Oil and Gas Lawyer Blog
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.
Devon proposed that the standard drilling unit for a well in the new field be 640 acres, but that operators be permitted to form optional drilling and proration units of 40 acres. Devon proposed that wells be drilled at least 330 feet from any lease or unit line, and that there be no minimum between-well spacing.
Devon also proposed as part of the new field rules two unusual provisions. First, Devon proposed an “allocation rule.” Devon asked that the rules allow an operator “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.” And Devon asked that that the rule provide that, if such a cross-unit well is drilled, “the following allocation formula will be presumed to constitute a fair and reasonable allocation of production from a well in this field: an allocation of 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 the first take point to last take point that lies under each unit or lease.” (A “take point” is a perforation in the casing in the horizontal wellbore through which gas is produced.) Devon argued that such a rule is necessary to properly develop horizontal wells in the Haynesville-Bossier interval. Because large pooled units had previously been created for development of vertical Cotton Valley wells in this area, and because those pooled units were not created with horizontal wells in mind, it would be difficult to efficiently drill horizontal wells without crossing the previously created unit boundaries. Such a new rule, Devon argued, would allow these cross-unit wells and provide for the method of allocating production from the wells between the units crossed by the wellbore for purposes of paying royalties on production.
Second, Devon asked for a “box rule” to be included in the new rules. The purpose of the “box rule” is to give operators some lee-way in complying with the lease-line spacing of 330 feet. Under Devon’s proposed box rule, as long as the operator did not violate the 330-foot rule by more than 50 feet it would be deemed to have complied with the spacing rule.
The RRC hearing examiners, in their proposal for decision, proposed rules providing for 320-acre standard drilling and spacing units; rejected Devon’s proposed allocation rule; and rejected Devon’s proposed box rule. As to the size of standard units, the examiners said that Devon produced no evidence showing that a Haynesville-Bossier well would be capable of draining 640 acres. In fact, the examiners said that Devon’s evidence showed that a well would be capable of draining up to 160 acres. The examiners recommended standard units of 320 acres, the same as the rules for the Newark, East (Barnett Shale) Field.
The examiners also rejected Devon’s proposal for an allocation rule to govern wells drilled across unit lines. The examiners opined that the RRC had no authority to adopt such a rule. Quoting the Texas Supreme Court, the examiners said that “the orders of the Commission cannot compel pooling agreements that the parties themselves do not agree upon.” Devon submitted an opinion from Ernest Smith, former Dean of the UT School of Law and professor of Oil and Gas Law at UT in support of its argument. The examiners said that Professor Smith’s opinion did not support Devon’s proposal.
Finally, the examiners rejected Devon’s proposed box rule for lease-line spacing.
As proposed, the rule would allow an operator to permit a horizontal well running parallel to its lease line 330 feet from an offset operator or unleased mineral owner. Because the well would be permitted at a regular location, no notice to offsets would be required. The operator could then drill the well with an actual location parallel to the lease line but only 280 feet from the offsetting tract along its entire length from penetration point to terminus. Under the proposed rule, the wellbore would be within the “box” and no Rule 37 exception (or notice to the offset being encroached on) would be required. In practical effect, the box rule changes the lease line spacing to 280 feet from offset tracts ratther than the 330 feet spacing distrance expressly state in the rule.
Devon argued that it is practically impossible to drill a horizontal well exactly along the path permitted and that some small deviation should be allowed. The examiners responded that the RRC has always recognized this problem and allowed wells to be drilled without exception as long as the operator has attempted in good faith to drill the well as permitted and the deviation is less than 10%.
The examiners’ proposed decision elicited a strong reaction from other operators in the Haynesville play. Resposes and objections were filed by EOG Resources, Chesapeake Operating Company, XTO Energy, Samson Lone Star, and others. Mostly, these other operators sought to overturn the examiners’ 320-acre unit size.
The RRC’s final decision adopted, on a temporary basis (for two years), field rules providing for the 640-acre units requested by Devon. It accepted the examiners’ decision rejecting the “allocation rule” proposed by Devon, but it accepted Devon’s proposed “box rule.” The parties have the right to appeal the RRC’s decision to state district court.
Most oil and gas leases in Texas have pooling clauses, and most of those pooling clauses allow the lessee to create pooled unit for gas wells of up to 640 acres “plus 10% tolerance, provided that should governmental authority having jurisdiction prescribe or permit the creation of units larger than those specified, units thereafter created may conform substantially in size with those permitted by governmental regulation.” Landowners have typically sought to limit the size of pooled units, because their share of production from the unit will decrease as the size of the unit increases. Although RRC rules cannot directly affect how royalties are paid, the language in leases often refers to RRC rules to establish the permitted size of pooled units. In my experience — which is verified by the outcome of the RRC proceeding discussed above — field rules often have little to do with how much area a well can efficiently drain. The size of drilling and proration units requested by operators more often is driven by their desire to hold as much acreage as possible under lease by production from a single well. I therefore resist lease provisions seeking to tie the size of pooled units to the size of drilling or proration units permitted or prescribed by the RRC.