oil and gas

When Do I Need to Obtain a Lease Bond to Operate on a Federal Oil and Gas Lease?

FAQs of Federal Oil and Gas Leases, , , ,

By Angela Franklin and Andy LeMieux

Pursuant to the Federal Onshore Oil and Gas Leasing Reform Act of 1987 (“1987 Reform Act”), when operating on federal lands, an adequate bond (or other financial assurance) must be posted (1) before commencement of any surface disturbing activities related to drilling to ensure reclamation of lands and waters adversely affected by oil and gas operations (“lease bonds”); (2) before entry and commencement of geophysical exploration or surface-disturbing operations and for parties other than lessees before conducting geophysical exploration operations; and (3) before any surface disturbing activities for surface protection.[1] This article focuses on lease bonds.

Lease Bonds Generally

A lease bond in an amount not less than $10,000 for each federal oil and gas lease is required before commencement of any surface disturbing activities related to drilling operations on the lease. The bond is to ensure complete and timely plugging of the well(s), reclamation of the lands, and restoration and reclamation of the lands and surface waters adversely affected by oil and gas operations after abandonment or cessation of oil and gas operations on the lease(s).[2] Although the triggering event, “commencement of drilling operations,” is not defined in the regulations, in practice, the approval an Application for Permit to Drill (“APD”) by the Bureau of Land Management (“BLM”) requires evidence of bond coverage.[3]

The bond may be posted by the lessee (record title owner), sublessee (operating rights owner), operator, or unit operator (if applicable).[4] An “operator” includes anyone who has assumed responsibility, in writing to the BLM, for operations conducted under a lease.[5] The operator on the ground must have a bond in its own name as principal or be covered by a bond in the name of the lessee or sublessee, but this latter option requires the consent of the surety or obligor on the bond.[6] A lease bond can be a surety bond[7] or pledge backed by cash, negotiable securities, a certificate of deposit, or a letter of credit.[8] If at least two principals have interests in different formations or portions of a lease, either separate bonds can be posted or lease operations may be covered by one bond.[9]

Rather than a lease bond for an individual federal oil and gas lease(s), most operators post a nationwide bond in an amount not less than $150,000 or statewide bond in an amount not less than $25,000 covering all their operations on federal oil and gas leases in the United States or a particular state.[10] Lease and statewide bonds and riders should be filed in the BLM State Office for the lands using Form 3000-4 (June 1988) Oil and Gas or Geothermal Lease Bond (“Form 3000-4 Lease Bond”).[11] Nationwide bonds may be filed in any BLM State Office.[12]

Assignments and Bonding Requirements

An assignee[13] of a record title or operating rights interest in a lease must certify compliance with 43 CFR Subpart 3102 regarding qualifications to own an interest in a federal oil and gas lease and post any required bond.[14] If the assignor has a lease bond and bond coverage is required, the assignee must either post a new lease bond in the assignee’s name or the consent of the surety or obligor under the existing bond to become a co-principal on such bond if the assignor’s bond does not already include such consent.[15] If the assignor remains a record title owner, the assignor remains responsible for all lease obligations, including bonding requirements.[16] If bond coverage is necessary for approval of the assignment and the assignee has a statewide or nationwide bond, no additional bond is needed but the BLM may increase the amount of the bond.

Several conditions appear in the Form 3000-4 Lease Bond. For example, Condition 2 provides a way for the BLM to increase the scope of the bond to cover subsequently acquired leases,[17] interests, and activities of the principal as operator. Conditions 3 and 4 provide for continuing coverage of the bond notwithstanding an assignment of an undivided interest, in which event the assignee is considered a co-principal on an individual bond, or assignment of all the interest in some of the leased lands, in which event the bond remains in effect as to those lands retained by the assignor.

Until approval by the BLM of an assignment, the assignor and its surety are responsible for performance under the lease and are liable for all lease obligations.[18] Even after the BLM approves an assignment, the assignor remains responsible for lease obligations accruing before the approval date of the assignment, whether or not those obligations were identified before the assignment date. Those obligations include, but are not limited to, responsibility for plugging wells and abandoning facilities that the assignor drilled, installed, or used before the effective date of the assignment. In cases where the assignor is not the operator, bond coverage may be maintained by the operator.

As to any bonds maintained by the operator and a successor operator is appointed, the new operator is required to provide a replacement bond in its own name or provide evidence that the surety under the existing bond has consented to the new operator’s becoming a co-principal with the prior operator under that bond.[19] Each operator is liable to the full extent of the leasehold.[20] Condition 6 of the Form 3000-4 Lease Bond further addresses the operator’s liability for those obligations.

Bond coverage is not required for producing leases that do not contain a well but are merely receiving allocated production.

Unit Operator’s Bonds

A unit operator[21] may, but is not required to, furnish a unit operator’s bond for operations on all federal oil and gas leases that have been committed to a unit agreement. The unit operator’s bond is in place of, not in addition to, individual lease, statewide or nationwide bonds. The BLM determines the amount of a unit operator’s bond on a case-by-case basis. If the unit operator already has a statewide or nationwide bond, coverage for the unit may be provided by a rider to that bond.[22] The rider must specifically cover the unit and the BLM may increase the amount of the bond. When the unit terminates, or a non-unit well is drilled (i.e. a well not capable of producing unitized substances in paying quantities), a lease bond must be obtained.

Conclusion

The bottom line is any drilling operations or producing wells on a federal oil and gas lease must be covered by a bond posted with the BLM. However, the principal may be the lessee record title owner, sublessee operating rights owner, or the operator, or a combination depending on the ownership in the lease and the operator of the drilling and production operations.

[1] Prior to the 1987 Reform Act, competitive leases required a bond at time of issuance and noncompetitive leases required a bond upon classification as being within a known geologic structure or prior to entry.

[2] 43 CFR § 3104.1.

[3] See Rocky Mountain Mineral Law Foundation, Law of Federal Oil and Gas Leases, § 17.03.

[4] 43 CFR §§ 3104.2, 3104.4.

[5] Id. § 3100.0-5.

[6] Id. § 3104.2; Law of Federal Oil and Gas Leases, § 17.03.

[7] A list of sureties approved by the federal government is available at https://www.fiscal.treasury.gov/fsreports/ref/suretyBnd/c570_a-z.htm.

[8] 43 CFR § 3104.1.

[9] Id. § 3104.2.

[10] Id. § 3104.3

[11] This form is currently available at https://www.blm.gov/services/electronic-forms in the category “Fluid and Solid Minerals, Mining Claims.”

[12] 43 CFR § 3104.6.

[13] In this article, the terms “assignor,” “assignee,” and “assignment” include “transferor,” “transferee,” and “transfer.”

[14] 43 CFR § 3106.2.

[15] Id. § 3106.6-1.

[16] See Western States International, Inc., 187 IBLA 365 (2016).

[17] Except as to individual lease bond.

[18] Id. § 3106.7-2.

[19] 43 CFR § 3106.6-1.

[20] Law of Federal Oil and Gas Leases, § 17.03.

[21] “Unit operator” is defined as the person authorized under a unit agreement approved by the BLM to conduct operations on unitized lands as specified in the unit agreement. 43 CFR 3100.0-5(b).

[22] 43 CFR § 3104.4.

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.

How Do I Access the Lands Under a Federal Oil and Gas Lease?

FAQs of Federal Oil and Gas Leases, Federal Lands, Lease Provisions, Oil and Gas Regulations, , , , , , , ,

At the end of Disney/Pixar’s “Finding Nemo,” a group of fish escape from their tank by jumping into plastic bags that are filled with water and then securely tied at the top. After hopping out of a window, they cross a busy street and land safely in the waters of Sydney Harbour. Still in a plastic bag and bobbing up and down on the water, one of the fish asks an important question: “Now what?” The whole point of escaping was to obtain freedom from captivity. Similarly, the whole point of obtaining a federal oil and gas lease is to produce the natural resources on which our nation relies. To do so, however, requires obtaining the necessary surface use authorizations, which can be complicated.

Lease Rights

The current form of federal oil and gas lease[1] grants to the lessee “the exclusive right to drill for, mine, extract, remove and dispose of all the oil and gas (except helium) [in the leased lands] together with the right to build and maintain necessary improvements . . . .”[2] Those rights, however, are “subject to applicable laws, the terms, conditions, and attached stipulations of [the] lease, the Secretary of the Interior’s regulations and formal orders in effect as of lease issuance, and to regulations and formal orders [promulgated after lease issuance] when not inconsistent with lease rights granted or specific provisions of [the] lease.”[3] That’s where things get complicated.

As mentioned, federal oil and gas leases are subject to “applicable laws.” Generally, this means federal laws, such as the National Environmental Policy Act (NEPA)[4] and Endangered Species Act,[5] which can significantly impact a lessee’s ability to access federal oil and gas. There are several other laws that may apply to the extraction of federal oil and gas, including state laws and local ordinances, and operators should consult with competent legal counsel when evaluating their compliance with all applicable laws.

Compliance must also be made with the terms and conditions of the lease. The current form of lease and current regulations, for example, require a bond for lease operations. This requirement can be satisfied by obtaining a lease bond (at least $10,000), a statewide bond (at least $25,000), or a nationwide bond (at least $150,000). An operator may apply for partial release of a lease bond as reclamation operations are completed. Partial release is not available for statewide or nationwide bonds.

Another example of lease terms and conditions is the “conduct of operations” section of the current lease form. This section requires the lessee to “conduct operations in a manner that minimizes adverse impacts to the land, air, and water, to cultural, biological, visual, and other resources, and to other land uses or users.” These requirements can express themselves in many ways. The BLM (and FS) have published generally applicable standards and guidelines for operators engaged in the production of federal oil and gas, commonly known as “The Gold Book,” which provides an indication of how the BLM may require operations to be conducted.[6]

As noted, a federal oil and gas lease is also subject to any attached stipulations. The specific stipulations will depend on the characteristics of the leased lands. By way of example, those stipulations may include, but are certainly not limited to, restrictions on operations due to (1) threatened, endangered, and special status species; (2) animal breeding or nesting sites; (3) protection of cultural resources; (4) congressionally designated historic trails; and (5) avoidance of conflicts due to multiple mineral development. The restrictions may sometimes be seasonal or only applicable during a certain time of day. It is important to carefully review all of the stipulations attached to your lease to ensure that your proposed operations can comply with them.

The Secretary of the Interior has also published regulations, formal orders, and “Notices to Lessees” that govern access to federal oil and gas. Many of the relevant regulations can be found in 43 CFR Part 3160, et seq. There are currently seven “Onshore Oil and Gas Orders” that govern federal oil and gas operations, including Onshore Order No. 1 (approval of operations); Onshore Order No. 2 (drilling); and Onshore Order No. 3 (site security). There are currently two National Notices to Lessees (NTLs) promulgated by the BLM, which govern the reporting of undesirable events and royalty or compensation for oil and gas lost, as well as one Utah-specific NTL regarding the standards for use of electronic flow computers in gas measurement.[7]

The surface access rights granted under a federal oil and gas lease only apply to operations on the leased lands or lands that are unitized therewith and are authorized as part of an Application for Permit to Drill (APD), as discussed below. For operations outside of the leased lands or unit, a right-of-way, permit, or other authorization will need to be obtained from the federal government, the state government, or private surface owner(s), as applicable.

Permitting and Approval of Lease Operations

The earlier you can start the process of gaining access to federal oil and gas, the better. Early coordination with the BLM during the planning stages can help bring to light site-specific issues and local requirements, which generally leads to a more efficient permit approval process. In addition to a BLM-approved APD, an operator will need to obtain any approvals required by other federal, Tribal, state, or local authorities, which can also take some time.

There are additional considerations that apply in split-estate situations (non-federal surface over federal oil and gas). When split-estate is involved, an operator must make a good faith effort to notify the surface owner before entering the land to conduct surveys or stake a well location. An operator is also required to make a good-faith effort to negotiate a surface use agreement (SUA) with the surface owner. If negotiations are not successful, then a separate bond will be required as part of APD approval. The bond must be at least $1,000 and is designed to compensate the surface owner for reasonable and foreseeable loss of crops and damage to improvements. If the surface owner objects to the amount of the bond, then the BLM will review and either confirm the previously established bond amount or set a new amount.

Geophysical operations involving federal oil and gas are considered lease operations that may be performed on a federal lease after filing a Sundry Notice[8] or Notice of Intent and Authorization to Conduct Oil and Gas Geophysical Exploration Operations (Notice of Intent)[9] with the BLM. The party filing the Notice of Intent will need to be bonded. The BLM may require cultural resource or threatened/endangered species surveys for geophysical operations that will involve surface disturbance. BLM approval is not necessary for geophysical operations involving federal oil and gas under fee or state surface. In that case, an operator must work with the fee surface owner or relevant state agency to obtain access to the lands.

Surveying and staking can take place before approval of an APD, but APD approval is required before drilling and any related surface-disturbing operations. To apply for a permit to drill, an operator has two options: (1) file a Notice of Staking (NOS), followed by an APD; or (2) file an APD only. An NOS is a formal request for an onsite inspection[10] prior to filing an APD and it initiates the 30-day posting period that the BLM is required to follow before approving an APD. Filing an NOS can be particularly useful if the operator anticipates concerns that will eventually need to be addressed in an APD. The BLM has published a sample form of NOS,[11] but no specific form is required.

A completed APD package includes (1) APD Form 3160-3;[12] (2) a well plat certified by a registered surveyor; (3) a Drilling Plan; (4) a Surface Use Plan of Operations (including a reclamation plan);[13] (5) evidence of bond coverage; (6) operator certification in accordance with the requirements of Onshore Order No. 1; and (7) any other information required by order, notice, or regulation. An operator may file a Master Development Plan for multiple wells within a single Drilling Plan and Surface Use Plan of Operations, but an APD and survey plat still have to be submitted for each individual well. Changes to plans reflected in an APD must be submitted for BLM approval by filing a Sundry Notice. After the well is completed, a Well Completion Report[14] must be filed. As of March 13, 2017, all of these filings must be done through the BLM’s electronic filing system.

The BLM is charged with the responsibility of ensuring compliance with NEPA. When evaluating an APD, the BLM will conduct an Environmental Assessment (EA), if one has not already been done, and issue a decision in that regard. Issues raised by an EA may prompt a more-comprehensive Environmental Impact Study, delay approval of an APD, or result in stipulations or conditions of approval in addition to those that are attached to the lease.

Before approving an APD, the BLM will also conduct an onsite inspection (whether initiated as part of an NOS or APD) to identify site-specific issues and requirements. The BLM will notify the operator if any cultural resource studies or threatened or endangered species studies will be required. The operator, any parties associated with the planning of a drilling project (such as the operator’s dirtwork contractor or drilling contractor), and the fee surface owner, if any, will be invited to attend the onsite inspection.

If an operator desires to request a variance from the requirements of an onshore order, or an exception, waiver, or modification of a stipulation attached to a lease, then a request may be filed with the BLM, explaining the basis for the variance and how the intent of the onshore order will be satisfied, or the reason(s) why the stipulation is no longer justified.

[1] For purposes of this article, “federal” refers to federal government lands administered exclusively by the Bureau of Land Management (the “BLM”), as opposed to the United States Department of Agriculture, Forest Service (the “FS”), other surface management agencies, or the Bureau of Indian Affairs (the “BIA”). While the BLM works with the BIA, FS, and other surface management agencies in administering the lands within their stewardship, the nuances relating to the lands of those other agencies are not addressed in this article.
[2] Form 3100-11, Offer to Lease and Lease for Oil and Gas, available at https://www.blm.gov/sites/blm.gov/files/uploads/Services_National-Operations-Center_Eforms_Fluid-and-Solid-Minerals_3100-011.pdf.
[3] Id.
[4] See 42 U.S.C. § 4321, et seq.
[5] See 16 U.S.C. § 1531, et seq.
[6] See, e.g., Surface Operating Standards and Guidelines for Oil and Gas Exploration and Development, United States Department of the Interior and United States Department of Agriculture, 2007, p. 41 (regarding painting of facilities), available at https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/operations-and-production/the-gold-book (The Gold Book).
[7] Links to the regulations, onshore orders, and NTLs are available at blm.gov.
[8] Form 3160-5, available at https://www.blm.gov/sites/blm.gov/files/uploads/Services_National-Operations-Center_Eforms_Fluid-and-Solid-Minerals_3160-005.pdf.
[9] Form 3150-4, available at https://www.blm.gov/sites/blm.gov/files/uploads/Services_National-Operations-Center_Eforms_Fluid-and-Solid-Minerals_3150-004.pdf.
[10] The BLM has 10 days to schedule an onsite inspection after receiving an NOS or APD, but there is no deadline for when the inspection itself must to take place.
[11] See The Gold Book, p. 61.
[12] Available at https://www.blm.gov/sites/blm.gov/files/uploads/Services_National-Operations-Center_Eforms_Fluid-and-Solid-Minerals_3160-003.pdf.
[13] In a split-estate situation, an operator must make a good-faith effort to provide the surface owner with copies of (1) the Surface Use Plan of Operations; (2) the approved APD with its conditions of approval; and (3) any proposals involving new surface disturbance.
[14] Form 3160-4, available at https://www.blm.gov/sites/blm.gov/files/3160-004.pdf.

What Are the Types of Federal Oil and Gas Leases?

FAQs of Federal Oil and Gas Leases, Federal Lands, Lease Provisions, , , , , , , ,

An Introduction to Federal Oil and Gas Leasing

The federal government is responsible for oil and gas leasing under three different types of land: onshore public lands, offshore public lands, and tribal lands.  For purposes of this series, we will focus on onshore public lands and, more specifically, those under the jurisdiction of the Bureau of Land Management (“BLM”).  Below is a brief history of federal oil and gas leasing, a summary of the most common types of oil and gas leases administered by the BLM (renewal / exchange leases, public domain leases, and right-of-way leases), and a basic outline of the federal oil and gas leasing process today.

History of federal leasing.  Prior to the Mineral Leasing Act of 1920 (“MLA”), the development of oil and gas on public lands was done by making a placer location under the General Mining Act of 1872.  Since the MLA was passed, oil and gas on public lands has been developed by leasing.  Specifically, the MLA originally authorized the issuance of competitive leases for lands within a known geologic structure (“KGS”) of a producing oil or gas field and prospecting permits for lands not within a KGS, until the Act of August 21, 1935, which replaced prospecting permits with non-competitive leases.  Although the MLA was amended numerous times, the basic framework remained the same from 1935 to 1987, when the Federal Onshore Oil and Gas Leasing Reform Act (“FOOGLRA”) was passed.  In addition to the numerous amendments to the MLA and FOOGLRA, Congress also passed additional laws affecting oil and gas development, including the Multiple Mineral Development Act of 1954, the National Environmental Policy Act of 1969, the Federal Land Policy and Management Act of 1976, the Federal Oil and Gas Royalty Management Act of 1982, and the Energy Policy Act of 1992.

Renewal and exchange leases.  Renewal and exchange leases are generally found only in very old oil and gas fields.  As discussed above, under the original MLA, the BLM issued oil and gas prospecting permits for lands not within a KGS.  Upon a valuable discovery of oil or gas, the permittee became entitled to obtain a lease on the greater of 160 acres or 1/4th of the permit area and a preferential right to lease the remainder of the permit area.  Under the MLA, such earned leases, as well as competitive leases issued before 1935, had 20-year fixed terms with no Habendum clause (i.e., no “and so long thereafter” language), but the lessee had a preferential right to a “renewal lease” for a fixed successive period of 10 years.  Renewal leases were subject to certain requirements, such as a limitation on existing overriding royalty interests of 5%.  There is no limit on the amount of times a renewal lease could be renewed, although a 1990 amendment to the MLA now provides that a renewal lease renewed after November 15, 1990 will continue for 20 years and so long thereafter.  Due to the uncertainty of operating under a fixed term lease, subsequent amendments to the MLA also authorized the lessee of any 20-year lease (including renewals of such leases) or any lease issued before August 8, 1946 to exchange the lease for an “exchange lease” with the customary Habendum clause.  Because they involve oil and gas leases issued prior to 1946, there are few active renewal and exchange leases today.

Public domain leases.  Public domain leases are the most common federal oil and gas leases.  They cover lands or mineral deposits owned by the United States that were never granted to the state, patented into fee ownership, or disposed of under any public land law (there are certain exceptions, such as lands incorporated by cities, towns, or villages, lands in national parks, monuments, or reserves, or lands in wilderness areas or wilderness study areas).  They can also cover acquired lands – lands patented into fee ownership and subsequently reacquired by the federal government – if consented to by the surface managing agency.  Public domain leases are authorized under the MLA.  However, because of the numerous amendments to the MLA, the history and terms of such leases vary significantly.  For example, the primary term, rentals, and royalties depend on several factors, including: whether the lease was issued competitively or non-competitively, the period of time in which the lease was issued, and the period in time in which the rental or royalty was required.  As a result, it is important to review the lease to confirm the terms of a public domain lease.  Where the original grant of the lease has been lost or destroyed, a review and understanding of the history of the MLA and applicable regulations becomes necessary.  Because most oil and gas leases issued today are public domain leases, we discuss current leasing of public domain lands in the final section of this article below.

Right-of-way leases.  The lands under federal rights-of-way, not subject to an oil and gas lease at the time the right-of-way was issued, may only be leased under the Right-of-Way Leasing Act of 1930 (the ROW Act).  Although the ROW Act appears to include all rights-of-way, the BLM typically only issues right-of-way leases under railroads and reservoirs.  Under the ROW Act, the right-of-way owner is the only party that may lease the lands, but an owner or lessee of the oil and gas rights in the adjoining lands may submit a compensatory royalty bid and the BLM will issue either a right-of-way lease to the right-of-way owner or a compensatory royalty agreement to the adjoining owner or lessee, whichever is the most advantageous to the United States.  Because of the limited instances where lands fall under this category, right-of-way leases are less common than public domain leases.

Oil and gas leasing today.  The MLA, as amended, and FOOGLRA still govern the leasing of public domain lands for oil and gas today.  Such leasing is accomplished as follows:

  • Lands available for oil and gas leasing are nominated
  • The BLM selects tracts to be included in an upcoming lease sale
  • Notice of the lease sale is made
  • The BLM considers any protests filed and makes a final list of included tracts
  • The lease sale is held and the tracts are offered for oral bidding
  • The BLM issues a lease on each tract to the highest qualified bidder

In the event any tract does not receive any bids or the minimum acceptable bid, the tract becomes available to be leased non-competitively for a period of two years following the lease sale to the first qualified applicant.  The current lease terms for both newly issued competitive and non-competitive oil and gas leases are a primary term of 10 years, a royalty interest of 12.5%, and rentals of $1.50 per acre for the first five years, then $2 per acre thereafter.  After a discovery on the leased lands, a minimum royalty of not less than the annual rental is due in lieu of the annual rental.

Utah Supreme Court Invalidates Tax Title as to Severed Minerals on Due Process Grounds

Oil and Gas Cases, , , , , , , ,

Can Utah’s four-year statute of limitations for challenging a tax sale prevent a property owner who never received notice of the sale from contesting it?  In prior years, the answer may have been “yes.”  In Jordan v. Jensen, 2017 UT 1, 2017 WL 104642, however, the Utah Supreme Court held that the answer is an unequivocal “no.”

In Jordan, the owners of the surface and mineral estates conveyed the surface and reserved the minerals in a deed recorded in early 1995, prior to levy and assessment of the property taxes by Uintah County.  The new surface owner failed to fully pay the property taxes levied by the County for 1995, and as a result, the County sold the property at a tax sale in 2000, without notifying the mineral interest owners.  Id. ¶¶ 4-6.  Years later, an oil and gas company seeking to develop the mineral estate obtained a title opinion that indicated that there was a question whether the severed minerals passed at the tax sale because the tax deed did not contain any language reserving the mineral interest.  The mineral interest owners unsuccessfully tried to obtain a quitclaim deed from the surface owners and eventually sued to quiet title to the minerals.  Id. ¶¶ 9-10.

The surface owners argued, among other things, that the County’s general property tax assessment included the nonproducing mineral estate and that the failure to give notice to the mineral owners did not void the tax deed as to the mineral interest because Utah has a four-year statute of limitations that bars challenges to a tax deed.  See id. ¶¶ 13-14.  (Under Utah law, the authority to tax minerals has been delegated exclusively to the Utah State Tax Commission.  The surface owners argued that his delegation was limited to producing minerals and that the counties had the authority to tax the nonproducing minerals).  The district court rejected the surface owners’ arguments and entered summary judgment in favor of the mineral owners.  The surface owners appealed.  Id. ¶ 11.

In its decision in Jordan, the Utah Supreme Court did not address the issue of whether a county has the authority to assess the nonproducing mineral interest, instead limiting its holding to the due process issue.  Id. ¶ 12.

Specifically, the court analyzed whether the four-year statute of limitations provided by Utah Code Ann. § 78B-2-206 prevented a challenge to the tax title even though the mineral owners never received notice of the County’s tax sale as required by the Due Process Clause of the Fourteenth Amendment to the U.S. Constitution.  Jordan, 2017 UT 1, ¶ 16.  In Hansen v. Morris, 283 P.2d 884 (Utah 1955), the Utah Supreme Court rejected a challenge to a tax sale based on the predecessor to section 206.  The court in Hansen stated that “a failure to provide notice or a due process violation does not prevent section 206 from applying to ‘validate tax titles.’”  Jordan, 2017 UT 1, ¶ 22 (quoting Hansen, 283 P.2d at 885).

In overturning Hansen, the Jordan court noted that subsequent U.S. Supreme Court cases have taken a different approach, finding that a statute of limitations “will not apply when it is triggered by constitutionally defective state action.”  Id. ¶ 23 (citing Schroeder v. City of N.Y., 371 U.S. 208 (1962); Mennonite Bd. of Missions v. Adams, 462 U.S. 791 (1983); Tulsa Prof’l Collection Servs., Inc. v. Pope, 485 U.S. 478 (1988)).  Applying these cases, the Jordan court held that section 206 requires state action—the conducting of a tax sale—before it takes effect, and that section 206 will not prevent a party from challenging a tax sale if constitutionally adequate notice is not provided to that party.  Id. ¶ 34.  The court also noted that constructive notice by recording a tax title is insufficient where the mineral owners’ names and addresses are “reasonably ascertainable and known to the county,” as was the case here.  Id. ¶ 38; see id. ¶ 37.  Rather, notice to such owners must be mailed to their last known address of record or otherwise given in a manner that ensures its delivery.  Id. ¶ 37.

The court concluded that because the mineral owners did not receive constitutionally adequate notice, the County did not have jurisdiction over the mineral interest, thus voiding the tax title to the extent it purported to convey the mineral interest.  Id. ¶ 42.  In doing so, the court overruled Hansen “[t]o the extent [it] states that section 206 can apply where a state or county fails to provide constitutionally adequate notice to an interested party of a tax sale….”  Id. ¶ 40.

(Re-printed from Andrew J. LeMieux, Utah Oil & Gas, Rocky Mountain Mineral Law Foundation Mineral Law Newsletter, Volume XXXIV, Number 1, 2017)

Utah Oil & Gas Update

Oil and Gas Regulations, Royalty Issues, Title Issues/Curative, , , , , , , , , , , , , ,

UTAH COURT OF APPEALS APPLIES THE OPEN MINES DOCTRINE, REJECTS PETITION TO CONSTRUE WILL IN FAVOR OF LIFE TENANTS

In re Estate of Womack, 2016 UT App 83, 2016 WL 1729528, involved a decedent whose formally probated Will devised a 160-acre parcel to his three children, in equal shares. See id. ¶ 2. In his Will, the decedent specified that “the oil, gas and mineral rights under the said property . . . are devised to each of my children, share and share alike, for life,” remainder to the decedent’s grandchildren. Id. In 1990, the district court entered an estate closing order that named the decedent’s three children as the owners of the 160-acre parcel outright. Id. ¶ 3. In 1992, the district court amended the estate closing order “to conform to the Will” and provide for the grandchildren’s remainder in the minerals, which had been incorrectly omitted in the prior order. Id. ¶ 4. In 2008, an oil and gas company leased the minerals underlying the 160-acre parcel, but a question arose as to who was entitled to the proceeds of production. Id. ¶ 5.

In an effort to clarify who was entitled to the proceeds of production, one of the life tenants petitioned the district court to reopen the decedent’s estate and construe the Will in favor of the life tenants. According to the life tenant, the prior order’s lack of specificity resulted in an ambiguity that should be resolved in favor of the life tenants, based on an affidavit from the drafting attorney regarding the decedent’s intent. Id. ¶¶ 5 and 6. Two of the remaindermen challenged the petition, asserting that the requested relief would require the court to re-construe a provision of the Will that had already been construed, and that the court would be required to vacate or modify its prior order. This, the remaindermen contended, was barred by a six-month statute of limitations. Id. ¶ 14 (citing Utah Code Ann. § 75-3-412). The district court agreed with the remaindermen and denied the life tenant’s petition to construe the Will.

The life tenant appealed, claiming that the district court had misinterpreted the nature of the petition, and that the petition only sought clarification of the prior estate closing order, which was not subject to the six-month limitations period. The Court of Appeals affirmed the district court’s decision. The Court cited the open mines doctrine and concluded that the remaindermen were entitled to the proceeds of production because the Will did not specify otherwise. The Court found that the prior estate closing order had already construed the Will as creating life estates in mineral rights, and “[l]ife estates in mineral rights, by default, do not encompass a right to any proceeds from new mineral extraction.” Id. ¶ 17 (citing Hynson v. Jeffries, 697 So.2d 792, 797 (Miss. Ct. App. 1997). In the Court’s view, the Will was not ambiguous, and clarification was not necessary. Id. The Court found that the prior estate closing order “implicitly granted extraction proceeds to the [remaindermen] (albeit by default).” Id. ¶ 19. Because the petition sought to prove the decedent’s intent for the life tenants to receive income from the minerals, “rather than letting such proceeds default to the holders of the remainder” under common law, the Court found that the six-month time limit for vacations and modifications of prior orders applied, and the petition was time-barred. Id.

UTAH LEGISLATURE CONFIRMS THAT FEDERAL, STATE, AND TRIBAL INTERESTS MUST BE EXCLUDED WHEN CALCULATING SEVERANCE TAX ON OIL AND GAS

In the May 2015 edition of the Rocky Mountain Mineral Law Foundation Mineral Law Newsletter, we reported on the Utah Supreme Court’s decision in Anadarko Petroleum Corporation v. Utah State Tax Comm’n, 2015 UT 25, 345 P.3d 648 (Utah 2015). In Anadarko, the Court held that an oil and gas operator may exclude federal, state, and tribal interests when calculating its severance tax rate.

The Utah legislature recently codified the rule established by Anadarko. See S.B. 17, ch. 324, 2016 Utah Laws (amending Utah Code Ann. §§ 59-5-102 and 59-5-103.1). S.B. 17 confirms that the severance tax on oil and gas does not apply to federal, state, or tribal interests in oil and gas. As such, for purposes of determining the amount of severance tax, these exempt interests should be excluded when calculating the value of oil and gas and the tax rate. S.B. 17 applies to a taxable year beginning on or after January 1, 2015, as well as to severance taxes “for any taxable year, including a taxable year beginning before January 1, 2015, that is the subject of an appeal that was filed or pending on or after January 1, 2016.” Id.

(Re-printed from Andrew J. LeMieux, Utah Oil & Gas, Rocky Mountain Mineral Law Foundation Mineral Law Newsletter, May 2016)

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

Due Diligence, Federal Lands, Fee Lease 101 Series, Lease Provisions, , , , , , ,

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Unitization Clause Checklist:

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

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

Co-Authors
David Hatch and Andrew LeMieux

Practical Advice Regarding Pooling Clauses

Fee Lease 101 Series, Lease Provisions, Title Issues/Curative, Uncategorized, , , , ,

Pooling is a fundamental concept within oil and gas law, but one that is often misunderstood. Pooling is most commonly defined as “the combining of two or more tracts of land into one unit for drilling purposes … accomplished voluntarily, or through compulsion.”1 In other words, it is how a lessee is able to extend a lease without physically drilling on the lease. For private (fee) oil and gas leases, the ability of the lessee to pool the lease is typically addressed in the lease provisions. These provisions are known as the pooling clause. This article provides some practical tips in dealing with the issues that arise from pooling clauses.

The first question that should be asked is if there is an existing spacing order in place for the lands and formation(s) involved. Many pooling clauses provide that the lease can only be pooled in conformity with a spacing order from the applicable state regulatory agency. If you encounter such a clause, you will need to check for a state spacing order, and if an order is not already in place, you will need to initiate the required steps to obtain an order. There may also be an order in place that does not match your proposed operation. If so, a new order would need to be obtained modifying the existing order. If spacing is governed by statewide spacing, you will want to double check the language in the pooling clause to confirm that statewide spacing is sufficient.

If the proposed well will be a horizontal well, there are special considerations that need to be addressed. Some lease provisions specifically address horizontal spacing. Many states have special statewide rules that are in place for horizontal wells. Particular attention should be paid to any total acreage limitation included in the pooling clause of the lease, for example, the lease cannot be included in a pooled unit for oil greater than 160 acres. If the lease has this limitation, an amendment to the lease may be the best option to eliminate this conflict.

The next question when reading a pooling clause is what role, if any, the lessor will have in the pooling process. The most common oil and gas lease terms allow the lessee to pool the lease without obtaining any additional consent from the lessor. In some cases, if the lessor desires to retain this right, they will strike out the pooling provision in the entirety, or add a specific lease provision requiring their consent. If the lease does not have a pooling clause, or if the pooling clause is stricken, the lease can only be pooled with the express consent of the lessor. This consent would be expressed by having the lessor execute a pooling agreement. The pooling agreement should be recorded to provide third parties with notice of the terms of the agreement. If obtaining consent is not an option, compulsory pooling by the governing state agency would be the alternative.

Some leases require that notice of the pooling be provided to the lessor in order for the pooling to be effective. If the pooling clause requires that notice be mailed to the lessor, an effort should be made to locate both the last address of record and a current address, utilizing online resources. If a more recent address is discovered, the notice should be mailed to both the address of record and the new address that was located. More commonly, the lease requires that for it to be properly pooled, a proper declaration of pooling needs to be executed and recorded by the lessee in the applicable county. Care should be taken in drafting the declaration of pooling. It should be signed by all parties owning a working interest in the lease. In order to be recorded, the signatures will need to be originals and it will need to be notarized. It should describe the specific lease(s) being pooled, including the recording information (Book/Page, Entry No.) for each lease. It should cite the authority to pool contained in the lease, for example: “Pursuant to Paragraph 10 of the lease.” It should define the pool, the total lands included and the formation(s) covered. If the lease covers more lands than what is being pooled, the declaration should describe all of the lands covered by the lease. This is particularly important in states that utilize a tract index recording system. If the pooling is in conformity with a state spacing order, it should be noted. If the party executing the declaration was not the original lessee, a statement as to the succession (Book/Page, Entry No. of the document transferring the interest in the lease) should be included. If the operator is drilling the well to earn an interest in the lease from another party, for example under a farmout agreement, it is recommended that the declaration be executed by both the record title owner and the party that is to earn the interest. Doing this would avoid any dispute as to the correct party to execute the declaration. Once executed, confirmation should be made that the declaration of pooling is properly recorded and, if it is a tract index state, that it is has been properly indexed against the lands.

Confirmation should be made that the effective date of the pooling is either the date of, or prior to the date, of first production. The effective date should also be prior to the termination date of the lease. Most lease provisions provide that the declaration of pooling must be prior to lease expiration. In the event the well was drilled prior to lease expiration, but the declaration of pooling was not timely recorded in order to avoid any issue, the lessor should execute a pooling declaration which includes a statement that the lease was properly pooled prior to the expiration date of the lease.

Finally, after reading the specific pooling provisions in the leases to be pooled, a broader examination of some additional issues raised by pooling the lease should be conducted. Confirmation should be made that all of the leases to be pooled are private leases. If the pool includes either federal, Indian, or state leases, additional steps will be needed to pool these leases. As to state leases, various state agencies have adopted different rules and procedures regarding private pooling agreements. As to federal and Indian leases, there are two ways to pool them: a federally approved unit or communitization agreement. The nuances of federal unitization and communitization will be further explored in a subsequent article in this series.

1 Patrick H. Martin and Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § P Terms. (LexisNexis Matthew Bender 2016).

BLM Postpones Another Oil and Gas Lease Sale

Federal Lands, ,

As with last month’s oil and gas lease sale in Utah, the BLM has now postponed its December 10th oil and gas lease sale of nine parcels in Arkansas and Michigan.  Although the BLM gave no reason for the postponement, environmental activists had announced that they were planning to challenge the oil and gas lease sale in an effort “to keep fossil fuels in the ground.”  The environmental groups opposed to oil and gas development have hailed the BLM’s postponement of the December lease sale as a victory.  If correct, this would be the second time in less than a month that environmental groups forced the BLM to postpone an oil and gas lease sale.

The Mother Hubbard Clause

Fee Lease 101 Series, Lease Provisions, , , ,

Imagine a scenario in which the property description in one of your leases, meticulously transcribed from a document in the record chain of title, is later found to describe only a portion of the lands thought to be included. You are suddenly at risk of losing part, if not all, of your investment. What do you do? The answer depends on whether the lease contains a “Mother Hubbard clause.”

What is a Mother Hubbard Clause?

The “Mother Hubbard” or “cover-all” clause is a common provision in an oil and gas lease1 that provides a mechanism to include lands not adequately described in the lease or certain interests that vest after the lease has been issued.2 It was primarily designed to protect against the loss of small strips of land that were unintentionally omitted from the property description. But it was also meant to ensure that certain types of after-acquired interests, such as those acquired through adverse possession, were covered by the lease.3 At its core, the Mother Hubbard clause is an insurance policy.

Although many variations exist, the Mother Hubbard clause typically consists of two basic components. The first is a property catch-all. For example, the property description might state that “in addition to the described premises the lease covers adjoining, contiguous, or adjacent lands owned by the lessor.” The second component is meant to cover any interests that vest in the lessor after the lease has been issued. This language will likely include a statement that “the property includes any interests which the lessor may hereafter acquire by revision, prescription or otherwise.” Most modern Mother Hubbard clauses include both of these safeguards. (more…)