[Editor's note: A version of this story appears in the January 2020 edition of Oil and Gas Investor. Subscribe to the magazine here.]

Five years have passed since commodity prices cratered and the energy industry faced an onslaught of producer bankruptcies. For almost as long, producers and midstream companies have squared off over whether dedications in gathering and processing agreements are real property interests—and therefore immune from the reach of the bankruptcy court—or executory contracts that may be shed by a debtor through the restructuring process.

The Permian Basin continues to be an attractive investment opportunity, thanks in no small part to its vast reserves of stacked, oil-bearing formations located within Texas—a state that has traditionally been pro-business and pro-development. Texas has also developed a body of statutory, regulatory and court-made oil and gas law giving investors and operators the certainty necessary to understand and account for the legal risks associated with oil and gas development. However, even in the Permian Basin, oil and gas development has always been a risky venture, and that is as true today as it was during the heyday of conventional development, if not more so. Permian Basin development poses certain legal risks that nonoperating investors in particular should be aware of.

Unconventional development through horizontal drilling is different in many aspects from conventional development, including the amount of land required for development, the way that wells are drilled and the way that gathering and processing facilities are located and built. And even those basic aspects of oil and gas development that are largely the same for unconventional as for conventional development, such as oil and gas leases and joint operating arrangements (JOAs), can create new layers of legal risk based on the differences between the two types of development. All of these factors combined have created both new legal issues and new twists on established oil and gas legal principles that Texas courts have not yet addressed, adding a layer of complexity and developmental risk not always present in conventional exploration and development.

Nonoperating investors should be alert to these four legal issues:

  • JOAs and the strong protection afforded operators under Texas law;
  • Unsettled legal issues unique to horizontal drilling;
  • Legal issues arising from potential development constraints; and
  • Legal issues surrounding various exit strategies for nonoperating investors.

Key ways JOAs favor the operator

Much ink has been spilled on the subject of JOAs, particularly the American Association of Petroleum Landmen (AAPL) Model Form JOAs widely in use in the U.S. Nonoperating investors, however, should be especially alert to some of the provisions that give incumbent operators strong protection, particularly given the likelihood that any lease position acquired in the Permian Basin will be subject to one or more of these agreements.

For starters, nonoperating investors who are less than pleased with the current operator of their assets should know that JOAs and Texas case law generally place a high bar to operator removal.

The 1989 AAPL Model Form JOA, for example, requires a showing of “good cause,” which need not be as high as gross negligence or willful misconduct (though those surely would count) but must still amount to a “material” breach or failure of obligation. What counts as “material” outside the gross negligence context is somewhat unclear because there are so few reported Texas cases on the subject.

In the Tri-Star Petroleum Co. v. Tipperary Corp. decision—arguably the best Texas case analyzing the level of conduct that might support removal for failure to carry out duties—a nonoperator satisfied the legal standard for removal by showing that the operator had: (1) improperly assessed charges against the joint account; (2) failed to supply reasonable information requested by the nonoperators; (3) commingled legal fees with other funds in the joint account; (4) classified and reclassified amounts billed to joint account, without explanation; (5) failed to provide timely and proper adjustments to the joint account; (6) double charged nonoperators on cash calls and subsequent billings; (7) allowed the premature loss of acreage to the government; and (8) was unable to sustain the deliverable quantities of gas under existing contracts.

While Tri-Star likely presents a more extreme scenario, the case provides a helpful roadmap for other operator removal disputes in terms of the quantity and quality of evidence required to replace an incumbent operator.

Additionally, insolvent operators may not always be subject to removal, even where the JOA provides for it. While it is commonplace for JOAs to provide that an operator may be removed based solely on insolvency or bankruptcy, Texas courts have held that such provisions are unenforceable under the Bankruptcy Code.

As one Texas bankruptcy court puts it in the U.S. Energy Development Corp. v. WBH Energy Partners case: “[N]otwithstanding a provision in an executory contract or unexpired lease, or in applicable law, an executory contract or unexpired lease of the debtor may not be terminated or modified, and any right or obligation under such contract or lease may not be terminated or modified, at any time after the commencement of the case solely because a provision in such contract or lease that is conditioned on ... the insolvency or financial condition of the debtor at any time before the closing of the case. ...”

The WBH Energy decision clarified that a bankrupt or financially insolvent operator can still be removed, despite an ipso facto clause, but only where the party seeking removal demonstrates other factors, beyond the bankruptcy itself, that justify removal. In other words, high-bar factors like those listed above still would need to be established.

Even when operator removal is not being considered, nonoperating investors should be aware that JOAs, by design, give the operator sole control over administration of the joint account and typically establish pay now, complain later billing regimes. They provide nonoperators with limited ability to refuse payment of disputed charges.

For instance, the 2005 Accounting Procedure recommended by the Council of Petroleum Accountants Societies Inc. provides, with limited exceptions, that each party shall pay its proportionate share of all bills in full within 15 days of receipt. Those exceptions cover major discrepancies like being billed at an incorrect working interest that is higher than the nonoperator’s actual working interest or being billed for a project or AFE that the nonoperator never approved.

For most everything else, though, the nonoperator’s only protection is that payment of any such bills does not prejudice its right to subsequently protest or question the correctness of the operator’s bills. Typically, those types of protests are raised during the course of annual or periodic expenditure audits, but the typical audit provision gives the operator a generous period of time up to 15 months after an audit report is issued, which itself could take several months to prepare to resolve any audit exceptions before they may be submitted to litigation or other alternative dispute resolution. This means that nonoperating investors could be forced to carry their proportionate share of improper charges against the joint account for as long as one to two years.

All of this is to say that what the JOA giveth the operator, the JOA generally does not taketh away and neither do Texas courts. Therefore, nonoperating investors in the Permian Basin should be mindful on the front end and scrutinize not only the operator’s operating experience, but also its administration experience and other back-office capabilities that are critical to the success of any multiparty oil and gas venture.

Unsettled legal issues related to horizontal drilling

Texas’ developed body of oil and gas law is a product of the conventional, vertical drilling prevalent while most of it was created during the 20th century. As a result, some established legal principles apply equally to unconventional and conventional development and some do not, leaving gaps in the law that Texas courts have yet to fill.

Two examples of established oil and gas principles that apply equally to conventional and unconventional development are the accommodation doctrine and the rule of capture. The accommodation doctrine in Texas gives the owner of the minerals, as the owner of the “dominant” mineral estate, access to the surface for operations to develop those minerals subject to an obligation to reasonably accommodated existing uses by the surface owner. The rule of capture, which allows the mineral owner to develop minerals under its tract without the risk of certain claims from adjacent tract owners, applies equally to unconventional development, as the Texas Supreme Court held in Coastal Oil & Gas Corp. v. Garza Energy Trust.

Certain legal issues affecting unconventional development, however, have not yet been addressed by the courts. Among these issues are whether certain common law claims will apply to the allocation of production of different ownership when it is commingled in a horizontal wellbore or at a central facility. Another is the enforceability of provisions in oil and gas leases that purport to make the payment of royalty a lease condition, the breach of which supports termination.

Traditionally, the breach of a royalty provision in an oil and gas lease would support only a claim for damages but not lease termination. These new provisions found in more modern lease forms, if enforceable, substantially raise the legal risks associated with paying royalties. Until the Texas Supreme Court resolves these issues, they will continue to add a layer of legal risk that oil and gas investors should account for.

Legal issues involving land, infrastructure and drilling constraints

The old real estate adage “location! location! location!” also rings true when investing in oil and gas assets in Texas. There are remote areas of far West Texas where production may exist, but without access to gathering systems, pipelines and other necessary infrastructure, development remains uneconomic.

For example, to leverage capital expenditure during times of $45 to $55 per barrel oil, longer laterals are necessary to drill economic wells. To do this, operators must acquire large lease positions with enough contiguous acreage to drill economic wells. Investors should be aware of the complexity and legal issues involved in creating a large enough land position for long-lateral and mega-pad horizontal drilling.

Because much of the Permian Basin has been previously developed, many leases are encumbered by legacy agreements that may hinder or prevent the ability to enter land swaps or other arrangements necessary to create a large enough land position. Additionally, many older leases in the Permian Basin are HBP from older, shallow wells with marginal production, which may be challenged based on an alleged lack of production in paying quantities.

Moreover, operators also need large tracts of land to site facilities and other infrastructure, such as storage tanks and pipelines to move both fresh and produced water, to handle the production from the large number of wells necessary to develop shale plays. A lack of adequate leased acreage to site these facilities can also render horizontal development uneconomic.

The inability to economically dispose of produced water is another impediment to development in the Permian Basin. Horizontal wells in the Permian Basin produce large amounts of water, which must be disposed of, often through disposal wells. However, produced water could outpace disposal capacity in the near future, and operators are already facing high disposal fees or unequal bargaining power allowing companies that take and dispose of produced water to command long-term agreements with minimum commitments and acreage dedications.

Additionally, there continues to be insufficient pipeline capacity to move production from far West Texas to points of sale along the Texas Gulf Coast. Midstream companies attempting to build the necessary pipeline capacity have faced legal challenges when routing these pipelines. For example, some counties, cities, and even individual landowners have filed lawsuits challenging the routing, construction and future operation of the Permian Highway Pipeline on multiple grounds, including lack of due process, inadequate compensation and environmental claims.

There also is a shortage of electrical infrastructure in parts of the Permian Basin (well-known for its remoteness) to provide reliable electrical service necessary to power the sophisticated equipment used to drill, complete and maintain production from oil and gas wells. This implicates a number of legal issues. First, if an operator cannot get access to electrical power, it may have no choice but to resort to using generators, which are not only more costly but also less environmentally friendly.

Additionally, where large well pad complexes straddle the service territories of more than one utility, this can lead to disputes between the operator and competing utilities over which utility has the right to serve the development field. Finally, rather than wait on a utility to build to them, some producers have opted to construct their own transmission lines to interconnect with utilities and self-serve, which avoids the need to go to the Public Utility Commission of Texas to obtain a certificate of convenience and necessity as utilities must do. Producers electing to go this route, however, must take care not to share costs of such construction with other producers (or, if they do, to properly structure their transactions) so as not to inadvertently become regulated electric utilities and/or run afoul of the Texas Utilities Code.

Legal issues surrounding various exit strategies

According to a July 2018 article by McKinsey & Co., “as the [private-equity] industry has matured, buyers are seeing fewer deals that are the first of their kind,” and this has caused buyers to be “more sophisticated—and more demanding—than ever.” That article was written about the private-equity industry writ large, but it applies just as aptly to the private-equity energy industry where commercial deal teams are well-versed in key performance indicators of success for energy assets, such as capital spend and cash flow.

It is telling, for example, that 9x to 10x EBITDA was market in 2016 and 2017, but, in 2018, private-equity sponsors are reportedly hoping for 6x to 8x EBITDA for their energy portfolio investments yet only receiving offers from buyers in the 3x to 5x range.

As this firm previously noted in its May 2019 Energy Litigation Spotlight on Oil and Gas, one implication of this trend has been that private-equity energy firms have sought to more concretely demonstrate the value of their assets, for example, in the form of drilling numerous revenue-generating wells, before entering the marketplace to flip them. But this approach requires such firms to hold on to those assets for longer periods of time before exiting than initially desired.

For the operationally savvy (and lucky) private-equity energy firm this may work out, but for most others it exposes them to greater risks, including litigation with contractors, vendors, neighboring operators, surface owners and the underlying mineral rights’ owners.

These disputes tend to have a life cycle of their own as a play itself matures. For example, in our experience it is not unusual in the early stages of an oil and gas play’s development to see a greater frequency of personal injury matters associated with active drill sites or lien disputes as players spat over responsibility for unpaid bills. As infrastructure is built out, the focus can then shift toward environmental or other nuisance-type claims, such as impacts from flaring (driven in part by the lack of takeaway capacity on pipelines) or noise or other impacts from large, regional processing facilities.

Later in the development cycle, once wells come online and mineral rights owners begin to share in production proceeds in the form of royalties, it is not unusual to see more of a shift toward royalty-based disputes, whether those concern the propriety of certain post-production charges, the failure to timely remit proceeds under the Texas Natural Resources Code, or efforts to wash out overriding royalty interests.

Given their emphasis on freedom to exit and obligation to pay a preferred return on any capital calls back to investors, however, private-equity energy firms will be comparatively more incentivized to resolve such litigation than engage in protracted and costly court battles.

In addition to holding on to assets longer and/or further developing them, some private-equity energy firms have agreed to exits based on receipt of stock in the buyer, a model that historically has been disfavored by the industry due to the comparatively illiquid nature of the consideration as compared to cash.

It was much publicized, for instance, that NGP Energy Capital Management sold WildHorse Resource Development Corp. (one of its portfolio companies) to Chesapeake Energy Corp. for $3.98 billion, with the deal remuneraion consisting of a combination of Chesapeake common stock and cash. Since that transaction closed in February 2019, Chesapeake’s stock price has declined from $2.79 to 69 cents in November 2019 (a 25-year low), revealing the risks of this type of exit structure.

A new, more radical monetization model is emerging as of late (coinciding with 2018 and 2019’s relatively mediocre and volatile crude oil prices). According to an article in The Wall Street Journal, shale companies seeking cash are courting investors with a new type of asset-backed security that involves bundling and securitizing oil and gas wells and selling bonds that will pay decent returns on the best quality wells but higher rates on riskier ones.

For example, the WSJ article reported that Raisa Energy LLC, which owns nonoperating interests domestically, privately offered its stakes in about 700 wells across the U.S., though few details were available on the offering, including how much it raised.

While this bonds-for-barrels approach is certainly creative, one cannot help but consider the parallels it bears to the mortgage-backed securities that sent the U.S. headlong into a recession in 2008. And given how imprecise oil and gas exploration can be, even with all of the advances of modern technology, these types of investments seem primed for legal risks.

For example, if the securitized wells do not end up performing as advertised (or at least close to it), there may be actions against underlying operator companies allegedly to blame or actions by sorely disappointed investors. Overall, because this is such a new form of structured financial product, it remains to be seen whether this new approach to monetizing the oil and gas value chain will take hold on a widespread basis. Either way, this new investment strategy is sure to be closely watched, not only from a financial perspective but a legal one as well.

Jason Newman is a partner at Baker Botts. He represents and advises energy clients on legal issues and disputes arising from horizontal development in all parts of Texas and throughout the U.S. Meghan McElvy is a partner at Baker Botts. She advises energy clients on most aspects of legal and operational issues arising from the development of shale plays and horizontal drilling throughout Texas.