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What Landowners Need to Know about Field Rules

TexasBarToday_TopTen_Badge_SmallTwo recent appellate opinions illustrate why landowners and their counsel need to know the basic fundamentals of field rules and how they can affect provisions in oil and gas leases. I wrote about those cases in 2015. Both involve the interaction between field rules and lease provisions. ConocoPhillips Co. v. Vaquillas Unproven Minerals, Ltd., 2015 WL 4638272 (Tex.App.-San Antonio Aug. 5, 2015), was appealed to the Texas Supreme Court but settled before the court acted on ConocoPhillips’ petition. Endeavor Energy Resources, L.P. v. Discovery Operating, Inc., 448 S.W.3d 169 (Tex.App.-Eastland 2014), has been briefed on the merits and is awaiting the court’s decision on whether to grant review. You can read my summary of the two cases here.

The root of the issue is that oil and gas lease forms typically refer to and adopt field rules to regulate how large pooled units and earned acreage units can be. For example, a printed form oil and gas lease that has been commonly used in Texas for many years contains the following provision:

Lessee is hereby granted the right, at its option, to pool ur unitize any land covered by this lease with any other land covered by this lease, and/or with any other land, lease, or leases, as to any or all minerals or horizons, so as to establish units containing not more than 80 surface acres, plus 10% acreage tolerance; provided, however, units may be established  … so as to contain not more than 640 acres plus 10% acreage tolerance, if limited to … gas, other than casinghead gas…. If larger units than any of those herein permitted, either at the time established, or after enlargement, are required under any governmental rule or order, for the  drilling or operation of a well at a regular location, or for obtaining maximum allowable from any well to be drilled, drilling or already drilled any such unit may be established or enlarged to conform to the size required by such governmental order or rule.

To understand how the italicized sentence in this lease form works, one must know what governmental rules govern the size of units for drilling wells at a “regular” location, and for “obtaining maximum allowable” from a well. These regulations are included in “field rules” adopted by the Texas Railroad Commission. (Warning: this post is longer than usual, so be prepared.)

Two other examples of lease language dependent on field rules can be found in the Vaquillas and Endeavor cases referred to above. In Vaquillas, the lease provided:

Lessee covenants and agrees to execute and deliver to Lessor a written release of any and all portions of this lease which have not been drilled to a density of at least 40 acres for each producing oil well and 640 acres for each producing or shut-in gas well, except that in case any rule adopted by the Railroad Commission of Texas or other regulating authority for any field on this lease provides for a spacing or proration establishing different units of acreage per well, then such established different units shall be held under this lease by such production, in lieu of the 40 and 640-acre units above mentioned.

The lease language at issue in the Endeavor case provided that at the end of a continuous drilling program the lease would terminate:

as to all lands and depths covered herein, save and except those lands and depths located within a governmental proration unit assigned to a well producing oil or gas in paying quantities and the depths down to and including 100 feet below the deepest productive perforations, with each such governmental proration unit to contain the number of acres required to comply with the applicable rules and regulations of the Railroad Commission of Texas for obtaining the maximum producing allowable for the particular well.

What, then, are proration units, well allowables, and spacing rules, and why are they referred to in oil and gas leases?

The Texas Railroad Commission was given authority over oil and gas operations in Texas in order to give order to the oil-field chaos that resulted from the drilling of multiple and unnecessary wells in a fierce competition to get the most oil. The result was a glut in oil supply that caused prices to plunge, the waste of capital and resources, and damage to the oil reservoirs. To give order to the industry (and to control the rate of production so as to reduce supply and increase the price), the Commission established rules to govern how far wells had to be spaced apart from each other and how much a well could produce in any given month. The standard, statewide rule provided, and still provides, that wells have to be at least 1200 feet from any other well producing from the same horizon, and that no well may be located less than 467 feet from the boundary of the lease on which the well is drilled. This established a drilling pattern requiring 40 acres around each well. The Commission also adopted a system by which each well in a field was assigned an “allowable,” a maximum amount the well could produce during any month. Each well’s allowable was based on factors intended to give the well its fair share of the total allowable production established for the field from which the well produced. The allowable system prevented operators from competing with each other to maximize production and thereby producing at rates that would damage the reservoir or produce more than the market could absorb. It also allowed the Commission to control supply. The Commission was the OPEC of the world in the early part of the last century.

The Commission allows operators to apply for “special” field rules for spacing and allowables that apply to particular reservoirs. Because each reservoir has different geological characteristics, well spacing and allowable assignments can be designed to fit the circumstances of each reservoir.

Field rules are requested by an operator who has drilled a well into a new reservoir or source of supply, to establish the spacing and allowable rules for wells drilled into that reservoir. Initially, temporary rules are established based on the limited information then available about the reservoir, and those rules are reviewed, usually after 18 months, and either modified or made permanent. Field rules may be and often are amended on application of interested parties.

The basic practice for establishment of field rules was developed in the era of exploitation of conventional reservoirs. The geology of conventional reservoirs was well understood – how accumulations of oil and gas were trapped in the reservoir, how they flowed within the reservoir under different conditions of pressure and production rates, and what rates of production best suited the reservoir to produce the most from the reservoir at the maximum safe rates of production. Field rules establish well spacing and density – how far wells must be spaced apart and from lease boundaries — and how many wells can be drilled on a lease or pooled unit. To govern well density, field rules provide for “proration units.” A proration unit is a designated area around a well that is assigned by the operator in accordance with the applicable field rules to establish the “density” of wells in the field. The size of the proration unit specified by the Commission is intended (or at least was originally intended) to establish the amount of acreage that a well in the field can drain effectively. Density rules are intended to prevent the drilling of unnecessary wells in the field. Field rules might establish density rules of 40 acres per well up to 640 acres per well. Density rules for gas reservoirs generally provide for larger proration units than oil wells because wells in conventional gas reservoirs are able to drain a larger area than wells in conventional oil reservoirs.

Field rules also often contain “optional” density provisions. The idea is that different parts of the same field may have different drainage characteristics. A less productive portion of the field may need two wells to drain a standard unit that in other areas of the field can be drained by one well. So some field rules allow “optional” proration units of a size smaller than the “standard” proration unit for the field.

Field rules also provide an “allocation formula” for wells in the field. The formula establishes how the allowable assigned to the entire field is distributed among the wells in the field. The factors used in the formula may include the amount of acreage in a well’s proration unit, the initial potential of the well, the initial pressure of the reservoir in the well, the deliverability of the well, or some combination of those factors. In most field rules, the acreage assigned to a well is a factor in establishing the “allowable” for that well – how much of the field’s total allowable is assigned to that well.

How, then, do field rules affect the rights of landowners under oil and gas leases? In the first example of a lease form I quoted above, the field rules establish how large a pooled unit can be.  Under that clause, the pooled unit can be as large as the field rules allow in order to obtain the “maximum allowable” for a well in the field. This makes sense. The field rules are intended to determine how much each well can produce, and that depends on the proration unit assigned to the well, so the lessor and the lessee would both want the well to produce at its maximum allowable rate. As long as the size of the proration unit and the well’s allowable have some relation to the well’s capacity to produce from the reservoir and the area that can be drained by the well, it is logical to tie the size of any pooled unit to the maximum proration unit allowed for the field.

Or take the language used in the Endeavor case. That lease provided that, at the end of a continuous drilling program, the lease would terminate:

as to all lands and depths covered herein, save and except those lands and depths located within a governmental proration unit assigned to a well producing oil or gas in paying quantities and the depths down to and including 100 feet below the deepest productive perforations, with each such governmental proration unit to contain the number of acres required to comply with the applicable rules and regulations of the Railroad Commission of Texas for obtaining the maximum producing allowable for the particular well.

The drafter of this provision adopted the field rules as the measure of how much lease acreage would be retained by production from a well in the field. This assumes that the field rules establish proration units as a measure of how much acreage in the field can be drained by one well. It also assumes that the lessor would not want the allowable for the well to be reduced because less than the maximum area for the proration unit is assigned to the well under the field rules.

This proration and field-rule system, developed during the era of exploitation of conventional reservoirs, served the industry and royalty owners well and allowed the Commission to prevent waste and protect the correlative rights of operators in a field by giving each operator a fair chance to produce its share of oil and gas from the field without damaging the reservoir by overproduction. It also allowed the Commission, through the proration system, to control supply and thereby regulate prices. But this system has not adapted well to the new era of unconventional wells in shale plays and unregulated production.

So what has changed?

Although the Commission continues to adopt field rules that provide for assignment of allowables to wells in the field – usually based on acreage assigned to each well under the field rules – as a practical matter the allowable system no longer limits or regulates the amount a well can produce. The allowable system for gas has been “suspended” by the Commission for many years, so gas wells can always produce at their maximum rate. And the field rules adopted for the fields in the new shale reservoirs usually set the allowable so high that no well in the field can produce in excess of its allowable, except perhaps in the early months of the well’s production. So, in those shale fields where the maximum allowable depends in whole or in part on the amount of acreage assigned to the well for allowable purposes, a well seldom if ever actually needs to have the maximum acreage assigned to the well in order to produce at its maximum rate. As a result, the language used in many leases, providing that the lessee can retain the amount of acreage necessary to “produce the maximum allowable” is no longer relevant to most wells.

Also, field rules adopted for shale fields have abandoned any effort to relate the amount of acreage that must be assigned to a well for allowable purposes to the amount of acreage that can be drained by a well in the field. Most wells in shales are horizontal. They are drilled in shales, which are rocks permeated by oil and gas. Such rock has almost no permeability – the measure of how oil and gas can move through the rock – and so must be produced by fracturing the rock to release the hydrocarbons. Hydraulic fracturing treatment creates these fractures in the rock, but the fractures extend only a few hundred feet from the wellbore, and so the area drained by a horizontal well may be only 200 or 300 fee on either side of the wellbore. A well with a 5,000-foot horizontal lateral that drains an area 300 feet on either side of the wellbore would drain an area of only about 70 acres. And yet field rules typically allow the operator to assign up to 640 acres or even more to such a well. Clearly, any effort to use field rules to estimate the amount of acreage drained by the well has been abandoned.

For example: the field rules adopted by the Commission for the Phantom (Wolfcamp) Field in the Permian Basin provide that no well can be drilled nearer than 330 feet from a lease or unit line. This indicates the Commission’s judgment that a wellbore more than 330 feet from the lease line will not likely drain hydrocarbons from the adjacent lease. And yet the rules provide for assignment of acreage for proration purposes of 320 acres plus additional acreage based on the lateral length of a horizontal well, as follows:

0′ to 1,500″ – 320 acres

1,501′ to 3,000′ – 480 acres

3,001′ to 4,500′ – 640 acres

> 4,500′ – 704 acres

So an operator who completes a horizontal well with a 5,000-foot lateral can assign as much as 704+320=1,024 acres to the well as a proration unit, even though the well will drain only 70 or 80 acres. The field rules provide that the maximum daily oil allowable for a well in the field is 13 barrels for each acre assigned to the well for allowable purposes. So a well assigned 1,024 acres for allowable purposes could legally produce 13,312 bbls per day!

Under the Phantom (Wolfcamp) field rules, if a lease allows pooled units to be based on the amount of acreage necessary to provide the maximum allowable for the well on the proration unit, a well with a 5,000-foot lateral would enable the operator to form a pooled unit as large as 1,024 acres for that one well. If a lease allows retained acreage based on the acreage necessary to obtain the maximum allowable for a well in the field, the well could retain up to 1,024 acres.

Because the relation between the amount a well can drain and the amount of acreage that can be assigned to a well for allowable purposes has been abandoned in modern shale field rules, landowners and those lawyers representing them should, in my opinion, eliminate any reference to field rules in their oil and gas leases. Negotiations for the maximum size of proration units or retained acreage units should be based on the amount of acreage a well can actually drain, not on field rules.

Operators obtain field rules without any notice to landowners. The language in field rules is arcane and understood only by oil operators and their counsel and the Commission staff. It is not even easy to find what field rules apply to a particular well. And operators often “shop” field rules when they decide what field to designate for the wells they complete, in order to use the field rules to their advantage in forming units.

Recently, the Texas General Land Office, responsible for management of minerals on State lands, has become more active in reviewing and opposing field rule applications where the proposed rules are not based on science, because such rules could apply under some GLO leases to the disadvantage of State interests. Most recently, the GLO protested proposed new field rules applied for by Apache for its Alpine High discovery in Reeves County.

The lesson: landowners and their counsel need to be cognizant of the relation between field rules and their lease language and suspicious of any lease provision referring to field rules.

 

 

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