For centuries the recording of deeds which pass title in real property from one to another has been carried out through some local designated official or recorder’s receipt and accounting of the physical deed itself. Now, at least in the Permian Basin (eastern New Mexico and West Texas), more counties of late have been accepting scans of such deeds or other documents conveying or affecting real property in lieu of receiving the physical form itself. This is a convenient situation for all involved, and in many cases it facilitates same-day recording as opposed to slowdowns caused by mailing each way and the document sitting on a pile in the county clerk or recorder’s office – no names mentioned (but the name of the county rhymes with Jeeves).

This convenience could potentially and unwittingly lead to unintended exposure when transacting to sell an asset during a remote or “virtual” closing where the parties are not physically meeting in the same location to close the deal. Under these circumstances in the mineral/royalty and leasehold A&D space, it is many times custom where escrow is not being utilized during the closing process for things to play out like this once both sides are in alignment following a buyer’s due diligence:

• Parties execute pre-closing documents in the lead-up to the actual closing (settlement statement, tax docs, non-foreign status form, etc.);
• Seller scans and emails the executed document conveying/affecting real property at the heart of the transaction; 
• Buyer remits payment, typically by wire transfer, following its visual inspection and approval of the scanned executed document; and
• Upon Seller confirmation of the arrival of the wire transfer(s), Seller overnights document(s) to Buyer and provides tracking info.

If you have read this article’s introductory paragraph then I imagine that you have already inferred where this is heading. Depending on the quality of the scanned image utilized in the step italicized in the list above, it is at least conceivable that a malfeasant buyer (especially a less well known one and/or one without an established reputation) could attempt to record the scan of the executed conveyance prior to remitting payment. The best outcome in such a scenario would be that it all gets sorted in the long run, but surely would be a nuisance. The worst outcome in such a scenario is that a buyer records the not-yet-paid-for conveyance document and then files a bankruptcy petition right afterwards, meaning the seller would likely be subjected to treatment by the debtor/trustee in possession as an unsecured creditor, and could potentially not end up recovering the ill-gotten property. The latter outcome is admittedly very specific and requires a very less than ideal set of circumstances, but the price of protection is very, very inexpensive.

Any seller of real property in our space would be wise to consider marking the scan of the conveyance document during a remote closing in some fashion that denotes that it is not intended—and not suitable—for recording. This can be achieved by watermark, some sort of inserted typeface indicating such, or even with a conspicuous “COPY” stamp. While the odds are low that a buyer would actually be brazen enough to attempt this, why not take a few seconds and totally negate that option?

Article also available at my LinkedIn page. Please note that this article is provided for informational purposes only, does not constitute legal advice, and represents the thoughts of the author individually and not necessarily those of his employer. All readers should contact their attorney to seek advice relating to the contents of this article, and should not act—or refrain from acting—based on the contents of this article without seeking such advice. 

Provisions in many modern oil and gas leases which effectuate depth severances (so-called “Pugh” clauses, often tied into retained acreage and/or continuous development provisions) can create great opportunity and value both for mineral owners and even potential subsequent lessees. Accurately ascertaining the demarcation point subsurface for such depth severances is critical – it could make the difference between the subsequent lessee paying for worthless subsurface depths or capturing prolific pay zones. Many of these depth severances are tied to a multitude of common reference points, including the depth of the deepest producing perforation in the wellbore, the base of the producing formation, and the total depth drilled in the well. 

Something I’ve seen a number of times in the last several years are determinations in title reports and title opinions that call the total depth drilled in a well vis-a-vis the Texas Railroad Commission’s “total depth” reference in its online database and record keeping system. This sounds pretty reasonable – after all, the plain meaning of total depth would seem to be pretty straightforward and clear on its face. Below is a screenshot of how this information would typically appear:

Easy enough, right? Well not so fast. If one were to examine the directional drilling report associated with the well, you’d see that the Railroad Commission’s total depth and the drilling report’s total vertical depth (“TVD”) of the well do not correlate once the well begins to deviate into a horizontal orientation, despite those numbers being nearly identical before the directional drilling commences. Oftentimes the two numbers are thousands of feet apart by the end – the length is continuously increasing on the X axis while on the Y axis it starts to taper off. Below are two excerpts of a drilling report associated with the well whose Railroad Commission total depth was previously set forth above – the first being at the beginning of the directional drilling, and the second at the conclusion of the directional drilling: 

On this well, the greatest TVD was around 10,685’ subsurface (which occurred in between the presented data sets), and this is obviously not as deep as the 13,500’ “total depth” stated on the Railroad Commission data set. Interestingly, if one were to examine the measured depth on the drilling report (“MD”), that more accurately ties back to the Railroad Commission “total depth.” It seems that “total depth” and TVD, when thinking back to an age of vertical wells, were one and the same since both were only increasing on the Y axis; the total depth drilled generally necessarily equaled the length of the wellbore. However, now that the wellbore’s trajectory is intentionally deviated from a vertical plane to a horizontal plane, the total depth/MD and the TVD of the well are consequently going to meaningfully deviate. 

With these details laid out the natural response would probably be “well of course”—particularly from any engineers in the audience—but for landmen and title attorneys blind to this nuance and who don’t spend all day in drilling reports, one can see where it would get past them sight unseen. So when making depth severance calls (whether in-house or as a contract land broker / title attorney), be sure to spend a few minutes perusing well drilling reports to get a more accurate understanding of where the depth severance may be since you may unwittingly and incorrectly declare valuable open depths as being subject to an existing oil and gas lease.

This article is also available at my LinkedIn page. 

This Saturday–July 20, 2019–will mark the 50th anniversary of mankind stepping foot on a non-Earth celestial body, a feat accomplished through the Apollo 11 mission. President Kennedy put forth the highly ambitious objective in 1961 to land an American on the moon before the end of the 1960s, made in the backdrop of the Soviets having recently beaten the United States into space with Yuri Gagarin being the first human to orbit our planet. Achieving that goal of landing man on the moon would take great mettle, effort, and sacrifice, but would become a resounding demonstration to the planet of what great feats America is capable of. Much of what we will hear about this week will be of the Apollo 11 astronauts particularly: Neil Armstrong, Buzz Aldrin (the two moonwalkers), and Michael Collins (who remained in lunar orbit). However, one of the unsung heroes and driving forces of the Apollo program who most people don’t know about was Gene Kranz, Flight Director of many of the program’s missions (the odd-numbered missions), including Apollo 11.

The Apollo program was created to succeed Project Gemini, which was designed to test human spaceflight in low Earth orbit and serve as a foundation for Apollo’s stated aim to eventually land man on the moon. However, the first mission in the program (Apollo 1) would be met with unthinkable tragedy when the mission’s three astronauts perished in a launch rehearsal test when a fire broke out in a pure oxygen environment of the flight capsule. Inquiries and investigations were conducted, and the consensus takeaway was that NASA had not sufficiently planned for contingencies, and flaws in the design of the vehicle contributed heavily in the astronauts’ deaths. On the Monday morning that followed the Apollo 1 disaster, Kranz assembled his team and told them the following, which would later be dubbed the “Kranz Dictum”:

Spaceflight will never tolerate carelessness, incapacity, and neglect. Somewhere, somehow, we screwed up. It could have been in design, build, or test. Whatever it was, we should have caught it. We were too gung ho about the schedule and we locked out all of the problems we saw each day in our work. Every element of the program was in trouble and so were we. The simulators were not working, Mission Control was behind in virtually every area, and the flight and test procedures changed daily. Nothing we did had any shelf life. Not one of us stood up and said, “Dammit, stop!” I don’t know what Thompson’s committee will find as the cause [of the disaster], but I know what I find. We are the cause! We were not ready! We did not do our job. We were rolling the dice, hoping that things would come together by launch day, when in our hearts we knew it would take a miracle. We were pushing the schedule and betting that the Cape would slip before we did.

From this day forward, Flight Control will be known by two words: “Tough” and “Competent”. Tough means we are forever accountable for what we do or what we fail to do. We will never again compromise our responsibilities. Every time we walk into Mission Control we will know what we stand for. Competent means we will never take anything for granted. We will never be found short in our knowledge and in our skills. Mission Control will be perfect. When you leave this meeting today you will go to your office and the first thing you will do there is to write “Tough” and “Competent” on your blackboards. It will never be erased. Each day when you enter the room, these words will remind you of the price paid by Grissom, White, and Chaffee. These words are the price of admission to the ranks of Mission Control.

Kranz still is able to deliver a good portion of this speech by heart, as demonstrated by this excerpt from a NASA documentary aired several years ago. It’s an amazing demonstration of self-reflection and the realization that NASA’s standards would need to much higher if they were going to successfully get a crew out of low Earth orbit and back, much less landing men on the moon. I and many others, despite the tragic circumstances that were at the root of Kranz’s speech, have found inspiration in his words and his ultimatum of not tolerating anything less than excellence that he delivered to his team.

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Back in 2015 and 2016, the lows of the oil market provided a painful reeducation of the volatility and whipsaw nature of the energy industry after a period of high prices and ceaseless optimism. Those same lows flushed out some less efficient operators and companies; in their stead came private equity-backed outfits looking to get into the Permian Basin while prices were still relatively low on the bet that oil prices – and consequently asset values – would proceed to march higher going forward. Flipping land and lease deals quickly became the transaction du jour and money poured in on the prospects of quickly multiplying money. For a few years lease and mineral deals seemed to be going that way. At this point, though, most of those easy deals are not being transacted quite as quickly or easily.

On the mineral side, not long ago the model was aggregate a large amount of mineral and royalty interests across a large chunk of the core areas in the Permian Basin, and then cash out to a buyer or buyers who would purchase large amounts across larger swaths of the Midland and Delaware Basins. Now, both E&P companies who choose to acquire minerals as well as institutional mineral/royalty funds are being much more selective about what they acquire and where. There are multiple reasons for this, the main ones being that the wild pace of drilling has been tempered (which slows down when minerals slated to be drilled upon would be producing cash flow), and even that some larger buyers are digesting a series of major acquisitions in the last couple of years. The consequence to private equity outfits is that now more effort will be required to hustle up and sell the acquired minerals; the days of one or a few massive firesales to liquidate large mineral and royalty portfolios would seem to be scant moving forward.

On the leasing side, for some time it had been easy to take some leases and quickly flip them to someone else who would either develop themselves or then pass it on to someone else who would. Blocking up an acreage position was just a function of taking leases strategically and then selling for the right price. Now the model requires more out of the lease reseller – oftentimes developing and proving the viability and value of the lease acreage, and then selling an end-stop buyer more of a turnkey asset. For private equity-backed companies, this represents far more risk and commitment then they may have anticipated going in. A good number of these private equity groups backing short-term acquisition companies probably did not anticipate having to sink millions of dollars into the ground in order to make their assets more attractive, nor the increased risk and potential operational and legal snafus that come along with holding and maintaining an operated asset producing oil and/or gas. This article from last month in the local Midland newspaper touches on these issues well.

So what does this all mean? At the surface level it means the typical amount of time from when a PE-backed company gets its funding to when it finally sheds itself of all of its acquired assets is surely going to increase. There will be more risk and exposure involved, particularly on the leasehold side where buyers in the market looking at a PE-backed company’s assets will insist on seeing wells drilled in order to assess how good the rock is before committing to purchase.  These are all manageable issues; the most important factor in all of this is that participants understand that the rules of the private equity game in the Permian Basin are ever-changing.

Please feel free to add me on LinkedIn. 

After having waited with baited breath for a few years, oil and gas professionals dealing with land, title, and leases heard from the Supreme Court of Texas (“SCOTX”) on a few anticipated disputes pertaining to “retained acreage” provisions. These provisions enable mineral owning lessors to encourage fuller development of the leased acreage and prevent lessee operators from holding an undue amount of acreage based on the production from one or a few wells.

In Endeavor Energy Resources, L.P., et al. v. Discovery Operating, Inc., et al., (No. 15-0155), SCOTX agreed with the lower court that, given the particular language of the lease’s retained acreage provision conditioning the amount of acreage retained to the assignment of acreage to a proration unit, that Endeavor’s inadvertent assignment of fewer acres than which it may have otherwise been entitled resulted in a termination as to their interest as to the leased lands not so assigned to the unit. At the urging of Discovery – as well as the numerous amici who chose to make their thoughts known to the Court – the justices determined that the idea of “assignment” used in this context is a term of art in the oil and gas industry, and can only reasonably be understood to mean the filing of a form with the Texas Railroad Commission assigning the number of acres according to that agency’s rules. While the Court agrees that the Railroad Commission does not have the power to adjudicate and determine property rights, in this situation the parties contracted in their lease such that the acres to be retained was expressly conditioned on such an assignment of acreage made with that regulatory body. Ultimately, as Chief Justice Hecht succinctly observes in the companion XOG case discussed below, Endeavor‘s holding is that a regulatory proration unit “assigned to a well” means acreage that is actually assigned by the operator, and not automatically by consequence of the applicable field rules governing the well.

Of note to the author was the discussion regarding “obtaining the maximum producing allowable,” a concept where the size of a proration unit in a given field can sometimes vary between a standard number of acres with the inclusion of up to a defined number of additional “tolerance” acres – this increase in size is tied to breadth of production. In a regulatory sense, larger units can produce more oil. In this case, Endeavor argued that because it could have assigned all of the tolerance acres available to it with the regulatory agency, that meant they could rely on language saying that the proration units were to have the “number of acres required to comply with [Commission rules governing obtaining “the maximum producing allowable for the particular well.” This reasoning did not persuade the Court; given that they assigned a number of acres per unit that was in between the standard and maximum sizes (with tolerance acreage applied), they were determined to have retained merely the lesser amount. More interestingly, toward the end of its discussion on this topic the Court briefly addressed the concept that the use of tolerance acreage – which affords the operator the ability to produce more oil from the well on that unit – in situations where the tolerance acreage is not needed nor warranted by the low production in an effort merely to squat in bad faith on more lease acreage than one would otherwise be entitled. The Court observed that “if a well is draining a certain amount of acreage, but the operator intends to claim more than the amount, the operator may open itself up to claims that it is not acting in good faith in purporting to retain a substantially greater amount of acreage.” Obviously this was not at issue here in this case, but this author believes that the Court is providing a preview of coming attractions in the next frontier of retained acreage disputes, where an operator assigns the standard acreage and also some or all of the tolerance acreage for a total greater than what it should be entitled to given lackluster production from the well in a given proration unit and purports to retain such excess acreage.

In XOG Operating, LLC v. Chesapeake Exploration LP (No. 15-0935), the Court leaves for the Endeavor decision the discussion on regulatory frameworks and lease provisions more broadly, but suffice it to say oil and gas practitioners know after reading these cases several things:

1. “Assignment” of acreage is, in the eyes of the Court, understood to mean an operator’s assignment of acreage with the regulatory agency (here, the Texas Railroad Commission).
2. The Court will consider any retained acreage dispute on the facts and particularly on the given language of the provision at issue, not unlike how the Court handles fixed vs. floating royalty disputes.
3. Scrutinize any retained acreage provisions that you or your client will be subject to quite carefully, because courts will apply them as written regardless of novel factual circumstances or unwitting clerical errors.

This blog post is also available at my LinkedIn page.