Articles Posted in Pooling

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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:

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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.

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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.

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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.

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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?

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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.

 

 

Finley Unit.JPG 

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.”

 

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The Texas Railroad Commission has denied Chesapeake Energy’s request for permission to produce its Ramey 1H well in Tarrant County, because the well was drilled in violation of RRC spacing rules. Chesapeake drilled the horizontal well with a 3,553-foot lateral, even though its permit was for a lateral of only 1,839 feet. The RRC ordered Chesapeake to plug back the well so as to comply with the permit. The problem was that the wellbore passed wihin 330 feet of an unleased tract, violating the Barnett Shale field rules that require all wells to be located at least 330 feet from the boundary of the lease or unit. Kevin Cunningham, regional counsel for Chesapeake’s southern division, said that the ruling “would have the negative effect of rendering a significant amount of gas” unrecoverable under Chesapeake’s leases. For the story in the Fort Worth Star-Telegram, click here. Situations like those faced by Chesapeake will drive the debate for forced-pooling legislation in Texas.

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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.

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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.”

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