agreements

How Are Federal Oil and Gas Leases Pooled and Unitized?

FAQs of Federal Oil and Gas Leases, Federal Lands, Oil and Gas Agreements, Oil and Gas Regulations, Uncategorized, , , , , , ,

In the context of federal oil and gas leases, the terms “communitization” and “unitization” are distinct concepts which are subject to different statutes, regulations, and procedures. As such, the method to “communitize” a federal oil and gas lease is different than the process used to “unitize” such leases. These respective differences are highlighted herein.

Communitization of Federal Oil and Gas Leases

Virtually all oil and gas producing states have promulgated minimum acreage requirements for the drilling of oil or gas wells.[1]  The United States recognized the importance of state conservation statutes, and accordingly passed an amendment to the Mineral Leasing Act which allowed federal lessees to conform to state well spacing orders through a communitization agreement.[2]  Communitization is the agreement to combine small tracts, of which one or more is federal or Indian lands, for the purpose of committing enough acreage to form the spacing/proration unit necessary to comply with the applicable state conservation requirement and to provide for the development of these separate tracts which cannot be independently developed in conformity with said conservation requirements.[3] In essence, communitization is the federal equivalent of pooling the lands in a spacing/proration unit under state law.  The common thread of all federal communitization agreements is that at least one federal or Indian lease or tract must be involved.[4]  That federal or Indian lease is communitized with other leases that may be federal, Indian, state, or fee.[5]

Although there is no prescribed form for a federal communitization agreement in the regulations, the regulations do require that certain information be included within the communitization agreement.  There are relatively few requirements for communitization agreements, but the applicant must usually provide sufficient information so the authorized officer can make a determination that it would be in the best interests of conservation and of the United States for the federal leasehold to be communitized.[6]  Specifically, the agreement must describe the separate tracts comprising the drilling or spacing unit, describe the apportionment of production or royalties to the parties, name the operator, contain adequate provisions for the protection of the interests of the United States, be filed prior to the expiration of the federal leases involved, and be signed by or on behalf of all necessary parties.[7]  The BLM Manual 3160-9-Communitization includes a standard or model communitization agreement form, one for federal leases and one for Indian leases, which should be used whenever possible.[8]

The necessary parties include all working interest owners and lessees of record. A communitization agreement may be approved without joinder by the royalty, overriding royalty, and production payment interest owners, but this will result in different payment scenarios depending upon the location of a successfully completed well.[9]

 If a state has them, the state’s compulsory pooling statutes may be utilized to commit a nonconsenting party’s interest to the communitization agreement; although, without the consent of the Secretary of the Interior, the state commission does not have jurisdiction to force pool unleased interests of the United States.[10]  Copies of any compulsory/force pooling order should be furnished with and be part of the communitization agreement if such interest owner does not execute the agreement.[11]  The authorized officer in the appropriate BLM office must approve, on behalf of the Secretary, the communitization agreement with respect to any included federal leases.[12]

Although not mandatory, the filing of a Preliminary Application for Approval to Communitize is recommended, particularly in instances where the model form of communitization agreement is not followed precisely.[13]  The BLM Manual provides that a request for preliminary approval to communitize may be filed at any time with the authorized officer. It is also recommended that preliminary approval be requested if there is some doubt as to whether the proposed tracts are logically subject to communitization, or if there is any doubt as to whether a communitization of multiple zones will be approved. The preliminary approval procedure will expedite final approval and may avoid the necessity of extensive revisions and re-execution of a finalized communitization agreement.[14]

The BLM will not approve an agreement that purports to communitize all horizons from the surface down to the center of the earth.[15] However, if it is anticipated that the well will be completed in multiple formations, it is important to include all formations and horizons that are producing or may produce hydrocarbons intended to be allocated pursuant to the terms of the communitization agreement.[16]  All communitized formations must be subject to the same spacing requirements and, where multiple and clearly distinct formations are covered by the same communitization agreement, the BLM Manual provides that Section 1 be amended to clearly state that the agreement shall apply separately to each formation as though a separate communitization agreement for each formation had been executed.[17]  In the event a proposed well is projected to test multiple formations that are subject to different spacing requirements, separate communitization agreements should be submitted to BLM for each formation or set of formations with the same spacing requirements.[18]

The communitization agreement must be filed prior to the expiration of the federal leases to be communitized.[19]  The regulations require that the communitization agreement be filed in triplicate with the proper BLM office.[20]  If state lands are involved one additional counterpart must be submitted.

An executed counterpart of the approved communitization agreement, duly acknowledged, should be filed of record in the county in which the land is located. When fee leases are involved, the operator should record either the communitization agreement or otherwise comply with the terms of the pooling provision of any fee lease.[21]

In order to approve a communitization agreement, the Mineral Leasing Act requires that the Secretary determine communitization is “in the public interest”[22]:

The public interest requirement for an approved communitization agreement shall be satisfied only if the well dedicated thereto has been completed for production in the communitized formation at the time the agreement is approved or, if not, that the operator thereafter commences and/or diligently continues drilling operations to a depth sufficient to test the communitized formation or establish to the satisfaction of the authorized officer that further drilling of the well would be unwarranted or impracticable.”[23]

Communitization agreements usually provide for a term of two years and so long thereafter as communitized substances are, or can be, produced from the communitized area in paying quantities.[24]  Assuming the public interest requirement is satisfied, any federal lease eliminated from an approved communitization agreement, or any federal lease in effect at the termination of the agreement, shall continue in effect for the original term of the federal lease or for two years after its elimination from the plan or termination of the agreement, whichever is longer, and for so long thereafter as oil or gas is produced in paying quantities.[25]  No lease shall be extended if the public interest requirement has not been satisfied.[26]

Unitization of Federal Oil and Gas Leases

Unitization is the agreement to jointly operate an entire producing reservoir or a prospectively productive area of oil and/or gas. The entire unit area is operated as a single entity, without regard to lease boundaries, and allows for the maximum recovery of production from the reservoir. Costs are reduced because the reservoir can be produced by utilizing the most efficient spacing pattern, separate tank batteries are not necessary, and there is no requirement to drill unnecessary offset wells. The objective of unitization is to provide for the unified development and operation of an entire geologic prospect or producing reservoir so that exploration, drilling, and production can proceed in the most efficient and economical manner by one operator.[27]

The Bureau of Land Management is the administering agency for federal onshore units and has established procedures that must be followed to unitize federal lands.[28] Although not required by the regulations, the BLM strongly encourages an informal discussion with the authorized officer of BLM office having jurisdiction over the area where the lands are located concerning the proposed area of the unit, the depth of the test well and formation to be tested, and the form of agreement.[29]  This should be done prior to filing of an application.[30] It is recommended that this is done in order to ensure the unit approval process moves smoothly.

BLM regulations provide that,  to initiate the formation of a federal unit, an application for designation of a proposed unit area be filed in duplicate.[31] The application must be accompanied by a map or diagram outlining the area sought to be designated and indicating the federal, state, privately owned, or Indian lands by symbols or colors.[32]  The plat must indicate the separate leasehold interests involved and identify them by serial number in the case of federal and Indian oil and gas leases.[33]  It is advisable to show the ownership and expiration dates of each lease involved. The application must also be accompanied by a geologic report and it must indicate the zones that are to be unitized (if all zones or formations are not to be included).[34]

The owners of any interest in the oil and gas deposits to be unitized are proper parties to the unit agreement. All such parties must be invited to join the agreement.[35] This includes royalty owners and holders of overriding royalty interests and any other non-cost bearing interests in production, as well as working interest owners. Prior to approval, notice of the proposed agreement must be given to all parties with a request to join the agreement.[36]  When state lands are to be unitized with federal lands, the unit agreement must be approved by the state prior to submission to the BLM for final approval.[37]

After the unit area has been designated and the unit agreement has been fully executed by the parties desiring to commit their interests to the unit, a minimum of four signed counterparts must be filed for approval with the proper BLM office.[38]  These instruments should be accompanied by a request from the proponent for final approval of the unit, setting forth the acreage interests fully committed, effectively committed, partially committed, and not committed and show the percentage in each category.[39]  A showing must also be made that all parties owning not committed interests within the unit area have been extended an invitation to join in the unit agreement and that a reasonable effort has been made to obtain the joinder of all such parties.[40]  The request for final approval must include a list of the overriding royalty interest owners who have executed or ratified the unit agreement.[41] A tract will be considered “fully committed” if all interest owners have joined the unit and all working interest owners have also executed the applicable operating agreement.[42] A tract will be considered “effectively committed” to the unit without joinder by overriding royalty interest owners and will be treated identically as a “fully committed” tract, but, will result in different payment scenarios depending upon the location of the successfully completed unit well.[43] A tract will be considered “partially committed” if less than all of the lessors/royalty interest owners have joined, or all operating rights owners of a federal lease have joined but the record title holder has not.[44]  Such partially committed tracts may be considered to be under the effective control of the unit operator, however, no unit benefits will accrue to the tract in the absence of actual operations on the partially committed tract or an allocation of production to that tract either from a well on the tract or from another location.[45] Finally, if any working interest owner in a tract does not commit its interest, that tract is deemed “not committed.”[46]  BLM regulations provide that a unit agreement will not be approved “unless the parties signatory to the agreement hold sufficient interests in the unit area to provide reasonably effective control of operations.”[47] Generally, 85% of the tracts in the unit must be fully, effectively or partially committed to meet this “effective control” requirement.[48]

After four signed counterparts of the executed agreement are submitted, the authorized officer approves the unit agreement upon a determination that the agreement is necessary or advisable in the public interest and is for the purpose of more properly conserving natural resources.[49] A model federal onshore unit agreement for unproven areas (hereinafter “Model Form”) is included in the BLM regulations and promulgated to help implement these provisions.[50] Section 9 of the Model Form specifically provides for the commencement of an initial test well within six months after the effective date of the unit.[51] If a discovery is not made in the initial test well, provision is made for continuous drilling on unitized lands until a discovery is made provided that not more than six months elapse between the completion of one well and the commencement of the next.[52]  Paying quantities for purposes of meeting the drilling obligations in section 9 is defined as quantities of unitized substances sufficient to repay the costs of drilling, completing, and producing operations, with a reasonable profit.[53]

Upon approval, the unit agreement becomes effective.[54]  However, the public interest requirement is satisfied only if the unit operator commences actual drilling operations and diligently prosecutes such operations in accordance with the terms of the agreement.[55]  If this requirement is not satisfied, the approval of the agreement and lease segregations and extensions shall be invalid.[56]  Evidence of the approved unit should be recorded in the county records to impart notice.

Finally, it is important to understand the interplay between the unit agreement and the unit operating agreement because both agreements, taken together, constitute the unit arrangement and establish the contractual rights and obligations of the parties.

In addition to setting forth the terms and conditions for the unit, the unit agreement prescribes the method of allocating production for purposes of determining royalties, overriding royalties, production payments, and other non-cost bearing burdens, but does not dictate the working interest owners’ respective shares of production or the allocation of costs/royalty burdens associated therewith.[57] These, and other duties and obligations among the working interest owners, are matters covered by the unit operating agreement.[58]

The BLM does not prescribe any particular form of unit operating agreement and the working interest owners are generally free to use whatever form of unit operating agreement they prefer.[59] The unit operating agreement is entered into by the working interest owners who are committing their interests to the unit in conjunction with the execution of the unit agreement.[60] The interests of the royalty owners are not affected by the form of unit operating agreement chosen by the working interest owners.[61] Two copies of the unit operating agreement are required to be filed in the proper BLM office before the unit agreement will be approved.[62]

[1] Angela L. Franklin, Communitization Agreements in the 21st Century, Federal Onshore Oil and Gas Pooling and Communitization, Paper 3-4 (Rocky Mt. Min. L. Fdn. 2006) [hereinafter Communitization Agreements].

[2] See Mineral Leasing Act, Pub. L. No. 696, § 17(b), 60 Stat. 952 (1946).

[3] See 2 Lewis C. Cox, Jr., Law of Federal Oil and Gas Leases § 18.01 (2017).

[4] Communitization Agreements, supra note 2, at 3-5.

[5] Id.

[6] 1 Bruce M. Kramer & Patrick H. Martin, The Law of Pooling and Unitization § 16.04 (3rd ed. 2017).

[7] 43 C.F.R. § 3105.2-3(a) (2018).

[8] Communitization Agreements, supra note 2, at 3-5.

[9] Id.

[10] Id. at 3-6.

[11] Id.

[12] 43 C.F.R. § 3105.2-3 (2018).

[13] Communitization Agreements, supra note 2, at 3-7.

[14] See id.

[15] Id. at 3-8.

[16] Id.

[17] Bureau of Land Management, BLM Manual 3160-9-Communitization .11M (1988) [herein after BLM Manual].

[18] Communitization Agreements, supra note 2, at 3-8.

[19] 43 C.F.R. § 3105.2-3(a) (2018).

[20] Id. § 3105.2-1.

[21] Communitization Agreements, supra note 2, at 3-10.

[22] 30 U.S.C. § 226(m) (2018).

[23] 43 C.F.R. § 3105.2-3(c) (2018).

[24] See Section 10 of Model Form of a Federal Communitization Agreement in BLM Manual app.

[25] 43 C.F.R. § 3107.4 (2018). But see, R. E. Hibbert, 8 IBLA 379 (1972), GFS (O&G) 6 (1973).

[26] 43 C.F.R. § 3107.4 (2018).

[27] Kramer & Martin, supra, § 18.01[2].

[28] Id. § 18.04[1].

[29] Kramer & Martin, supra, § 18.04[2].

[30] See id.

[31] 43 C.F.R. § 3183.2 (2018)

[32] Kramer & Martin, supra, § 18.04[3] (citing 43 C.F.R. §§ 3181.2, 3183.2).

[33] See id. § 18.04[3].

[34] See 43 C.F.R. § 3181.2 (2018).

[35] 43 C.F.R. § 3181.3 (2018).

[36] See Kramer & Martin, supra, § 18.04[4].

[37] 43 C.F.R. § 3181.4(a) (2018).

[38] 43 C.F.R. § 3183.3 (2018).

[39] See Kramer & Martin, supra, § 18.04[6].

[40] Id. (citing 43 C.F.R. § 3181.3).

[41] See Kramer & Martin, supra, § 18.04[6].

[42] See Frederick M. MacDonald, Preparing and Finalizing the Unit Agreement: Making Sure Your Exploratory Ducks are in a Row, Federal Onshore Oil and Gas Pooling and Communitization, Paper 8-23 (Rocky Mt. Min. L. Fdn. 2006).

[43] Id. at 8-24.

[44] Id.

[45] Id.

[46] Id. at 8-25.

[47] 43 C.F.R. § 3183.4(a) (2018)

[48] MacDonald, supra, at 8-16.

[49] See Kramer & Martin, supra, § 18.04[6]. (citing 43 C.F.R. § 3183.4).

[50] See Thomas W. Clawson, Paying Well Determinations, Federal Onshore Oil and Gas Pooling and Communitization, Paper 11-3 (Rocky Mt. Min. L. Fdn. 2006).

[51] See Model Form, § 9, 43 C.F.R. § 3186.1.

[52] See Kramer & Martin, supra, § 18.03[2][b][iii].

[53] Model Form, § 9, 43 C.F.R. § 3186.1.

[54] Kramer & Martin, supra, § 18.04[6] (citing Lario Oil & Gas Co., 92 IBLA 46, GFS(O&G) 54 (1986)).

[55] Kramer & Martin, supra, § 18.04[7].

[56] 43 C.F.R. § 3183.4(b) (2018).

[57] See Steven B. Richardson and Lynn P. Hendrix, The Unit Operating Agreement for Federal Exploratory Units, Oil and Gas Agreements: Joint Operations, Paper 13-3 (Rocky Mt. Min. L. Fdn. 2008).

[58] Id.

[59] Id. at 13-1.

[60] Id. at 13-3.

[61] Id.

[62] Id.

Top Leases: Assessing (and Avoiding) the Risks of Novation

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You only have three more months on the primary term of an oil and gas lease that was issued nearly five years ago with a 1/6th royalty.  A drilling permit should be issued any day now, and you anticipate commencing operations to drill a well in sufficient time to hold the lease.  You instruct your landman to obtain a top lease from the mineral owner just in case there is a hiccup and you can’t start operations in time to hold the existing lease. Your landman negotiates a new lease from the mineral owner covering the same lands but has to agree to a 3/16ths royalty in order to obtain the top lease.  But, the top lease fails to expressly state that it is a top lease to the existing lease and doesn’t contain any other language clarifying that the top lease will only be effective if and when the underlying existing lease expires.  Despite the precautionary top lease, the well permit is issued when expected and you are able to commence drilling a well in time to hold the prior existing lease.

After the well is drilled and completed, is there a risk that the mineral owner could successfully argue that the new top lease is a replacement of the existing lease and you are required to pay a 3/16ths royalty instead of a 1/6th royalty? In the oil and gas industry, you often hear landmen and attorneys frame the question as whether or not the top lease will be deemed a “novation” of the prior existing lease. But what is the standard to prove a novation? How likely is it that the mineral owner above could successfully argue that the top lease is a novation of the prior lease, even though the well was drilled in time to hold the prior existing lease? This article will provide a brief overview of the elements and burden of proof to establish a novation.

A recent 2015 case out of Pennsylvania provides an excellent overview and example of the novation analysis in the context of oil and gas leases. In Mason v. Range Resources-Appalachia LLC, 120 F. Supp. 3d 425, 433 (W.D. Pa. 2015), an oil and gas lease was issued in 1961 in Western Pennsylvania and was arguably held by gas storage operations on the property (and by the payment of rentals). Years later, during the Marcellus shale boom, a landman working for Range Resources obtained an oil and gas lease in 2007 from the same mineral owners and covering the same lands as the 1961 lease. Range Resources only later discovered that it already owned the existing 1961 lease. Testimony in the case indicated that the leasing environment at that time was “chaotic,” that Range Resources did not have a good process for evaluating lease validity, and that landmen were taking leases without conducting complete due diligence of possible existing leases. Range Resources did not drill a well within the term of the 2007 lease, and the mineral owners asserted that the 2007 lease was a novation of the 1961 lease (which had unique provisions allowing the lease to be held by rental payments for gas storage), and that the 2007 lease then expired.

The Pennsylvania court set forth four elements to show a novation, which elements are the same or similar in other jurisdictions that have undertaken a discussion of novation:

“(1) the displacement and extinction of a prior contract, (2) the substitution of a valid new contract for the prior contract, (3) sufficient legal consideration for the new contract, and (4) the consent of the parties.”1

The Pennsylvania court further stated that “whether a contract has the effect of a novation primarily depends upon the parties’ intent” and “the party claiming the existence of a novation bears the burden of demonstrating the parties had a meeting of the minds.” The court stated that evidence of the parties’ intent to enter in to a novation can be shown “by other writings, or by words, or by conduct, or by all three.” Courts in other states have similarly emphasized that a party claiming a novation has the burden of proof, and that the party asserting the claim of novation has the burden of proving all of the required elements for a novation.2 A novation is never presumed. Instead the presumption is that the new contract was taken conditionally or as additional security, absent evidence of intention to the contrary.3 In the Pennsylvania case, the court determined that the mineral owners continued to accept rentals under the 1961 lease even during the term of the 2007 lease, and there was no evidence that the parties expressly intended to replace the 1961 lease with the 2007 lease.

Returning to our example above, the case law suggests that a mineral owner attempting to argue that the top lease was a novation of the base lease would have a very challenging case. But there is still a risk of such a claim, even if the claim is ultimately for nuisance value only. How can an operator protect itself from novation claims? Obviously, the best approach is to always put language in any top lease that makes it clear that the lease will only go into effect if and when the base lease expires by its terms, and make that intent clear in any other written correspondence to a landowner (such as an initial offer letter).

But what if an operator accidentally obtains a standard lease with no top lease language when it already owns an existing lease? For drilling purposes, the mineral interest will be leased either way. But an operator should ideally take steps to address any ambiguity resulting from the top lease and clarify the intent of the parties. If the well is successfully completed in time to hold the existing lease, the best approach would be to have the mineral owner (and operator) sign and record a ratification document where the parties acknowledge that the base lease was held by the drilling of the well, and that the top lease will remain of record as a top lease only in the event the well ceases operations.

Another approach (with attendant risks) would be to send an informative letter to a landowner prior to drilling, informing them of the pending well, stating that the operator will deem the base lease as held by the drilling of the well. That would at least set up an estoppel argument, and the operator will know prior to drilling the well whether or not the landowner objects and claims a novation. Or, an operator may simply pay proceeds on the prior existing lease, see if the landowner accepts royalty payments under that lease, and simply run the risk of a future novation claim. There may also be facts that make an operator more confident that a novation argument will be unsuccessful that justifies a riskier wait-and-see approach.4

Each fact scenario will be different, and an oil and gas lessee must evaluate the facts and risks to determine what level of clarification and curative action it requires to address risks of novation claims when there are overlapping leases.

1 Another novation case in the oil and gas context, Warrior Drilling & Eng’g Co. v. King, 446 So. 2d 31, 33-34 (Ala. 1984), framed the elements as: “[T]o establish a novation there must be: (1) a previous valid obligation, (2) an agreement of the parties thereto to a new contract or obligation, (3) an agreement that is an extinguishment of the old contract or obligation, and (4) the new contract or obligation must be a valid one between the parties thereto.”
2 In re United Display & Box, Inc., 198 B.R. 829, 831 (Bankr. M.D. Fla. 1996). See also Fusco v. City of Union City, 618 A.2d 914 (App. Div. 1993); Alexander v. Angel, 236 P.2d 561 (1951); Scott v. Bank of Coushatta, 512 So. 2d 356 (La. 1987); Credit Bureaus Adjustment Dep’t, Inc. v. Cox Bros., 295 P.2d 1107 (1956).
3 For example, a Utah court conducting a novation analysis stated: “The burden of proof as to a novation by the transaction in question rests upon the party who asserts it; … an intention to effect a novation will not be presumed; … in the absence of evidence indicating a contrary intention, it will be presumed, prima facie, that the new obligation was accepted merely as additional or collateral security, or conditionally, subject to the payment thereof; and the intention to effect a novation must be clearly shown.” First Am. Commerce v. Washington Mut., 743 P.2d 1193 (Utah 1987); see also Tri-State Oil Tool Indus., Inc. v. EMC Energies, Inc., 561 P.2d 714, 716 (Wyo. 1977).
4 For example, if the existing lease covers multiple parcels in several drilling units, and the new lease only covers one parcel, that may make an argument for a novation more difficult. Also, if there are unrecorded documents that evidence clear intent that the second lease was intended only as a top lease, that fact may make an operator more confident that a novation claim would be unsuccessful.

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

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“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.

Exercising Rights to Setoff and Recoupment in Bankruptcy

Bankruptcy, Due Diligence, Oil and Gas Agreements, , , ,

Current market conditions are straining business relationships in the oil and gas industry. In a growing number of cases, distressed companies are seeking chapter 11 bankruptcy protection. In that event, a creditor-debtor relationship is formed between the bankrupt company and the performing partner. For example, in the context of a joint operating agreement, an operator (the performing partner) may seek to recapture drilling costs from a non-operator (the bankrupt company). In these bankruptcy cases, the performing partner should consider its ability to offset debts with the bankrupt company through “setoff” or “recoupment”.

Setoff is simply a creditor’s right to offset mutual debts. Setoff is captured in Section 553(a) of the Bankruptcy Code, which preserves a creditor’s right to offset the mutual debts of the creditor and debtor provided that both debts (the debt owed by the creditor to the debtor and the debt owed by the debtor to the creditor) 1) arose before commencement of the bankruptcy case and 2) are mutual, meaning that both parties owe a debt to the other.1 The mutual debt need not, however, arise out of the same transaction in order for setoff to be available under the statute. 2 In fact, debts subject to setoff generally arise from different transactions.3

For example, A and B are jointly developing two wells and A is the operator of the wells. One well, called Boom, is producing, but the other, called Bust, is not. Boom generates $500,000 a month in revenue, but B owes A $1 million for B’s share of operating costs on Bust. In this case, setoff may allow A to withhold B’s share of revenue from Boom and credit it to B’s unpaid costs from Bust. This is because the purpose of setoff is to avoid “the absurdity of making A pay B when B owes A.”4

Setoff is limited in three ways. First, setoff is not a right created by the Bankruptcy Code.5 While Section 553(a) preserves a right to setoff, that right must first exist under “applicable non-bankruptcy law” (e.g. state law).6 Second, unlike recoupment (discussed below), a creditor can only offset pre-bankruptcy (pre-petition) debts. In other words, a creditor cannot use setoff to recover a pre-bankruptcy debt out of post-bankruptcy (post-petition) payments owed to the debtor.7 Third, a creditor’s right to setoff is automatically stayed (i.e. suspended) when a debtor files for bankruptcy protection.8 Creditors seeking to setoff must first obtain relief from the automatic stay imposed by Section 362(a) of the Bankruptcy Code and should consult bankruptcy counsel to assist in that effort.

Recoupment is similar to setoff in that it recognizes the basic inequities of allowing a debtor to enjoy the benefits of a transaction without also meeting its obligations.9 But, recoupment only permits a creditor to withhold funds to offset debts arising from the same transaction.10 Claims arise from the “same transaction” when both debts arise out of a single, integrated contract or similar transaction, such as a joint operating agreement.11

For example, A operates a well and B is a non-operator with an obligation to reimburse A for 25% of the drilling costs. A incurs $1,000,000 in costs and B fails to pay its $250,000 share. If B files for bankruptcy protection, then A has a $250,000 claim against the bankruptcy estate. In this case, recoupment may allow A to withhold B’s revenues from the well and credit the revenues against the costs incurred by A. This example illustrates how recoupment functions like a security interest in that it grants priority to a creditor’s claim in the bankruptcy estate, provided that the estate has a claim against the creditor arising from the “same transaction” as the creditor’s claim.12

Recoupment has certain benefits that are unavailable under setoff. First, a creditor can exercise its right to recoupment without regard to the timing and other requirements of Section 553 of the Bankruptcy Code.13 Second, recoupment allows a creditor to recover a pre-bankruptcy debt out of post-bankruptcy payments owed to the debtor.14 Third, a creditor who properly exercises its right to recoupment will not violate the automatic stay imposed by Section 362(a) of the Bankruptcy Code.15 However, a creditor may wish to seek relief from stay to clarify its right to exercise recoupment and to avoid any uncertainty about the amount the creditor can recoup. Bankruptcy counsel can help a creditor analyze its right of recoupment and assist in seeking relief from the automatic stay.

111 U.S.C. § 553(a).
2In re Davidovich, 901 F.2d 1533, 1537 (10th Cir. 1990).
3Conoco, Inc. v. Styler (In re Peterson Distrib.), 82 F.3d 956, 959 (10th Cir. 1996).
4Citizens Bank v. Strumpf, 516 U.S. 16, 18 (1995).
5Id.
6Id.
7See 11 U.S.C. § 553(a).
811 U.S.C. § 362(a)(7).
9Peterson Distrib., 82 F.3d at 960.
10In re Adamic, 291 B.R. 175, 181-82 (Bankr. D. Colo. 2003).
11Davidovich, 901 F.2d at 1538.
12Peterson Distrib., 82 F.3d at 960.
13Davidovich, 901 F.2d at 1537.
14Beaumont v. VA (In re Beaumont), 586 F.3d 776, 780 (10th Cir. 2009).
15Id. at 777.

Fraudulent Transfer Risks in Oil and Gas Transactions

Bankruptcy, Due Diligence, , , ,

Over the past few months, the economics of the oil and gas industry have changed dramatically. As oil and gas prices have fallen, so too have profit margins and working capital. Many companies will weather this storm. A fortunate few will expand their positions and acquire additional assets, some of which will be purchased from distressed companies. In dealing with these distressed companies and their assets, landmen and other oil and gas industry professionals will need to have a working-knowledge of select bankruptcy-related laws and concepts to protect their company’s assets. In this article, we will discuss one aspect of relevant bankruptcy law: fraudulent transfers and how they may affect property transactions.1

What is a fraudulent transfer?

When a company files for bankruptcy, the bankruptcy trustee may avoid any fraudulent transfer of property made within four years of filing in most states, if certain conditions are met. Fraudulent transfers occur when: (1) there was an intent to hinder, delay, or defraud creditors; or (2) the debtor transfers property without receiving “reasonably equivalent value” in exchange for the transfer and is insolvent at the time of the transfer, becomes insolvent as a result of the transfer, or is left with an unreasonably small amount of capital to operate its business as a result of the transfer.2 If a transaction is deemed to be a fraudulent transfer, the bankruptcy trustee can recover the property or obtain a judgment for the value of the property.

The first type of fraudulent transfer involves an actual intent to defraud and is more easily identified. For example, in In re Tronox, a court found that a debtor transferred property with environmental liabilities with an intent to hinder, delay, or defraud creditors through a spinoff.3 In another case, In re ASARCO, a court found that the debtor hindered and delayed creditors by directing all of the consideration from a sale of a majority of a mining entity to one of the Debtor’s creditors, to the detriment of other creditors.4 These situations usually involve related parties.

The second type of fraudulent transfer, commonly referred to as a constructively fraudulent transfer, occurs when a company purchases an asset without paying reasonably equivalent value. This can occur when purchasing assets from a third party or, more commonly, when buying-out a partner to resolve a debt or other obligation. If the seller files for bankruptcy subsequent to the transaction, there is a risk that the bankruptcy trustee could seek to have the transaction declared to be a fraudulent transfer.

In determining “reasonably equivalent value” a bankruptcy court looks at the totality of the circumstances. Fraudulent transfer laws are designed to preserve the assets of the debtor for the benefit of creditors. When carrying out this intent, courts disregard the form of a transaction and look “instead to its substance.”5 Fraudulent conveyance law is “designed to protect creditors’ rights” and looks at transactions from “the perspective of creditors.” 6 Whether a purchaser paid reasonably equivalent value is a subjective question that depends on the facts of each individual situation.

What does this mean for landmen?

Oil and gas professionals should be aware of the risks of acquiring property from distressed companies. To avoid constructively fraudulent transfers, a purchaser should ensure that they are giving “reasonably equivalent value” for the asset. This can be difficult. Under certain circumstances, when the value of the property is enhanced by the buyer after the sale closes (through drilling or other development) the debtor may later contend that the buyer failed to pay reasonably equivalent value.

The best way to determine “reasonably equivalent value” when dealing with a distressed company is to obtain an appraisal from an independent third party. If an appraisal is not cost-effective or is impractical, the risk of a fraudulent transfer can be mitigated by conducting proper due diligence.

An awareness of the financial health of the companies you are doing business with is as important as ever. By evaluating the transaction now, you can avoid problems down the road.

1There are many tools that an oil and gas company can use to mitigate its exposure to bankruptcy risks. A full discussion of all the tools is beyond the scope of this article. If you have questions on how to mitigate bankruptcy risks, or if a business partner files for bankruptcy, we advise you to contact a bankruptcy expert immediately to protect your assets.
2 See 11 U.S.C. § 548.
3 In re Tronox Inc., 429 B.R. 73 (Bankr. S.D.N.Y. 2010).
4 See In re ASARCO, L.L.C, 702 F.3d 250 (5th Cir. 2012).
5 In re HBE Leasing Corp. v. Frank, 48 F.3d 623, 638 (2d Cir.1995) (construing the New York’s fraudulent conveyance statute).
6In re Crowthers McCall Pattern, Inc., 129 B.R. 992, 998 (S.D.N.Y.1991).

The Nuts and Bolts of Farmout Agreements

Royalty Issues,

An oil and gas farmout agreement is an agreement by the owner of an oil and gas lease (the “farmor”) to assign all or part of the working interest in that lease to another party (the “farmee”), who agrees to drill a well and do testing on the property in exchange for the opportunity to earn a formal assignment of working interest. The farmout agreement usually requires the farmee to drill a well to a certain depth, at a specified location, and within a certain time frame, at the farmee’s own risk and expense. Typically, the farmee must complete the well as a commercial producer to earn an assignment, because the farmor desires to preserve the lease (although some farmouts require only drilling to earn). Generally speaking, the greater the risks a farmee takes, the greater the area in which the farmee will earn an interest.

In a farmout, the farmor usually reserves an overriding royalty interest, with the option to convert the overriding royalty interest to a working interest in the lease upon payout of drilling and production expenses, otherwise known as a back-in after payout (BIAPO). As an example, the agreement may provide for:

Before Payout of Well Cost (“BPO”)
3% overriding royalty		 After Payout of Well Costs (“APO”)
Option to keep 3% ORRI or convert to 25% working interest subject to royalty burden

Payout occurs when the farmee has recovered all of its drilling costs out of its share of production after deducting its operating costs, certain taxes, and other expenses. The farmout should include a complete definition of “payout” by stating exactly what will be deducted in calculating the payout amount.

Farmouts can present a number of potential issues for land departments and title examiners. First, the parties often fail to record notice of the farmout. As a result, the farmee’s rights under the farmout may not be protected against a third-party bona fide purchaser or the bankruptcy of the farmor. It is critical for a farmee to provide notice of the farmout and protect its operator’s lien rights by perfecting its interest under the farmout. Fortunately, this issue can be easily resolved by recording a memorandum of the farmout agreement in the county where the lands are located.

Second, a farmout is different than a lease assignment in that the farmor retains leasehold title until the farmee has completed the required drilling and testing of the property and has earned an assignment. Without a formal assignment of interest from the farmor, the records may not be clear as to whether the farmee has in fact earned an interest under a farmout agreement, and a factual inquiry and careful analysis is required. To aid this analysis, the conditions for earning an assignment and when the assignment will be delivered to the farmee should be clearly drafted in the farmout. Once the farmee receives the assignment, it should be timely recorded in the county where the lands are located for the same reasons as discussed above.

Third, the election of the farmor to retain an overriding royalty interest or convert it to a BIAPO working interest affects the rights of both parties and their successors-in-interest. Therefore, the farmor’s election must be clear from the records. The election should be reflected either in the recorded assignment or in a subsequently recorded instrument.

Other farmout provisions of note include the formation of an AMI, or “area of mutual interest,” which obligates one party to the farmout to offer the other party a certain percentage of the interest the first party acquires in oil and gas rights within the defined geographic boundary of the AMI. Additionally, a farmout may contain a call on production clause, under which the farmor has a continuing preferential right to purchase all oil and gas production from the farmout acreage.

Farmouts are negotiated agreements taking many different forms that often include complex provisions. The parties would be wise to carefully review the terms and conditions of the farmout to ensure their rights and obligations. In addition, the parties should protect their rights under the farmout by recording a memorandum of the farmout, the interest earned by the farmee, and the elections of the farmor.

If It’s Wrong, You Got Nothin’ – Execution of Instruments

Title Issues/Curative, , ,

To state the obvious, one of the most important aspects of any lease, deed, assignment or any other contract is making sure the appropriate party executes it. If the wrong person signs it, it will be either invalid or voidable at best. This is exactly what happened when only one manager of a limited liability company signed a 99 year lease. Unfortunately, the articles of organization on file with the secretary of state required both of the managers identified therein to sign such a lease. The lessee did not know there were two managers or that the articles of incorporation contained such requirement. The court found that the manager who signed the lease lacked actual and apparent authority to execute the lease and the lease was declared invalid.1 To assist in determining the appropriate party to execute a lease, deed, assignment or other contract, set forth below is a list of the common entities and scenarios that may be encountered in any title examination or transaction. 2

Attorneys-in-Fact. An attorney-in-fact is one who is authorized by a power of attorney to act on behalf of the actual owner of the property. Such authority will be defined in the power of attorney and will be strictly construed. Several states require recordation of the power of attorney in the county where the property is located.3

Associations: Religious, Cooperatives, Lodges, Educational, Non-Profits. These associations may encumber or convey real property held in the association’s name through its officers as authorized by its bylaws and resolutions. Such association’s governing documents and the laws of the state in which it is organized must be reviewed to determine authority.

Contracts for Deed. Generally, the holder of a contract may convey or encumber the applicable interest, unless the contract specifically provides otherwise. The holder of a contract for deed should join in the execution of the instrument in the same way as a life tenant joins (see below).

Corporations. The laws of the state of incorporation4 and the corporation’s governing documents (articles of incorporation, bylaws or resolutions) define the appropriate officer(s) or agent to execute a contract on behalf of a corporation. Typically, the president or vice president are authorized to execute a contract. If required, the officer’s signature should be attested and a corporate seal affixed.

Estates (Personal Representatives, Executors, Administrators). Generally, the authority of the personal representative, executor, or administrator to execute a contract is granted by a court having jurisdiction over the real property. Accordingly, applicable probate proceedings must be initiated in the state in which the property is located, not the resident state of the deceased. The resulting letters testamentary evidencing the party’s authority to act must be reviewed to confirm any limitations that may be imposed on the party’s authority, including the time period for which the party’s was granted authority to represent the estate of the decedent.

General Partnerships. Typically, an instrument can be executed by any partner, if acting within the scope of his or her authority, unless otherwise restricted in the partnership agreement or the laws of the state in which the partnership is organized.

Individuals. Any competent person may execute a contract. However, a contract executed by a minor is voidable at the minor’s election either before the age of majority or within either a statutorily defined time or a reasonable time thereafter. The typical age of majority is 18 years unless otherwise emancipated. If an interest is owned by a minor or incompetent, a guardian or conservator should be appointed by a court, who then may execute on behalf of the minor or incompetent. If a person cannot sign his or her own name, he or she may execute a contract by a mark. The signature of one or more credible witnesses or the acknowledgment by a notary public is typically required. As to competency, absence actual or constructive knowledge, a person of the age of majority is presumed to be competent. A person is not considered mentally incompetent until declared as such by a court. However, there appears to be a general standard that if the person is entirely without understanding, generally such person has no power to execute a contract. Any contract executed by a mentally incompetent person is voidable at the person’s election for a reasonable time after the person is judicially declared competent and most likely void if the person is under a guardianship.

If an individual is married, a variety of laws and circumstances exist which must be considered before it can be determined if a married person can legally convey such property without a joinder by his or her spouse. Under certain circumstances, the contract may be void even as to the party who signed.5 Therefore, it is generally recommended that a contract be signed by both spouses. However, in order to prevent any unintended consequences or benefits to the non-record title owner spouse, the proposed contract should be carefully drafted to avoid any unintended consequences. The types of ownership by married individuals are as follows:

Community Property. In a community property state, the property is owned by the community or, in other words, each spouse may claim an undivided one-half interest. This type of ownership applies to most property acquired during marriage by the husband or the wife. It generally does not apply to property acquired prior to the marriage or by gift or inheritance during the marriage. After a divorce, community property is either divided equally or according to the discretion of the court. Some of the applicable community property states include Alaska6, California, Louisiana, Nevada, New Mexico, and Texas7. Unless it can be determined that the property is owned separately, both spouses must execute or be a joining party to the instrument. Generally, upon the death of one spouse, the spouse’s interest passes to his or her devisees if the decedent spouse died testate or to his or her surviving spouse if the decedent spouse died intestate. Therefore, it is recommended to have the contract executed by the heirs or devisees of the deceased spouse and by the surviving spouse until the estate of the decedent spouse has been formally probated. Most importantly, even if the real property is not located in a community property state, if the husband and wife are domiciled in a community property state, the community property laws will apply.

Tenancy by the Entirety. Tenancy by the entirety is recognized in Alaska, Michigan, Ohio, Oklahoma, and Wyoming. This type of ownership is similar to joint tenancy, except that the parties must be husband and wife and the property cannot be conveyed by only one spouse. In the event the parties divorce, the property will transform into a tenancy in common.

Joint Tenants. For a joint tenancy to be created, it must be expressly declared in the contract conveying the real property by use of such language as “joint tenants” or “with rights of survivorship.”8 In the event of the death of one of the joint tenants, the surviving joint tenants continue to own the property (as joint tenants), regardless of the will of the deceased or any intestate laws. All joint tenants will need to execute the instrument (preferably the same one) in order to convey the full interest. Execution of an instrument by less than all joint tenants will validly convey the interests of the individual interests who sign and likely sever his or her joint tenancy.

Tenants in Common. An interest in real property created in two or more owners is presumed to be a tenancy in common unless specific language or circumstances indicate otherwise. Although listed under the header “Individuals,” a business entity can also be a tenant in common. Each cotenant is generally free to convey and encumber his or her own interest without the consent of the other cotenants. Upon the death of a cotenant, title passes to the cotenant’s heirs or devisees as previously designated by will or through intestacy.

Life Tenant and Remainderman. A life estate is an estate in which the duration of interest is measured by the life of one or more persons. The measuring life is usually that of the life tenant, but can also be the life of another (pur autre vie). Although the life tenant has the right of possession, he or she cannot execute a lease or otherwise dispose of the property without being liable to the remainderman for waste. Therefore, unless otherwise provided in the instrument creating the life estate, both the life tenant and the remainderman must execute any instrument affecting the real property .

Limited Liability Companies. Typically, a manager(s) or, if there is not a manager, then any member, is the appropriate party to execute a contract.9 The state of organization’s laws may also determine who has the authority to execute a contract on behalf of the company.

Limited Partnerships. The general partner of the limited partnership is the appropriate party to execute a contract unless the authority is otherwise provided in the partnership agreement or state laws in which the partnership is organized.10

Mortgages and Deeds of Trust. Generally, a mortgagee is not required to join in the execution of a lease. However, it is recommended that the mortgage subordinate its interest to an oil and gas lease in order to protect the rights of the lessee in the event the mortgagor defaults on the mortgage. In the unusual case a mortgage or deed of trust specifically prohibits the mortgagor from performing certain acts (e.g., leasing for oil and gas), the mortgagee should remove the prohibition contemporaneously with the execution of the lease.

Perpetual or Term Royalty Interest. A royalty interest may be reserved or conveyed out of the mineral interest for a fixed or perpetual term. Typically, the mineral interest owner retains the executive rights, subject to the right of the royalty owner to participate in production. Generally, a royalty interest is owned separately from the mineral interest and the royalty owner signs only instruments relating to his or her royalty. However, the instrument creating the royalty interest should be carefully reviewed.

Proprietorships or DBA’s. A person may adopt a name in which the person acquires property and transacts business in his or her individual capacity. The sole proprietor has the sole authority to execute in behalf of such an entity. Any contract executed by a sole proprietor should recite the person’s name and also that the person is doing business as the adopted name.

Term Mineral Interest. A mineral interest may be reserved or conveyed for either a fixed term only or a fixed term and so long thereafter as minerals are produced in paying quantities. Similar to a life estate interest, a conveyance should be obtained from both the term interest owner and the reversionary interest owner. If a lease is granted by only the term interest owner, a ratification of the lease should also be obtained from the reversionary interest owner.

Trusts. An individual or entity (the trustee) may own legal title to a property for the benefit of another. Each state’s laws and the terms of the trust agreement will govern the trustee’s authority to execute any contract and any limitations on the trustee’s powers. At a minimum, the contract should describe the grantor or grantee trust by including the name of the trust, the date of the trust, and the name(s) of the trustee(s).

As stressed above, the governing state laws and the governing entity documents are critical in determining whether the appropriate party is executing the contract. Many unintended consequences may exist by failing to consult such laws and documents.

1Zions Gate R.V. Resort, LLC v. Oliphant, 362 P.3d 118 (Utah Ct. App. 2014).
2See also Landman’s Legal Handbook , Rocky Mt. Min. L. Found., 5th ed. 2013; Oil & Gas Law: Nationwide Comparison of Laws on Leasing, Exploration and Production, Am. Ass’n Prof. Landmen, 2011.
3See, e.g., Colo. Rev. Stat. § 38-30-123; Nev. Rev. Stat. § 111.450; N.D. Title Standard 2-11; N.M. Stat. Ann. § 47-1-7.
4See, e.g., Colo. Rev. Stat. § 38-30-144 (allowing the president, vice-president, or other head office of the corporation); Mont. Code Ann. § 70-21-203(1)(b) (allowing president, vice-president, secretary or assistant secretary or by any other person duly authorized by resolution).
5If the property is qualified as a homestead, both husband’s and wife’s signature is required. See N.D. Cent. Code § 47-18-05; Mont. Code Ann. § 70-32-301; Wyo. Stat. § 34-2-121. In New Mexico, if a spouse fails to join in the instrument, it is void and of no effect, unless ratified by the spouse in writing. Marquez v. Marquez, 513 P.2d 713 (N.M. 1973); Hannah v. Tennant, 589 P.2d 1035 (N.M. 1979).
6Alaska is an opt-in community property state; therefore, property is separate property unless both parties agree to make it community property through a community property agreement or a community property trust.
7Colorado, Montana, North Dakota, Oklahoma, South Dakota, Utah, and Wyoming are not community property states.
8See Cal. Civ. Code § 683; Utah Code Ann. § 57-1-5(3). Additionally, Utah statutes create a presumption in favor of a joint tenancy being created when the granting clause refers to a husband’s and wife’s marital status without further joint tenancy language. Utah Code Ann. § 57-1-5(1).
9See, e.g., Mont. Code Ann. § 35-8-301; N.M. Stat. Ann. § 53-19-30; Wyo. Stat. Ann § 17-29-407 (consent of all members required).
10See Mont. Code Ann. § 35-12-803, 806; N.M. Stat. Ann. § 54-2A-110; Nev. Rev. Stat. § 88.445; Wyo. Stat. Ann. § 17-14-503.

The Attorney-Client Privilege: A Primer for Landmen

Title Issues/Curative, , , ,

Your attorney has finally sent you a title opinion advising you that some of your leases may be dead. Management decides to drill anyway. It’s a gusher and the lessors sue. Can you prevent the title opinion from being given to the lessors’ attorneys? What if you previously gave a copy of the opinion to an independent contractor landman to work on curative for you? What if you gave it to other working interest owners in the drillsite? The attorney-client privilege may protect confidential information from disclosure in a lawsuit, but the privilege does not apply in all instances.1

The attorney-client privilege applies to confidential communications between attorneys and their clients, or their respective representatives, for the purpose of obtaining legal advice. If the privilege applies, it can protect such communications from mandatory disclosure in a lawsuit or other legal proceeding. The privilege may apply to oral or written communications. There is no “blanket” privilege for title opinions or any other type of attorney-client communication. Rather, whether the privilege applies to a communication is determined on a case-by-case basis.

The confidentiality of the communication is key. A confidential communication is one that the client reasonably expects will be kept confidential and that is not disclosed, or intended to be disclosed, to persons other than the attorney and client or their respective representatives. If a client discloses, or consents to the disclosure of, the communication to a third party, then the privilege may be lost. So, is the privilege lost when an operator gives a copy of a title opinion received from an attorney to participating working interest owners? There does not appear to be any case law addressing this situation, but it is possible that the operator’s disclosure of the title opinion to those third parties might be viewed as a waiver of the privilege, and the title opinion might be admitted as evidence in a lawsuit or other legal proceeding against the operator, such as in a lawsuit alleging a title defect that invalidates the operator’s oil and gas lease(s) and that was discussed in the title opinion.

Generally, if disclosure to a third party serves the interests of the client, or if the third party’s presence is necessary to accomplish the purposes of consulting the attorney, then disclosure to the third party might not waive the privilege. For example, if an operator’s independent contractor, such as an independent landman who is working for the operator, learns of or participates in a confidential communication between an attorney and the operator, the privileged status of the communication might not be in jeopardy if the independent contractor is the “functional equivalent” of an employee of the operator.

What happens when only part of a privileged communication (for example, a single comment and requirement of a title opinion) is disclosed to a third party? Is the privilege lost for the entire communication? Some courts view disclosure of a single communication as waiving the privilege for all communications regarding the “same subject matter.” In theory, a court could view the entire title opinion as one communication about a single subject matter—title to the subject lands—and require disclosure of the entire opinion. Other courts, however, take a more narrow approach and attempt to distinguish between what is privileged and what is not, finding that the privilege is lost only as to those portions of a communication that were disclosed to third parties. In short, if the privilege is lost for one comment and requirement, the privilege may still be intact as to a comment and requirement regarding a completely different subject matter, depending on the facts of the case and the court’s approach to the scope of the waiver.2

Not all types of communications are privileged. To be privileged, the communication must relate to legal advice. For example, if an attorney-client communication relates to business advice, as opposed to advice regarding an operator’s legal rights and obligations, then the privilege may not apply. In instances where the communication contains both legal and non-legal advice, then to the extent the non-legal advice can be separated from the legal advice, the privilege may not apply. Further, if an attorney has been hired to merely draft a document, such as a deed, as opposed to providing advice regarding a document’s legal effect, then the privilege may not apply and the attorney may be required to testify in a legal proceeding as to communications regarding the drafting of the document.

In sum, if you disclose a confidential communication or legal advice that is covered by the attorney-client privilege to a third party, then you may be required to disclose it again, but this time in a lawsuit or other legal proceeding. If you must share the confidential communication or legal advice to a third party, then you should only disclose those portions of the communication that absolutely must be disclosed in an effort to preserve the privilege for as much of the communication as possible.

1This article discusses certain aspects of the attorney-client privilege in general terms and is not intended to be a comprehensive analysis of the law of attorney-client privilege or the law of any particular jurisdiction. The reader should consult with competent legal counsel regarding the law that applies to any particular situation and jurisdiction.
2There are relatively few court cases that deal directly with title opinions and the attorney-client privilege. However, the Supreme Court of Colorado recently discussed the privilege in the context of title opinions and noted that if the parties cannot agree as to what title opinions, or portions of title opinions, are privileged, then the court can be requested to review the title opinions to determine what is privileged and what is not. See DCP Midstream, LP v. Anadarko Petroleum Corporation, 303 P.3d 1187, 1200 (Colo. 2013). Therefore, it appears that at least one court has recognized the possibility of having portions of a title opinion covered by the privilege, even if other portions are not