operators

What Are the Types of Interests in Federal Oil and Gas Leases and How Are They Assigned?

Federal oil and gas leases are administered by the Bureau of Land Management (“BLM”) pursuant to the Mineral Leasing Act of 1920, as amended (“MLA”), and the implementing federal regulations. Federal leases have a slightly different ownership scheme than fee oil and gas leases. As to fee leases, the lessee owns a leasehold interest that includes the right to drill for and produce the leased substances, subject to royalty payments to the lessor. The term “working interest” is commonly used and is generally considered synonymous with the lessee’s interest and the term “leasehold interest.” As to federal leases, the lessee’s leasehold interest includes both record title and operating rights. Initially, these two types of interests are merged together as  the record title interest, but the operating rights interest can be severed from the record title interest by assignment.  The record title interest includes the obligation to pay rent and the rights to assign and relinquish the lease.[1] The operating rights interest authorizes the holder to drill for and conduct operations and produce the leased substances.[2] When all or a portion of the operating rights have been severed from the record title, the operating rights interest owner is primarily liable for its pro rata share of payment obligations under the lease while the record title interest owner is secondarily liable.[3] At the extreme, if all of the operating rights as to all depths are severed by assignment from the record title interest, the lessee owns “bare” record title interest and has no rights to drill for and produce the leased substances. The term “working interest” is generically associated with the operating rights interest unless said operating rights interest has not been severed from the record title interest, then it is associated with the record title interest. Otherwise, the range of interests that may be created out of federal leases is nearly the same as fee leases.

The interests in federal leases are generally conveyed by a “transfer,” being defined in the federal regulations as “any conveyance of an interest in a lease by assignment, sublease or otherwise.”[4] Set forth below is a discussion of the different types of interests that may be transferred in federal leases and whether the instrument transferring the interest must be filed with and approved by the BLM.[5]

Record Title Interests

The MLA and federal regulations use the term “assignment” for a transfer of all or a portion of the lessee’s record title interest in a lease.[6] All assignments of record title interests must be on the currently approved BLM form Assignment of Record Title Interest in a Lease for Oil and Gas or Geothermal Resources, Form 3000-003.[7] Record title interests may be transferred as to all or part of the acreage in the lease or as to either a divided or undivided interest therein.[8] Record title interests may not be transferred as to limited depths or horizons, separately as to either oil or gas, less than part of a legal subdivision,[9] or less than 640 acres (outside of Alaska).[10]

Upon receipt of the assignment, the BLM will engage in an “adjudication” process whereby the BLM will determine and identify the owners of interests and their percentage interest in the lease as a consequence of the assignment and approve the assignment if it meets all statutory and regulatory requirements. The rights of the assignee will not be recognized by the BLM until the assignment has been approved.[11]

Operating Rights Interests

The MLA and federal regulations use the term “sublease” for a transfer of a non-record title interest in a lease, including a transfer of operating rights. All transfers of operating rights interests must be on the currently approved BLM form Transfer of Operating Rights (Sublease) in a Lease for Oil and Gas or Geothermal Resources, Form 3000-3a.[12] For transfers of operating rights interests, the MLA and federal regulations do not contain any limitations on such transfers other than it must be as to “all or part of the acreage in the lease.”[13]

Upon receipt of the transfer, the BLM will engage in the adjudication process to determine and identify the owners of interests and their percentage interest in the lease as a consequence of the transfer and approve the assignment if it meets all statutory and regulatory requirements. The rights of the transferee will not be recognized by the BLM until the transfer has been approved.[14]  However there was a period of time where most state offices of the BLM did not adjudicate transfers of operating rights.

Beginning in 1985, the BLM issued internal guidance, Washington Office Instruction Memorandum No. 1986-175 (Dec. 30, 1985) (“IM 1986-175”), stating that it was not necessary for the BLM to “adjudicate” operating rights assignments[15] on the grounds that they are third-party contracts. The BLM adjudicators were instructed to stop adjudicating operating rights transfers, and to instead “rubber stamp” them within 30 days of their submission when there was no “evidence to the contrary regarding qualifications and proper bonding.”[16] Accordingly, most BLM offices began accepting transfers of operating rights and “approved” the transfers without confirming and determining the ownership of the operating rights interests. In 2013, the BLM issued Instruction Memorandum No. 2013-105 (April 4, 2013) (“IM 2013-105”), directing all BLM offices to immediately begin again adjudicate transfers of operating rights interests.[17]  Understanding that there would be a backlog to carry this out this directive, IM 2013-105 provides a priority schedule for adjudicating existing and future transfers of operating rights as follows: if first production occurs on or after October 1, 2012, adjudicate all transfers of operating rights immediately; if first production occurred prior to October 1, 2012, adjudicate as necessary to enable the Office of Natural Resources Revenue (“ONRR”) to issue appropriate orders to the owners; and adjudicate all remaining unadjudicated operating rights transfers when time and staffing allows.

Obviously, the BLM offices are faced with trying to adjudicate and determine the current operating rights interest owners based on over thirty years of potentially incomplete and possibly erroneous transfers contained in the BLM lease files. A survey was conducted in 2017 of the following BLM State Offices to determine how they were implementing IM 2013-105 and adjudicating transfers of operating rights.[18]

Colorado

For leases occurring prior to 2012, the Colorado State Office is only conducting reviews for leases with production at the request of ONRR. When it discovers discrepancies, it considers those transfers null and void from their inception and does not provide or send out unapproved operating rights decision letters because the transfers were never adjudicated. Colorado is not willing to accept county records or other outside sources to assist in curing title deficiencies. For leases occurring after October 1, 2012, the Colorado Office will adjudicate all transfers accordingly.

Montana, North Dakota, South Dakota, and Utah[19]

The Montana and Utah State Office never stopped adjudicating transfers of operating rights; accordingly, IM 2013-105 did not change how they are adjudicating such transfers.

New Mexico, Kansas, Oklahoma, and Texas[20]

The New Mexico State Office is conducting a piecemeal review of its lease files. Initially, when the New Mexico State Office received a new assignment and could not account for the purported interest to be assigned, they retroactively denied previously approved transfers either (a) all the way back until the title examiner could account for the purported interest; or (b) through 1991. It appears that recently, the New Mexico State Office has become willing to consider outside records in examining title to fill in gaps in currently filed assignments, such as recorded assignments, evidence of corporate successions, etc.

Wyoming

The Wyoming State Office adjudicates operating rights for all new leases, as well as any adjudications requested by ONRR. It also has plans to adjudicate operating rights for all producing leases according to staff availability. The Wyoming State Office is currently using the Lease Interest Worksheet to chain title retroactively and adjudicate operating rights at the request of the ONRR. During this review, and when any new transfer is filed, if the State Office examiner cannot account for the purported interest to be assigned, they stamp the Lease Interest Worksheet “discrepancy.” Thereafter, the Wyoming State Office will not approve any subsequent transfer until the problem in the chain of title is resolved. No notice of the discrepancy is provided to the parties who received interests through transfers now marked with a discrepancy, so without review of the current BLM case file for each lease or subsequently denied transfer, parties who believed they previously owned operating rights are not aware their rights have been called into question. This requires the Wyoming State Office to deny any subsequent transfers for leases containing a discrepancy, and to disregard any assignments occurring before the discrepancy that were previously approved.

In an attempt to complete a chain of title, bring current its files, and resolve any discrepancies, the Wyoming State Office is accepting a certified copy of an assignment recorded in the county records and attached to a BLM form Transfer of Operating Rights that is completed by general references to the attached county assignment. The Wyoming State Office will issue a decision stating that its records are incomplete and in order to complete its records, it is accepting and approving the assignment.

Overriding Royalty Interests, Production Payments, and Other Interests

The federal regulations make specific reference to only two other types of interests, overriding royalty interests and production payments.[21] Transfers of these interests must be filed with the BLM and will be included in the lease file, but are not subject to BLM approval.[22] While they can be filed on either a BLM form assignment,[23] any form of assignment may be used.

While net profits interests and carried interests are not expressly mentioned in the regulations governing assignments of interests, such interests are included in the definition of “interest.”[24] The usual practice is to follow the same filing procedures prescribed from assignments of overriding royalty interests and production payments above.

Liens and Security Interests under Mortgages and Other Financing Instruments

Liens and security interests in federal leases created under mortgages and other financing instruments do not fall within the definition of “interests” under the regulations and are not required to be accepted for filing under the regulations. Most BLM offices will discourage or even reject the filing of mortgages and other financing instruments. As a result, mortgages and other financing instruments are typically only filed in the county records.

Transfers by Operation of Law

The regulations identify two types of transfers by operation of law: death and corporate reorganization. When an owner dies, his or her rights will be recognized as having been transferred to the heirs, devisees, executor, or administrator of the estate, upon the filing of a statement that all parties are qualified to hold an interest in a federal lease.[25] The BLM office will typically also require, along with the statement, supporting information concerning the demise of the owner.

In the case of corporate name change, merger, or conversion, no assignment is required unless otherwise required by state law. The regulations require that notification of the name change, merger, or conversion be furnished in the proper BLM office.[26]

_____________________

Prior to filing any transfer with the BLM, it is always to the advantage of the parties to the transfer to make inquiry of the oil and gas adjudication personnel at the applicable BLM office to confirm that the parties have prepared the transfer in compliance with the office’s policies and procedures.


[1] 43 CFR § 3100.0-5(c). Record title is the ownership in a federal lease as recognized by the BLM.  Therefore, it has no connection to the title or leasehold ownership reflected in the applicable county records.

[2] 43 CFR § 3100.0-5(d). The term “operating rights” should not be confused with the right to serve as operator on the ground. An operator is the person or entity that is responsible under the terms and conditions of the lease for operations being conducted on the leased lands; it can include, but is not limited to, the lessee record title interest owner or operating rights interest owner. See 43 CFR § 3160.0-5

[3] See 43 CFR §§ 3106.7-6(b), 3216.12.

[4] Id. § 3100.0-5(e).

[5] Not addressed herein are the qualifications to own an interest in a federal lease and the specific filing requirements.

[6] Id. § 3100.0-5(e).

[7] Most recent revision date is August 1, 2015.

[8] Id. § 3106.1(a). Note, the assignment of the entire interest in a portion of the leasehold will result in a segregation of the lease.

[9] Generally, requiring all of a governmental lot or quarter-quarter section under the Public Land Survey System.

[10] 30 USC § 1987a; 43 CFR § 3106.1. The 640 acre limitation was added to Section 30A of the MLA in 1987 pursuant to the Federal Oil and Gas Onshore Leasing Reform Act. Assignments of record title of less than 640 acres will be approved if the assignment constitutes the entire lease or is demonstrated to further the development of oil and gas.

[11] 43 CFR § 3106.1(b).

[12] Most recent revision date is August 1, 2015.

[13] 43 CFR § 3106.1. There is no written guidance defining “part of the acreage” or addressing this apparent acreage requirement. It appears that at least some minimal amount of acreage must be transferred to comply. Accordingly, although some BLM State offices will accept transfers of operating rights for less than 40 acres, they will not accept for approval, or even for filing purposes only, transfers of operating rights in a wellbore only.

[14] Id. § 3106.1(b).

[15] The term “assignment” is used generically in the IM applying to an assignment of either a record title interest or an operating rights interest.

[16] IM 1986-175.

[17] IM 2013-105 was issued in direct response to the 1996 amendment to Section 102(a) of the Federal Oil and Gas Royalty Management Act, 30 USC § 1712(a), providing that the owner of the operating rights shall be primarily liable for its pro rata share of payment obligations under the lease and the owner of the record title interest (if different from the owner of the operating rights interest) became secondarily liable. The federal regulations at 43 CFR Section 3016.7-6 and 3216.12, reflect these same principals. Furthermore, the BLM form Transfer of Operating Rights (Sublease) in a Lease for Oil and Gas or Geothermal Resources specifically provides that the transferee’s signature “constitutes acceptance of all applicable terms, conditions, stipulations, and restrictions pertaining to the lease… (Part B, paragraph 3) and “upon approval of a transfer of operating rights (sublease), the sublessee is responsible for all lease obligations under the lease rights transferred to the sublessee” (Part C, paragraph 8).

[18] See Jared A. Hembree and Uriah J. Price, Holding a Wolf by the Ears – A Look into BLM’s Policy on the Retroactive Adjudication of Operating Rights, 63 Rocky Mt. Min. L. Inst., Paper 11 (2017) (not yet published).

[19] The Montana State Office administers federal lands in Montana, North Dakota, and South Dakota. The Utah State Office administers federal lands in Utah only.

[20] The New Mexico State Office administers federal lands in New Mexico, Kansas, Oklahoma, and Texas.

[21] 43 CFR § 3106.1.

[22] 43 CFR § 3106.1(b).

[23] Both of the current BLM forms include a box that can be checked to indicate that it is for an overriding royalty interest assignment.

[24] 43 CFR § 3000.0-5(1).

[25] Id. § 3106.8-1.

[26] Id. § 3106.8-3.

Unitizing the Lessor’s Interest: No, It’s Not the Same as Pooling

The terms “pooling” and “unitization” are often used interchangeably, but they have different meanings. Pooling is “the bringing together of small tracts sufficient for the granting of a well permit under applicable spacing rules,” while unitization is “the joint operation of all or some portion of a producing reservoir.”[1] While pooling and unitization are both used to prevent waste and protect correlative rights,[2] unitization works on a much larger scale, allowing an operator to maximize the amount of resources extracted from an entire field or reservoir, without regard to lease or property boundaries. Generally, the lessee of a fee (private) oil and gas lease is free to commit its working interest to the unit agreement, but the lessee can only commit the lessor’s interest through voluntary ratification, compulsory unitization, or a unitization clause. This article will focus specifically on the third option: the unitization clause in fee leases.

Unitization clauses (if included at all) generally follow two patterns. First, the unitization clause may be interwoven into the pooling clause. Second, the unitization clause may appear separately, often immediately following the pooling clause (we believe this to be the preferred method). There are typically four parts to a “standard” unitization clause.

Part One – When can the lessee unitize the lessor’s interest?

Example: Lessee shall have the right to unitize, pool, or combine all or any part of the leased premises with other lands in the same general area by entering into a cooperative or unit plan of development approved by any governmental authority.

The unitization clause should expressly grant to the lessee the authority to unitize the leased premises under a cooperative or unit plan of development. Depending on the type of unit being formed (for example, a federal exploratory unit or a state voluntary unit), the language should be broad enough to cover the proposed plan of development. Because the lessee may not know its future unitization plans at the time it negotiates a lease, the lessee should ensure that the unitization clause is broad enough to cover all forms of unitization.[3]

Even with a unitization clause, the lessee has an implied duty of good faith and fair dealing when pooling or unitizing a fee oil and gas lease.[4] This means that the lessee should be careful when attempting to commit a lease that is about to expire or includes non-productive lands, or when the lessee’s economic interests are not aligned with those of the lessor. However, if the unit plan of development is approved by a governmental entity (such as the BLM or the state conservation commission), courts will generally defer to the government’s approval in determining whether the lessee acted in good faith.[5]

Unfortunately, when describing how the leased premises can be unitized with other lands, it is not uncommon to find combined pooling/unitization clauses where the lessee mistakenly used pooling language (such as “into a drilling or spacing unit in conformance with a state drilling or spacing order”) instead of replacing it with unitization language (such as “to one or more unit plans or agreements for the cooperative development or operation of one or more oil and/or gas reservoirs or portions thereof”).

Properly drafted unitization clauses should cover the development of a field or reservoir as opposed to just those lands within a single drilling or spacing unit.

Part Two – How will the terms of the lease be affected?

Example: When such a commitment is made, this lease shall be subject to the terms and conditions of the unit plan or agreement and this lease shall not terminate or expire during the life of such plan or agreement.

To effectively extend the lease under the unit plan of development, the lease terms should be amended to conform to those of the unit agreement. This can be done either by having the lessor ratify the unit agreement or by including express language to that effect (such as described above) in the unitization clause. This will ensure that the lease won’t expire while the operator of the unit is actively engaged in drilling operations under the unit agreement.

Conforming the lease to the unit agreement may not be the end of the analysis in terms of lease extension. Specifically, all or a portion of the leased premises could still expire if the lease contains a severance provision in the unitization clause or a separate Pugh clause. A severance provision in a unitization clause could result in lease expiration as to any non-unitized lands at the end of the primary term. For example:

Anything in this lease to the contrary notwithstanding, actual drilling on, or production from, any unit or units (formed by private agreement or by any State or Federal governmental authority, or otherwise) embracing both lands herein leased and other land, shall maintain this lease in force only as to that portion of Lessor’s land included in such unit or units, whether or not said drilling or production is on or from the leased premises.

Similarly, a Pugh clause could result in lease expiration as to any non-producing lands at the end of the primary term. For example:

Notwithstanding any provision to the contrary, this lease shall terminate at the end of the primary term or any extended term, as to all the leased land except those lands within a production or spacing unit prescribed by law or administrative authority on which is located a well producing or capable of producing oil and/or gas or lands on which Lessee is engaged in drilling or reworking operations.

The threat posed by either of these provisions requires careful review of the lease as a whole. Oftentimes, Pugh clauses are negotiated independently of the general lease terms and ultimately included on an addendum attached to the lease. As a result, they are not always consistent with the other terms of the lease. To avoid ambiguity, when negotiating a fee oil and gas lease, it is prudent to review any included Pugh clause (and all other lease terms) and consider how it will reconcile with the unitization clause. Ideally, the Pugh clause should only result in lease expiration as to those lands outside of an approved unit. However, at a minimum, the Pugh clause should be drafted (or amended) so as to not sever the lands within a unit production area (for example, a participating area in a federal exploratory unit).

Part Three – How will the lessor’s royalty interest be calculated?

Example: Where there is production on any particular tract of land covered by such plan, it shall be regarded as having been produced from the particular tract of land to which it is allocated and not to any other tract of land and the Lessor’s royalty interest shall be based upon production only as so allocated.

Generally, a pooling clause will allow the leased premises to be combined with other lands to form a drilling unit, wherein proceeds from production anywhere on the drilling unit are allocated according to the percentage of the acreage of each tract divided by the total acreage of the drilling unit. However, because units are concerned with the development of a field or reservoir, the unitization clause should provide that proceeds from production should only be allocated to that tract included in a unit production area (such as a participating area in a federal exploratory unit). In other words, if the lessor’s interest is properly committed to a cooperative or unit plan of development, production anywhere on the unit will hold the lease, but the lessor will only receive proceeds from production if its tract is included in a unit production area containing a producing well (not the drilling or spacing unit that would exist if the well was drilled outside of the unit).

So what happens if the lessee’s working interest is committed to the unit agreement, but the lessor’s royalty interest is not? While the lessee will be allocated proceeds according to its proportionate share of the unit production area, the lessor will be allocated proceeds on a leasehold basis. This can result in a windfall either for the lessor or the lessee (compare the allocation of proceeds from the 1H and 2H wells in the diagram to the right, assuming 320 acre standup spacing units).

Part Four – How can the lessee commit the lessor’s interest?

Example: Lessor shall formally express Lessor’s consent to any cooperative or unit plan of development by executing the same upon request of Lessee.

The mechanism for the lessee to commit the lessor’s interest to a cooperative or unit plan of development varies depending on the unitization clause. Many unitization clauses allow the lessee to unilaterally commit the lessor’s interest by executing the unit agreement. In some cases, such unitization clauses require the lessee to record a memorandum of the unit agreement. Other unitization clauses, such as the example above, require the lessor to formally consent to the unit plan of development when requested by the lessee. This is typically done by executing a ratification of the unit agreement. In any event, the agency administering the unit (for example, the BLM for a federal exploratory unit) may need to confirm the commitment status of the fee lessor. As such, and to avoid a potential dispute down the road, the lessee may decide to obtain the lessor’s ratification of the unit agreement, even if the terms of the lease do not require it.

Unitization Clause Checklist:

  • ✓ Is there a unitization clause?
  • ✓ Does the unitization clause cover the proposed type of unit?
  • ✓ Does the unitization clause allow the leased premises to be combined with other lands for the development of a field or reservoir (as opposed to a single drilling unit)?
  • ✓ Does the unitization clause amend the lease terms to those of the unit agreement?
  • ✓ If there is a severance provision in the unitization clause, will it impact the proposed operations?
  • ✓ If the lease contains a Pugh clause, is it consistent with the unitization clause? Will it impact the proposed operations?
  • ✓ Does the unitization clause allocate proceeds from production within the unit production area (as opposed to a drilling or spacing unit)?
  • ✓ Will the proposed unitization plan be exercised in good faith?
  • ✓ If required, did the lessor execute a ratification of the unit agreement? Was it recorded?

[1] Williams & Meyers, The Law of Oil and Gas, § 8-U.
[2] In Utah, for example, correlative rights are defined as “the opportunity of each owner in a pool to produce his just and equitable share of the oil and gas in the pool without waste.” Utah Code Ann. § 40-6-2(2).
[3] See, e.g., Trans-Western Petroleum, Inc. v. U.S. Gypsum Co., 584 F.3d 988 (10th Cir. 2009).
[4] See, generally, Williams & Meyers, The Law of Pooling and Unitization § 8.06.
[5] See Amoco Prod. Co. v. Heimann, 904 F.2d 1405 (10th Cir. 1990).

Co-Authors
David Hatch and Andrew LeMieux

No JOA, That’s OK: Practical Solutions For Operators in A Cotenancy Relationship

“The panic appears to be over. Now is the time to get worried.”
William Keegan (1938–), British author and journalist

A signed and recorded joint operating agreement (JOA) is often the first line of defense for an operator dealing with distressed partners.  For example, a JOA generally grants an operator a lien upon the oil and gas rights of a non-operator in default and may establish certain penalties that can be assessed against a party who does not pay their share of development.  But what happens when there is no JOA?

In short, the rules of cotenancy govern.  Cotenants have an equal and coextensive right to occupy the premises so long as they do not exclude the other cotenant(s) from their equal right of access.  An occupying cotenant must account to the non-occupying cotenants for all profits, but can recover the expenses that the occupying cotenant incurred to generate such profits.  In most oil producing states, this means that one owner may develop minerals without the consent or joinder of its co-owners, but must proportionately share the proceeds of development minus the costs of development and production.  If oil and gas operations are unsuccessful, however, the entire burden falls upon the developing concurrent owner.

Unfortunately, these general rules do little to explain what an operator can do to recover the debts owed by a distressed partner for development costs.  So what tools does an operator have without a JOA?

What can an operator setoff?

One tool to collect debt owed by a distressed partner is the right to offset mutual debts.  The doctrine of setoff is generally broad enough to permit an operator to offset debts owing in one well with production in another well when there is no JOA explicitly establishing the right to do so.  This concept, known as the right of setoff, was recognized by the U.S. Supreme Court when it explained that “[t]he right of setoff (also called ‘offset’) allows entities that owe each other money to apply their mutual debts against each other, thereby avoiding ‘the absurdity of making A pay B when B owes A.’”  Citizens Bank of Maryland v. Strumpf, 516 U.S. 16, 18-19 (1995).

Generally, the doctrine of setoff will permit the offset of mutual debts on unrelated transactions, including the netting of obligations owed on unrelated wells.  Setoff can be a powerful tool because it affords an operator the opportunity to immediately collect 100% of the debt owed by a defaulting cotenant.  That said, although the doctrine is widely recognized, operators should be aware of a few precautions when deciding to exercise the right of setoff.

First, where possible, an agreement that expressly provides for the offset of mutual obligations should be sought.  This “best practice” will fortify the right of setoff and reduce the risk that a defaulting cotenant will challenge the setoff in the future.  Second, a company exercising the right of setoff must ensure that there is no preexisting contractual agreement or statutory obligation (such as a royalty obligation) which would prohibit or contravene setoff.  And third, although the doctrine of setoff is widely recognized, there is little case law specific to its use in the context of oil and gas cotenants.  The doctrine of setoff can be raised as an equitable defense in litigation, but the risk that a defaulting cotenant will challenge the setoff cannot be eliminated.

Ultimately, an operator must exercise its business judgment when setting off debts from unrelated wells.  In many cases, the immediate benefit of being able to collect a debt is well worth the risk that a defaulting party might challenge the setoff.

Can operators use state lien statutes?

State oil and gas lien statutes may provide an operator with additional remedies in the case of a defaulting cotenant.  Although lien statutes are most commonly used by oil and gas service providers, some courts have recognized that operators may also use these statutory liens.  John Carey Oil Co. v. W.C.P. Investments, 533 N.E. 2d 851 (Ill. 1988) (owner operator could attach statutory oil and gas lien upon interest of nonoperating co-owner under Illinois Oil and Gas Lien Act); Amarex v. El Paso Natural Gas Co., 772 P. 2d 905 (Okla. 1987); Kenmore Oil Co. v. Delacroix, 316 So. 2d 468, 469 (La. Ct. App. 1975).

When available, state lien statutes have specific procedures that must be closely followed in order to obtain a statutory oil and gas lien.  These statutes generally provide that the mineral lien must be perfected within a certain period of time from when the labor or services were last performed by filing information that defines the nature and amount of the lien with the appropriate state authority.  Individual state laws also differ regarding what property to which the lien extends.  For example, North Dakota’s lien statute states that the lien extends to the whole of the leasehold and includes the proceeds of production.  N.D.C.C. § 35-24-03.  But in Texas, the statute does not specifically reference proceeds of production as property subject to the lien, and Texas courts have held that mineral liens do not attach to the proceeds of production.  See e.g. In re Hess, 61 B.R. 977, 978 (N.D. Tex. 1986); Tex. E. Transmission Corp., 254 F.Supp.114, 118 (“in Texas the lien acquired by recording a judgment cannot attach to oil and gas after severance, or to proceeds resulting from its sale.”).  Although the scope and availability of lien rights varies from state to state, the filing of a lien can be a useful tool when dealing with distressed partners.

What about force pooling?

Finally, a force pooling order from the state regulatory agency may help an operator recover and in some states, secure the debts of a defaulting cotenant.  Most oil and gas producing states have a statutory provision allowing an operator to compel the integration of a non-participating working interest owner into a pooling arrangement.  After certain notice and hearing requirements are met, the state agency can integrate the owner into the pooled area and require the sharing of costs and revenues.  Force pooling may help an operator resolve outstanding debts with a cotenant in several ways.

First, the entry of a state force pooling order will clarify that an operator must pay a non-participating working interest owner only after the operator has deducted that owner’s share of drilling and completion costs.  Although this right already exists under the rules of cotenancy, legal disputes often arise about which costs are considered “reasonable and necessary.”  A force pooling order will define, by statute, what costs can be recovered by the operator.

Moreover, many states establish a “risk penalty” that, to compensate for the operator’s assumption of drilling risk, allows the operator to recover more than the non-participating owner’s proportionate share of costs.  In Colorado, for example, an operator may recover 200% of the force pooled owner’s share of drilling and completion costs.  C.R.S. § 34-60-116.  In these cases, a force pooling order is doubly helpful because it allows the operator to recover costs in excess of those actually expended.

Finally, in certain states, a force pooling order may authorize a lien on production to secure the debt of the non-participating cotenant.  In North Dakota, for example, the state force pooling statute provides that the operator has “a lien on the share of production from the spacing unit accruing to the interest of each of the other owners for the payment of his proportionate share of such expenses.”  N.D.C.C. § 38-08-08 (2015).  A similar provision exists in Oklahoma except that it provides that the operator “shall have a lien on the mineral leasehold estate or rights owned by the other owners therein and upon their shares of the production” until the operator is paid the amount due under the pooling order.  Okla. Stat. Ann. tit. 52, § 87.1 (2015).  In these states, upon executing the necessary steps to perfect a lien as provided by state statue, the operator will have a lien on production and/or the cotenant’s mineral estate until the cotenant’s share of costs has been recovered.

Even without a JOA, a savvy operator can do more than worry.  There are many effective legal tools that operators can use to recover and secure debts.  Those who take proactive steps to review these remedies now will be at an advantage later.

Co-Authors
Risa Wolf-Smith is a Partner at Holland & Hart and has in-depth experience in oil and gas business bankruptcy reorganizations and workouts.
Elizabeth Spencer is Of Counsel at Holland & Hart and specializes in regulatory and transactional work for oil and gas businesses.