Oil and Gas Agreements

Can I Drill Through Unleased Federal Lands?

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

As horizontal wells and larger spacing units become the norm, the question often arises how to deal with an unleased federal tract in the proposed drilling unit.  Generally, you cannot drill through and produce from an unleased tract of land that is entirely or partially owned by the United States, but there are some options available. 

Can I include unleased federal lands in my drilling unit if I don’t penetrate that tract?

Yes, there is precedent where drilling units have been approved and operators have drilled horizontal wells that come close to the boundary of an unleased federal tract, but do not actually penetrate the unleased federal tract.  The BLM Manual and the BLM Handbook specifically provide that a communitization agreement (CA) can be approved with unleased federal lands if there is at least one other leased tract (federal, state, fee, or Indian), there is a well producing in paying quantities, and it would be a long delay (i.e., more than six months) in leasing the unleased federal lands (or presumably if the unleased federal lands are not available for lease).[1]

In regard to the well producing in paying quantities requirement, we note there is nothing in the federal statutes or regulations requiring a producing well.  We suspect this requirement exists to determine the well drainage and spacing unit for the lands.  If a drilling unit has already been established by the relevant state regulatory body, we do not believe a well producing in paying quantities should be required for approval of a CA with unleased federal lands.  The BLM Manual and Handbook also direct that any unleased federal lands should be leased as soon as possible.  Any lease subsequently issued will be subject to the successful bidder joining the CA or otherwise showing why joinder should not be required.[2]  

If the unleased federal lands are committed to a CA, an interest-bearing account is established and 8/8ths of all proceeds attributable to the unleased federal lands are to be placed  in the account.  Once the tract is leased, the suspended proceeds will be settled with the successful bidder.  In lieu of leasing an unleased federal tract, a compensatory royalty agreement (CRA) for small tracts of unleased lands may also be negotiated.[3]  The BLM has specific procedures in place for this situation, which require an unleased lands account to be established for any unleased lands.  The CRA must be executed by the United States and all adjoining interest owners in lands draining the unleased federal lands. The royalty rate will typically be the same as the rate for a competitive lease.

Unfortunately, there is no precedent that commitment of the unleased federal lands to a CA and/or CRA gives the operator the right to drill into and produce from the unleased federal lands.  There is a potential argument that the BLM’s approval of the CA commits the unleased federal lands to the CA and provides the operator of the CA with full access to all the communitized lands (including drilling on and through the unleased federal lands), but there is no guidance on this point. 

What if I drill through, but don’t produce from unleased federal lands?

Yes, it is possible to drill through unleased federal lands so long as they are not perforated or otherwise produced from.  This is because, when it comes to federal miners, there is a distinction between subsurface trespass (drilling through but not producing from unleased federal minerals) and mineral trespass (drilling through and producing from unleased federal minerals).  It should be noted that the penalties for mineral trespass against the United States can be quite severe.[4] 

Although there is a split in jurisdictions (and even inconsistency within certain jurisdictions) as to the ownership of the pore space after the severance of the surface and mineral estates, the BLM generally defers to the surface owner for approval to drill through (but not produce from) unleased federal lands.  The BLM will not typically assert any approval authority in this situation unless the federal minerals are at risk of harm or interference.[5]  However, a prudent operator may seek a subsurface access agreement from the BLM (even if it is not ultimately granted) to at least notify the BLM of the proposed operations in an effort to protect itself from the risk of subsurface trespass.  In some states, when an APD is filed, the state’s oil and gas commission will either send notice or require the operator to send notice to the BLM when federal lands are involved.

What if the tract is only partially unleased federal minerals?

Generally, whether or not federal or state law controls when dealing with federal minerals is a difficult question to answer.[6]  When the subject involves the disposition or development of federal minerals, state regulatory authorities generally have no jurisdiction or authority.[7]  Specifically, scholars believe that Congress has the ability to preempt conservation regulations under the Supremacy Clause or the Commerce Clause of the Constitution or state regulation of federal lands under the Property Clause of the Constitution.[8] 

As a result, it is not clear whether traditional remedies available for a co-tenant (e.g., compulsory pooling) apply to minerals owned in part by the United States.  On one hand, a private party attempted to force pool unleased federal minerals and a federal court found that compulsory pooling of federal lands could not be done without the Secretary’s consent, essentially requiring a communitization agreement.[9] On the other hand, courts have found that lands reacquired by the United States are subject to state law.[10]  

Furthermore, if the unleased federal minerals are committed to a CA, it would be difficult to argue that development of the unleased federal minerals is a mineral trespass because the Secretary consented to the pooling and development of the unleased federal minerals by approving the CA.  Unfortunately, we have not been able to identify a situation where an operator has attempted to develop a partially-owned unleased federal tract as a co-tenant. 

In the event an operator is actually successful at developing a tract with partially federal minerals, a CA will need to be approved and an interest-bearing account will be established as discussed above.

[1] BLM Manual 3160-9 Communitization, .1.11.H.;  BLM Handbook 3105-1 Cooperative Conservation Provisions, Section II.A. 

[2] It is uncertain whether the latter is actually possible due to the fact that a lease within a CA cannot be independently developed. 

[3] 43 C.F.R. § 3100.2-1.

[4] In assessing the penalty for mineral trespass of federal minerals, the BLM will first look to state law governing oil trespass to measure damages.  If the state where the trespass occurred has no law governing oil trespass, the BLM’s assessment of damages will depend on whether the trespass was “innocent” or “willful.”  For innocent trespass, BLM will measure damages based on the value of oil taken, less expenses of “taking” the oil (i.e., drilling costs).  For willful trespass, the BLM will measure damages based on the “[v]alue of the oil taken without credit or deduction for the expense incurred by the wrongdoers in getting it.”  The BLM’s trespass regulations do not address measurement of damages from gas trespass, but generally state that it will measure damages for “other trespass” based on the laws of the state in which the trespass occurred.  See, generally, Kathleen C. Schroder & William Lambert, “Permitting and Trespass Issues Associated with Horizontal Development on Federal Lands and Minerals,” 62 Rocky Mt. Min. L. Inst. 12-1 (2016).

[5] See U.S. Government Accountability Office, Oil and Gas: Updated Guidance, Increased Coordination, and Comprehensive Data Could Improve BLM’s Management and Oversight, GAO-14-234, Published May 5, 2014, Reissued May 16, 2014.

[6] In the astute words of Professor Bruce M. Kramer, “The rules are in flux, which makes it an exciting time for academics and a difficult time for those providing legal advice to oil and gas explorers and producers.”

[7] Kleppe v. New Mexico, 456 U.S. 529, 540 (1976); Kennedy & Mitchell, Inc. 68 IBLA 80, 83 (1982) (finding “Congress has preempted from the state regulation of communitization or drilling agreements affecting Federal oil and gas leases . . . [U]ntil [a] communitization agreement [is] approved . . . each Federal oil and gas lease . . . [has] to stand by itself”).

[8] Owen L. Anderson, “State Conservation Regulation – Single Well Spacing and Pooling – Vis-à-vis Federal and Indian Lands,” Federal Onshore Oil and Gas Pooling and Unitization, 2-12 (Rocky Mt. Min. L. Fdn. 2006).

[9] Kirkpatrick Oil & Gas Co. v. United States, 675 F.2d 1122, 1125 (10th Cir. 1982) (holding “no state-ordered forced pooling would bind the government without the Secretary’s consent”).  It appears that obtaining a CA may be the more practical approach because the BLM Manual instructs that, in this situation, the operator should submit a copy of the state order force pooling the interest with the CA and the CA will be approved if executed by the operator and complete in all other respects.

[10] See Mallon Oil Co., 104 IBLA 145, 150 (1988) (applying Montana law as to the ownership of the subsurface to find the United States owns both the surface and subsurface of acquired lands located in Montana.

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.

What Is the Difference Between Leasing BLM and Forest Service Lands?

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

Leasing on National Forest System lands requires coordination between the BLM and the Forest Service throughout the leasing process. The BLM and the Forest Service share the responsibility over oil and gas leasing on National Forest System lands.[1] The BLM issues the oil and gas leases on National Forest System lands with the consent of the Forest Service.[2] Generally, the Forest Service manages the surface of the lands, while the BLM manages the subsurface, and the agencies work together to develop the permitting conditions under their separate management authorities.[3]

How do I get an oil and gas lease and drill on National Forest Service lands?

Obtaining an oil and gas lease on National Forest Service lands requires the consideration of multiple applicable laws as well as coordination between the two federal agencies. First, the Forest Service must make a determination regarding which federal lands are available for leasing. Next, a prospective lessee must send an informal request to the BLM for a specific parcel to be offered for sale. Finally, if the Forest Service consents to the sale and the BLM determines that the parcel is available and suitable for leasing, the parcel is included by the BLM in a notice of competitive oil and gas lease sale in the same manner as parcels located outside a national forest.  Assuming that the parcel is sold at a competitive lease sale and the BLM issues the lease, the lessee must obtain an approved application for a drilling permit and surface use plan. Drilling can begin once the BLM and the Forest Service have issued the necessary approvals and permits.[4]

  1. The Forest Service’s Availability Decisions

The Forest Service makes availability decisions identifying minerals on National Forest System lands that are available for leasing. These decisions are made through an appropriate National Environmental Policy Act (“NEPA”) process in cooperation with the BLM.[5] The Forest Service must exclude from the analysis lands that have been withdrawn from mineral leasing, lands recommended for wilderness designation, and lands designated as wilderness study areas (unless oil and gas leasing has been specifically allowed).[6]

As part of the leasing analysis, the Forest Service identifies on maps those areas that will be either open to development under the conditions of standard oil and gas leases, open to development under lease stipulations (e.g., conditions of surface occupancy), or closed to leasing.[7] The Forest Service promptly notifies the BLM of its availability decision, who adopts the Forest Service’s leasing analysis and decision.[8]  In offering the parcel for sale, the BLM includes any lease stipulations that the Forest Service notified it were necessary, as well as any additional lease stipulations that the BLM, as manager of the subsurface, determined are necessary.

  1. Expression of Interest to the BLM

A prospective lessee will submit an expression of interest (“EOI”) to the BLM.  An EOI is an informal request that identifies land that the BLM should consider offering for oil and gas competitive lease sales.[9] The BLM must obtain the consent of the Forest Service to offer the specific lands for leasing, which will be subject to the NEPA document, the land and resource management plan, and the Forest Service’s conditions of surface occupancy.[10] The BLM will review the nominated lands to ensure that they are “available, eligible, and suitable for leasing,” and may also conduct an analysis “to identify conditions or restrictions on oil and gas activities to protect the environment” before offering the lands for sale.[11]

  1. Leasing and Development

In order to develop an oil and gas lease on National Forest System lands, a lessee must submit an Application for Permit to Drill (“APD”) to the BLM, who forwards all APDs, including the Surface Use Plan of Operations (“SUPOs”), and Notices of Staking (“NOSs”) to the Forest Service for approval.[12] Both the BLM and the Forest Service post a 30-day public notice of all APDs and NOSs.[13]

“All SUPOs are subject to a level of NEPA analysis and documentation, including public involvement . . . .”[14] In addition, the SUPOs must comply with all other applicable laws, including the Endangered Species Act, National Historic Preservation Act, and Clean Water Act.[15] After reviewing the SUPO, the Forest Service will notify the operator and the BLM of its decision either approving the SUPO, approving the SUPO with conditions, or disapproving the SUPO, and will provide public notice of the decision.[16] The BLM reviews the APD for potential subsurface impacts, and, after receiving the approved SUPO from the Forest Service, issues the final approved APD.[17] Once all approvals and permits have been received, drilling can begin.[18]

[1] Memorandum of Understanding Between United States Department of the Interior Bureau of Land Management and United States Department of Agriculture Forest Service, at 3 (eff. Apr. 14, 2006), https://www.fs.fed.us/geology/MOU_BLM_Oil_Gas.pdf (“MOU”).

[2] 30 U.S.C. § 226(h).

[3] MOU, at 3–5.

[4] U.S. Forest Serv., Stages of Oil & Gas Exploration and Development on National Forest System Lands, at 2 (Dec. 12, 2005), https://www.fs.fed.us/emc/nepa/oged/includes/stages_summary_final.pdf.

[5] 36 C.F.R. § 228.102(a)–(b); MOU, at 8.

[6] 36 C.F.R. § 228.102(b).

[7] Id. § 228.102(c).

[8] Id. § 228.102(d); MOU, at 9.

[9] U.S. Dep’t of the Interior, National Fluids Lease Sale System, https://nflss.blm.gov/importantinfo (last visited Apr. 25, 2018).

[10] 36 C.F.R. § 228.102(e).

[11] U.S. Dep’t of the Interior, National Fluids Lease Sale System.

[12] MOU, at 12.

[13] Id.; see 30 U.S.C. § 226(f).

[14] U.S. Forest Serv., Stages of Oil & Gas Exploration and Development on National Forest System Lands, at 1.

[15] Id.; see also 36 C.F.R. §§ 228.104(b)(1), 228.108.

[16] 36 C.F.R. § 107(b)(2).

[17] MOU, at 14–15; U.S. Forest Serv. Wayne National Forest Oil & Gas Leasing Process, https://www.fs.usda.gov/detail/custergallatin/landmanagement/resourcemanagement/?cid=fseprd516706 (last visited Apr. 25, 2018).

[18] U.S. Forest Serv., Stages of Oil & Gas Exploration and Development on National Forest System Lands, at 2.

What is a Federal Right-of-Way Lease for Oil and Gas?

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

As mentioned in the first article published in “The FAQs of Federal Oil and Gas Leases” series,[1] the oil and gas under certain federal rights-of-way can only be leased under the Right-of-Way Leasing Act. Unbeknownst to some lessees, their federal oil and gas lease[2] may not cover all the lands described in the lease if there is a right-of-way on the lands that was issued prior to the lease. Sometimes the federal oil and gas lease will specifically exclude the right-of-way lands, leaving the lessee wondering how to lease the excluded lands. The only way to lease the oil and gas under a right-of-way granted before the issuance of a federal oil and gas lease is pursuant to the Right-of-Way Leasing Act as discussed below.[3]

Background. The problem with whether or not a federal oil and gas lease covers the lands within a federal right-of-way stems from a series of decisions issued around the turn of the 20th century.[4] Certain rights-of-way acts were held to grant to the right-of-way owner a “limited fee,” rather than fee simple or mere easement. The right-of-way owner actually owns the right-of-way lands, subject to the ownership reverting back to the United States if the right-of-way owner quits using the land for the granted purposes.[5] Based on those decisions, the Department of Interior took the position that it did not have sufficient incidents of ownership in the lands upon which to issue federal oil and gas leases under the Mineral Leasing Act of 1920, but it did have sufficient incidents of ownership to prevent the leasing of such lands by the right-of-way owner.

As a result, Congress passed the Act of May 21, 1930 (the “1930 Act” or “Right-of-Way Leasing Act”),[6] providing that the Secretary of Interior is authorized to “lease deposits of oil and gas in or under lands embraced in railroad or other rights of way acquired under any law of the United States, whether the same be a base fee or mere easement; Provided, That, … no lease shall be executed hereunder except to the … [owner] by whom such right of way was acquired, or to the lawful successor, assignee, or transferee of such [owner]….[7] The original regulation implementing the 1930 Act contained the same broad language of the 1930 Act. However, in 1983, the Department of the Interior amended its regulations in an apparent attempt to limit the effect of the 1930 Act. Specifically, the relevant regulation states, and still provides, that the government will exercise its authority under the 1930 Act:

only with respect to railroad rights-of-way and easements issued pursuant either to the Act of March 3, 1875 (43 U.S.C. 934 et seq.), or pursuant to earlier railroad right-of-way statutes, and with respect to rights-of-way and easements issued pursuant to the Act of March 3, 1891 (43 U.S.C. 946 et seq.).[8] The oil and gas underlying any other right-of-way or easement is included within any oil and gas lease issued pursuant to the Act[9] which covers the lands within the right-of-way….[10]

In addition to limiting the effect of the 1930 Act, the 1983 amendments were issued to apparently confirm the Department of Interior’s understanding of the caselaw, i.e. the 1930 Act applied only to limited fee rights-of-way, and to apparently confirm its past practices. Notably, the amended regulation conflicts with the 1930 Act’s provision that it applies to “other rights of way acquired under any law of the United States, whether the same be a base fee or mere easement.” Regardless, we are not aware of any case in which the Bureau of Land Management (“BLM”) has issued a lease for a right-of-way other than those granted under the railroad acts or reservoir act identified in the regulation above.

How It Works. The owner of the right-of-way has the right to apply for an oil and gas lease or assign its right to apply for the lease to a third party. The owner, or its assignee, must file an application with the BLM along with the applicable fee. The standard Form 3100-11 Offer to Lease and Lease for Oil and Gas is used with adjustments made by BLM personnel for the necessary references to the 1930 Act and specific requirements of the Act. If the right-of-way owner has assigned its preferential right to lease, the application must include an executed copy of the assignment of the right. The application should detail: the facts of the ownership of the right-of-way and of the assignment, if applicable; the development of oil or gas in adjacent or nearby lands, including the location and depth of the wells, production, and probability of drainage of the oil and gas in the right-of-way; and a description of the right-of-way, including at least each legal subdivision through which a portion of the right-of-way is to be leased passes.

Once the BLM determines that leasing of the right-of-way lands is consistent with the public interest, either upon consideration of an application or on its own motion, it will serve notice on the owner or lessee of the oil and gas in the adjoining lands. Although the adjoining owners or lessees are not entitled to an oil and gas lease for the right-of-way lands, they do have the preferential right to submit a bid for a compensatory royalty they would agree to pay for producing the oil and gas beneath the right-of-way lands from a well drilled on the adjoining lands. The compensatory royalty would be paid to the United States in lieu of it issuing a lease to the right-of-way owner or its assignee. A compensatory royalty agreement is to be on a form approved by the Director. The owner of the right-of-way, or its assignee, is given the same period of time to submit its bid for the royalty interest rate is willing it pay if the lease is issued. The royalty cannot be for less than 12.5%.

If the adjoining owners submit compensatory royalty bids, the right-of-way lease or the compensatory royalty agreement shall be awarded to the offer that is most advantageous to the United States.  If a lease is awarded, the term shall not be more than 20 years.

Be Alert. When dealing with lands owned by the United States, landmen and title examiners should be on alert for the existence of any rights-of-way pre-dating a federal oil and gas lease and the possibility the right-of-way lands are unleased. Considering the BLM’s current practice of only issuing 1930 Act leases for railroad and reservoir rights-of-way as described in the above regulation, the federal oil and gas lessee is unable to fully secure a valid leasehold interest in lands under all other types of rights-of-way. Under those circumstances, the lessee should take action to protect itself against the conflict between the 1930 Act and its regulations, possible trespass claim, and a compensatory royalty bidding war.

[1] D. Hatch, “What are the Types of Federal Oil and Gas Leases?” The Oil & Gas Report, April 4, 2017.

[2] The vast majority of federal oil and gas leases are issued pursuant to the Mineral Leasing Act of February 25, 1920, as amended. For purposes of this article, reference to a “federal oil and gas lease” will mean a lease issued under the 1920 Mineral Leasing Act.

[3] If a right-of-way is granted after the issuance of a federal oil and gas lease, the federal oil and gas lease will cover the oil and gas under the right-of-way lands.

[4] See Northern Pac. Ry. v. Townsend, 190 U.S. 267, 271-72 (1903); Rio Grande Western Ry. Co. v. Stringham, 239 U.S. 44, 47 (1915); Windsor Reservoir & Canal Co. v. Miller, 51 I.D. 27, 34 (1925).

[5] Subsequent decisions have clarified that the property interest granted under such right-of-way statutes is an easement rather than a limited fee. See Great Northern Ry. Co. v. United States, 315 U.S. 262, 279 (1942); Solicitor Opinion, 67 Pub. Lands Dec. 225 (1960)

[6] 30 U.S.C. §§ 301 to 306.

[7] 30 U.S.C. § 301 (emphasis added).

[8] The Act of March 3, 1891, pertains to rights-of way for irrigation canals, ditches, and reservoirs (hereinafter referred to as the “reservoir rights-of-way”) .

[9] Typically, the Mineral Leasing Act of 1920.

[10] 43 CFR § 3109.1-1 (emphasis added).

Saving the Best for Last – What Is All That Stuff at the End of My Lease?

Fee Lease 101 Series, Lease Provisions, Oil and Gas Agreements, , , , , , ,

On this blog, we have posted our complete Fee Lease 101 Series covering many of the standard fee oil and gas lease provisions from the granting clause to the pooling clause. However, there is typically a group of clauses towards the end of the lease form that appear to be the left-over clauses. These clauses include the assignment clause, proportionate reduction clause, warranty clause, surrender or release clause, and preferential right to purchase or option clause. They can have important ramifications on the relationship of the lessor and lessee and status of the lease and, accordingly, are discussed below.

I.      Assignment Clause

The assignment clause governs how the lessor and lessee may assign their respective interests. It may contain a restraint on the lessee’s power to assign the lease in whole or in part without the lessor’s consent. It may also contain a restraint on the minimum acres or minimum interest that may be assigned, such as “no less than forty acres” or “no less than the lessee’s entire undivided interest.” This restraint on assigning/alienation by the lessee is generally allowed; however, it will be strictly construed.

To avoid a claim that the clause is an unreasonable restraint on alienation, contemporary leases typically authorize assignments by either the lessor or lessee, in whole or in part, but will often include conditions to the assignment. For instance, it may state that lessee will not recognize a change in the lessor’s ownership until it receives an original or authenticated copy of the assignment. It may allow a partial assignment by the lessor, but will require that the assignment cannot increase the lessee’s obligations under the lease, such as drilling offsetting wells, protection of drainage, requiring separate measuring, or installation of separate tanks.

Although often the intent of the assignor, it is important that the assignment clause provides that the lessor relieves the lessee of any further obligations concerning the interest assigned.1 The assignor does not want to assign the interest and thereafter be stuck with the royalty payments if the assignee fails to pay the lessor. If a partial assignment of the lessee’s interest is allowed, a provision should be included that deals with the apportionment of rentals and royalties.

The following example assignment clause addresses all of the above requirements:

Ownership Changes. The interest of either Lessor or Lessee hereunder may be assigned, devised or otherwise transferred in whole or in part, by area and/or by depth or zone, and the rights and obligations of the parties hereunder shall extend to their respective heirs, devisees, executors, administrators, successor and assigns. No change in Lessor’s ownership shall have the effect of reducing the rights or enlarging the obligations of Lessee hereunder, and no change in ownership shall be binding on Lessee until 60 days after Lessee has been furnished the original or duly authenticated copies of the documents establishing such change of ownership to the satisfaction of Lessee or until Lessor has satisfied the notification requirements contained in Lessee’s usual form of division order. In the event of death of any person entitled to rentals or shut-in royalties hereunder, Lessee may pay or tender such rentals or shut-in royalties to such persons or to their credit in the depository, either jointly, or separately in proportion to the interest which each owns. If Lessee transfers its interest hereunder in whole or in part Lessee shall be relieved of all obligations thereafter arising with respect to the transferred interest, and failure of the transferee to satisfy such obligations with respect to the transferred interest shall not affect the rights of Lessee with respect to any interest not so transferred. If Lessee transfers a full or undivided interest in all or any portion of the area covered by this lease, the obligation to pay or tender rentals and shut-in royalties hereunder shall be divided between Lessee and the transferee in proportion to the net acreage interest in this lease then held by each.2

II.       Proportionate Reduction3

The proportionate reduction clause is also referred to as the lesser interest clause. It provides for reduction of rentals and royalties owed to the lessor in the event the lessor owns less than the full mineral estate. A typical proportionate reduction clause will provide:

In case said Lessor owns a lesser interest in the above described land than the entire and undivided fee simple estate therein, then the rentals and royalties herein provided shall be paid to Lessor only in the proportion that his interest bears to the whole and undivided fee.

However, the above example does not differentiate between the proportionate reduction of rentals and proportionate reduction of royalties. It focuses on the entire leased lands. What is the result if the lease covers a 640-acre section, the lessor owns 100% of the mineral estate in the W/2 of the section, 50% of the mineral estate in the E/2 of the section, and the well is located on the E/2? The lessor’s proportionate interest is 75% [(100% x 320/640) + (50% x 320/640)]. The lessor would not only receive 75% of the rental, but also 75% of the royalty even though the well is located on the lands in which the lessor only owns a 50% mineral interest.

The following example makes a distinction between rentals and royalties:

If Lessor owns less than the full mineral estate in all or any part of the leased premises, payment of rentals, royalties, and shut-in royalties hereunder shall be reduced as follows: (a) rentals shall be reduced to the proportion that Lessor’s interest in the entire leased premises bears to the full mineral estate in the leased premises, calculated on a net acreage basis; and (b) royalties and shut-in royalties for any well on any part of the leased premises or lands pooled therewith shall be reduced to the proportion that Lessor’s interest in such part of the leased premises bears to the full mineral estate in such part of the leased premises.

III.       Warranty Clause4

The warranty clause provides a warranty of title by the lessor with respect to the interest described in the granting clause. Additionally, the warranty clause provides the basis for applying the doctrine of after-acquired title in the event the lessor acquires an interest in the leased premises after giving the lease. The following are two examples of warranty clauses:

    • Lessor hereby warrants and agrees to defend the title to the land herein described and agrees that the Lessee, at its option may pay and discharge in whole or in part any taxes, mortgages, or other liens existing, levied, or assessed on or against the above described lands, and in the event it exercises such option, it shall be subrogated to the rights of any holder or holders thereof and may reimburse itself by applying the discharge of any such mortgage, tax, or other liens, to any royalty or rental accruing hereunder.
    • Lessor hereby warrants and agrees to defend title conveyed to Lessee hereunder, and agrees that the Lessee at Lessee’s option may pay and discharge any taxes, mortgages or liens existing, levied or assessed on or against the leased premises. If Lessee exercises such option, Lessee shall be subrogated to the rights of the party to whom payment is made, and, in addition to its other rights, may reimburse itself out of any royalties or shut-in royalties otherwise payable to Lessor hereunder. In the event Lessee is made aware of any claim inconsistent with Lessor’s title, Lessee may suspend the payment of royalties and shut-in royalties hereunder, without interest, until Lessee has been furnished satisfactory evidence that such claim has been resolved.5

The second warranty clause above allows the lessee to suspend payments to the lessor without interest in the event of a title dispute. However, a lessee should never suspend rental payments even if there is a title dispute. Failure to pay rentals could be fatal if the suspension is later determined to be unjustified.

As set forth in the above examples, the warranty clause often will contain a subrogation provision pertaining to a superior lien existing prior to the execution of the lease. To protect the lessee from the lease being extinguished if the superior lien is foreclosed, the clause authorizes the lessee to satisfy any liens and be subrogated to the rights of the lienor. The clause may vary in the types of claims or obligations the lessee is authorized to satisfy, including mortgages, deeds of trusts, taxes, assessment, charges, and encumbrances. Additionally, the clause may address whether the lessee may satisfy the claim or obligation prior to maturity thereof; and whether the lessee is authorized to withhold payments to the lessor for rentals, royalties, or other sums in satisfaction of the claim to reimbursement.

The warranty clause must be read in relationship to the granting clause and proportionate reduction clause. If the lessor owns less than 100% of the mineral interest, a granting clause that only describes the lands, but not the interest, is technically a breach of the warranty clause, but the proportionate reduction clause acts to proportionately reduce the lessor’s interest and the rental and royalties owed. If the granting clause describes the lessor’s percentage mineral interest in the lands, there is no breach of warranty, but there may be confusion as to the applicability of the proportionate reduction clause – is the lessor entitled to 100% of the rentals and royalties, i.e. not further proportionately reduced.

Cases have held that the warranty in the lease does not warrant the title of the lessor, it actually warrants title to the lessee. The warranty clause can be used to make a claim for a breach of warranty if the mineral interest covered by the lease is subject to an interest carved out of the mineral estate. For example, if prior to execution of the lease, the lessor’s mineral interest is subject to a non-participating royalty interest, it could be argued that the warranty clause, in some cases, results in the lessor’s royalty interest being reduced by the amount of the non-participating royalty interest.6

Many lessors will strike out or delete the warranty clause. As discussed above, legitimate reasons exist for using this clause. If the lessor insists on deleting the warranty clause, the lessee should at least propose one of the options for protection: make it a special warranty (“by, through and under”); limit the damages for a breach of warranty to money paid for the bonus, rentals, and royalties; or have the lessor execute an indemnifying division order in the event of production attributable to the leased premises.7 However, even if stricken, some courts have held that a warranty of marketable title is implied by law by use of the words “grant” or “convey” in the granting clause.

IV.       Surrender or Release Clause8

The surrender or release clause was originally included in the “or” form lease to relieve the lessee of the obligations to either drill or pay rentals by allowing the lease to be surrendered back to the lessor. In contrast, the “unless” form lease permits a lessee to extinguish its obligations by merely failing to perform the obligation, i.e. lease will terminate unless rental is paid. However, a surrender clause is also useful in an “unless” form lease when the lessee desires to surrender only a portion of the lease. Following are two examples of a surrender clause:

      • Lessee may, at any time and from time to time, deliver to Lessor or file of record a written release of this lease as to a full or undivided interest in all or any portion of the area covered by this lease or any depths or zones thereunder, and shall thereupon be relieved of all obligations thereunder arising with respect to the interest so released. If Lessee releases less than all of the interest or area covered hereby, Lessee’s obligation to pay or tender rentals and shut-in royalties shall be proportionately reduced in accordance with the net acreage interest retained hereunder.
      • Lessee may at any time surrender or cancel this Lease in whole or in part by delivering or mailing such release to the Lessor, or by placing the release of record in the County where said land is situated. If this Lease is surrendered or cancelled as to only a portion of the acreage covered hereby, then all payments and liabilities thereafter accruing under the terms of this Lease as to the portion cancelled, shall cease and terminate, and any rentals thereafter paid may be apportioned on an acreage basis, but as to the portion of the acreage not released the terms and provisions of this Lease shall continue and remain in full force and effect for all purposes.

Of course, there are many variants of the surrender clause. As set forth in the above examples, a surrender clause may require that written notice be provided to the lessor and/or recording of the release. In some cases, the clause requires the notice be given at some particular date or after certain events have occurred (such as “after production is achieved”) or the surrender is not effective until some particular date after giving notice (such as “the surrender shall become effective 30 days after delivery of the release to Lessee”). The clause may also require a payment as a condition to the surrender.

As to partial surrenders, as provided in the examples above, if the lessee releases part of the lease, the lessee is relieved of all obligations concerning the released part, and rentals and shut-in royalties are proportionately reduced according to the amount of acreage released. However, some clauses specifically provide that certain obligations, including payment of rentals or royalties, will not be affected by a partial surrender. If a partial surrender is authorized, the size of the surrendered or retained lands may be addressed in the clause, i.e. “not less than ten (10) acres;” “contiguous;” or “any legal subdivisions thereof.” Including the phrases “at any time or times” or “may at any time, or from to time to time” clearly evidence that successive partial surrenders by the lessee are allowed. The lessee should include a provision that the partially surrendered lands shall remain subject to the easements and right-of-way provided in the lease for the lessee’s operations. Additionally, restrictions on the lessor’s or its subsequent lessee’s use of the surrendered land should be included stating that the lessor shall not interfere with the original lessee’s operations and requiring adequate set-backs from the exterior boundary of the lands retained or any well drilled by the original lessee.

V.       Preferential Rights to Purchase and Options10

To protect the lessee, particularly with the advent of the short primary terms contained in contemporary leases, preferential rights to purchase and options to extend the primary term or renew the lease have been added to the lease. The following is a preferential right to purchase a new lease clause:

If during the term of this lease (but not more than 20 years after the date hereof) Lessor receives a bona fide offer from any party to purchase a new lease covering all or any part of the lands or substances covered hereby, and if Lessor is willing to accept such offer, then Lessor shall promptly notify Lessee in writing of the name and address of the offeror, and of all pertinent terms and conditions of the offer, including any lease bonus offered. Lessee shall have a period of 30 days after receipt of such notice to exercise a preferential right to purchase a new lease from Lessor in accordance with the terms and conditions of the offer, by giving Lessor written notice of such exercise. Promptly thereafter, Lessee shall furnish to Lessor the new lease for execution, along with a time draft for the lease bonus conditioned upon execution and delivery of the lease by Lessor and approval of the title by Lessee, all in accordance with the terms of said draft. Whether or not Lessee exercises its preferential right hereunder, then as long as this lease remains in effect any new lease from Lessor shall be subordinate to this lease and shall not be construed as replacing or adding to Lessee’s obligations hereunder.11

The twenty year limitation is to avoid a violation of the rule against perpetuities in some states. This provision provides that the new lease is subordinate to the old lease to avoid any question about the status of the new lease while the old lease is still in effect.

An option to extend the primary term may provide for the lease to be extended for a specified period of time upon payment of a specified consideration. For instance, the following is an option to extend the primary term:

Lessee is hereby given the option to extend the primary term of this lease for an additional Two (2) year(s) from the expiration of the original primary term hereof. This option may be exercised by Lessee at any time during the original primary term by paying the sum of One Hundred and 00/100 Dollars ($100.00) per net mineral acre to Lessor or the credit of Lessor mailed to Lessor at the above address. This payment shall be based upon the number of net mineral acres then covered by this lease and not at such time being maintained by the other provisions hereof. If, at the time this payment is made, various parties are entitled to specific amounts according to Lessee’s records, this payment may be divided between said parties and paid in the same proportion. Should this option be exercised as herein provided, it shall be considered for all purposes as though this lease originally provided for a primary term of Five (5) years.

A lease may also contain an option to renew the lease. Courts have differed on whether there is a distinction between “renew” or “extend.” In an Ohio decision, the court held that the clause “Lessor grants Lessee an option to extend or renew under similar terms a like lease” provided the lessee with two options: (1) to extend the lease on the same terms as the existing lease; or (2) to renegotiate for a renewal “like lease” on similar terms. The court reasoned that the terms “renew” and “extend” are distinct terms.12

In our Fee Lease 101 Series, we have covered most of the standard fee oil and gas lease clauses. As discussed above, these “left-over” provisions can affect the lessor’s and lessee’s, and their successor and assigns, rights, interests, and obligations and the status of the lease. A caveat for this article, and all our Fee Lease 101 Series articles, in interpreting any lease provision, care must be used in examining the specific language of the provision and the case law of the jurisdiction must be understood and applied. In order to avoid unintended consequences, the same caveat applies to drafting any lease provision.

1 See Pennaco Energy v. KD Co. LLC, 2015 WY 152, ¶ 19 (2015) (Finding, “Among the covenants [obligations] the original lessee-assignor retains after assignment of its interest are those requirement payments of rentals and/or royalties and restoration of the surface to its original condition once production activities have ceased.”).
2 Thomas W. Lynch, The “Perfect” Oil and Gas Lease (An Oxymoron), 40 Rocky Mtn. Min. L. Inst. 3-1, § 3.10 (1994).
3 See, generally, id. § 3.09.
4 See, generally, 4-6 Williams & Meyers, Oil and Gas Law § 685.1.
5 See, generally, Lynch at fn. 3, § 3.15.
6 Id.
7 Milam Randolph Pharo & Gregory R. Danielson, The Perfect Oil and Gas Lease: Why Bother!, 50 Rocky Mtn. Min. L. Inst. 19-29 (2004).
8 See, generally, 4-6 Williams & Meyers, Oil and Gas Law § 680.
9 The use of the terms “surrender” or “release” are used interchangeably to describe this clause. For purposes of this article, we will use the term “surrender”.
10 See, generally, 4-6 Williams & Meyers, Oil and Gas Law § 697.6.
11 See, generally, Lynch at fn. 3, § 3.17.
12 Kenney v. Chesapeake Appalachia, 2015 Ohio 1278 (Ohio Ct. App. 2015); Eastman v. Chesapeake Appalachia, 754 F.3d 356 (6th Cir. 2014).

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

Due Diligence, Fee Lease 101 Series, Lease Provisions, Oil and Gas Agreements, Title Issues/Curative, , , , , , , , ,

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.

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.

Recording JOAs In the Face of Looming Bankruptcies: Better Now Than Never

Bankruptcy, Oil and Gas Agreements, ,

While the oil and gas industry has experienced a significant downturn as a result of the collapse of global and regional oil prices, it wasn’t so long ago that times were booming and wells were being drilled at a rapid pace. During the recent boom years, everyone in the industry was scrambling to keep ahead of the curve, and some tasks previously viewed as routine fell to the way side. One action item that has been increasingly overlooked in recent years is the recording of a joint operating agreement, or a memorandum thereof (generally herein, including the recording of a memorandum applicable, a “JOA”) to provide notice of the operator’s lien rights. Considering the current downturn, the failure to record a JOA could come back to bite operators as defaults and bankruptcies appear to be looming for many players in the industry. As an operator, there still may be time to repent and record those agreements in order to protect your rights and interests.

The most current 1989 A.A.P.L Model Form of Operating Agreement, and most other commonly used agreements for joint operations, contains provisions whereby each party to the JOA grants a lien upon any interest it owns or acquires in real or personal property in the contract area covered by the agreement to secure such party’s obligations under the JOA.1 The form JOA contains provisions allowing for the recording of a memorandum (or “recording supplement”) of the JOA, or the agreement itself, which is acceptable in most states, to perfect the liens granted in the agreement.

It is generally well known that recording the JOA acts to perfect the operator’s lien of record as to competing lienholders. For example, if a JOA is recorded and there is later recorded a judgment lien against a non-operator, the operator’s lien would be superior to the claims of the later judgment creditor. As the current industry slowdown continues, and the risks of bankruptcies of non-operators looms, what is the impact of the failure to record a JOA upon the filing of Chapter 11 bankruptcy by the non-operator?

Upon filing for bankruptcy under Chapter 11 of the bankruptcy code, the appointed bankruptcy trustee of the debtor has the authority to either accept or reject “executory contracts.” 11 U.S.C. 365. An executory contract is a contract wherein there are ongoing or unperformed obligations on both sides. It is generally held and expected that JOAs will most likely be deemed executory contracts under the bankruptcy code. If a bankruptcy trustee accepts an executory contract, that will mean that the debtor, as an ongoing concern, will cure past defaults under the contract, compensate for default damages or losses, and give assurances for future performance. However, a bankrupt debtor that is a non-operator under a JOA will often have an incentive to reject a JOA as an executory contract. If a JOA is rejected, then ongoing rights and obligations of operators and non-operators, including the non-operator debtor, will likely be governed by common law tenants-in-common principles. If a bankruptcy trustee rejects an executory contract, then that is treated as a breach of the contract and the creditor party to the executory contract is granted damages resulting from the default under the rejected contract. Whether a JOA is recorded or not will not impact whether a JOA is an executory contract, but it will impact whether or not the damages granted to the operator under the rejected JOA will be secured or unsecured. If a JOA was never recorded, then the operator will be deemed an unsecured creditor and join the pool of other unsecured creditors (which creditors will either not get paid at all or may get pennies on the dollar for outstanding debts). But if the JOA was properly placed of record to perfect lien rights, then the damages afforded to the operator upon rejection of the JOA as an executory contract will give the operator a secured lien.

Of course, just because a recorded JOA perfects an operator’s lien, that does not mean it is necessarily first in time and has a superior lien position. For example, a non-operator may have granted a prior recorded mortgage or deed of trust for the benefit of a bank, which first-recorded lien could trump a later-recorded JOA (or memorandum thereof). Ideally, operators should obtain subordinations to the JOA from holders of outstanding mortgages or deeds of trust (much like operators do for important oil and gas leases or surface use agreements), but in practice this rarely occurs. But certainly recording the JOA will perfect the operator’s lien as to subsequently recorded liens (and remove the operator from the general unsecured creditor pool in bankruptcy).

The question facing land departments now is: what if we didn’t record a JOA at the time of execution – is it too late? The answer, as most other answers offered by attorneys, is: it depends. Within 90 days of filing for bankruptcy, any payments made for prior debts by a debtor in bankruptcy to certain creditors, but not others, can be held to be preferential transfers under the bankruptcy code. A preferential transfer is most typically a payment made to and for the benefit of one creditor, to the detriment of other creditors, within 90 days of the bankruptcy filing. A Texas bankruptcy court has held that recording a JOA within 90 days prior to the bankruptcy filing was a preference that benefited a single creditor to the detriment of other creditors and was thus invalid.2 You cannot forecast if and when a non-operator will file for bankruptcy. But one thing is certain – it doesn’t hurt to record the JOA. If you record and a non-operator does file for bankruptcy within 90 days, the recording may be invalidated. But if the non-operator files for bankruptcy on the 91st day, you may have been fortunate enough to perfect your operator’s lien. Also, while you may have lost lien priority during any delay in failing to promptly record the JOA, you might still have time to perfect your lien as to other subsequent lien claimants down the road (and you may still have time to secure a first-position lien). Being a second position lienholder on oil and gas assets under a JOA behind the first lien of, for example, a non-operator/debtor’s bank, will still grant you certain advantages in terms of negotiating an acquisition of those assets or preserving some rights to proceeds (certainly over and above the rights of unsecured creditors).

So in the face of potential loan defaults, judgment liens, bankruptcies, and all the other unfortunate events that result from oil and gas downturn cycles, operators should act soon to record JOAs. Obviously, priority should be given to agreements where there are sizeable and mounting debts by certain non-operators. While there may be findings down the road that the late recording of a JOA fails to perfect lien rights, there are no good reasons not to simply record JOAs today.

1See Article VII.B of 1989 Model Form Operating Agreement.
2See In Re Wilson, 69 B.R. 960 (Bankr. N.D. Tex. 1987).