Big data, the oil industry, and legal frontiers

I remember the days when our family fax machine would churn all night to deliver well logs line-by-line for my father (geologist) to interpret. Back then (only ~20 years ago), great oil discoveries began by drawing on maps and geologic printouts with colored pencils.

By the time I was in college, his Blackberry (with its infamous scroll wheel) delivered near real-time updates on the drilling progress of horizontal wells in the Haynesville Shale. As a summer intern at a service company around the same time, I worked on a project to install eye-tracking devices in the dashboard of frac trucks to ensure drivers wouldn’t fall asleep at the wheel. My team also troubleshot how to link up various well site tools to real-time monitoring from Houston.

Things have changed rapidly, but the oil industry has always been at the cutting edge of technology, despite some perceptions to the contrary.

The new trend appears to be “big data” – the compiling and analysis of mountains of digital information. The hope is that somewhere in the numbers, a company can find competitive advantage in making new discoveries, improving efficiency, preventing waste, reducing emissions, trading commodities, preventing accidents, etc. A quick glance at open jobs at Houston oil companies reveals the trend of hiring for statistics, “big data,” and “data science”:

Friends in the industry with these skills have written software programs that detect illegal siphoning from pipelines, optimize oil hauling from tank batteries, and use machine learning to improve production tools. These kinds of projects just scratch the surface of what is afoot.

These changes in industry lead to new frontiers in litigation. Based on comments from practitioners (especially in-house folks) at recent CLE conferences, the following seem like practice areas set to grow in importance as a result of this increased focus on information technology, data, and statistical analysis:

Leaving employees. Though employment lawsuits to prevent trade secret misappropriation, violation of non-competes, etc. have always been common in the oil business, it seems likely there will be even more. With high paying statistics-driven and software-driven positions becoming more common, competitive information is no longer just held by geoscientists or managers. The secret sauce of lucrative predictive software, statistical conclusions, and other results of the data science revolution expands the number of employees who can hurt a company by leaving. Indeed, the information they take with them could be even more valuable, given that it may aggregate information from across the company.

Data breaches. Plenty of litigation has already arisen from data breaches in the consumer/retail industry. Data breaches in the oil business will look different. That is, they aren’t storing millions of people’s credit card information, but some (especially service companies) may be storing mountains of much more valuable proprietary customer data. Moreover, the potential perpetrators of hacking may include unsavory state-affiliated companies conducting industrial espionage. Violation of NDAs, confidentiality agreements, and even international arbitration may result.

Public policy torts. We’re in an era of climate change, methane emission, and coastal erosion litigation. Proving causation and damages are difficult, but data science projects looking for efficiency gains may inadvertently create damaging evidence for similar cases in the future. In other words, large scale data projects may match the scope of what these megalawsuits allege.



Poetic Oil & Gas Case Resolves New Mexico & Colorado Royalty Issues

“Fossil fuels are the decomposed remains of prehistoric flora (coal) and fauna (oil and gas). They have driven the world’s economy (particularly that of the United States) for over a century. Discovering marketable deposits, extracting them from the ground, refining them, and delivering them to consumers in useful form is big business, on one hand fraught with risk and on the other richly rewarding . . . Since oil and gas are the most energy dense and convenient of the fossil fuels, litigation and regulation abound with respect to them. “

–  Circuit Judge Terrence L. O’Brien, writing for the Tenth Circuit in Anderson Living Tr. v. Energen Res. Corp., No. 16-2124, 2018 WL 328884 (10th Cir. Jan. 9, 2018).

Poetic introduction aside, this case delves into two important issues in royalty litigation. Attorneys and landmen in the San Juan Basin, Permian, etc. should take note. As should royalty practitioners elsewhere, because one of the issues (royalty implications of fuel gas) is regularly the subject of royalty audits and lawsuits.

Marketable Condition Rule

First, the case addresses whether and to what extent New Mexico adopts the so-called “marketable condition rule.” Jurisdictions that follow this rule interpret the implied covenant to market in oil and gas leases such that lessees generally bear more of the cost of post-production expenses in the calculation of royalty payments. The gist of the rule is that lessees must first make the hydrocarbons “marketable” at their own expense. After that, post-production expenses can be charged to royalty owners if they are cost-justified. If and when a product is “marketable” is usually the subject of controversy.

In this case, the plaintiffs (a group of New Mexico royalty trusts) sued Energen for breach of this implied covenant, relying on the marketable condition rule. They had leases specifying that royalty is paid based on the “market value at the well” or the “prevailing field market price.” The federal district court granted Energen’s motion to dismiss this claim prior to discovery for failure to state a claim. On appeal from this order, the Tenth Circuit recognized that New Mexico has not yet decided whether to follow the marketable condition rule, but recognized that the Tenth Circuit, predicting New Mexico law, had already decided that New Mexico would not adopt the rule. Notably, the Tenth Circuit declined to certify a question to the New Mexico Supreme Court on this issue.

Fuel Gas

Lessees (or their midstream providers) often use produced natural gas as fuel to power equipment needed to process the gas and/or move the gas through gathering systems and transmission lines. Here, the royalty trusts (including an additional one from Colorado) alleged that Energen must pay them royalty on the volumes of gas used as fuel. The Tenth Circuit largely rejected this claim, but it’s important that practitioners are aware of this decision, especially its reasoning:

  • The “free use” clause in the New Mexico leases permitted the lessee to use gas in “furtherance of the lease operations.” This is a broad view of free use clauses in that is driven by purpose of the relevant activity, not location (on/off lease). Not so for the Colorado leases, because Colorado has not favorably cited a case adopting this broad view, like New Mexico has.
  • When the royalty clause calls for payment on “marketed” volumes of gas, fuel gas is excluded from the calculation because it is never marketed (i.e. sold). By contrast, when the royalty clause calls for payment on “produced” volumes, royalty is owed on fuel gas, because fuel gas was “produced” even though it was later burned before being sold. This is intuitive based on the plain language, but this is one of the first published cases to directly address this distinction.
  • In a twist, the Court then held that because some of the relevant royalty provisions call for valuation at the “prevailing field market price . . . at the time when produced,” the lessee “may deduct the value of the fuel gas consumed as a post-production cost (along with other post-production costs), but it must also pay royalty on the wellhead value of the fuel gas consumed.” This is confusing because, unless I’m mistaken, the result is that these will cancel out because the value of the gas when used is unlikely to differ much (if at all) from the value at the wellhead.

Eagle Ford non-op can contest excessive gathering fees in court

The Houston 14th Court of Appeals issued a very interesting decision last month concerning the “exclusive jurisdiction” of the Texas Railroad Commission. The case is In re BHP Billiton Petroleum Properties (N.A.), LP, No. 14-17-00436-cv, 2017 WL 6331103 (Tex. App.—Houston [14th Dist.] Dec. 12, 2017, orig. proceeding) (mem. op.).

Discussing the difficult task of balancing environmental stewardship and hydrocarbon production with Texas Railroad Commissioner Christi Craddick.

A non-op in the Eagle Ford sued BHP, the operator, for charging excessive gathering fees under a set of JOAs. The gist of the claim is that BHP owned part of the gathering company (named Eagle Ford Gathering), so it had a  conflict of interest in the gathering fee negotiations that disadvantaged the non-ops, who had no interest in the gathering company. The JOAs contained  language that BHP would operate the joint prospect as a “reasonable prudent operator, in a good and workmanlike manner, with due diligence and dispatch, in accordance with good oilfield practice, and in compliance with applicable law and regulation . . .” (emphasis based entirely on the name of this blog). In the non-op’s view, by agreeing to an above-market gathering rate with a BHP-affiliated gathering company, BHP breached this contractual standard of care.

When the non-op sued BHP in Houston, BHP filed a plea to the jurisdiction contending that the court had no jurisdiction over this gathering fee claim because the Texas Railroad Commission had exclusive jurisdiction over the rates charged by gas utilities such as Eagle Ford Gathering. The trial court denied the plea, but BHP filed a petition for a writ of mandamus in the Houston Court of Appeals to order the trial judge to dismiss this claim.

BHP argued in its mandamus petition that the Texas Gas Utility Regulatory Act vested sole power to decide the reasonableness of gathering fees in the Texas Railroad Commission. This argument struck me as far-fetched when I first read it, but after reading further, I can see why BHP gave this a shot. The Act states that it establishes “a comprehensive and adequate regulatory system for gas utilities to assure rates, operations, and services that are just and reasonable to the consumers and to the utilities.” Its scope is also broad, applying to all natural gas transportation infrastructure not subject to federal regulation by FERC. Best of all (for BHP),  the Act also says that “[t]he railroad commission has exclusive original jurisdiction over the rates and services of a gas utility.” Utilities must file rate schedules with the RRC, and the RRC then determines if a gathering fee is “just and reasonable” based on factors set forth in the Act. That all sounds like a plausible exclusive jurisdiction argument.

However, the Houston Court of Appeals rejected BHP’s argument, based on a key distinction. In the Court’s view, the non-op was not specifically contending that the gathering fee was not “just and reasonable” under the Act. If that were the case, the non-op would have sued Eagle Ford Gathering, the gathering company, not BHP. Instead, the non-op was claiming that BHP chose to hire the wrong gathering company (out of several different options), all of which had their rates approved by the RRC. In other words, there may be several gathering companies with “just and reasonable” rates under utility regulations, but an operator may still be liable to the other working interest owners for hiring the most expensive one based on an alleged conflict of interest.

Keep in mind that the Houston Court of Appeals addressed only the jurisdictional issue of whether the trial court is the proper place to fight. BHP can still contest the non-op’s allegations about BHP’s conflict of interest and the above-market gathering fee. Moreover, cases like this depend on the specific JOA language, which may contain a gross negligence/willful misconduct standard, waivers of certain kinds of damages, provisions related to the use of affiliates, etc.


Dead Royalty Owners Doom Motion to Remand from Beyond the Grave

Yes, the title of this post is a shameless Halloween reference, but the underlying issues in a recent federal court decision from Oklahoma are important to royalty litigation practitioners. The case is Jerry Venable Revocable Family Tr. v. Chesapeake Operating, LLC, 2017 WL 4052808 (W.D. Okla. 2017).

Here’s what happened: some royalty owners filed a class action complaint against Chesapeake in Beaver County in the Oklahoma panhandle.  Chesapeake removed the case to federal court under the Class Action Fairness Act (CAFA), but the royalty owners filed a motion to remand the case back to state court. The royalty owners claimed the case fell under the so-called “home state exception” to CAFA jurisdiction, which prevents removal to federal court when 2/3 of the proposed class and the defendant are both “citizens” of the removal state (here, Oklahoma).

To prove that 2/3 of the proposed class were Oklahoma citizens, the Plaintiffs hired a statistics expert. This expert used random sampling and other statistics tools to make that case that 2/3 of the proposed class were  Oklahoma citizens and submitted an affidavit to the Court alongside the Plaintiffs’ motion to remand.

The expert and the royalty owners’ motion ran into two problems, however.

  • First, the expert’s data did not take into account that around 14% of the proposed class were trusts (legal entities), whose citizenship is determined by the citizenship of their underlying members/beneficiaries, which was apparently unknown.
  • Second, “the Court found a number of individuals that were found to be Oklahoma citizens on plaintiff’s counsel’s data compilation that [other data provided by the expert] indicated were deceased.”

Obviously, this was an embarrassing mistake, but the presence of dead royalty owners in the expert’s calculations also had legal consequences. Namely, the Court would need to know the citizenship of the dead royalty owners’ heirs, which was unknown, in order to determine whether the 2/3 Oklahoma citizens threshold under CAFA had been met.

This case the highlights the need for royalty class action attorneys to understand the nuances of determining and proving state citizenship (for corporations, LLCs, trusts, deceased potential class members, etc). These issues are especially important in complicated “overlapping,” parallel, or “gerrymandered” class actions where class definitions often refer to residents or citizens of certain states in order to avoid removal under CAFA. Indeed, in most of these situations, the procedural and jurisdictional nuances become like a tortuous civil procedure and federal courts exam from law school. Best to stay up to date and do your jurisdictional homework. Otherwise, you risk being haunted by deceased class members, as here.

Oilfield Contractor Cannot be Held Liable for Damage to Adjacent Vertical Well

A few months ago, the Wall Street Journal article “Frackers Collide With Traditional Oil Drillers” was widely shared in the oil and gas world, concluding that “[s]upersized new oil wells are sometimes running into existing wells, a little-noticed consequence of the shale boom that has started to trigger complaints and lawsuits.” So-called “well interference” was the talk of the town. Here’s a link to the original WSJ article, which has retreated behind a paywall.

Well, a federal court in Oklahoma has helped clarify who can be sued for well interference and who can’t, at least in Oklahoma. In short, the court held that Halliburton, the completions contractor for a horizontal well drilled by Newfield in the SCOOP/STACK play, could not be held liable for alleged damage to an adjacent vertical well owned by another operator.

Here are the facts: Singer Oil Company, a small privately-held Oklahoma exploration and production company, had a vertical well in Kingfisher County, Oklahoma. Newfield came along and completed a horizontal well next to it, allegedly damaging Singer’s vertical well in the process. Singer sued Newfield and its completion contractor, Halliburton, seeking to recover for the damages to its wellbore.

Halliburton filed a motion for summary judgment, arguing that, as the mere contractor of Newfield, it had no “duty” (a required element for tort claims) to Singer. Thus, it could not be held liable for the damage in this case. Singer tried to keep Halliburton in the case by arguing that Halliburton had a duty to provide Singer with notice of the impending completion job, but the Court rejected this argument and alternatively held that, even if Halliburton had such a duty, the failure to warn was not the “proximate cause” of the vertical well damage.

For now, the case remains pending against Newfield.

TRO-X v. Anadarko: Participation Agreements, Top Leases, and Releases

Landmen and upstream counsel should take note of a case set to be argued in the Texas Supreme Court in early 2018: TRO-X v. Anadarko. The case involves several important issues: negotiating with landowners when they claim a lease has expired, how to draft “anti-washout” language in a participation agreement (or similar contract), and the significance (or lack of significance) in executing formal releases of expired leases.

The basic facts are that TRO-X took a lease in 2007 out in the Permian. TRO-X later assigned the lease but reserved the right to “back in” for a 5% working interest if the lease reached payout (i.e. total revenues = total costs of development). This back-in right was contained in a participation agreement with the assignee. Eventually, Anadarko acquired the lease, subject to the participation agreement.

Notably, the participation agreement contained a clause stating that the back-in right “shall extend to and be binding upon any . . . top lease(s) taken [on the original lease] within one (1) year of termination [of the original lease].” (emphasis added by me)

Williams & Meyers Manual of Oil & Gas Terms defines a “top lease” as: “A lease granted by a landowner during the existence of a recorded mineral lease which is to become effective if and when the existing lease expires or is terminated.” (citing almost 3 pages of case citations). More on this in a minute.

While Anadarko was operating the lease, the lessors claimed that Anadarko had violated its contractual duty under the lease to drill an offset well. That is, Anadarko had drilled a well on the lease next door, which the lessors claimed triggered a lease provision requiring Anadarko to drill on well on their lease, too, in order to prevent drainage of the oil under their land. According to the lease, such a failure was grounds for termination. Anadarko apparently conceded this failure but entered into negotiations with the lessor over how to fix things.

TRO-X and Anadarko dispute what happened next. Anadarko claims the original lease expired and it took an entirely new lease on the property. Because an entirely new lease is not the same thing as a “top lease” (per the definition above), Anadarko argues that it does not owe TRO-X the 5% back-in under the participation agreement. In other words, Anadarko effectively “washed out” TRO-X’s back-in.

TRO-X, on the other hand, claims that Anadarko did, in fact take a “top lease.” As evidence, TRO-X noted that the new lease was signed 13 days before a formal release of the 2007 lease was executed. According to TRO-X, there is at least an inference that the new lease was signed while the 2007 lease was still in effect; thus, the new lease was a “top lease” triggering the back-in right under the participation agreement.

After a one day bench trial, the trial court entered judgment in favor of TRO-X, concluding that TRO-X had a back-in right to the new lease and ordering Anadarko to produce financial information to determine whether payout had been reached.

On appeal, the El Paso Court of Appeals framed the issue as whether there was legally sufficient evidence to support the trial court’s conclusion that the new lease was, in fact, a “top lease.” This is a question of intent (both Anadarko’s and the lessors’). The Court concluded that the only evidence supporting the trial court’s decision that the lease was a top lease was the 13-day gap between the signing of the new lease and the execution of the release. The Court noted, however, that “the presence or absence of a written release is not outcome-determinative” of the leasing parties’ intent, and absent some other evidence (email, deposition testimony, etc.) besides the 13-day gap that the new lease was intended to be “top lease,” there was not enough evidence to justify the trial court’s decision.

Based on the briefing the parties submitted to the Texas Supreme Court, the high court looks as if it will primarily address: (a) who bears the burden of proof in proving or disproving that the new lease was a “top lease”; and (b) whether a 13-day delay in executing a formal release is, standing alone, sufficient to support a finding that the original lease was still in effect when the new lease was signed.

But there are more takeaways from this case. One is that this entire case could have been avoided had TRO-X drafted a more robust “anti-washout” clause in the participation agreement. By limiting its back-in rights to “top leases,” TRO-X opened itself up to washout via other forms of leasing.  Better to include all forms of renewals, extensions, top leases, and brand new leases taken on the same property within a given time frame and specified area. Moreover, the argument that a delay in execution of a formal release could mean the original lease remained in force is surprising to me. The original lease here apparently (and I am not 100% certain) made compliance with the offset clause akin to a special limitation (as opposed to a covenant), where any breach of the clause results in automatic termination and reversion of the lease to the lessor. If so, execution of a formal release is a more of housekeeping matter for title record purposes than a necessary condition for reversion of the lease.

We’ll have to wait and see how this one turns out – oral argument is set for January 9, 2018.

Tenth Circuit Affirms Return of Royalty Class Action to Oklahoma State Court

Earlier this week, the Tenth Circuit affirmed an Oklahoma federal district court’s decision to remand a putative royalty class action to state court under the so-called “discretionary” exception to federal jurisdiction under the Class Action Fairness Act (CAFA). The case is Speed v. JMA Energy Co., LLC, 2017 WL 4342615 (10th Cir. 2017) and is a must-read for anyone who works with royalty class actions, because of its relatively deep dive into the so-called “discretionary” exception to CAFA jurisdiction.

The plaintiff royalty owner, represented by the well-known plaintiffs’ side Lanier Law Firm from Houston, filed the case against JMA Energy in Hughes County, Oklahoma alleging, among other things, that JMA committed fraud by concealing its obligation to pay interest on late royalty payments in accordance with an Oklahoma law. JMA removed the case to federal court, but then Speed moved to remand under the jurisdictional exceptions in CAFA.

It’s easy to forget about the exceptions in CAFA, so take note: not every $5 million, non-gerrymandered class action stays in federal court. Two exceptions are mandatory, but both require (in addition to other things) that 2/3 of the class members be citizens of the state from which the case was removed. The third exception is discretionary but only requires at least 1/3 of the class members to be citizens of the removal state and that the “primary defendants” are also from the removal state. In other words, cases that seem very-Oklahoma must stay in Oklahoma state court and cases that are at least somewhat-Oklahoma might stay in state court.

In this case, the parties stipulated that the number of Oklahoma class members was between 1/3 and 2/3 of the total, so we are mercifully spared from having to delve into the other requirements for mandatory remand under CAFA – only the discretionary exception matters.

Under CAFA, if the two prerequisites for the discretionary exception are met, a district court analyzes six factors (listed in CAFA) to decide a motion to remand. Notably, a trial court’s grant/denial of a motion to remand based on these factors is reviewed for abuse of discretion and the burden is on the party seeking remand.

In its opposition to Speed’s motion to remand, JMA Energy made two clever (but unsuccessful) arguments. First, JMA argued that the number of class members from the removal state should be looked at on “sliding scale.” The more class members from the removal state (up to 2/3), the more likely remand should be; the less from the removal state (down to 1/3), the less likely remand should be. Unfortunately for JMA, the percentage in this case was roughly halfway between 2/3 and 1/3 (48%), so this argument took them nowhere. JMA also argued that “neutral” factors should count against remand because the burden is on the other side; the Court disagreed, holding that the factors are evaluated “in the aggregate.”

Here’s how the factors played out:

(A) whether the claims asserted involve matters of national or interstate interest;

  • All the wells are in Oklahoma, and this was built into the class definition;
  • Even though some royalty owners live elsewhere, they “purposely availed” themselves of Oklahoma jurisdiction by owning minerals there;
  • The influence of Oklahoma law on other jurisdictions weighs in favor of letting Oklahoma courts, which are more familiar with Oklahoma law, to decide the issue

Weighs in favor of remand.

(B) whether the claims asserted will be governed by laws of the State in which the action was originally filed or by the laws of other States;

  • The “backbone” claim is about an Oklahoma royalty statute;
  • The trial court should have given more weight to potential choice-of-law issues on Speed’s fraud claim, but this was a “piggyback” claim on the statutory claim, and it looks like the choice-of-law question would result in Oklahoma law applying, anyway;
  • “Almost everything about this case is suffused with the distinct aroma of Oklahoma.” (???)

Weighs in favor of remand.

(C) whether the class action has been pleaded in a manner that seeks to avoid Federal jurisdiction;

  • Exclusion of public companies from the class definition was not a gerrymander to avoid CAFA. According to Speed, these companies are violating the same royalty statute; (we’re going to see more of these class actions?)
  • It’s somewhat common practice to do this.

Weighs in favor of remand.

(D) whether the action was brought in a forum with a distinct nexus with the class members, the alleged harm, or the defendants;

  • Seems obvious that Oklahoma has a nexus with wells in Oklahoma and violations of an Oklahoma statute;
  • The use of “forum” rather than “state” in this factor does not mean that the court should look to intra-state jurisdictional divisions, such as counties with little connection to the case, absent “clear abuse”;
  • No evidence of such abuse here;
  • Look to state jurisdictional rules once you’re back in state court.

Weighs in favor of remand.

(E) whether the number of citizens of the State in which the action was originally filed in all proposed plaintiff classes in the aggregate is substantially larger than the number of citizens from any other State, and the citizenship of the other members of the proposed class is dispersed among a substantial number of States;

  • Even though a majority of class members are from out of state and 20% are from Texas, the purpose of this factor is to “ensure that no other state has a significant interest in the controversy as does Oklahoma.”

Weighs in favor of remand.

(F) whether, during the 3-year period preceding the filing of that class action, 1 or more other class actions asserting the same or similar claims on behalf of the same or other persons have been filed.

  • No overlapping class actions on file. (yet?)

Weighs in favor of remand.

Altogether, every factor weighs in favor of remand, despite clever lawyering by JMA’s counsel. Accordingly, the trial court did not abuse its discretion in sending the case back to Hughes County.

New “Induced Seismicity” Study Published

Geophysicists at the University of Alberta recently published findings their study of modern oil and gas operations’ impact on seismic events, such as earthquakes. The paper,  entitled “Human-induced seismicity and large-scale hydrocarbon production in the USA and Canada” was published in Geochemistry, Geophysics, Geosystems, available here:

(note paywall).

This is just the latest in long line of academic papers discussing whether hydraulic fracturing and/or wastewater injection in shale plays contribute to man-made earthquakes. The scientific controversy relates to lawsuits in North Texas, Oklahoma, and Arkansas (and likely others), and has been covered in great detail at some of the major industry CLEs.

Available summaries of the article indicate this most recent publication is generally pro-industry in its conclusion – that hydraulic fracturing and wastewater disposal are generally not correlated with increased seismic activity – though it appears there may be exceptions for Oklahoma and localized areas.


Christmas in July – New Publications Every Oil and Gas Attorney Should Read

After a long Fourth of July weekend, I returned to the office to find two stellar new publications from the Oil, Gas & Energy Resources Section of the Texas bar in my inbox.

The first is a hardcover compilation of “Twenty Cases That Shaped Texas Oil and Gas Jurisprudence,” published by the Section itself.  Right away, I noticed that the book is beautiful, worthy of a place on a display shelf or coffee table. But the content is also outstanding. The editors included not just the twenty cases themselves, but also recruited a who’s who of prominent Texas oil and gas practitioners and scholars to provide commentary about why each case was selected, additional facts influencing the case behind the scenes, and how the case fits in the long arch of Texas oil and gas law. Included were cases I expected: Elliff, Koontz, Vela, & Middleton, but also several surprises, some of which I still need to read. All in all, this is an excellent publication and a wonderful surprise from the Section.

The second arrival was the quarterly Section report from the State Oil and Gas bar, which never disappoints in terms of relevance to current practice. From a high-stakes civil litigation perspective, I found two articles particularly worth reading.

  • First was “Upstream and Midstream Enforcement Trends” by  James Martin, Jennifer Keane, and Patrick Leahy – a comprehensive survey of recent regulatory actions by federal and state agencies affecting oil and gas operations. Though I do not practice in the regulatory space, the events addressed in the article – excess emissions, oil spills, etc. – regularly spawn parallel civil lawsuits (property damage, lost production, royalty underpayment, surface use, force majeure, contract liability, personal injury, and so forth), as I’ve seen in my own practice. Staying up to date on regulatory enforcement provides a window into what keeps my clients up at night besides their pending civil cases, foreshadows at least some of the kinds of civil cases I should expect to see in the future, and keeps me apprised of technological developments in the industry so I can better understand my clients’ businesses. This article helped with all of that, especially the summary of recent consent decrees (essentially regulatory settlements) entered into by major producers for tank battery emissions.
  • The second was “Area of Mutual Interest Agreements” by JJ McAnelly and Molly Butkus, an introduction to major legal issues regarding the enforceability of AMIs, which in my anecdotal experience, are an increasingly common basis for oil and gas lawsuits. The authors’ treatment of whether and how the Rule Against Perpetuities applies to AMIs in multiple jurisdictions serves is a handy go-to summary for deal and trial lawyers alike tasked with drafting, enforcing, or busting AMIs, as the case may be.

Happy reading to all in the oil and gas bar. Until then, keep operating prudently.


Why did it take you so long to launch this blog, Robert?

Because I have discussed creating this blog with some of you more than once over the last several months, but had taken no action, I’m sure that some of you had lost hope that would ever see the light of day. Alas, here we are.

So, what took so long? Well, that is a great topic for my first post.

The short answer is three scheduled trials and $451.4 million in combined alleged damages.

  • $1.4 million. One of our oil and gas clients entrusted me and a colleague to handle an aggressive personal injury matter involving a company truck. I was grateful for the opportunity to handle most of the major tasks (depositions, mediation, etc.) due to the smaller amount in controversy, and we managed to secure a favorable settlement less than a month before trial.
  • $300 million. Just days after settling the personal injury matter, I was off to a class action royalty trial in federal court in Little Rock, Arkansas. The case involved more than 12,000 Fayetteville Shale royalty owners seeking $100 million in actual damages and double that in punitive damages for alleged improper royalty deductions for gathering and treating services provided by an affiliated midstream company. I’ll spare you the details for now (an appeal has been filed), but the case is certainly one of the few (only?) large royalty class actions to be tried to a verdict in recent history.  After a two-week trial, the jury deliberated for roughly seven hours late into a Friday night (they ordered pizza), and returned a full defense verdict for our client. It was an exhausting but thrilling victory. I flew home, took the weekend off, grilled a celebratory steak, got back into childcare duty, took my dog on a walk, and finally made it back to the gym. But another trial was on the horizon.
  • $150 million. The third and final act was a negligence, subsurface trespass, and nuisance case arising out of the operation of an “acid gas” disposal well that injects hydrogen sulfide and carbon dioxide (unwanted production byproducts) underground in a rural county in a major shale play. An adjacent operator alleged that our client’s disposal activities had impacted its production to the tune of almost $150 million. This past Wednesday, less than three weeks before voir dire was set to begin, the Court granted summary judgment in favor of our client, disposing (pun intended) of all the pending claims.

Now, with a little breathing room, it’s time to get this blog going. So get ready – because of these trials, I have a Dropbox folder that is backlogged and overflowing with interesting cases and articles to read.