With the drop in oil prices has come a wave of litigation over underpayment of royalties. Multiple suits have been filed against Repsol (formerly Talisman) over its royalty payments in the Eagle Ford. Multiple suits against Devon for royalty underpayment have been consolidated into a multi-district docket in San Antonio. A federal court in Fort Worth has certified a class action against Devon for underpayment of royalties in the Barnett Shale. Conoco is settling class actions brought in Oklahoma that also cover class members in Texas. These suits allege underpayments of royalty on oil and gas. The San Antonio multi-district suits also allege breach of lease provisions requiring the lessee to protect the lease against drainage from wells on adjacent properties.
These cases present opportunities for plaintiffs’ attorneys to earn large contingency fees. They also point out the problems faced by land and mineral owners in determining whether their lessee is complying with their oil and gas lease. What should landowners do to monitor lease compliance?
There are no easy answers to these questions. Below are some suggestions.
Know how to read your check detail.
Companies are required by law to report certain details on how royalties are calculated and paid on the check detail that comes with each royalty payment. Texas Natural Resources Code Chapter 91, Subchapter L, requires that the check stub include:
The lease, property or well name and identification number, and the county and state in which the well is located;
the month and year during which sales occurred for which payment is being made;
the number of barrels or mcf of gas sold;
the price per barrel or per mcf of oil or gas used for calculating royalties;
the total amount of state severance taxes paid;
any other deductions or adjustments;
the net value of total sales after deductions;
the owner’s decimal royalty interest;
the owner’s share of the total value of sales before and after any deductions; and
an address and phone number at which additional information regarding the payment may be obtained and questions may be answered.
The statute also requires a payor to provide additional information about any deductions if a request is sent by certified mail.
Check stubs have codes that identify the product for which royalty is being paid – oil, condensate, gas, natural gas liquids – and the type of deduction – transportation, processing, gathering, etc. Each company has its own format and codes. Explanation of the codes may be on the check stub or may be provided in a separate insert with the check stub. Some companies also have explanations on how to read their check stubs on their website. Some companies sub-contract royalty payment and reporting to other companies who process the checks and provide the check details. Oildex is a major subcontractor.
Check stubs often show adjustments in payments for previous periods. These adjustments often make the check stub virtually unreadable. Usually, prior period adjustments are shown by two entries, one reversing out an entry made in the previous period, and a second making a new entry for the same period with the adjusted amount shown. The adjustment may be in the price or volume, or may reflect a new or adjusted deduction amount.
Many companies now make check stubs available online. Some companies have sought to require royalty owners to access their check stubs online. The Texas Legislature recently passed a bill requiring companies to provide paper check stubs if requested by the royalty owner. An advantage of accessing check stubs online is that they can be downloaded either as Xcel spreadsheets or as pdfs that can be converted into Xcel spreadsheets. But some online versions of check stubs will limit the number of lines of code from the check detail that can be downloaded.
Know your lease.
The lessee’s obligations to the royalty owner are governed by the oil and gas lease. The lease determines how royalties are calculated and paid. Some royalty clauses provide for payment based on market value, some based on proceeds received from sale. Some leases allow deduction of post-production costs, some do not. A lease may also set forth the consequences for failure to pay royalty in accordance with the lease.
The oil and gas lease may impose additional covenants on the lessee that should be monitored. If there is no production at the end of the primary term, the lease terminates and the lessee should sign and file a release. The lease may impose drilling requirements after the end of the primary term, and may require releases of acreage not developed after drilling operations cease. The lease may require release of depths below those from which the lessee is producing. It may contain express covenants for protection against drainage.
If the lessor is the owner of the surface estate in the leased premises, the lease may contain obligations regarding the lessee’s use of the surface of the land. Surface damage payments, use of roads, construction of pipelines, keeping gates closed — all of these should be monitored to assure that the lessee is in compliance.
Monitor the lessee’s drilling and production activities.
A royalty owner should know when his/her lessee is drilling on the lease, when a well is completed and commences production. The lessee usually does not notify the royalty owner of these activities unless the lease so requires. The Texas Railroad Commission now has online search capabilities that allow a mineral owner to track activities on the property. Mineral owners should learn how to use those search capabilities.
Once production commences, operators must report production monthly to the RRC, and that information is available online. Volumes reported to the RRC should be compared to volumes reported on check stubs. It should be noted, however, that volumes on check stubs may not match RRC-reported volumes, particularly for gas. If gas is processed for removal of natural gas liquids before sale, the volume reported to the RRC will be the wellhead volume, whereas the volumes reported on the check stub may be the residue gas and NGL volumes.
If the dollar amount of royalties are sufficient to justify a professional audit to confirm that the royalties being paid comply with lease requirements, a royalty owner should consider hiring an auditor to conduct such an audit. Such audits can be expensive, depending on the number of wells, the complexity of the lessee’s marketing system, the cooperativeness of the lessee, and the terms of the lease. But audits often uncover substantial underpayments.
Under Texas law, the statute of limitations for royalty payments is four years. So a royalty owner who is underpaid must file suit to recover royalties owed within four years from the date the royalty is due. Because audits often take several months to complete, one should consider an audit well before the end of the four-year period for which the audit will be conducted.
Gaps in production.
Most oil and gas leases provide that, if a well stops producing for mechanical reasons, the lease will continue in force as long as the lessee commences efforts to restore production within 60 or 90 days and continues such efforts with no gaps in operations of more than 60 or 90 days until production is restored. If a royalty owner sees a gap in production of more than 60 or 90 days (depending on the lease), the owner should inquire with the operator whether operations were conducted during that period so as to keep the lease in effect. Absent such operations, the royalty owner should consider whether to claim that the lease has terminated.
Production in “paying quantities.”
Texas case law requires that a lease remains in effect after its primary term only if oil and/or gas is produced in “paying quantities.” In general, this means that the lessee must be making a profit after payment of operating costs of the well or wells on the lease. A large body of case law has developed over how to determine whether a lease is producing in paying quantities, and that topic is too large to discuss here. If a royalty owner suspects that a lease is not producing in paying quantities, he/she should consult an attorney to evaluate the issue.
Spills and leaks.
Spills and leaks of oil, gas and produced water are a common occurrence in the oil field. Landowners with oil and gas operations on their property should expect them to occur occasionally. Jurisdiction of those events is in the Texas Railroad Commission. Operators are required to report spills and leaks of more than five barrels of liquid, and RRC rules provide cleanup standards for those events. Landowners should be proactive in reporting leaks to the RRC when they find them, be sure that RRC inspections and follow-up inspections occur, and insist that the RRC require the operator to clean up the spill or leak as required by RRC regulations.
Some leaks are often not detected until long after they commence. Lighter crude, condensate or produced water may percolate into shallow groundwater aquifers with little or no evidence on the surface. Texas law requires landowners to bring suit within two years of discovery of such events. Audits of surface operations may be conducted by professional environmental engineers to detect such events. Remediation of groundwater is very expensive and complex, and the sooner such leaks are detected the easier it will be to deal with them.
Pool your resources.
Royalty interests in some cases are divided among family members who have inherited those interests. While it may not be economical for one royalty owner to hire professionals to conduct a royalty audit, several royalty owners with interests in the same lease might do so economically. Some families have formed family offices to monitor their production and engage in audits where justified. In my experience those family offices often pay for themselves in recoveries of underpaid royalties and management of their family mineral interests.