both for economic reasons and in order to protect the environment. EDF hopes the commission will revisit this issue in the future.”

The new rules don’t become effective until January 1, 2014.

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A recent article in the New York Times highlights the difference between “oil,” or “owal” as we say in Texas, and the heavy crude oil mined from Canadian tar sands. A major waste product of that mining is coke.  The tarry substance mined in Canada goes through an initial refining process to separate the crude from tarlike bitumen, caled “coking.” The tarry solid left from the process is called coke. It can be burned, and is an essential ingredient in making steel. The coke created from Canadian tar sands has a high sulfur content. Some of the Canadian tar sands are now being coked in a refinery in Detroit owned by Marathon Petroleum, and the coke by-product is sold to Koch Carbon, owned by Charles and David Koch. (I’m not making this up.) The Koch brothers have recently been in the news for considering an offer to buy the Los Angeles Times and the Chicago Tribune. They are also famous for supporting conservative and libertarian political causes. 

Here is the picture from the NYT article showing the stockpile of coke along the Detroit River belonging to the Kochs:

PILE-articleLarge.jpg

The crude oil generated by the coking process is the oil that is supposed to go through the Keystone pipeline running from Canada to the Texas coast, if that pipeline ever gets regulatory approval. According to the NYT article, Canada has 79.8 million tons of coke stockpiled. Efforts are underway to export Canadian coke to China and Mexico as a fuel. California, which also produces heavy crude that has to be coked, exports about 128,000 barrels of coke per day, mostly to China. The EPA does not permit it to be burned in the US. The Oxbow Corporation, owned by William I. Koch (a brother of David and Charles), is one of the world’s larges dealers in petroleum coke, selling about 11 million tons a year.

Here are some pictures of petroleum mines in Alberta, Canada:

Alberta oil sands 1.jpg

Alberta oil sands 2.jpg

Alberta oil sands 3.jpg

Alberta oil sands 4.jpg

This is what the raw petroleum sand looks like:

Alberta oil sands 5.jpg

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The Texas Supreme Court has recently refused to hear Friddle v. Fisher, 378 S.W.3d 475 (Tex.App.-Texarkana 2012). The court of appeals’ opinion has an interesting discussion of the duties of a mineral owner to owners of non-participating royalty interests burdening the mineral estate and of the application of the discovery rule to claims that such duties were breached.

These are the facts of the case:  In 1949, M.L. Friddle conveyed 84.7 acres in Hopkins County to Barney Martin, reserving 1/4 of the royalty. The reserved royalty interest later came to be owned by M.L. Friddle’s son Marvin.  In 1995, Barney Martin conveyed 1/4 of the royalty in the 84.7 acres to Mable Robinson, and 1/4 of the royalty to Helen Warde. The following day, Martin conveyed the land to Fred and Ruth Fisher.  Later, Marvin Friddle acquired from Mable Robinson and Helen Warde the royalty interests that were conveyed to them. So, at the time this controversy arose, the Fishers owned the land and minerals, subject to a NPRI owned by Marvin equal to 3/4 of the royalty.

In 1998, the Fishers signed an oil and gas lease on the 84.7 acres, reserving a 1/8 royalty. Valence Operating Company formed a pooled unit, the Ames-Antrim Gas Unit, and pooled the 84.7 acres into the unit. Valence drilled a well on the unit, but the well was not located on the 84.7 acres. Neither Valence nor the Fishers notified Marvin of the granting of the lease, the formation of the pooled unit, or the drilling of the well. Valence paid all of the royalty attributable to the 84.7 acres to the Fishers.

Marvin did not find out about the Ames-Antrim Gas Unit until 2008, shortly before he filed suit against the Fishers and Valence. In his suit, Marvin contended that the Fishers and Valence had a duty to notify him of the lease and the unit and give him the opportunity to ratify the lease and/or the unit so that he would share in unit production and get his 3/4 of the royalty on the portion of unit production allocated to the 84.7 acres. Marvin also claimed that the Fishers had a duty to hold his share of the royalty in trust for him until it could be paid to him.

Marvin’s suit against Valence was severed into a separate suit. The trial court granted the Fishers’ motion for summary judgment and ruled that Marvin should take nothing by his suit. Marvin appealed.

The court of appeals reversed and remanded the case for trial. The court held that the Fishers, as holders of the leasing rights in lands in which Marvin has a royalty, had a duty — the court calls it a fiduciary duty — to notify Marvin of the lease and to “hold the portion of the funds which would be payable to the holder of the NPRI as constructive trustees for the use and benefit of the holder of the NPRI.” The court relied as precedent on Andretta v. West, 415 S.W.2d 638 (Tex. 1967).

The facts in Andretta are similar to Marvin’s case. In Andretta, the Wests signed an oil and gas lease on lands in which Andretta had a royalty interest. Superior Oil Company held the Wests’ lease and an adjacent lease. Superior drilled a well on the adjacent lease, and the Wests claimed that Superior had a duty to drill an offsetting well on their property. In a settlement of that claim, Superior agreed to pay the Wests a compensatory royalty, as if the Wests had a 1/8th royalty in production from the adjacent tract. When Andretta found out about this settlement, he sued the Wests claiming 1/4th of the compensatory royalty payments being made to the Wests. The Texas Supreme Court held that Andretta was entitled to his 1/4th of that compensatory royalty. It said that, if the Wests knew the name and whereabouts of the royalty owner, “it was their duty to notify him of the [settlement] and account to him for his share of the payment as received.”

The court of appeals in Friddle v. Fisher also had to address the Fishers’ claim that Friddle had waited too long to file his suit. Under Texas law, a claim like Friddle’s – a suit for breach of a fiduciary duty — must be brought within four years of the date when the plaintiff discovered or should have discovered the breach of fiduciary duty. The court of appeals held that there was conflicting evidence in the record as to when Friddle discovered or should, in the exercise of reasonable diligence, have discovered the facts that gave rise to his claim, and that a jury should be asked to determine when Friddle should have discovered his claim.

The Fishers’ attorneys argued strenuously that the discovery rule – the rule that the four-year limitation period for bringing suit does not begin until Friddle discovered or should have discovered his claim – should not apply to his claim, based on three recent Texas Supreme Cout cases, HECI Exploration Co. v. Neel, 982 S.W.2d 881 (Tex. 1998), Shell Oil Co. v. Ross, 35 S.W.3d 924 (Tex. 2011), and BP America Production Co. v. Marshall, 342 S.W.3d 49 (Tex. 2011). In those cases, the Texas Supreme Court has held that the discovery rule does not apply to royalty owners’ claims against their lessee for additional royalties, and that the royalty owners have a duty to look after their interests and investigate whether they should be entitled to royalty payments. The court of appeals distinguished those cases on the ground that an oil and gas lessee does not owe a “fiduciary” duty to its lessor, but only a duty to act in good faith and as a prudent operator. A person owed a fiduciary duty is relieved of the obligation to diligently inquire into the fiduciary’s conduct. He is entitled to assume that the fiduciary is looking after his interest until facts to the contrary are brought to his attention. So Friddle was relieved of any duty to “diligently inquire” into the Fishers’ conduct, and the discovery rule applies to determine when he is barred by limitations from pursuing his claim.

I have previously written critically about the Texas Supreme Court’s opinions in Shell v. Ross and BP v. Marshall. I believe that the court has placed an unreasonable burden on royalty owners to “diligently inquire” into their lessee’s conduct to discover errors or misdeeds. The court is being asked to revisit this issue in another case now pending on petition for review, Hooks v. Samson Lone Star, L.P., on appeal from the First District Court of Appeals in Houston.

Many properties in Texas are burdened by non-participating royalty interests. In the early days of the oil business it was common for landowners to buy and sell NPRI’s as a way to speculate on possible future oil and gas development. In some tracts there are dozens or even hundreds of royalty owners. The standard industry practice when tracts subject to NPRI’s are leased is for the lessee to seek out the NPRI owners and request that they sign ratifications of the lease. The lessee wants the ratifications because they give the lessee the right to pool the NPRI interests in accordance with the pooling clause in the lease. Most mineral owners who sign leases on lands burdened by NPRI’s assume that their lessee will obtain those ratifications and properly account to the NPRI owners for their share of production. Even identifying and tracking down the NPRI owners is sometimes a large task, one that most mineral owners would not wish to assume. While Friddle v. Fisher does not impose that burden on the mineral owner, the case does impose some amount of obligation on the mineral owner to see that the NPRI owner is dealt with fairly.

It may be prudent for mineral owners whose interests are burdened by NPRI’s to include provisions in their leases affirmatively obligating their lessee to seek out and account to the NPRI owners, and to provide that information to the lessor so that he can assure that his obligations are satisfied.

 

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