The examiners who heard the Klotzmans' protest of EOG Resources' application for an allocation well permit have issued their Proposal for Decision in the case. A copy of the PFD can be viewed here: 2013-06-25 PFD EOG Klotzman (2).pdf Our firm represents the protestants in the case. For my prior discussion of the case and allocation well permits, see here and here and here. The parties now have until July 10 to file exceptions to the proposal, and replies to exceptions are due within 10 days thereafter. After that, if no changes to the PFD are made, it will go before the Railroad Commissioners for their decision.
Recently in Pooling Category
Production allocation wells continue to be a simmering issue in Texas. Last Friday I attended the Ernest E. Smith Institute on Oil, Gas and Mineral Law sponsored by the University of Texas School of Law, and one of the topics presented was a paper titled "Drafting Production Sharing Agreements." The paper included information about allocation wells.
I've written about allocation wells before, here and here. The Texas Railroad Commission uses that term to refer to a horizontal well that is drilled across the boundary line of two leases or units without pooling the two leases or units. Up until recently, it was assumed that the Commission would not grant a permit for such a well. Several years ago, operators began applying for permits to drill "production sharing agreement" wells. Those are wells drilled across the boundary line of two existing leases or pooled units, where the operator has obtained a "production sharing agreement" from some or all of the royalty owners to drill such a well. The production sharing agreement with the royalty owners provides that production from the well is allocated between or among the tracts crossed by the well lateral, for purposes of calculating royalties due, based on the number of feet of well lateral on each tract compared to the total lateral length of the well. In 2008, the Commissioners agreed that they would grant permits for production sharing agreement wells if at least 65% in interest of the royalty owners in all tracts on which the well would be located had signed production sharing agreements.
According to the paper submitted to the seminar, to date some 700 production sharing agreement - or "PSA" - well permits have been granted by the Commission. More than 600 of those were granted to Devon Energy.
More recently, operators have convinced the Commission staff to grant drilling permits for wells crossing two or more leases or units even if the operator has no pooling or production sharing agreements with the royalty owners. The Commission refers to such wells as "allocation wells." According to the seminar paper, permits have been granted for 98 allocation wells. The Commission is granting such permits even though it has no rule authorizing the granting of the permits.
As I have earlier written, our firm represents a landowner who has protested a permit EOG applied for to drill an allocation well. A hearing has been conducted on that protested permit, and the parties are awaiting a proposal for decision from the hearings examiners.
The seminar paper, written by Mickey Olmstead of the McElroy Sullivan firm here in Austin, and Robert Jowers of the Shannon Gracey firm in Houston, is in large part a brief arguing that allocation wells should be permitted by the Commission. The paper does not mention the EOG protested permit application.
I have learned since the EOG permit hearing that there is at least one pending lawsuit by a mineral owner against EOG for drilling an allocation well. I have also seen a permit granted for an allocation well based on the operator's misrepresentation to the Commission that the well will be drilled on a pooled unit, even though the operator has no authority to pool the two leases across which the horizontal well will be drilled. I have also been told that operators are applying for permits for allocation wells without disclosing to the Commission that the well will be an allocation well. So it is difficult if not impossible to determine how many allocation wells have in fact been drilled.
The right to agree - or not agree - to the pooling of one's royalty interest has been long-recognized by Texas courts, and is a significant right for all royalty and mineral owners in Texas. Texas has no forced-pooling statute like those in Oklahoma and Lousiana that force mineral owners into pooled units against their will. (Texas' Mineral Interest Pooling Act does allow forced pooling under limited circumstances.) Recently there was substantial opposition to a bill pending in the Texas legislature, HB 100, that arguably grants operators the right to force-pool royalty interests. In my opinion, if operators are granted permits to drill allocation wells, despite having no pooling agreements with the royalty owners, the rights of royalty owners to negotiate pooling provisions in their leases will be seriously eroded.
The Texas Supreme Court denied the LaSalle Pipeline's petition for review in LaSalle Pipeline v. Donnell Lands, leaving the San Antonio Court of Appeals' original opinion intact. See my discussion of the case here. The trial court awarded $468 per rod $28.36/foot) for an easement for a 16-inch pipeline. The Court of Appeals affirmed, finding sufficient evidence to support the award.
The Texas Railroad Commission denied the Texas Land and Mineral Owners' Association's petition for a rulemaking on the Commission's policy regarding permits for "allocation wells." See my prior posts here and here. In their discussion concerning the petition, the Commissioners agreed that allocation wells should be addressed by rule, but they concluded that there are presently too many pending rulemakings for the Commission staff to take on more at this time. The Klotzmans' protest of EOG's allocation well permit remains pending, awaiting a proposal for decision from the hearings examiners.
In a prior post, I wrote about a new development at the Texas Railroad Commission: granting permits for "allocation wells" - horizontal wells drilled across lease lines without pooling the leases. Since I wrote that post, our firm was retained to represent the parties protesting EOG Resources' application for a permit for an allocation well. A hearing on the application was held at the RRC on December 3. In addition to EOG and the protestants, Devon Energy appeared at the hearing supporting EOG, and the Texas General Land Office appeared opposing allocation wells on State-owned minerals. All parties have now submitted closing statements and responses, which can be viewed below:
Our firm was also retained by the Texas Land and Mineral Owners' Association and several mineral owners to file a petition for rulemaking with the RRC, asking the RRC to address the issue of allocation wells by commencing a rulemaking proceeding. The RRC has not yet responded. The petition can be viewed here: Rulemaking Petition.pdf
State Representative Van Taylor, R-Plano, and Senator Rodney Ellis, D-Houston, have introduced a bill to allow for forced pooling in Texas. The House bill, HB 100, may be viewed here.
The bill would allow an operator to force-pool mineral, royalty and leasehold interests into a unit if the operator obtains agreement from 70% of the leasehold owners and 70% of the royalty owners in the area to be unitized. Unleased mineral owners could be pooled, and would be treated as owning a 1/6 royalty interest and a 5/6 working interest. The unit operating agreement can provide for a "sit-out" penalty of no more than 300% for a working interest owner who elects not to pay its share of the well costs. The bill does not allow force-pooling of mineral or royalty interests owned by the State.
Here is just one interesting provision in the bill:
Lease or surface use provisions that conflict with the use of the surface for unit operations in such a manner as to prevent or render uneconomical the implementation of the plan of unitization as approved by the commission must be amended by the unit order to the extent, and only to the extent, necessary to implement the plan in an economical and efficient manner.
If I read this correctly, the bill would allow the Railroad Commission to amend any oil and gas lease surface use provisions if those provisions "conflict with the use of the surface for unit operations in such a manner as to prevent or render unecomonical" the plan of unitization.
Another interesting provision: The operator can apply for and obtain an order forming the unit before getting approval of 70% of the royalty owners. The operator then has six months to get 70% sign-up.
The participation of unit tracts in unit production is not necessarily on a per-acre basis. The bill provides that
A tract's fair share of the unit production must be measured by the value of each tract and its contributing value to the unit in relation to like values of other tracts in the unit, taking into account acreage, the quantity of oil, gas, or oil and gas recoverable from the tract, the tract's location on the geological structure, the tract's probable productivity of oil, gas, or oil and gas in the absence of unit operations, or as many other factors, including other pertinent engineering, geological, or operating factors, as are reasonably susceptible of determination.
Passage of this bill would materially change the nature of the relationship between mineral owners and operators in Texas.
I have recently become aware of recent changes in Texas Railroad Commission policies regarding "production sharing agreements" and "allocation wells" that deserve some comment. Some background is necessary to understand these recent developments.
Over the last couple of years I have been asked to review and explain proposed "production sharing agreements" sent to royalty owners. Operators in the Haynesville came up with the concept of production sharing agreements when they were faced with trying to drill wells in areas that were held by production from large pooled units producing from vertical Cotton Valley wells. The pooled units were not configured to allow for efficient drilling of Haynesville horizontal wells. Operators wanted to drill laterals crossing the boundaries of the pooled units, and apparently the pooled units covered the Haynesville depths as well as the Cotton Valley. So, they came up with the idea of production sharing agreements. The agreements provide that the royalty owners in the two existing units agree that production from the horizontal well will be "shared" between the two units based on the percentage of lateral length on each unit, and production allocated to each unit will be treated for lease and royalty payment purposes as if produced from the unit. Devon was a big proponent of these agreements. From the royalty owner's point of view, the agreements have advantages and disadvantages. The advantage is that the royalty owner will get royalties on production from a new well that might not be drilled unless a production sharing agreement is signed to allow drilling across lease or unit boundaries. The disadvantage is that production from one well serves to keep all of the leases in both units in effect for as long as it produces.
A well drilled across lease or unit boundaries pursuant to a production sharing agreement is referred to at the RRC as a "PSA" well, because the permit is granted based on the operator's assertion that it has production sharing agreements with royalty owners for allocation of production between or among tracts; or as an "allocation well," because production from the well is allocated to two or more separate leases or units. When operators began applying for drilling permits for these wells, there was discussion at the RRC about how to handle them, because they did not fit the standard model of pooled units. Eventually, the RRC staff adopted an informal, unwritten policy that, if the operator would represent in its permit application that it had production sharing agreements from at least 65% of the royalty owners in both units, the RRC would grant the permit. The RRC has created a new form, the "PSA-12" form, to replace the Form P-12 that operators must file to represent that they have the right to create a pooled unit. If the operator submits the PSA-12 form, the RRC grants a PSA well permit, based on its informal 65% joinder policy.
I have now learned that recently operators have asked the RRC to grant permits for allocation wells even if they don't have PSAs from 65% of the royalty owners - or even if they have no agreements from royalty owners. The RRC has granted some 40 such permits without requiring the operators to have PSAs with any of the royalty owners. Some of the permits granted for such "non-PSA" allocation wells contain the following disclaimer:
Commission Staff expresses no opinion as to whether a 100% ownership interest in each of the leases alone or in combination with a "production sharing agreement" confers the right to drill across lease/unit lines or whether a pooling agreement is also required. However, until that issue is directly addressed and ruled upon by a Texas court of competent jurisdiction it appears that a 100% interest in each of the leases and a production sharing agreement constitute a sufficient colorable claim to the right to drill a horizontal well as proposed to authorize the removal of the regulatory bar and the issuance of a drilling permit by the Commission, assuming the proposed well is in compliance with all other relevant Commission requirements. Issuance of the permit is not an endorsement or approval of the applicant's stated method of allocating production proceeds among component leases or units. All production must be reported to the Commission as production from the lease or pooled unit on which the wellhead is located and reported production volume must be determined by actual measurement of hydrocarbon volumes prior to leaving that tract and may not be based on allocation or estimation. Payment of royalties is a contractual matter between the lessor and lessee. Interpreting the leases and determining whether the proposed proceeds allocation comports with the relevant leases is not a matter within Commission jurisdiction but a matter for the parties to the lease and, if necessary, a Texas court of competent jurisdiction. The foregoing statements are not, and should not be construed as, a final opinion or decision of the Railroad Commission.
With this background, we now come to the most recent developments: EOG Resources filed an application to drill the Klotzman (Allocation) Well 1-H, in the Eagleville (Eagle Ford 2) Field, in DeWitt County. The proposed well would cross over two different oil and gas leases, neither of which authorizes the lessee to pool the leased premises with any other tract. The owners of the royalty in these two leases filed a protest to EOG's permit application. The protest stirred a discussion at the RRC and caused its staff to call an informal conference on the matter. After that conference, the director of the Hearings Division of the RRC, Collin Lineberry, wrote a letter to the parties, which can be viewed here: Lineberry letter.pdf. Mr. Lineberry said that the royalty owners' assertions "cast sufficient doubt on the applicant's assertion of a good faith claim to preclude the administrative approval of the requested permit at this juncture." He concluded that, if either party wanted to request a hearing on the matter, he would "set an evidentiary hearing to allow both parties to present evidence and argument regarding whether, on the specific facts of this case, EOG has a sufficient good faith claim to authorize issuance of an RRC drilling permit for the proposed allocation well." A hearing has now been set for December 3.
To me, the RRC's issuance of permits for "allocation wells" without requiring the operator to obtain production sharing agreements or pooling agreements from royalty owners in the tracts crossed by the wellbore is in effect allowing operators to force-pool tracts. Forced pooling in Texas is allowed only under limited circumstances and requires an application, notice to affected parties, and a hearing. Texas - unlike other producing states - has never given its regulatory body broad authority to force-pool tracts into drilling units. The RRC staff's "policy" of allowing such permits appears to have been adopted without any hearing and without consideration by the Commissioners themselves. As evidenced by the comments quoted above from one of the allocation permits, the applicants appear to have convinced the Commission staff that the proper allocation of production between tracts on which an allocation well is drilled is a matter of private contract between the parties over which the RRC has no jurisdiction and does not affect its decision whether to grant the permit. This appears to me to be contrary to prior RRC policy and existing RRC rules regarding pooled units, which require the operator to assert in the permit that it has authority to pool the tracts included in the proposed drilling unit.
I expect that there will be further developments on this issue in the near future.
EOG Resources has filed an application with the Texas Railroad Commission proposing the adoption of temporary field rules for wells drilled in the Eagle Ford Shale in South Texas that could have a significant impact on thousands of oil and gas leases in the field. The application proposes to consolidate 27 designated fields that produce from the Eagle Ford Shale formation, and the proposed rules will replace any field rules previously adopted for those fields. The consolidated rules would apply to Eagle Ford Shale wells drilled in Railroad Commission of Texas Districts 1, 2 and 4. A copy of the notice of the Railroad Commission hearing for the adoption of the proposed rules may be found here: eagle ford field rules.pdf. The hearing is scheduled for June 25, 2010, at 9 am in the William B. Travis Sate Office Building, 1701 Congress Avenue, Austin. Persons wishing to participate in the hearing must file a notice of intent to appear at least five working days in advance of the hearing date and serve a copy of the notice on the applicant and any other parties of record. More information can be obtained by calling the Office of General Counsel of the Railroad Commission at 512-463-6848.
Field rules are adopted by the Railroad Commission to govern the spacing of wells in a field. They specify how far wells must be from each other, how far wells must be from the nearest lease line, and how much acreage must be assigned to a well in order to obtain a permit to drill a well. The acreage assigned to a proposed well is known as a "proration unit." Well spacing and density rules were developed by the Commission after it was given jurisdiction over oil and gas operations in Texas in the early days of the oil industry, principally because of unregulated drilling in the East Texas Field. Because of unregulated drilling in that field, wells were being drilled that were not necessary for the efficient development of the field, and oil prices plummeted. The Commission was also given authority to "prorate" production from a field -- that is, to limit production, and to allocate or "prorate" the specified limit of production from a field among the wells in a field. The stated purposes of spacing and density rules are to avoid waste and protect the correlative rights of producers in the field. Theoretically, field rules should designate a size for proration units that approximates the amount of acreage in the field that can be efficiently drained by a single well.
The field rules proposed by EOG would provide:
An interesting case has recently been filed in Louisiana challenging the authority of the Louisiana Department of Conservation to approve pooled units containing multiple wells. In Gatti et al. vs. State of Louisiana, et al., Number 589350, Division 23, filed in the 19th Judicial District Court in East Baton Rouge Parish, the plaintiffs sued the State Department of Conservation and several operators in the Haynesville field, including Chesapake, Encana, Exco, Conoco Phillips, Petrohawk, SWEPI, EOG, Questar, Forest and XTO, claiming that the Department of Conservation was routinely allowing the drilling of "alternate unit wells" on previously established units, in violation of Louisiana law. A copy of the petition may be found here. Gatti v. St of Louisiana.pdf.
Louisiana has a forced-pooling statute that allows an operator to propose to the Department of Conservation a unit for a well which, if approved, forces all mineral owners in the unit to pool their interests for the drilling and production of that well. According to the plaintiffs, this statute only authorizes the Department to approve units large enough to cover an area drained by one well. The practice in Lousiana for the Cotton Valley and Haynesville fields is to obtain orders for 640-acre units, and later obtain approval to drill additoinal "alternate unit wells" on those units. The suit contends that this practice is unfair to the owners of minerals and royalties in the unit, and violates state law. The suit seeks certification of a class action on behalf of all owners of mineral rights in Haynesville Zone in Louisiana. It seeks a declaration that the Department has no authority to establish a unit having an area in excess of the area drainable by one well, and that any such unit is "null and void." The suit also seeks unspecified damages against the defendant companies.
An interesting article describing the history of forced pooling in Louisiana and arguing that multiple-well units are illegal may be found at fairdrilling.com.
I have written previously about the proceeding before the Texas Railroad Commission for adoption of field rules for the Carthage (Haynesville Shale) Field. In that proceeding, the applicants sought and obtained field rules establishing a standard proration unit of 640 acres for wells in the field, with "optional" 40-acre units. The examiners who heard the evidence opined that Devon had produced no evidence that a well in the field could drain 640 acres, and they recommended a 320-acre standard unit, but the Commissioners overruled them and agreed to Devon's request for 640-acre units.
It appears that in both Lousiana and Texas the regulators are going along with the fiction advocated by operators that wells in the Haynesville should be developed with 640-acre units, despite the fact that everyone knows the wells will in fact be drilled with 160 or 80-acre spacing. Everyone understands that this fiction is intended to accommodate the desires of the operators to construct larger units in order to (i) have more flexibility in how they space their wells and (ii) hold more acreage with a single well. I have sympathy with the first objective, but not with the second. It is impossible to drill wells with horizontal legs of 5,000 feet or more unless fairly large units are created. Conversely, it is unfair to the mineral owners in a large unit for their leases to be held by production from a single well in the unit where several wells are necessary to fully develop the reservoir under their lands.
In a previous post I reported on the application of Devon Energy asking the Texas Railroad Commission to include in the new Field Rules for the Carthage (Haynesville Shale) Field a provision allowing it to drill horizontal wells across lease or pooled unit boundaries. These new rules apply to wells drilled in the Haynesville and Bossier formations in Harrison, Nacogdoches, Panola, Shelby and Rusk Counties in East Texas. Devon asked that the rules provide what it calls a "default allocation method" for horizontal wells drilled across unit boundaries.The rule proposed by Devon reads as follows:
"Operators shall be permitted to drill and complete horizontal wells that traverse one or more units and/or leases as long as that operator has a lease or other mineral ownership right to produce from each such unit or lease. If such a well is not already subject to an agreement regarding the allocation of production, the following allocation formula will be presumed to constitute a fair and reasonable allocation of production from a well in this field and shall be utilized by the Commission in assigning acreage attributable to the separate units/leases traversed by the horizontal drainhole: an allocation of acreage and production to each of the units and/or leases traversed by and completed in the horizontal well based on the percent of said horizontal well from first take point to last take point that lies under each unit or lease."
The Commission concluded that it had no authority to adopt such a rule, because pooling is a contractual issue between private parties, and (except as provided in the Mineral Interest Pooling Act) the Commission has no right to impose allocations of production among different tracts penetrated by a horizontal well.
In its appeal, Devon argues that the Commission's refusal to adopt its proposed "allocation rule" is arbitrary and an abuse of its discretion, without a rational basis, discriminates against producers in the Carthage Field, and will result in the waste of oil and gas.
I believe that Devon has little chance of forcing the Commission to adopt its proposed "allocation rule." But if it is successful, it is certain that operators in the Barnett Shale and other shale fields now being developed in Texas will ask for a similar rule. Such a rule would have significant impacts on royalty owners and their rights to consent to pooling of their royalty interests.
On December 15, the Railroad Commission adopted new field rules for a newly designated field, the Carthage (Haynesville Shale) Field, in East Texas. It also consolidated several previously designated fields in East Texas that produce from the Haynesville and Bossier formations into this single RRC-designated field. These rules will govern the development of the Haynesville and Bossier formations in Harrison, Nacogdoches, Panola, Rusk and Shelby Counties in East Texas. These new rules are important to landowners principally because they will give operators a basis to form pooled units of up to 640 acres or more for development of the field.
A little backrgound is in order: Large portions of the land in East Texas within the Haynesville and Bossier play were previously drilled to develop the shallower Travis Peak and Cotton Valley formations. The field rules originally adopted for the Cotton Valley fields provided that only one well could be drilled for each 640 acres of land. Over time, the field rules were amended to allow operators to drill wells in the Cotton Valley with a density of as little as 40 acres per well. Operators initially formed pooled units of up to 704 acres, a size allowed by most lease standard pooling clauses. Cotton Valley wells drilled on these pooled units are still producing, thus keeping in force the leases included in the pooled units. Generally, the pooled unit designations filed by operators for the Cotton Valley wells pooled all depths under the units, including the Haynesville and Bossier formations, which lie immediately below the Cotton Valley formation. Companies now desire to develop the deeper Haynesville and Bossier formations under these Cotton Valley units.
Field rules are special rules adopted by the Railroad Commission governing the spacing of wells in a designated field. Once special field rules are adopted for a field, they govern how wells must be spaced in that field and how much acreage an operator must have to drill a well in the field. Special field rules are adopted in response to an application made by an operator of wells in the field. The operator presents evidence to hearings examiners at the RRC as to the characteristics of the formation and how much area will be drained by a well in that field, and the operator proposes rules to be adopted by the RRC. The hearing examiners review the evidence and may or may not adopt the rules requested by the applicant. The hearing examiners make a recommendation to the three RRC commissioners, and the commissioners may either adopt the recommendations of the examiners or make changes in those recommendations.
Devon Energy Production Co., LP made application to the RRC for new field rules for development of the Haynesville and Bossier formations in East Texas, and it requested that several fields previously designated by the RRC be consolidated into a single "field" for purposes of the new rules. The new rules proposed by Devon would govern wells completed in the Haynesville and Bossier formations in Harrison, Nacogdoches, Panola, Rusk and Shelby Counties. In effect, Devon proposed that the Haynesville and Bossier formations be treated as a single formation for RRC regulatory purposes. Devon identified the Haynesville-Bossier formation as the formation found at depths between 9,568 feet and 11,089 feet in the Devon-Hull Unit A Lease, Well No. 102 (API No. 42-365-36749), in Panola County. This interval is more than 1,500 feet in thickness.
I have recently received several inquiries about the rights of unleased mineral owners whose tract is included in the boundaries of a pooled unit. There seems to be some general miss-perception about this issue.
A typical oil and gas pooling clause allows the lessee to combine separate tracts covered by separate oil and gas leases into a single pooled unit for purposes of exploration and production. This allows the lessee to treat the pooled unit as a single lease. Wells drilled anywhere on the pooled unit are considered to have been drilled on the leased premises covered by each separate lease in the pooled unit, and production from the pooled unit will keep the lease in force beyond its primary term, just as if the production were from each tract in the pooled unit. Production from wells on the pooled unit is allocated among the tracts in the unit, for purposes of paying royalty, on an acreage basis. If a tract in the unit comprises 25% of the total acreage in the pooled unit, then 25% of the unit production is allocated to that tract for royalty purposes, and the mineral owners in that tract receive their royalty on production from the pooled unit just as if 25% of the unit production were produced from the tract.
What happens, then, if the lessee has acquired oil and gas leases on only a portion of the minerals in a tract? Can the lessee include that tract in a pooled unit? If so, how are royalties paid to the owners of unleased minerals in that tract? Do the unleased mineral owners have the right to share in production from the pooled unit?
The Texas Railroad Commission handed down an interesting order last August that may have broad application for operators' use of Texas' Mineral Interest Pooling Act to force unleased mineral owners into pooled units. In Docket No. 09-0252375, Finley Resources applied under the MIPA to form a pooled unit in the Barnett Shale consisting of 96.32 acres, for the drilling of a horizontal well. The proposed unit is in an urbanized area with numerous lots, and Finley was evidently unable to get all lot owners to sign leases. A plat of the proposed unit is shown below. As can be seen from the plat, there are a lot of unleased lots (the white spaces) in the proposed unit.
Under the MIPA, the operator seeking to form the unit must make a "good faith offer" to unleased owners before filing an MIPA application to force them into the unit. Finley offered the unleased lot owners the right to receive a 1/5th royalty and a 4/5ths working interest, which means that 45ths of those owners' share of production from the well would bear its share of the drilling and operating costs of the well. After studying the matter for a year, the Railroad Commission approved Finley's application. One unusual aspect of the order is that the unleased owners suffer no "risk penalty." In most MIPA applications, a party who has refused to join the unit voluntarily must bear its share of the drilling costs plus a "risk penalty," not to exceed 100% of the drilling and completion costs, before participating in revenues from the well. The Commission's order in Finley allows the unleased owners to participate in revenues as a working interest owner once the operator has recovered 100% of drilling and completion costs, with no "risk penalty."
Texas Railroad Commission orders Chesapeake Energy to plug back illegally-drilled Barnett Shale well
Last week I discussed Wagner & Brown v. Sheppard, a recent Texas Supreme Court case that involved a lease termination clause. Sheppard's lease in that case provided that, if royalties were not paid to her within 120 days after first production, the lease would automatically terminate. That is exactly what happened.
Landowners are usually surpriesed to learn that, under a "standard form" oil and gas lease, the lessee's failure to pay royalties does not give the lessor the right to terminate the lease. The lease remains in effect, and the lessor's only remedy is to sue for the unpaid royalties. Landowners often seek to negotiate a clause like Sheppard's that gives the lessor the right to terminate the lease for failure to pay royalties. Exploration companies of course do not like such a provision. It puts them at risk that, if royalties are not timely paid for some inadvertent reason, they can lose the lease even though they are willing and able to pay the royalties.
First, I think it is not a good idea to include a provision that a lease terminates automatically if royalties are not paid within a specified time. Depending on the circumstances, it may not be in the lessor's best interest to terminate the lease, even though royalties have been delayed. A better provision is that, if royalties are not paid by a specified date, the lessor has the option to terminate the lease.
Second, I think that the lessee has a good point as well. The lessor should not be able to terminate a lease because of inadvertence, or an innocent mistake, in paying royalties. A well-drafted termination clause should provide that, if royalties are late, the lessor must give written notice to the lessee and an opportunity to cure the problem. Only if the late payment is not rectified should the lessor have the right to terminate the lease.
A recent decision of the Texas Supreme Court, Wagner & Brown, Ltd. v. Sheppard, has caused quite a stir in oil and gas legal circles. The court was faced with a question never before answered by a Texas appellate court, what is known as a "case of first impression." Such cases are always interesting to oil and gas lawyers, so I thought I would weigh in on the arguments.
The facts in the case are these: Jane Sheppard owns a 1/8th mineral interest in 62.72 acres in Upshur County. She leased her 1/8th interest, and her lease - along with leases of the other 7/8ths interest in the 62.72 acres and leases of other lands- was pooled to form the W.M. Landers Gas Unit, containing 122.16 acres. Two wells were drilled on Sheppard's tract, both producing gas.
Sheppard's lease contains a provision requiring payment of royalties within 120 days of first sales of gas, failing which the lease would terminate. She was not paid on time, and her lease terminated.
Texas law is clear that, if there had been no pooled unit, upon termination of her lease Sheppard would become what is known as a "non-consenting co-tenant" in the two wells on her tract. She would be entitled to receive her 1/8th share of proceeds of sale of gas from the wells, less 1/8th of the costs of production and marketing. But Wagner & Brown contended that Sheppard's tract was still bound by the pooled unit, even though her lease had expired. Under the pooling clause in Sheppard's lease, her royalty would be calculated based on the number of acres of her tract compared to the total number of acres in the unit - in this case, 62.72/122.16, or 51.34% of the wells' production. Wagner & Brown contended that Sheppard should receive 1/8th of 51.34% of production from the wells, less that same fraction of the cost of production and marketing. The Supreme Court agreed with Wagner & Brown, holding that "the termination of Sheppard's lease did not terminate her participation in the unit."