Introduction
The exploration and production, or “E&P” segment of the domestic energy business is booming, particularly the unconventional oil plays in South Texas, West Texas, Pennsylvania, North Dakota and the Rocky Mountain region. Investors are making significant capital expenditures per acre for oil and gas leases and the right to drill multi-million dollar wells. The economic stakes are high.
As the technology of drilling and producing wells has become more complicated, so have the legal issues related to the E&P business. Investors should be aware of these evolving legal pitfalls that, if not recognized and addressed during due diligence, could change the economics of E&P deals in ways that the investors had not imagined.
Traditionally, parties investing in E&P opportunities have rightfully focused their due diligence on title issues. Leases taken from the mineral owners are the typical industry agreements that give the E&P companies the right to drill for and produce hydrocarbons. So it has always been customary for an investor and its attorneys to focus on whether the leases being acquired cover all the underlying mineral interests, and whether those leases are in full force and effect.
Diligence in an oil and gas acquisition goes beyond reconciling title. The related contracts are numerous, complex and unique. Correctly analyzing each requires a special knowledge of the specific piece of the oil and gas industry with which they relate. In an effort to avoid certain costly pitfalls, an E&P investor should specifically conduct (1) a studied analysis of the exact terms of the leases being acquired, paying keen attention to certain royalty provisions that are becoming commonplace, and (2) a review of the provisions of any operating agreements with third parties that cover wells drilled or to be drilled.
Analysis
Oil & Gas Lease Issues and Pitfalls
Continuous Drilling and/or Acreage Release Provisions
The term or duration of a Lease is usually determined by the habendum clause. These clauses commonly provide that the Lease will be for a fixed primary term, i.e., two years, and then “so long thereafter” as hydrocarbons are produced in paying quantities. Once production has been established in commercial quantities by the drilling of an initial well, these leases are essentially “held by production” (HBP) as to all acreage and all depths. Thereafter, the E&P company has rather wide latitude as to when and where to drill any subsequent wells. The practical result is that E&P companies, as lessees, have tied up leases for years without testing new formations or drilling additional wells.
In response, mineral owners have begun to insist upon continuous drilling clauses and/or acreage release provisions. A continuous drilling clause sets a rigorous schedule for the drilling of additional wells on the leased acreage. This schedule may require a new well to be drilled within 60 or 90 days from the completion of a previous well. If this schedule is not strictly met, then any acreage not included in a defined producing unit is released back to the mineral owner. This release may include all depths and formations not producing. When acquiring leases with a continuous drilling clause or acreage release clause, one must carefully evaluate when additional wells need to be drilled. Although the Lease may be in full force and effect at the time of the closing of an acquisition and may otherwise be free of any title defects, the clock is ticking. The parties involved in the acquisition need to be aware of any requirements to continue to drill these multi-million dollar wells in order to perpetuate the entire Lease, and it may be only a few days before the next well has to be spudded.
Leases Not Designed for Horizontal Wells
Some of the hottest plays are in areas of historical production where the original wells were vertical wells drilled into conventional sandstone or limestone formation. The original production has perpetuated the old Lease, and investors are now acquiring the right to drill horizontal wells in non-conventional formations, such as shale formations.
Simply stated, these old leases, and even some new leases that have not been updated, were not drafted in a way to make proper allowances for horizontal wells. For example, most leases contain a pooling provision that allows the E&P company to pool several small tract leases into a single producing unit. But the acreage limit in the pooling provision may be too small to accommodate the long lateral leg of the horizontal wells. The point is that the restrictions of each Lease – whether old or new – must be compared with the expected development plan for the Lease to determine whether the contemplated wells can actually be drilled as planned.
Surface Protection Provisions That Impair Mineral Development
The general rule of law is that the mineral estate is recognized as the dominant estate, and as a consequence, the lessee of a Lease has the right to use so much of the surface estate as is reasonably necessary for the proper development of the oil or gas production. This rule is subject to the accommodation doctrine that requires the E&P company to use alternative means of development to reasonably minimize the interference with the existing use of the surface estate.
In response to the dominant estate doctrine, mineral owners who also have an interest in the surface estate have developed a myriad of surface protection clauses over the years that can materially impair drilling and production activities. Some of those clauses regulate access to the leased acreage, some regulate where and when wells can be drilled, and some provisions in leases in urban areas ban all surface activities on the Lease, while allowing subsurface horizontal wells. Thus, due diligence by a prospective E&P investor should include a detailed review of any surface protection provisions in the leases to be acquired.
JOINT OPERATING AGREEMENT ISSUES AND PITFALLS
When more than one E&P entity is involved in developing certain acreage, it is customary for the parties to agree contractually to appoint one party as the operator and to enter into a joint operating agreement (JOA). Most JOAs follow a model form promulgated by the American Association of Petroleum Landmen (AAPL). There are several iterations of this model form. Some of the older forms present problems for the uninitiated.
Standard of Performance by the Operator and Removal of the Operator
Standard form JOAs remain in effect so long as any leases subject to the JOA remain in effect or so long as there is production or operations for production. So JOAs can remain in effect for many years.
The operator contractually appointed pursuant to the JOA is given “full control of all operations on the contract area” subject to few restrictions. While the operator is required to conduct operations “in a good and workmanlike manner,” all of the AAPL form JOAs contain an exculpatory clause that protects the operator from liability except in instances where the operator has engaged in “gross negligence or willful misconduct.” This exculpatory clause has been repeatedly upheld.
A great deal of expertise is required to drill deep horizontal wells and to complete wells properly in non-conventional reservoirs. Even among companies that have this expertise, the cost of drilling wells can vary widely from operator to operator, and certain operators have a better history than others in refining completions to maximize production. Now more than ever, the economics of an E&P deal can turn upon the proficiency and level of expertise of the operator.
Under the model form JOAs, an operator cannot be removed and replaced simply because there are more qualified operators who could drill the wells at a lower cost and with better results. To put this in context, until the 1989 version of the AAPL model form JOA, an operator could not even be removed for failing to operate in a good and workmanlike manner. It is therefore important for an E&P investor to ascertain whether there is a JOA covering the acreage to be drilled, and if so, the expertise of the operator and the legal grounds or basis for the possible removal of the operator.
Well Costs Overruns
When a well is proposed to be drilled the operator will normally circulate an authorization for expenditures (AFE) to the non-operating parties to the JOA setting forth the proposed drilling depths, length of lateral, etc., along with estimated costs for the proposed operations. Regardless of the costs projected in the AFE and unless the JOA is modified to address this issue, each party who consents to the drilling of the well will be responsible for its share of the actual costs and may be responsible for its pro-rata share of costs not paid by other parties who default in paying them. Time and time again investors have been blind-sided by substantial cost overruns, and due to the language of the JOA, have been left with no recourse against the operator. The risk associated with cost overruns cannot be properly analyzed without a review of the provisions of any applicable JOA.
Conclusion
Many of the recent oil and gas plays have taken on a gold rush mentality, with even sophisticated investors scrambling to get in on a piece of the action. Regardless of the pressure to get a deal done, these issues demonstrate that familiarity with the various clauses of oil and gas contracts is crucial. Seemingly minor nuances, which to the untrained eye may appear to be boiler-plate provisions, could have significant impact on an acquisition’s economics.
