Pooling

Published on: January 10, 2013

Taylor and Ellis Introduce Forced Pooling Bill in Texas Legislature

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:

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Published on: November 10, 2012

Herein of “Production Sharing Agreements” and “Allocation Wells”

By John McFarland

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.

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Published on: June 10, 2010

EOG Resources Proposes Temporary Consolidated Field Rules for Eagle Ford Shale

By John McFarland

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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Published on: April 23, 2010

Gatti vs. State of Louisiana – a Challenge to Multiple-Well Pooling Orders in Louisiana

By John McFarland

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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Published on: March 14, 2010

Devon Appeals Temporary Field Rules for Carthage (Haynesville Shale) Field

By John McFarland

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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Published on: December 24, 2009

Texas Railroad Commission Adopts New Temporary Field Rules for Carthage (Haynesville Shale) Field

By John McFarland

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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Published on: December 7, 2009

Pooled Units and Unleased Mineral Interests

By John McFarland

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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Published on: May 22, 2009

Expanded Use of Mineral Interest Pooling Act?

By John McFarland

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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Published on: April 21, 2009

Texas Railroad Commission orders Chesapeake Energy to plug back illegally-drilled Barnett Shale well

By John McFarland

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.

Published on: March 18, 2009

Oil and Gas Lease Termination Clauses

By John McFarland

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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