Articles Posted in Lease clauses

Published on:

I recently wrote about two appellate opinions dealing with retained acreage clauses in oil and gas leases. A retained acreage clause requires the lessee to release acreage not assigned to a producing well at the end of the primary term, or at the end of a continuous drilling program conducted after the primary term. One commentator has said that the purpose of a retained acreage clause is to “replace the lessor’s need to utilize the implied covenant of reasonable development as the sole means to see that its  acreage is fully developed.”  Bruce M. Kramer, Oil and Gas Leases and Pooling: a Look Back and a Peek Ahead, 45 Tex. Tech L. Rev. 877, 881 (2013).

A retained acreage clause should be included in any oil and gas lease that covers a significant amount of acreage – more than 100-200 acres. Below is a retained acreage clause, from the TLMA lease form. TLMA is the Texas Land and Mineral Owners Association. I prepared the lease form, and TLMA provides it to all of its members:

Upon expiration of the Primary Term, or upon cessation of “Continuous Drilling Operations” (as hereinafter defined), whichever is later, this Lease shall terminate as to all the lands and depths then covered thereby except lands and depths then designated by Lessee, in accordance with the requirements of this Paragraph, to be within a “Production Unit” (as hereinafter defined) assigned to each well then producing in paying quantities on the Leased Premises or lands properly pooled therewith.

  • Continuous Drilling Operations. Lessee shall be considered to be engaged in “Continuous Drilling Operations” at the end of the Primary Term for purposes of this Paragraph if Lessee is engaged in Drilling Operations on the Leased Premises or lands pooled therewith at the end of the Primary Term, or if Lessee has completed or abandoned a well within ninety (90) days prior to the end of the Primary Term; and Lessee shall be deemed to be engaged in Continuous Drilling Operations for as long thereafter as Lessee conducts Drilling Operations on the Leased Premises or lands pooled therewith with due diligence and with intervals of not more than ninety (90) days between the date of completion or abandonment of one well and the date of commencement of actual drilling of the next well. If Lessee is engaged in Continuous Drilling Operations at the end of the Primary Term, then such Continuous Drilling Operations will be deemed to have ceased when Lessee fails to commence actual drilling of a well within ninety (90) days after the completion or abandonment of the preceding well, and this Lease shall thereupon terminate except as to Production Units assigned to wells then producing in paying quantities from the Leased Premises or lands pooled therewith, as provided in this Paragraph.
  • Production Unit. A “Production Unit,” for purposes of this Lease, is a designated area of land around a well having the minimum amount of acreage necessary to obtain a regular permit for the drilling of a well, as required by the field rules of the Railroad Commission of Texas applicable to the field from which such well is producing. Each Production Unit shall be limited in depth to one hundred (100) feet below the deepest perforation in any well on such Production Unit.
  • Maximum Sizes of Production Units. Notwithstanding any density rules applicable to any well, however, no Production Unit assigned to any well shall exceed the following sizes:
    • If the well is classified as a vertical oil well under the Rules and Regulations of the Railroad Commission then in effect, the maximum size of the Production Unit shall be __________ acres [if the well is producing in whole or in part from formations less than __________________ feet beneath the surface, and ___________ acres if the well is producing from formations located wholly below ___________ feet beneath the surface].
    • If the well is classified as a vertical gas well under the Rules and Regulations of the Railroad Commission of Texas then in effect, the maximum size of the Production Unit shall be __________ acres [if the well is producing in whole or in part from formations less than __________________ feet beneath the surface, and ___________ acres if the well is producing from formations located wholly below ___________ feet beneath the surface].
    • If the well is classified as a horizontal well (whether oil or gas) under the Rules and Regulations of the Railroad Commission then in effect, then the maximum size of the Production Unit shall be determined by the following formula: A = 40 + .____ X L, where A = the area (in acres) of the Production Unit and L = the length (in feet) of the horizontal lateral component of the drainhole of the well, from the first take point to the last take point.

If at the time Lessee must designate Production Units in accordance with this Paragraph there is a well or wells on the Leased Premises producing from a field for which no field rules have yet been adopted, then Lessee shall designate a Production Unit complying with the size requirements listed in (i), (ii), or (iii) above, as applicable, and Lessee shall, if and when requested by Lessor, proceed with diligence to apply for field rules for such field; and when such field rules are adopted by the Commission, if such field rules provide for proration units smaller than the maximum Production Unit sizes provided for above, Lessee shall designate a Production Unit for such well complying with such field rules, and shall release the lands no longer included in the Production Unit for such well or wells; provided, however, that Lessee may maintain this Lease as to such excluded lands if Lessee commences Drilling Operations on such lands within sixty (60) days from the final adoption of such field rules, and continues such Drilling Operations with no cessation of more than sixty (60) consecutive days until production is established, in which event Lessee shall designate Production Units and this Lease shall remain in force as to the units so designated as provided in this Paragraph.

  • Configuration of Production Units. Insofar as possible, taking into consideration the productive limits of the producing interval and the configuration of the Leased Premises, the lands included within the Production Unit for a well shall be in the form of a square or rectangle. Every effort shall be made in designating Production Units to avoid releasing small or irregularly shaped portions of the Leased Premises, or portions not contiguous with other released portions. Acreage assigned to wells producing from different zones may overlap, and shall overlap when necessary to comply with the requirements of this Paragraph. If a well is producing from more than one formation, its Production Unit’s size and configuration shall conform to the Railroad Commission rules applicable to the well which provide the largest Production Unit (subject to the size limitations stated above). If all or a portion of the Leased Premises is included in a pooled unit, then for purposes of this Paragraph all the lands within the pooled unit shall be considered a part of the Leased Premises, and the size and configuration of the pooled unit must conform to the requirements of this Paragraph for a Production Unit.
  • Maintenance of Lease after Designation of Production Units. As to acreage and depths which are included within a Production Unit, this Lease may be held in force after the termination of the Primary Term or cessation of Continuous Drilling Operations, whichever is later, only by Operations conducted (as provided in this Lease) on such Production Unit (or lands pooled therewith), with no cessation of operations of more than sixty (60) consecutive days; and Operations conducted on one Production Unit (or lands pooled therewith) will not maintain this Lease in force as to any other acreage included within any other Production Unit, but such production or Operations will maintain this Lease only as to the acreage within the Production Unit or Production Units upon which such Operations are being conducted.
  • Recordable Release. Upon termination of this Lease as to any portion of the Leased Premises, Lessee shall deliver to Lessor a plat showing the designated Production Units around each well (and designating the depth) and a partial release designating such Production Units in compliance with the requirements of this Paragraph, suitable for recording. Such release shall include a release of the depths below 100 feet below the deepest perforation of the well with paying production in each Production Unit, respectively.

Some comments:

The term “production unit” is used to distinguish it from pooled units and proration units. The three are quite different.

The time between completion and commencement of wells for “continuous drilling operations” is negotiable. Definitions for commencement of Drilling Operations and Completion of a well should be provided.

The definition of a Production Unit includes a depth limitation. How that depth limitation is defined may be the subject of negotiation. For example, the lease could require release of depths above and below the producing formation in each Production Unit.

The maximum size of Production Units is negotiated and may be different for oil and gas wells, different depending on depth of completion, and different for horizontal wells. Note that the size of Production Units for horizontal wells is the same for wells classified as oil or gas wells.

The maximum size of a Production Unit for a horizontal well is based on a formula: 40 + ____ X L, where L is the length of the lateral, from first take point to last take point. A take point is a perforation in the casing from which oil and gas is being produced. If the parties agree that the Lessee may have a 160-acre production unit for a well with a lateral length of 5,000 feet, then the formula is 40 + .024 X L.  To derive the number that goes in the blank based on the desired size of the Production Unit, use the formula (A – 40)/L, where A = the desired size of the production unit for a well with a lateral length of L. For example, if the parties agree that a well with a 5,000-foot lateral will have a maximum Production Unit size of 320 acres, then the fraction to use in the formula is (320-40)/5000 = .056. Using this formula, if the well has, say, a 7,000-foot lateral, then the Production Unit for the well can be up to 40 + .056 X 7,000 = 432 acres.

After continuous drilling operations have ceased, each Production Unit in effect becomes a separate lease. Production from one Production Unit will not keep the lease in force as to any other Production Unit.

There are many other variations on retained acreage clauses; the above clause is only one example and does not address every issue that might be negotiated in such clauses. A retained acreage clause should, however, address each of the elements that is the subject of each of the paragraphs of the clause copied above.

Published on:

In its 2009 Legislative Session, the Texas Legislature passed House Bill 2259, whose stated purpose is to ensure that inactive oil and gas wells get plugged and that surface equipment associated with those wells gets removed. I provided a summary of the bill’s terms in a post on this site. A summary of the bill’s requirements from the Texas Railroad Commission may be found here. The Texas Land and Mineral Owners Association, which lobbied for the bill, has now issued its report card: the Railroad Commission is not doing its job.

HB 2259 does not actually require that inactive wells be plugged. It imposes requirements on operators of inactive wells, depending on how long the wells have been inactive, to: disconnect the wells from electricity; post additional bonds to assure that the wells will eventually be plugged; and remove surface equipment from the wells. These provisions are phased in over a 10-year period. HB 2259 provides that an operator who does not comply with the new requirements will lose its operating permit (known as a P-5) — meaning that it will not have the right to continue to operate any wells in the State.

Recently, TLMA asked the RRC how many P-5 permits have been denied because of failure to comply with HB 2259. The answer: none. Even though, according to TLMA, almost 1,500 operators failed to comply with the statute.

After HB 2259 was passed, operators complained to the Lege that they could lose their P-5 for simple paperwork violations that were not substantive. So the Lege in 2011 amended the statute to provide to the operator an opportunity to appeal the RRC’s denial of an operating permit.

TLMA asked the RRC how many violations of the statute resulted from paperwork problems and how many were substantive violations. The RRC was unable to provide that information.

According to the RRC’s website, there are 38,854 inactive wells in Texas that have been inactive for 10 years or more. Inactive wells pose a hazard to the environment, including groundwater resources, and are an eyesore on Texas land.

Under a typical oil and gas lease, the operator has no obligation to plug a well as long as the lease remains in effect. When leases reach their later stages of production they are often transferred to smaller operators who continue to operate the active wells on the lease as “stripper” wells. When a lease is transferred, the RRC requires that the permit to operate wells on the lease be transferred to the new operator. As long as the wells are in compliance with RRC rules and the new operator has a valid operating permit, the transfer will be approved. Once transfer of the permits for the wells is approved, the prior operator has no further obligation with respect to the wells transferred. So the prior operator in effect has transferred the obligation to plug any inactive wells on the lease to the new operator. Stripper well operators may have limited financial resources and will continue to defer plugging of active wells as long as they can. In many instances, the stripper operator eventually goes broke, and the obligation to plug the wells falls on the State. The wells become “orphan” wells.

I have struggled to find an appropriate way to address inactive wells in my oil and gas leases. Operators naturally want to delay spending the money to plug inactive wells. One solution I have used in oil and gas leases is to impose a “rental” on inactive wells. The lease provides that the lessee must pay the landowner for the right to keep a well unplugged and inactive. The annual rentals increase over time, thus increasing the operator’s incentive to either plug the well or put it back into production. Failure to pay the rental may result in termination of the lease.

With the new drilling boom in Texas, the problem of inactive wells will only continue to increase. It remains to be seen whether HB 2259 will improve the situation.

Published on:

Recently some of my clients have received notices of class action settlements in Coll v. Abaco Operating, LLC, et al., in the U.S. District Court for the Eastern District of Texas, Marshall Division, C.A. No. 2:08-CV-345 TJW. The case reveals a little-known aspect of royalty payments: many companies never reimburse their royalty owners for refunds of severance taxes.

Most royalty owners know little about severance taxes except that they are a deduction that regularly appears on their royalty check stubs. Texas imposes a tax on the value of all oil and gas produced in the state: 7.5% for gas and 4.6% for oil. Most producing states impose similar severance taxes. Pennsylvania has been debating whether to pass a severance tax in light of its budget problems and recent development of the Marcellus Shale in that state. Texas’ severance taxes are paid into its “rainy day fund” that has been much in the news of late.

Continue reading →

Published on:

I always counsel my clients to provide in their oil and gas leases that they have the right to inspect and copy all documents of the lessee necessary to determine whether royalties have been paid correctly, and to audit the records of the lessee to confirm accurate payment of royalties. Royalty owners generally assume that the royalty payments they received have been calculated and paid as required by their leases. This is not always the case, as illustrated by a recent case, Shell Oil Company SWEPI LP v. Ross, 2010 WL 670549 (Tex.App.-Houston [1st Dist.], decided February 25, 2010. The case illustrates typical schemes used by producers to underpay royalty owners, and their efforts to prevent royalty owners from knowing how royalties are calculated and, when the royalty owners discover the underpayment, to prevent royalty owners from recovering the underpayment. 

In Shell v. Ross, the trial court and Houston Court of Appeals held that Shell had underpaid royalties due to Ross.  Shell has appealed to the Texas Supreme Court.  The Texas Supreme Court refused to consider the case, but Shell has filed a motion for re hearing that is still pending. Other producers are very interested in the case:  friend-of-the-court briefs have been filed by Chesapeake, Texas Oil & Gas Association, and the American Petroleum Institute asking the Court to reverse the Court of Appeals.

The facts of the case require some explanation but illustrate well the importance of verifying the correct calculation of royalties.


Continue reading →

Published on:

A royalty owner in the Barnett Shale has sued Chesapeake in Oklahoma federal court for failure to properly pay royalties. The suit, Robyn Coffey vs. Chesapeake Exploration, L.L.C. and Chesapeake Operating, Inc., Civil Action No. CIV-10-1054-C, was filed on September 27 in the U.S. District Court for the Western District of Oklahoma, in Oklahoma City. A copy of the complaint can be viewed here: Coffey v Chesapeake.pdf  The plaintiff seeks to bring the case on behalf of all royalty owners in the Barnett Shale formation, as a class action.

The plaintiff alleges that Chesapeake “employs a scheme” to reduce royalty payments by selling the gas to its wholly owned subsidiaries at a price “substantially less than either the market value at well or the amount actually received by Chesapeake Operating.”

The royalty clause in the plaintiff”s oil and gas lease is unusual. It provides for payment of royalties based on the “market value at the point of sale,” but not less than “the actual amount realized by the Lessee.” The clause says that all royalty paid to the lessor “shall be free of all costs and expenses related to the exploration, production and marketing of oil and gas production from the lease including, but not limited to, costs of compression, dehydration, treatment and transportation.” Most gas royalty clauses provide that gas royalties will be based on “the amount realized by Lessee, computed at the mouth of the well,” or similar language.

The plaintiff’s lease does not expressly address sales by a lessee to a company which is affiliated with the lessee. The plaintiff in this case will therefore have to prove in effect that the sale to Chesapeake’s affiliate is a sham designed to cheat its royalty owners. It is possible to draft a royalty clause that would deal with sales to affiliates — in effect providing that royalties shall be based on the proceeds received by the lessee or any affiliate of the lessee — in other words, based on the price received in the first arms-length sale to an unrelated third party.

The case is obviously drafted to be a class action. The amount of the individual plaintiff’s claim is not stated in the complaint, but the plaintiff owns royalties on only about 3 acres. If the plaintiff is able to get the case certified as a class action on behalf of all Chesapeake royalty owners in the Barnett Shale, millions of dollars of royalty will be at issue in the case.  It is evident that the lawyers elected to file in Oklahoma because the Texas Supreme Court has been very hostile to royalty owner class actions in Texas. In light of the unusual language in this royalty owner’s lease, it will be interesting to see if the federal court in Oklahoma will be willing to certify this case as a class action.

Published on:

A major issue in shale plays is the use of underground supplies of fresh water to fracture-stimulate the well. Horizontal shale wells are fracture-treated with fresh water to which various chemicals are added, and huge volumes of fresh water are needed. A 5,000-foot lateral horizontal well will use up to seven million gallons of fresh water. Depending on the availability of underground water at the lease, the operator’s use of that resource could have a substantial adverse impact on the landowner’s subsurface water supply.


The impact of fracing in the Barnett Shale was a subject of study by the Texas Water Development Board in 2007. The TWDB concluded that 89% of the water supply for the region of the Barnett Shale field was supplied by surface water sources, and that groundwater used for Barnett Shale development accounted for only 3 percent of all groundwater used in the study area. In East Texas, underground water is more plentiful and using it to frac wells may not place a strain on aquifers. But the Eagle Ford Shale is generally in a more arid part of the state where surface water supplies are more scarce and underground water is a more precious resource. Where the mineral owner also owns the surface estate, attention needs to be paid to the impact of mineral development on underground water supplies.

Companies have developed recycling methods to re-use frac water, which have been tested on an experimental basis. Devon has reported that it has been able to recycle a small percentage of the frac water used in its Barnett Shale wells and in the last three years has recycled nearly 4 million gallons. One obstacle is cost. It was reported that it costs about 40 percent more to recycle the water than to dispose of it by underground injection. Devon has said that its cost of recycling water in Barnett Shale wells is $4.43 per barrel, vs. $2 to $2.50 per barrel for typical water disposal into an injection well. Devon said that less than 5% of Devon’s revenue goes toward the cost of handling flow-back water. For a good article on recycling frac water, go to this link.

Continue reading →

Published on:

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:

Continue reading →

Published on:

As landowners have become more sophisticated in their negotiations of oil and gas leases, they have begun to insist on the inclusion of a “continuous operations” or “continuous drilling” clause in their leases. The idea behind such clause is that the lessee should have a reasonable time to fully develop the leased premises, after which the lessee should release that portion of the leased premises not necessary for the production of the wells it has drilled.

There is no “standard form” of continuous operations clause. Generally, a continous operations provision should address the following:

Continue reading →

Contact Information