Oil and Gas Update

Fixed or Floating? Another Texas Case Tackles Interpreting NPRIs

    A Texas court of appeals recently issued a decision construing the reservation of a nonparticipating royalty interest (NPRI) in a deed and resolving a dispute concerning the nature and calculation of such NPRI.  The case, Hoffman v. Thomson[1], is another example of the “fixed” vs. “floating” royalty line of Texas cases, which has become an area of frequent litigation in the oil and gas arena, and is one in a recent line of such cases in which the court had to assess the impact of the parties’ inclusion of a double fraction in the deed.

    A fixed royalty is a fixed fraction of the total production.  A floating royalty refers to a fraction of the entire royalty interest, meaning the total amount the NPRI owner receives depends on the royalty rate negotiated in the lease.  Confusion arises with double fractions.  For example, does “1/2 of the 1/8 royalty” result in a fixed 1/16 royalty or a floating 1/2 royalty?

Recent Cases

    Before discussing Hoffman, a brief recap of recent decisions is useful in framing the case.

 Hysaw v. Dawkins[2]

             In this 2016 case from the Supreme Court of Texas, a woman’s 1946 will left each of her three children a NPRI of “an undivided one-third (1/3) of an undivided one eighth (1/8) of all oil, gas or other minerals in or under that may be produced from any of said lands.”[3]  This language created an issue of whether the double fraction reserved a fixed 1/24 royalty or a floating 1/3 royalty.  The Court found this was a floating 1/3 royalty for a variety of reasons.  It made sense that three children would be given equal 1/3 shares, the standard royalty at the time the will was drafted was 1/8, and a fixed interest would create disharmony among deed language.

U.S. Shale Energy II, LLC v. Laborde Properties, L.P.[4]

            The Supreme Court of Texas dealt with a case very similar to Hysaw in 2018.  Here, a 1951 deed reserved “an undivided one-half (1/2) interest in and to the Oil Royalty, Gas Royalty and Royalty in other Minerals in and under that  may be produced or mined from the above described premises, the same being equal to one-sixteenth (1/16) of the production…”[5]  Again, this was found to be a floating royalty based on the standard 1/8 royalty of the time, “…the same being equal to one-sixteenth…” serving as clarifying language to the calculation, and the 1/2 interest being tied to the royalty rate.

Five Star Royalty Partners Ltd. v. Mauldin[6]

             The Fifth Circuit answered another question about a deed containing floating royalties in this 2020 decision.  The confusion stemmed from a 1927 deed conveying a “royalty interest of three-eighths (3/8) of all … minerals…” which also included the clauses, “the royalty interest hereby conveyed is a three-eighths (3/8) part of the royalty provided by said lease to be paid…” and “three-eighths of one-eighth interest… is a royalty interest only…”  In determining whether this was a fixed 3/64 royalty or a floating 3/8 royalty, the court looked to factors such as the usual 1/8 royalty during that era, the deed did not relieve the grantee of the requirement to pay production costs, and the previous lease with a 1/8 royalty terminated.  The court held this was a floating 3/8 royalty, resulting in a victory for the royalty interest owners, who were represented by Thompson & Knight attorneys.

Van Dyke v. Navigator Group[7]

            This late 2020 decision comes from another Texas court of appeals.  The court found a fixed 1/16 NPRI existed.  The deed reserved a “one-half of one-eighth of all minerals and mineral rights,” and this figure was the only mention of the size of an interest.  The court determined the language in the deed to be unambiguous, since there was no other language used to describe the reservation, thus creating a fixed 1/16 reservation.

            All of the above cases (particularly Hysaw and U.S. Shale Energy II) show a trend of a holistic approach in deed interpretation, rather than a mechanical approach.  Hoffman continues to follow this trend.

Hoffman v. Thomson

             In 1956, the Hoffmans conveyed a tract of land to Peeler and reserved “an undivided three thirty-second’s (3/32’s) interest (same being three-fourths (3/4’s) of the usual one-eighth (1/8th) royalty) in and to all of the oil, gas and other minerals, in to and under or that may be produced from the land herein conveyed…”[8] Both parties argued the deed was unambiguous, with the Hoffmans asserting the deed reserved an undivided floating 3/4 royalty and the Peelers claiming the deed only reserved a fixed 3/32 NPRI.  The parties did not dispute any facts; this was purely a deed construction case.  The trial court sided with the Peelers and construed the deed to reserve a fixed 3/32 NPRI.

            Before beginning its interpretation, the court laid out a few basic deed construction principles that it stated guided its analysis.  Continuing in the line of cases discussed above, the court placed particular emphasis on the fact that at the time when the deed was written in 1956, a 1/8 royalty was considered “standard and customary.”[9]

            Ultimately, the court honed in on three clauses contained in the deed, which read as follows:

Clause 1          “There is hereby expressly reserved… an undivided three thirty-second’s (3/32’s) interest (same being three-fourths (3/4’s) of the usual one-eighth (1/8th) royalty) in and to all of the oil, gas and other minerals…”

Clause 2          “Hoffman … shall receive a full three thirty-second’s (3/32’s) portion thereof as his own property…”

Clause 3          “Hoffman, shall own and be entitled to receive three thirty-second’s (3/32’s) of the gross production of all oil, gas and other minerals produced and saved…”

The court noted that, read in isolation, the latter two clauses would likely establish a fixed royalty interest.  Clause 3, for example, appears to expressly require that the owner be entitled to three thirty-seconds (3/32’s) of the “gross production.”  However, the court stated it “must give effect to, and harmonize, all the language, even if the second and third clauses might initially appear inconsistent or contradictory to the entire first clause.”[10]

When harmonizing the language, the court noted again that the “same being three-fourths (3/4’s) of the usual one-eighth (1/8) royalty” was consistent with the usual 1/8 royalty of that time, meaning the Hoffmans kept a 3/32 interest, or 3/4 of the royalty, whatever that royalty may actually be under the relevant lease at issue.  Thus, the court concluded, when 3/32 is used in the later clauses, it was used as “a placeholder or shorthand” for the full 3/4 of the royalty.[11]  According to the court when 3/32 is replaced with “three-fourths of the royalty” in later clauses, the “substitution also gives full effect to the language in all three clauses and does not create any conflicts or render any provision meaningless.”[12]  If the deed reserved only a 3/32 interest, the “same being three-fourths … of the usual one-eighth royalty” language would be both meaningless and create a conflict if the royalty was anything besides 1/8.  In continuing to follow the trend of holistic interpretation, the court determined the deed established a floating 3/4 royalty interest, reversing the trial court’s decision.

Current Status

            On March 24, 2021, a motion for extension of time to file motion for rehearing was granted.

Download Hoffman v. Thomson

 

Anna Boyer

Thompson & Knight, LLP

 

[1] No. 04-19-00771-CV, 2021 WL 881286 (Tex. App.—San Antonio Mar. 10, 2021, no pet. h.). 

[2] 483 S.W.3d 1 (Tex. 2016).

[3] Id. at 2.

[4] 551 S.W.3d 148 (Tex. 2018).

[5] Id. at 150.

[6] 973 F.3d 367 (5th Cir. 2020).

[7] No. 11-18-00050-CV, 2020 WL 7863330 (Tex. App.—Eastland Dec. 31, 2020, no pet. h.).  On March 12, 2021 a Second Motion for Extension of Time to File Petition for Review was granted.

[8] Id. at *1.

[9] Id. at *3 (citing Hysaw, 483 S.W.3d at 9).

[10] Id. at *4.

[11] Id. at *6.

[12] Id.

Determining When A Well Is “Complete”

Although operationally it may be clear when the a drilled well is completed. From a legal perspective, the “completion” concept is more nuanced. The date of completion can have continuous development and retained acreage consequences, so accurately defining and determining completion in the lease is important. Texas courts have analyzed the following events as potential completion dates:

• Production- Limited authority treats this as completion. Generally, completion has a broader meaning referring to finishing the required work on the well, regardless of whether it actually produces.
• Preparation for Production- The Texas Supreme Court has held that completion occurs when a hole is “bored in the ground, and if oil or gas in paying quantities is encountered, the casing must be perforated or otherwise prepared for production.” Preparation likely includes acidizing, perfing, fracking, or similar procedures.
• Reaching Total Depth on a Dry Hole- If no hydrocarbons are found, some Texas cases state that reaching total depth may be all that is required for the well to be completed. Texas case law is not clear if the well is a dry hole if it is actually capable of producing, just not economically.
• Abandoning a Dry Hole- Several appeals courts have held that abandonment of a dry hole constitutes completion. Whether plugging, desertion, or desertion with intent to desert a dry hole is the operative event for abandonment is still an open question under Texas case law.

Operators and others attempting to determine when the well is completed may refer to the following decision tree to aid their analysis.

Conrad Hester

Thompson & Knight LLP

Property Subject to an Oil and Gas Mechanics and Materialmen's Lien

    The last blog post discussed the initial considerations in determining whether an oil and gas service or material provider is entitled to a Texas statutory lien (an “M&M Lien”) to secure amounts owed to the provider. The key is whether the provider performed labor or provided materials in a mineral activity either directly or indirectly to a mineral property owner.

    If the initial hurdles are satisfied, then the question is what property will be subject to the lien. Not surprisingly, the M&M Lien attaches to all materials, machinery and supplies that a provider furnished or handled. The M&M Lien also attaches to each of the following for which the lien claimant provided services or materials:

• land;
• leasehold;
• oil or gas well or water well;
• oil or gas pipeline and its right-of-way.

    An M&M Lien that attaches to a leasehold estate covers not only the well on which the claimant provided services or materials but also all other wells located on the leasehold in which the mineral property owner owns an interest. For example, if there are six producing wells on a lease, the mineral property owner drills a seventh well on the lease and fails to pay the drilling contractor, all seven wells will be subject to the contractor’s M&M Lien.

    An M&M Lien does not attach to property for which a service provider did not provide services or materials. As an example, Mr. Jones, who is a mineral property owner contracts with Mr. White, a drilling contractor, to drill three wells located on three separate tracts of land that are not operated as a unit. Mr. Jones pays Mr. White for services performed for two of the wells but not the third. Mr. White will be able to secure an M&M Lien only on the well for which he has not been paid and the tract of land on which such well is located. Even though Mr. White’s contract with Mr. Pink covered all three tracts of land, because they are separate tracts not operated as a unit, Mr. White cannot claim an M&M Lien on the two tracts for which he has received payment.

    An M&M Lien attaches only to the interests of mineral property owners who are parties to the contract. So, if Mr. Pink is an operator who holds only a one percent working interest in the well drilled by Mr. White, Mr. White can secure an M&M Lien only on Mr. Pink’s one percent interest.

    A service provider’s claim for payment for services or materials provided before a mineral property owner assigns all or a portion of its interests to a third party may burden the assignee’s interest. For example, assume that Mr. Pink owns 100% of a leasehold at the time Mr. Pink and Mr. White enter into a contract for drilling on the lease. After Mr. White performs the services, Mr. Pink assigns twenty-five percent of his interest in the lease to Mr. Green. Mr. White then files to secure an M&M Lien on the well and the lease. Mr. White would not be obligated to give notice of the lien to Mr. Green because he had contracted with Mr. Pink before the assignment, and Mr. Green’s interest would be subject to the lien.

    The Texas statutory lien does not attach to proceeds of oil and gas production. Courts have generally been unwilling to expand the coverage of the lien to property not listed or described in the statute. Nevertheless, in 1997, an appellate court upheld an appointment of a receiver to take possession of the proceeds from production prior to the foreclosure of the M&M Lien. The court held the action necessary to protect the lienholder because production was diminishing the lienholder’s collateral. The court did not address the previous line of cases holding that M&M lien claimants were not entitled to proceeds of production.

    To be able to take advantage of the protection afforded by the Texas statutory M&M Lien, a service provider must properly secure the lien. The next blog post will set forth the necessary steps.

Protecting Oil and Gas Service Providers

    Some legal topics are cyclical in nature.  The topics lay dormant until an economic change makes them relevant.  One of the most cyclical topics is the Texas statutory oil and gas lien available to service and material providers.  When oil prices hovered around $100 per barrel, providers to the energy industry were not overly concerned about protecting their rights to payment.  After the oil price collapse and continued doldrums, the topic of oil and gas mechanic's and materialmen's liens has once again become relevant. 

    Over the next few blog posts, we will discuss (i) who is entitled to a mechanic's and materialmen's lien ("M&M Liens"), (ii) what property may be subject to an M&M Lien, (iii) how an M&M lien is secured, and (iv) how a lienholder enforces an M&M Lien.  To understand M&M Liens, one must first understand who is entitled to utilize the statutory protection.

    Chapter 56 of the Texas Property Code provides statutory liens for persons who provide services or materials in the drilling, operation or maintenance of a well.  One of the key definitions is that of a "mineral property owner."  Section 56.001(3) of the Texas Property Code defines a "mineral property owner" as someone who is an owner of:

• land;
• oil, gas or other mineral leasehold;
• oil and gas pipeline; or
• oil or gas pipeline right of way.

Only persons who have provided services or materials, either directly or indirectly, to a mineral property owner can claim an M&M Lien.

    A provider who contracts directly with a mineral property owner for the provision of services or materials in mineral activities constitutes a "mineral contractor" under the M&M Lien statute.  A "mineral subcontractor," on the other hand, is anyone who:

• furnishes materials or performs labor used in mineral activities under a contract with a mineral contractor or another subcontractor, or
• performs labor in mineral activities as an artisan or day laborer employed by a subcontractor.

Whether a person is a contractor or subcontractor depends on the person's relationship with the mineral property owner at the time of contracting.  The classification of a provider as a contractor or subcontractor is important because the necessary steps to secure an M&M Lien vary depending on the relationship between the provider and the mineral property owner.

    The services or materials provided to a mineral property owner must constitute "mineral activities"  Section 56.001(1) of the Texas Property Code defines "mineral activities" as:

• digging, drilling, torpedoing, operating, completing, maintaining or repairing
• an oil, gas or water well, an oil and gas pipeline or a mine or quarry. 

In general, any activity that helps facilitate the potential production of oil and gas will constitute a "mineral activity."

    Even though the definition is broad, courts have found that the following activities do not constitute mineral activities:

• dismantling and removing an underground pipeline;
• creation of business plans for a pipeline;
• preparation of gas contracts; and
• costs for repairs to rental equipment, unless the mineral owner caused the damage.

It is not a requirement that the services provided include physical labor on the mineral property.  Courts have found a range of services to be essential to the production of oil and gas and, therefore, entitled to an M&M Lien.  Examples of such services are:

• catering services to an offshore rig;
• plumbing work incorporated into the living quarters of an offshore platform; and
• rentals of equipment or casing.

    To recap, the initial step in analyzing whether or not an M&M Lien can be secured is to determine whether the services or materials were provided to a mineral property owner in a mineral activity.  The next blog post will discuss what property may be subject to an M&M Lien.

 

Debra J. Villarreal

Thompson & Knight LLP

 

 

 

Forced Pooling in Pennsylvania

Pennsylvania’s Act 66 of 2013

During its 2013 Session, the Pennsylvania legislature passed and Governor Tom Corbett signed into law Senate Bill 259, which has since become known as Act 66. Much of Act 66 deals with disclosure of deductions and other payment information to Pennsylvania royalty owners. However, Section 2.1, below, stands apart from the other provisions:

“Where an operator has the right to develop multiple contiguous leases separately, the operator may develop those leases jointly by horizontal drilling unless expressly prohibited by a lease.  In determining the royalty where multiple contiguous leases are developed, in the absence of an agreement by all affected royalty owners, the production shall be allocated to each lease in such proportion as the operator reasonably determines to be attributable to each lease.”

 Oil and Gas Lease Act, 58 Pa. Pub. Stat. § 34.1 (2013)

In plain language, Act 66 is a forced unitization statute. The purposes of forced unitization statutes are to increase production efficiency, protect against waste, and prevent landowners from  strategically withholding consent to pool in order to negotiate the highest possible bonus.

Forced Unitization in Pennsylvania

The Act is not the first of its kind in Pennsylvania; the Pennsylvania Oil and Gas Conservation Law of 1961 also allowed lessees to unitize without a lessor’s consent. However, that law applied only to wells that penetrate the Onondaga formation, not to wells in the shallower Utica and Marcellus
Shales.

Due to this limited application, forced unitization in Pennsylvania has historically been rare, and thus there are many existing leases that do not expressly forbid pooling. Under the old law, lessees wishing to unitize had to return to the lessor and renegotiate the terms of the original lease before
commencing horizontal drilling operations across multiple leaseholds. This process often resulted in an additional and often significant by-the-acre bonus payment for the lessor.

 The Effect of the Act

The enactment of Act 66 has rendered renewed negotiations unnecessary. The Pennsylvania Chapter of the  National Association of Royalty Owners has voiced a concern that lessors will suffer financial loss and  has additionally argued that the forced unitization provision of Act 66 should have been drafted and promoted separately from the rest of the Act. Nevertheless, Act 66 is currently binding law, and parties to existing leases in Pennsylvania would do well to understand its effects.

 Application of Act 66

Act 66 only applies to leased tracts, so it does not allow forced pooling on tracts where no lease has been signed. The Act also does not appear to authorize forced unitization where an existing lease has a specified maximum unit size, or where its pooling clause has been properly crossed out. As such, parties to an existing Pennsylvania lease should review its terms for these provisions prior to acting in reliance on Act 66.

Kelli Sims – Thompson & Knight LLP

A Global View of Upstream Law

Andy Derman and I recently co-authored a chapter for Upstream Law and Regulation:  A Global Guide.  Our chapter addresses regulatory frameworks in the states of Louisiana, North Dakota, Oklahoma, Pennsylvania and Texas.  The other chapters in the book summarize oil and gas regulations in thirty-two countries in Africa, Latin America, Europe, the Middle East, Asia and the Pacific. The book highlights how relatively new types of resources – unconventional oil and gas – have led to new regulatory frameworks being adopted in countries not traditionally known as petroleum producing countries, such as Poland. 

It is evident that shale gas has triggered dramatic changes in the industry worldwide.  Not only are industry standard documents, such as joint operating agreements, being modified to address unconventional plays but national laws around the world are also being revised or enacted to deal with the new production. 

When we look internationally, we see how the range of responsibilities and roles of national oil companies are also evolving.  Some national companies are active in international markets and act
either as an arm of the country or as an international company in the industry.   The Chinese national companies seem particularly active. 

 As the editors of Upstream Law and Regulation, Eduardo G. Periera and Kim Talus, point out, China is an interesting example because it has several national companies that have differing roles in the industry.  China National Petroleum Corporation (CNPC) is China’s largest oil and gas producer and is also a major oilfield and engineering services provider.  Sinopec is the largest integrated petroleum and petrochemical company and is the largest refined oil producer in China.  CNOOC Limited is an upstream company and is the dominant oil and natural gas producer in offshore China.  Under Chinese laws, CNOOC is responsible for negotiating with foreign partners in offshore upstream activities.  CNPC and Sinopec both have the right to negotiate contracts with foreign partners in onshore upstream endeavors.  Of course, all three of the Chinese national oil companies have acquired reserves in North America in recent years. 

The book reflects how the ownership of oil and gas in the United States remains very different from ownership in the rest of the world.  Only the United States and certain parts of Canada allow for individual ownership of minerals.  Elsewhere, the ownership of petroleum reserves is either shared among the people of a country or rests with the state, with the resources then being managed by the state or a national oil company on behalf of the state.    

You can view the book's index at  http://www.globelawandbusiness.com/ULR/ to see the emerging oil and gas jurisdictions covered by the book.

Debra Villarreal, Thompson & Knight LLP

 

Pooling and Communitization Topics

Part 2 – Current Allocation Well Issues

It is well settled that an oil and gas lessee’s authority to pool several leases together is derived solely from the terms of the leases, or from a separate pooling agreement.[1] The absence of appropriate pooling authority in a lease can lead to numerous problems, if not outright confrontations, between lessee and landowner.

A striking example of this is currently playing out at the Texas Railroad Commission, revolving around the concept of “allocation well” permits. Generally speaking, the term “allocation well” permit refers to a horizontal well that runs beneath two or more un-pooled tracts,[2] where no production sharing agreement is in place to govern the participation of each tract in the well’s production (or there is a production sharing agreement, but the operator has not successfully signed up 65% of the royalty interest). The Commission has, on a number of occasions, issued drilling permits for such wells, under the reasoning that the Commission was without jurisdiction to determine whether or not the leases permitted the operator to drill without pooling. Such matters have historically been resolved by the courts, and therefore the Commission had for some time decided not to second-guess an operator’s assertion that it had the good faith claim to drill the well (failure to pool notwithstanding). No rule or regulation was ever issued to formalize this practice.

The allocation well issue has clearly been headed for a confrontation, which arrived when EOG
Resources Inc.[3] filed an application to drill the Klotzman (Allocation) #1H well in DeWitt county, Texas. The oil well would have crossed the boundary of two separate tracts, both of which were 100% leased to EOG, and the applicable field rules required at least 80 acres to form a drilling unit for the well. EOG intended to form an 80 acre pooled unit for the well, containing 40 acres out of each tract. The leases, however, did not permit EOG to pool for oil at all. Talks to create appropriate pooling authority failed. Therefore, EOG applied to permit the well as an allocation well. Not only the affected landowners, but the Texas General Land Office and numerous observing mineral owners protested the application.

The parties raised a multitude of arguments, the most important of which is this: Klotzman (the mineral owners) and their aligned parties believe that, regardless of whether the well is called a unit well, allocation well, or anything else, the act of drilling a horizontal well across the boundary to two tracts, or the permitting of such a well (or both), is per se a pooling of these tracts. Therefore, if the leases do not permit the tracts to be pooled, then by definition the leases forbid the operator from drilling the well. If the leases prohibit the well, the Commission must deny the permit because the operator necessarily cannot in good faith claim the authority to drill the well.

EOG and its aligned parties vehemently protested that assertion. EOG cited a litany of prior commission practices, industry expectations, and avoidance of waste, and even invoked the opinion of Professor Ernie Smith. But at the end of the day, the counterargument is (i) running a lateral across two tracts does not per se pool them, and (ii) even if it does, the Railroad Commission has no authority to make that call.

The examiners sided rather dramatically with the mineral owners, stating that “[EOG’s] actions are the definition of pooling,” and further found:

Regardless of how it is denominated, combining a 40-acre tract from the Georgia Dubose-Glassell 516.569-acre lease with a 40-acre tract from the Georgia Dubose-Pierce 304.97-acre lease to form an 80-acre drilling unit for the purpose of drilling a well would be pooling the tracts.”

The examiners further characterized the authority to pool as “a property right retained by [the Klotzmans].” Because the Commission regulations may not cause the transfer of any property rights, the Commission could not grant the permit for the well because it would “strip the Klotzman’s of a property right they still own (pooling authority for oil) and transfer it to EOG.”

The Commissioners have not yet ruled on the examiners’ recommendation, but both operators and mineral owners are focused on this issue. A decision on the jurisdictional grounds rather than the underlying issue is a real possibility. But whatever the outcome at the Commission, further appeals are likely. That being said, the examiners’ recommendation raises a number of interesting issues:

• If the combination of several tracts into a drilling unit is a “pooling” of those tracts, is it pooling for all purposes, or only the limited purpose of permitting the well? The ordinary understanding of “pooling”, for purposes of an oil and gas lease, implies that royalties are shared on (usually) an acreage basis among the several tracts, and operations on one unit tract will hold the other leases in effect.[4] The examiners probably did not mean to say that operations in a drilling unit alone will now maintain a lease as to all tracts in the drilling unit, or the issuance of a drilling permit will now  require sharing of royalties within the drilling unit, but these concepts are not clearly distinguished in the proposal for decision. It is unclear what the purpose of “pooling” would be from the lessee’s perspective, absent these items.  
• The examiners’ proposal for decision appears to state that a drilling unit is invalid if it assigns acreage, for spacing and/or density purposes, in excess of the pooling authority of the lease. There may be a number of cases where even vertical wells have  drilling units that do not correspond exactly with the pooled unit designations filed in county courthouses. The effect of this decision on those cases is also not clear.
• The proposal for decision states that the authority to pool a lease is itself a property interest, rather than contractual right. Texas has long accepted the theory that pooling (in the “courthouse unit” sense) results in a cross-conveyance of interests among the owners of the several unit tracts, but the authority to pool a lease has not previously been described as a separate property interest. The distinction could be important in, for example, the rejection of contracts by bankruptcy trustee, who may have the power to avoid some contract obligations, but generally will not alter pre-petition property rights).
• Consider Browning v. Luecke,[5] which is a well known case dealing with a failed unit for a horizontal well. The Browning court correctly pointed out that a lease is not pooled if the lessee attempts to form a unit but does not comply with the pooling provisions. However, the proposal for decision indicates that such lease would be  pooled because it was included in the drilling unit for the horizontal well, making the result for the operator utterly confusing. To paraphrase Schrödinger, the lease would be both pooled and not pooled at the same time. What effect, if any, does this have on the operator’s continued authority to produce the well as far as the Commission is concerned?

 

Gaye White and Lucas LaVoy, Thompson & Knight LLP

 

---

[1]
With very limited exceptions under the Mineral Interest Pooling Act.

[2]
This could also be a well running between two separate pooled units, or certain other combinations of tracts, but for purposes of this discussion un-pooled tracts are the most relevant.

[3]
The facts of this case are recited in the Proposal for Decision issued June 25, 2013 in Oil & Gas Docket No. 02-0278952, Hearings Division, Railroad Commission of Texas.

[4]
See Southeastern Pipe Line Co. v. Tichacek, 997, S.W.2d 166, 170 (Tex. 1999) ([t]he primary legal consequence of pooling is that production and operations anywhere on the pooled unit are treated as if they have taken place on each tract within the unit”).

[5]
38 S.W.3d 625 (Tex. App.— Austin 2000, pet. denied).

Pooling and Communitization Topics

Part 1 – Pooling Introduction and Types of Units

Over the past six to twelve months, I have seen a marked increase in the number (and complexity) of pooling, communitization, and unitization problems encountered by our clients.

Horizontal development is now ubiquitous, and the resource plays have become mature, which is pulling the rug back from some long-dormant legal issues.

This is the first of a multi-part series examining these issues and current developments. Operators, their counsel, and the courts are going to need to achieve some combination of consensus and case law. Navigating this new landscape will require an understanding of the foundations of pooling, communitization, and units for the development of oil and gas. We examine these issues mostly through the lens of Texas law due to its influence on the law of other jurisdictions and its relevance for much current resource development.

There are numerous types of units one may encounter. Each type is a different reflection of the basic problem:  the English law of property evolved in a time when oil and gas had no value and land could be divided by boundary lines on the ground rather than by subsurface formation or reservoir. These types of units can be divided into two broad groups. First, those created by statute or regulation and, second, those created by contract. Confusion between the various types can lead to serious problems in contract drafting, in extreme cases causing failure of legal descriptions and contract unenforceability.

The industry sometimes broadly refers to all regulatory units as “proration units”, but this not technically accurate.  The Texas Railroad Commission (“RRC”) uses both drilling/spacing units and proration units. Drilling or spacing units are (intended to be) the area of land around a well that can be drained by that well. They exist because Statewide Rules 37 and 38, and their counterparts in the Field Rules, require minimum distances between wells and from wells (or take points) to lease lines.[1]  These rules, in turn, exist because of the drilling excesses and waste that occurred during the oil boom in the early 20^th century.[2] Proration units (a separate concept) are based on the RRC’s determination of how much oil an entire field can efficiently produce, taking into account the volume of production that the market will bear. This amount is then distributed to individual wells – the well’s allowables – within the field based on various formulae. Some, but not all, of these formulae use acreage to allocate field production. Note that virtually all gas allowables are suspended, so likely “proration units” will not exist for gas. Statewide rules do not allocate acreage to oil wells based on acreage, only certain field rules do so. The only time a “proration unit”, as acreage on the ground, is likely to exist is when (i) the well is an oil well, (ii) field rules are in place, (iii) those rules use acreage to allocate allowable production, and (iv) the operator files a plat of the allocated acreage to define the allowable.[3]

If an operator’s lease is too small to support either the drilling unit or the desired proration unit, the RRC allows it to form a pooled unit. An operator must certify its right to pool the tracts on Form P-12, but beyond that initial showing and once the permit is granted, the RRC does not have jurisdiction over lease maintenance, royalty payment, pooled units, or any other private property ownership matter. A pooled unit at the RRC is not a pooled unit under any lease (unless the lease says it is).

Pooling and the formation of units under oil and gas leases is contractual, not regulatory, even though it attacks the same problem of exploring for and developing fugacious minerals across fixed property boundaries. The vast majority of oil and gas leases permit the lessee to combine the leased premises with other leases and/or lands and develop them in concert, and will contain an express agreement of the parties as to how production royalties are shared, and the leases are maintained, by these operations. Being creatures of contract, these units can only be formed in strict compliance with the lease, which usually requires filing declarations in the county courthouse.[4] Sometimes where a lease has insufficient pooling authorization, pooled units can be formed by a separate contract, but the result will be much the same.

“Production units” are another type of contractual unit that are created under the terms of the oil and gas lease. Many larger leases expire as to undeveloped acreage after the expiration of the primary term when the operator stops drilling.[5] Each well will hold a designated sub-tract of land out of the leased premises around that well, usually called the production unit.  These production units are also usually formed by filing a legally sufficient description in the public records, and the permissible size of the retained production units is usually a major deal point in lease negotiation.

Still yet, there are secondary recovery units, which are similar to pooled units, but are larger, more complex, and usually created in order to carry out a water flood, gas or air injection, or other large-scale project over a wide area. These are formed under authority granted by certain leases, agreements and ratifications by the lessors of other leases or mineral owners, agreement by the affected working interest owners, and approval by the RRC. They share characteristics of pooled
units and of joint operating agreement contract areas.

Finally, there are force-pooled units, which are common in Oklahoma, North Dakota, and other producing states, and are capable of collapsing many or all of the thorny legal issues arising out of lease pooling into a single regulatory order. However, this tactic is unavailable to Texas operators in any practical way.[6] Operators need to take care to clearly describe which type of unit they are referring to in their agreements and leases, or ambiguity and confusion can result.

 

Lucas LaVoy -- Thompson & Knight LLP

 

 

 

 

 

 

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[1]
These are, for example, the unit plats attached to W-1 application to obtain a permit to drill a well.

[2]
http://www.tshaonline.org/handbook/online/articles/doe01

[3]
Using the form P-15.

[4]
See Southeastern Pipeline Company, Inc. v. Tichacek, 997 S.W.2d 166, 394 (Tex. 1999).

[5]
Or falls behind a pre-determined schedule.

[6]
The Texas Mineral Interest Pooling Act, Tex.Rev.Civ.Stat. art. 6008c, is primarily useful for royalty and other small interest owners seeking access to adjacent unit production; although operators have met with limited success in using it to create units in the Barnett Shale, where urban drilling presents unique land issues.

Beware of Improper Property Descriptions

Parties to all types of contracts must remain wary of the statute of frauds when drafting, as agreements may be held unenforceable due to inadequate descriptions of property. In 2012, both the Fifth Circuit and the Dallas Court of Appeals heard cases involving this issue.

An instrument that conveys an interest in real property in Texas is subject to the Statute of Frauds.  To satisfy the Statute of Frauds, the instrument must, among other things, identify the property to be conveyed with reasonable certainty. In a 1972 case, Morrow v. Shotwell, the Texas Supreme Court said it this way:

The rule by which to test the sufficiency of the description is so well settled at this point in our judicial history, and by such a long series of decisions by this court, as almost to compel repetition by rote: To be sufficient, the writing must furnish…the means or data by which the land to be conveyed may be identified with reasonable certainty.   

However, “reasonable certainty” is not a bright-line standard.

In May v. Buck,  a letter agreement identified property to be conveyed as a “100 acre spacing centered around the David Morris Gas Unit #1.” The court reasoned that the description gave rise to “several possible configurations of tracts.” With no information regarding shape or boundaries, the Appellants contention that the description was for a rectangle surrounding the well was struck down when the Appellant admitted that either a square or a halo would also be properly “centered”. The Court of Appeals of Texas, Dallas, found the description failed to satisfy the Statute of Frauds.

In Coe v. Chesapeake Exploration, the conveyance at issue was for “certain oil and gas leases located in Harrison County, Texas…such leases being shown in the map attached hereto as Exhibit “A””. While other Texas courts had found similar descriptions in separate cases to be inadequate, and Chesapeake relied on these rulings in their appeal, the Coe court informed Chesapeake that Texas courts had not yet established whether this exact language satisfied the statute of frauds.  The court then identified a central motivation for the “reasonable certainty” requirement was to “avoid instances in which a court enforces the sale of property that the seller did not intend to convey or the buyer did not intend to purchase.” After stating that metes and bounds descriptions are not the only proper way to identify property, the court relied on a “recital of ownership” standard, which is a means of identifying the property to be conveyed by identifying the person who owns the property. Under this theory, if it can be proven that a grantor owns only a single tract of property which matches the description of that to be conveyed OR the grantor is conveying all of his property in a specific area described, the risk of improper identification is eliminated and the statute of frauds is satisfied. In Coe, since in the conveyance in question the grantor transferred all of his rights, title and interests in the areas described on Exhibit “A”, the Fifth Circuit found the description adequate.

Although Texas courts have shown the willingness to void conveyances based on land description discrepancies, they have also admitted “reasonable certainty” may be achieved through different means of identification. A drafter must take care so as to ensure the description maximizes clarity, accuracy, and precision so the only property able to match the description is the one to be conveyed.

- Casey Ragan, Thompson & Knight LLP

 

Area of Mutual Interest Agreements: Avoiding Property Description Pitfalls

In the push to develop prospects in U.S. shale boom areas, several oil and gas companies may own interests in the same geographic area. An area of mutual interest agreement or AMI can allow two or more companies to efficiently develop an interest while legally protecting all players’ interests.

Generally speaking, an AMI is a contract between two companies who want to maintain a specified
allocation of ownership interests within a prospect area (e.g., Company A will own 25% and Company B will own 75%).  AMIs are frequently incorporated in purchases and sales of fractional leasehold interests and farmout agreements,where a third party undertakes drilling obligations for a company wanting to maintain its leasehold interest.

The basics for a well-drafted AMI include:

• How the interests and acquisition costs will be split

• The process for distributing the acquired interest to the other company

• The length of time the AMI contract will be in effect

And most importantly…

• The geographic location and description of the prospect area

Few oil and gas investors would purchase or sell property without sufficient legal  property descriptions such as oil and gas lease recording information, names of lessors and lessees and lease dates. Yet some AMI agreements overlook these important details, leaving the parties at risk for enforceability issues down the road.

Insufficient property descriptions are some of the most common errors made in drafting AMIs.  In Texas, all real property contracts must include a signed writing or memorandum containing an adequate description of the property.[1]  Because AMIs are agreements to assign an interest in oil and gas leases, they are subject to these same requirements.[2]

What constitutes a legally sufficient property description?

Texas courts have held that a property description “must furnish within itself, or by reference to some other existing writing, the means or data by which the [property] to be conveyed may be identified with reasonable certainty.”[3]  In other words, property descriptions should be clear, specific and verifiable.

Here are some tips for writing a property description that will be enforceable:

DO…

a)    Include metes and bounds descriptions.  While it’s not always practical to have a prospect area described by metes and bounds, it is one of the best ways to ensure your AMI is legally enforceable.

b)    Reference surveys and abstracts.  Consider referencing the General Land Office survey names and abstract numbers included in the prospect area. Abstract and survey boundaries may not exactly overlap the desired prospect area. Still, it may be worthwhile to slightly modify the
location of the prospect area if a metes and bounds description is not available.

DO NOT…

a)     Use maps as the only point of description.  Maps are used to help E&P companies get a general idea on the size and location of a prospect area. However, they often lack sufficient information to make an AMI enforceable. This is especially true where the boundaries of the prospect area don’t overlap survey or abstract lines.

b)    Describe acreage as being “centered” on a fixed point.  AMI agreements are unenforceable if the property description is subject to multiple interpretations.  For example, a prospect area described as “1,000 acres centered around the XYZ No. 1 wellbore” is probably not enforceable because it’s unclear if the 1,000 acres should be configured as a square, a circle or some other shape centered on the wellbore. 

One final note, if you’re concerned your prospect area description may be lacking, consider adding a statute of frauds savings clause in your agreement. These clauses generally provide that if there is any doubt as to the exact location of the AMI boundaries, the boundaries will be deemed to follow the lines of the General Land Office abstracts or surveys most nearly aligned to such boundaries as depicted on an exhibit.

 

Cole Bredthauer

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[1] Tex. Bus. & Com. Code §26.01 (West 2012); Pick v. Bartel, 659 S.W.2d 636 (Tex. 1983).

[2] Westland Oil Dev. Corp. v. Gulf Oil Corp., 637 S.W.2d 903, 908 (Tex. 1982).

[3] Long Trusts v. Griffin, 222 S.W.3d 412, 416 (Tex. 2006) (per curiam) (quoting Morrow v. Shotwell, 477 S.W.2d 538, 539 (Tex. 1972)).