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Energywire has been following the political implications of the University of Oklahoma’s study of the causes behind the huge increase in earthquakes in Oklahoma, and OU’s relationship with Harold Hamm, CEO of Continental Resources. In a recent investigative article, Energywire reported that “University of Oklahoma officials were seeking a $25 million donation from billionaire oilman Harold Hamm last year, records show, at a time when scientists at the school were formulating the state’s position on oil drilling and earthquakes.” OU initially “came up with a position that squared with Hamm’s, saying most of the hundreds of earthquakes rattling the state are natural and not caused by the oil industry.” Hamm turned down the donation request, and OU’s Geological Survey subsequently changed its position and now says that most earthquakes in Oklahoma are “very likely” triggered by oil and gas activities.

Earthquakes in Oklahoma have increased from 20 with a magnitude of 3.0 or greater in 2009 to 585 in 2014, and Oklahoma is now expected to have more than 800 such quakes this year.

OU’s president, David Boren, a former senator, serves with Hamm on Continental’s board of directors and according to Energywire has received $1.6 million from the company since 2009. Hamm has pressured OU to avoid linking quakes to injection of produced water in Oklahoma.

Meanwhile, here in Texas, scientists from Southern Methodist University issued a peer-reviewed study of quakes around the town of Azle in the Barnett Shale, concluding that quakes there were probably caused by two salt water disposal wells near the town. Those scientists recently participated in a panel discussion about earthquake activity in Texas organized by Railroad Commissioner Ryan Sitton. In response to the SMU study, the RRC scheduled two hearings, requiring the operators of those SWD wells, Enervest and XTO, to appear and show cause why their disposal wells should not be shut down.

RRC show-cause hearings are conducted before hearings examiners, who act as administrative law judges and make recommended decisions to the commissioners. At the Enervest and XTO hearings, the companies offered sworn testimony and arguments that SMU’s study was flawed and that their disposal wells did not cause the Azle quakes. The examiners admitted the SMU study as evidence over the objections of the companies’ attorneys. No SMU scientist appeared at the hearings. The examiners have not yet issued their proposal for decision.

Separately, the RRC concluded that disposal wells in Johnson County, also in the Barnett Shale, were not the cause of a 4.0 magnitude quake in that county on May 7. After the quake, the RRC ordered five disposal wells in the area shut down for testing. After analysis of the tests, the RRC issued a statement, concluding: “At this time, there is no conclusive evidence the disposal wells tested were a causal factor in the May 7 seismic event. The tests were conducted to help determine the effect of injection operations on pressures within subsurface rock formations.”

Science and politics do not make good bedfellows.

 

 

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The Texas Supreme Court has ruled 5 to 4 that Chesapeake cannot deduct post-production costs from the Hyder family’s gas royalties.

The case in the Supreme Court actually addresses only the Hyders’ overriding royalty. As part of the Hyders’ oil and gas lease, the Hyders agreed that Chesapeake could use their land to drill horizontal wells producing from their neighbors’ land — the surface location on the Hyders’ land, but all of the productive lateral of the well under the neighbor’s property. In exchange, Chesapeake agreed to pay the Hyders a 5% royalty on production from such wells. Because the Hyders have no mineral interest in the lands from which these wells produce, the parties referred to this royalty as an overriding royalty.

The Hyders’ lease contains very specific provisions prohibiting Chesapeake from deducting post-production costs from the Hyders’ royalty on production from their lands. But the lease provision granting the overriding royalty on production from wells bottomed under their neighbors’ property is not so clear. Although Chesapeake originally fought to deduct post-production costs from both the royalties and the overriding royalties, the trial court and court of appeals ruled for the Hyders on all claims, and Chesapeake elected to appeal to the Texas Supreme Court only on the issue of deductibility of post-production costs from the Hyders’ overriding royalty.

The lease provision granting the overriding royalty calls for “a perpetual, cost-free (except only its portion of production taxes) overriding royalty of five percent (5%) of gross production obtained” from wells bottomed under neighbors’ land.” The lease also provided that “Lessors and Lessee agree that the holding in the case of Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996) shall have no application to the terms and provisions of this Lease.”

Justice Hecht wrote the majority opinion, joined by Justices Green, Johnson, Boyd and Devine. The parties’ arguments in their briefs and at oral argument focused on what was meant by “cost-free (except only its portion of production taxes).” Chesapeake argued that “cost-free” refers only to production costs. The Hyders argued that an overriding royalty is by definition free of production costs, so “cost-free” must refer to post-production costs. Justice Hecht said that “We disagree with the Hyders that ‘cost-free’ … cannot refer to production costs. … But Chesapeake must show that while the general term ‘cost-free’ does not distinguish between production and post-production costs and thus literally refers to all costs, it nevertheless cannot refer to post-production costs.”

Chesapeake made another argument, based on the requirement that the overriding royalty be based on “gross production.” It reasoned that “gross production” meant all gas, measured at the well when produced, so the value of that production must be measured at the wellhead, and any costs incurred thereafter must be shared by the royalty owner. The overriding royalty is expressed as a fraction of “gross production,” a royalty payable in-kind. Chesapeake argued that, if the Hyders elected to separately market their share of the gas, they would have to incur those post-production costs to get the gas to market, so the parties intended that the Hyders should bear those costs if Chesapeake sold the gas and paid the Hyders their 5% share of proceeds.  Hecht disagreed. “The fact that the Hyders might or might not be subject to post-production costs by taking the gas in kind does not suggest that they must be subject to those costs when the royalty is paid in cash.” Hecht concluded that “‘cost-free’ in the overriding royalty provision includes post-production costs.”

Four justices dissented. Justice Brown wrote the dissenting opinion, joined by Justices Willett, Guzman and Lehrmann. The dissenters agreed with Chesapeake that, because the overriding royalty was on “gross production,” the Hyders had to bear post-production costs. They concluded that “Though the overriding royalty may not have been expressed using the familiar market-value-at-the-well language, I read its value as being just that. Cf. Heritage, 939 S.W.2d at 131 (Owen, J., concurring).” Further discussing Heritage, Justice Brown said:

As recognized in Heritage, royalty clauses that purport to modify a royalty valued at the well are inherently problematic. 939 S.W.2d at 130 ((Owen, J., concurring)(“The concept of ‘deductions’ of marketing costs from the value of the gas is meaningless when gas is valued at the well.”). Here, no post-production costs have been incurred at the time of production, and it means nothing to say that the overriding royalty is free of those yet-to-be incurred costs.

In short, Justice Brown gave controlling effect to the “gross production” language, while Justice Hecht gave controlling effect to the “cost-free” language.

Justice Hecht’s opinion is interesting in its discussion of two other lease provisions. Although the case before the court did not encompass whether Chesapeake could deduct post-production costs from the Hyders’ royalty, Justice Hecht discussed the royalty clause. One of the provisions in the royalty clause states that the Hyders’ royalty shall be

free and clear of all production and post-production costs and expenses, including but not limited to, production, gathering, separating, storing, dehydrating, compression, transporting, processing, treating, marketing, delivering, or any other costs and expenses incurred between the wellhead and Lessee’s point of delivery or sale of such share to a third party.

Remarkably, Justice Hecht considered this language “surplusage”:

The gas royalty in the lease does not bear post-production costs because it is based on the price Chesapeake actually receives for the gas through its affiliate … after post-production costs have been paid. Often referred to as a ‘proceeds lease’, the price-received basis for payment is sufficient in itself to excuse the lessors from bearing post-production costs. And of course, like any other royalty, the gas royalty does not share in production costs. But the royalty provision expressly adds that the gas royalty is ‘free and clear of all production and post-production costs and expenses,’ and then goes further by listing them. This addition has no effect on the meaning of the provision. It might be regarded as emphasizing the cost-free nature of the gas royalty, or as surplusage.

Another provision in the Hyders’ lease disclaimed the holding in Heritage v. NationsBank:

Lessors and Lessee agree that the holding in the case of Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996) shall have no application to the terms and provisions of this Lease.

The royalty clause in Heritage  provided that Lessor’s royalty is

1/5 of the market value at the well of the gas so sold or used, provided, however, that there shall be no deductions from the value of the Lessor’s royalty by reason of any required processing, cost of dehydration, compression, transportation or other matter to market such gas.

The court in Heritage held that the lessee could deduct transportation costs from the royalty, and that the “no-deductions” proviso was “mere surplusage.”

The Hyders argued that the “Heritage disclaimer” clause in their lease showed the parties’ intent that their overriding royalty should be free of post-production costs. Justice Hecht disagreed:

Heritage Resources does not suggest, much less hold, that a royalty cannot be made free of post-production costs. Heritage Resources holds only that the effect of a lease is governed by a fair reading of its text. A disclaimer of that holding, like the one in this case, cannot free a royalty of post-production costs when the text of the lease itself does not do so. Here, the lease text clearly frees the gas royalty of post-production costs, and reasonably interpreted, we conclude, does the same for the overriding royalty. The disclaimer of Heritage Resources’ holding does not influence our conclusion.

The dissent also discussed Heritage.  Justice Brown notes that, unlike the gas royalty clause, the oil royalty clause in the Hyder lease provides for payment based on the “market value at the well” of the oil, just as in Heritage.  Justice Brown questions Justice Hecht’s conclusion that the “Heritage disclaimer” in the Hyders’ lease should have no effect even as applied to the oil royalty clause: “The disclaimer could be interpreted as a belt-and-suspenders attempt to ensure the ‘free and clear’ language is given effect despite its conflict with the oil royalty’s market-value-at-the-well definition.” In other words, the Heritage disclaimer might not be “surplusage.” But the four dissenting justices would nevertheless in effect follow Heritage. They would give effect to the “gross production” language in the overriding royalty clause, and would hold that this term is equivalent to the “at the well” clause in the Heritage royalty provision; and they would then hold that, because the overriding royalty is to be valued “at the well,” the language making the overriding royalty “cost-free” is, under Heritage, surplusage.

So, what should royalty owners and their counsel take from these opinions?

This firm filed an amicus brief in Hyder on behalf of the Texas Land and Mineral Owners’ Association and the National Association of Royalty Owners-Texas, in which we urged the court to clarify how royalty clauses should be construed in relation to post-production costs, and how much, if at all, the court’s prior decision in Heritage v. NationsBank should be relied on as precedent. Unfortunately, this case does not provide much guidance. Justice Hecht does note in a footnote that, on rehearing in Heritage, the court re-aligned itself, and one justice recused himself. The result, not mentioned in the footnote, is that the court was evenly divided on whether the Court’s original opinion was correct. And Justice Hecht’s opinion does say that “Heritage Resources holds only that the effect of a lease is governed by a fair reading of its text.” Perhaps this is Justice Hecht’s way of saying that Heritage has little precedential value where the text of the royalty clause differs from that in Heritage. But the continued power of Heritage is reflected in the fact that four justices dissented and would hold that Heritage requires a reading of the Hyder overriding royalty clause that would allow Chesapeake to deduct post-production costs, despite its “cost-free” language.

One lesson royalty owners and their lawyers should take away from Hyder: a “Heritage disclaimer” clause in a lease, without more, will not insulate the royalty owner from post-production costs.

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Yesterday the Texas Railroad Commission held the first of two scheduled show cause hearings called by the RRC to determine whether two salt water disposal wells near Azle, Texas should be shut down because they caused earthquakes in the area. The earthquakes in that region of Parker County are the subject of a recently published study by scientists at Southern Methodist University, which concluded that the quakes were probably caused by the injection wells. One of the wells is owned by XTO Energy, the other by Enervest. Enervest’s show cause hearing is scheduled for next week.

The XTO hearing was before two hearings examiners, Marshall Enquist and Paul Dubois. Hearings examiners act as administrative law judges in RRC hearings; they then propose a decision to the three commissioners, who can either accept or reject their proposed decision.

Only XTO appeared at the hearing, represented by their attorney Tim George, who called three witnesses and introduced more than 30 exhibits. XTO argued that the earthquakes were natural phenomena not caused by their injection activities. No witnesses appeared to oppose XTO’s position. A staff attorney at the RRC did ask some questions of XTO’s witnesses and offered the SMU study as evidence, over XTO’s objection. Tim George argued that the study was hearsay and that the scientists were not available to be cross-examined on the study. Marshall Enquist admitted the study as evidence over George’s objection, saying “in a way, [the SMU study] is why we’re here today.”

When the commissioners voted on whether to call the show cause hearings for XTO and Enervest, Ryan Sitton, the newest commissioner, opposed the order. Sitton organized a panel discussion on the SMU study at the RRC that took place last Friday, at which the SMU scientists, as well as scientists from UT, the RRC seismologist, and representatives of Enervest appeared. Sitton acted as moderator, but the other two commissioners did not attend. Enervest also argued in that panel discussion that its disposal well did not induce seismic activity, and that the SMU study is flawed.

Following the show cause hearing, the two examiners will write a proposal for decision that will be submitted to the commissioners.

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The Texas legislative session has now ended. I followed 44 bills identified as potentially affecting the interests of mineral owners. Only two of those bills passed.

HB 40

The bill that produced the most controversy was HB 40, introduced by Rep. Darby, chair of the House Energy Resources Committee. It restricts the ability of municipalities to regulate oil and gas operations within their jurisdictions. This bill and several other bills were introduced in response to the referendum passed by the City of Denton barring hydraulic fracturing. The bill allows cities to adopt ordinances related to oil and gas activity only if the ordinance regulates “aboveground activity … at or above the surface of the ground, including … fire and emergency response, traffic, lights, or noise, or imposing notice or reasonable setback requirements,” is “commercially reasonable,” and “does not effectively prohibit an oil and gas operation conducted by a reasonably prudent operator.” The bill defines “commercially reasonable” as:

a condition that would allow a reasonably prudent operator to fully, effectively, and economically exploit, develop, produce, process, and transport oil and gas, as determined based on the objective standard of a reasonably prudent operator and not on an individualized assessment of an actual operator’s capacity to act.

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The Texas Legislature has passed a supplemental appropriation of $4.471 million to fund a study of the cause of recent earthquakes in the Dallas-Fort Worth area. The money will be used to fund the purchase and use of seismic monitoring equipment and modeling of reservoir behavior, testing any connection between oil and gas activity and the recent swarms of quakes in the region.

The Bureau of Economic Geology at the University of Texas will lead the study in collaboration with other Texas universities, including the Texas A&M Engineering Experiment Station. The legislation requires formation of a nine-member technical advisory committee to direct the study. Members of the committee must include two members from universities who have seismic or reservoir expertise, to experts from the oil and gas industry, and the Texas Railroad Commission seismologist, Craig Pearson. A report must be provided to the Legislature by December 2016.

It is notable that the Legislature chose not to entrust the study to the Texas Railroad Commission, even though industry representatives favored that position. The Commission’s three elected commissioners rely heavily on contributions from the industry to fund their campaigns, and until the recent seismic activity in the DFW region, the commissioners refused to recognize the connection between earthquakes and oil and gas production in the Azle area of the Barnett Shale. Last month, a team of scientists published a paper concluding that the Azle seismic activity was more than likely linked to salt water injection wells in the vicinity. Those scientists testified before a legislative committee about their findings.

When Dallas shakes, people listen.

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Two recent articles brought to mind the trade-offs in the debate over hydraulic fracturing.

First, the Department of Environmental Conservation of New York State issued its Final Supplemental Generic Environmental Impact Statement, on the environmental impacts of allowing hydraulic fracturing in New York. New York has had a moratorium on fracking for the last several years, even though a substantial portion of the Marcellus formation underlies the state. It appears that New York is headed for a permanent ban on the practice.

I haven’t studied the EIS, which runs to several hundred pages. But it is a thorough catalogue and discussion of the environmental impacts of the drilling boom from fracking and horizontal drilling, most of which we know well by now: water use, surface spills, groundwater impacts, waste disposal, air quality, greenhouse gas emissions, health risks, visual impacts on the landscape, truck traffic, seismicity — all are discussed in great detail.

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Google has teamed up with the Environmental Defense Fund to detect leaks in gas lines in the Los Angeles Area, Boston, Indianapolis, Staten Island, Syracuse, and Burlington, Vermont. Google attached methane detectors to the cars it uses to create its street map images and has mapped the locations where it found levels of methane high enough to indicate pipeline methane leaks. A great use of new technology for a public purpose. View Google’s maps here.  EDF has teamed up with industry and scientists to attack methane emissions, part of EDF’s efforts to combat global warming.

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An excellent article by Judon Fambrough of the Real Estate Center at Texas A&M University, about how oil and gas leases can be extended beyond there primary term, can be found here. Great tips about how to avoid pitfalls in lease terms. Mr. Fambrough has written many good articles about negotiating oil and gas leases.

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Modern oil and gas leases often contain restrictions on the right of the lessee to assign the lease to third parties. The lease may require the consent of the lessor to any assignment, or it may impose conditions on the right to assign — for example, that the lessee retain an interest in the lease and/or remain operator.

Recently I received a draft of an article that will be published next year in the Buffalo Law Review addressing the validity of restrictions on assignments in oil and gas leases, and the authors asked that I make it available on this blog. It is titled “The Validity of Restraints on Alienation in an Oil and Gas Lease,” and it is authored by  Luke Myer and Rory Ryan, professors at Baylor Law School. There are actually two draft articles, one explaining the issue in layman’s terms and a second providing a more scholarly legal analysis with citations. The second article is titled “Aggregate Alienability.” The articles I think give a good analysis of the issue. There is actually little authority on whether restrictions on assignment, or “restraints on alienability,” in an oil and gas lease are valid. The authors make a good argument that such restrictions are valid. Good information for oil and gas lawyers, including tips on how to draft restrictions that are more likely to be upheld and enforced. The draft articles can be viewed here and here.

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This graphic from Bloomberg article, US Fracklog Triples as Drillers Keep Oil from Market (click to enlarge):

Fracklog

Bloomberg says that these uncompleted wells, if completed (that is, hydraulically fractured), would produce 322,000 bbls/day, equivalent to the current production of Libya. Total drilled but uncompleted wells, according to Bloomberg: 4,731.

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