FAQs of Federal Oil and Gas Leases

Will My Federal Lease Be Extended?

Like virtually all modern oil and gas leases, federal leases have a fixed primary term (typically 10 years)[1] and a habendum (i.e., “so long thereafter”) clause.  But understanding the provisions of the Mineral Lands Leasing Act of 1920 (“MLA”) and BLM regulations governing extension of federal oil and gas leases can be tricky.

Production in paying quantities.  Obtaining production is the most obvious means of lease extension – if there is a producing oil or gas well on the leased premises when the primary term expires, the lease is extended for so long as oil or gas is produced in paying quantities.[2]  The term “paying quantities” means production “sufficient to yield a reasonable profit after payment of all the day-to-day costs incurred after the initial drilling and equipping of the well, that is, the costs of operating the well, including workovers and maintenance, rendering the oil or gas marketable, and transporting and marketing that product.”[3]

However, it isn’t necessary for there to be actual production from a federal lease for it to be extended beyond the primary term; rather, the lease will be extended indefinitely if there is a well “capable of producing oil or gas in paying quantities” on the leased premises.[4]  BLM determines whether a well meets this requirement.  The well must be physically in a condition to produce by “flipping a switch” with little or no additional work.  For example, a shut-in well qualifies as capable of producing in paying quantities, but a well in which the casing has been set and cemented but not perforated does not qualify.[5]  The IBLA also has upheld lease termination when equipment required for production was not on site.[6]

This extension has its limitations, since the MLA grants BLM the authority to order the lessee to begin production within a period of not less than 60 days from receipt of notice from that agency.[7]  Failure to commence actual production within the time allowed by BLM results in termination of the lease.[8]  And because federal leases are not paid-up leases, the lessee also must pay annual rentals on or before each anniversary date of the lease until oil or gas in paying quantities actually is produced from the lease.

Drilling over primary term.  If the lessee is engaged in drilling operations at the expiration of the primary term of the lease,[9] the lease term will be extended for an additional two years if certain requirements are met.[10]  Actual drilling operations that penetrate the earth are required.  Mere site preparation, or even moving a rig on site, is not enough to obtain extension of a federal lease by drilling.[11]  The operations must be conducted under an approved application for permit to drill (“APD”).  Also, to get the drilling over extension, the lessee must have paid rentals on or before the lease anniversary date.

After commencing drilling operations, the lessee must diligently conduct such operations in a bona fide effort to drill and complete the well as a producer.  The standard is that of a reasonably prudent operator, and drilling operations must be conducted in a manner that “anyone seriously looking for oil or gas can be expected to make in that particular area, given the existing knowledge of geologic and other pertinent facts.”[12]  Notably, the drilling over extension relates only to the primary term, and it is not available if the lease was previously extended for another reason.  Nonetheless, the drilling over extension can apply if the lease was suspended (see below), since that results in tolling the lease term.

Commencement of additional drilling operations.  If production in paying quantities ceases on a federal lease in its extended term, the lessee must commence reworking operations or drilling operations for a new well within 60 days or the lease will terminate.  Because the MLA itself provides that the 60-day period to commence drilling or reworking operations begins running “after cessation of production,”[13] the safest course is to commence operations within that period.  BLM regulations, on the other hand, provide that the 60-day period does not begin until receipt of notice from BLM that the lease is not capable of production in paying quantities.[14]  As with drilling over the primary term, once commenced, continuous operations in the extended term also must be conducted with reasonable diligence.[15]

Assign part of the lease.  If the lessee assigns 100% record title (and operating rights) in a portion of a federal lease, such assignment will cause a segregation of the assigned lands into a separate lease.  Such segregation potentially can extend a federal lease in different ways.  First, if a discovery of oil or gas in paying quantities later is made on any portion of the original leased lands, both the base lease and the segregated lease will continue for the longer of the primary term of the base lease or for two years after the date of discovery.[16]  Interestingly, there is no requirement to complete a well – a discovery can be proved by other evidence.[17]  However, a well eventually must be completed as capable of producing in paying quantities in order to qualify.  As with other extensions, rental payments are still required until there is a discovery.  Second, if the base lease is in an extended term due to production (actual or allocated) or by payment of compensatory royalties, the undeveloped portion will continue for two years from the effective date of the assignment and so long thereafter as oil or gas are produced in paying quantities.[18]

Pay compensatory royalty.  If the leased premises are determined by BLM to be subject to significant drainage from a well on neighboring lands and the lessee enters into a compensatory royalty agreement with BLM and pays a compensatory royalty for the drainage, such payment will extend the lease for the period in which the compensatory royalties are paid plus one year thereafter.[19]  As a practical matter, BLM typically will not enter into a compensatory royalty agreement if it believes the lessee can drill an offset well.  The lessee also must pay rentals.

Unit-related extensions.  If consent of the necessary parties is obtained and approval is obtained from BLM (which includes a public interest determination), the lessee may commit a federal lease to a federal exploratory unit, which can affect lease extension.  A federal lease is not extended automatically through commitment to a unit agreement alone.  However, production of oil or gas in paying quantities anywhere in the unit area will maintain a committed federal lease so long as the lease remains committed to the unit.[20]  Production from a well that meets the paying quantities test on a lease basis but which is not sufficient to establish a unit well and form a participating area (often called a “Yates well”) nonetheless will extend the leases committed to the unit.[21]  Also, the drilling over extension discussed above will extend a federal lease when actual drilling over the end of the primary term occurs on any lease committed to the unit.  Until a well capable of production in paying quantities is drilled on the lease or a participating area is established and production is allocated to the lease, the lessee must continue paying rentals.

Commitment of a federal lease to a unit with lands both inside and outside of the unit area will cause the lands outside of the unit area to be segregated into a separate lease.  The uncommitted lands will be extended for the term of the original lease, but for not less than two years from the effective date of the commitment to the unit.[22]  Similarly, when all of the leased lands in a federal lease committed to a unit are eliminated from the unit by termination or contraction of the unit, the lease will be extended for the term of the original lease, but for not less than two years from the effective date of the elimination.[23]  However, in both cases, there is no extension if the public interest requirement is not met.  The public interest requirement is met “if the unit operator commences actual drilling operations and thereafter diligently prosecutes such operations in accordance with the terms of said [unit] agreement.”[24]

Partial commitment and elimination from a unit can result in some lease extension complexities.  In particular, if a federal lease is producing beyond its primary term when it is partially committed to a unit (and thus the non-committed land is segregated), the segregated portion that does not have a producing well will remain in effect for so long as production in paying quantities continues from the existing well(s) on the other portion, regardless of which portion is committed to the unit.[25]  This typically is referred to as “associated production.”  But if the lease is still in its primary term (even if the lease is producing), the non-producing portion will not receive the benefit of the existing production after segregation.  Instead, it will remain in effect for the rest of its fixed term or two years, whichever is longer.

Additionally, a producing lease fully eliminated from a unit will receive a fixed term equal to the later of two years from the effective date of elimination or its original primary term, even though the lease is producing in an extended term at the time of elimination.[26]  This means that if the lease subsequently is partially committed another federal unit it would not receive any “associated production” as discussed above.  There are many nuances and interesting results when a federal lease has been committed to and eliminated from multiple units.  Thus, the facts and relevant law should be reviewed carefully to determine whether a lease in this situation has been properly extended.

Communitization agreement related extensions.  Commitment of lands in a federal lease to a communitization agreement is the federal equivalent of pooling.  A communitization agreement generally must conform to an existing state spacing pattern or commission order and it must be approved by BLM.[27]  Unlike unitization, commitment of part of the lands in a federal lease to a communitization agreement does not result in segregation, and thus the segregation extension mentioned above does not apply.

Similar to federal units, if any portion of a federal lease is committed to a communitization agreement, the entire lease will be extended by production in paying quantities or by the completion of a well capable of producing in paying quantities on any communitized land.[28]  In addition, actual drilling operations over the primary term of a federal lease anywhere on the communitized lands will extend the lease for two years.[29]  BLM’s approval of the communitization agreement need not be obtained prior to the end of the primary term in order to obtain the lease extension benefits, but the agreement must be signed by all necessary parties and filed with BLM prior to lease expiration.[30]  Finally, if a communitization agreement is terminated, so long as the public interest requirement was met, the eliminated federal lease will receive an extension of the remainder of its primary term or two years, whichever is longer.[31]

Suspensions.  The MLA also provides for another means of keeping a federal lease alive that technically results in tolling of the lease term and adding the period of suspension to it.[32]  The MLA gives BLM the authority to grant two types of suspension of an entire federal oil and gas lease following receipt of a timely application from all record title holders (or the unit operator with respect to all leases committed to a federal unit) showing why such relief is necessary.  First, BLM may grant suspensions of both operations and production “in the interest of conservation” (known as a Section 39 suspension).[33] Section 39 suspensions are intended to provide extraordinary relief when a lessee is denied beneficial use of its lease.[34]  For example, BLM might grant a Section 39 suspension to allow time for the reviews required by environmental statutes such as NEPA and the Endangered Species Act.  BLM also has identified many situations in which a Section 39 suspension is not warranted – a significant one being when an APD is submitted incomplete or untimely.  A Section 39 suspension terminates if the lessee undertakes activity such as road construction, site preparation or drilling. Rentals and minimum royalty payments are suspended under a Section 39 suspension.

Second, BLM may grant suspension of operations only or a suspension of production only when the lessee is prevented from operating on or producing from the lease, despite the exercise of due care and diligence, by reason of force majeure (known as a Section 17 suspension).[35]  BLM may only grant Section 17 suspension after operations on the lease have commenced and production has been obtained.[36]

[1] Competitive federal leases issued between 1988 and 1992 have five-year primary terms, and some older leases with 20-year terms subject to renewal remain in effect.

[2] 30 U.S.C. § 226(e); 43 C.F.R. § 3107.2-1.

[3] Abe M. & George Kalaf, 134 IBLA 133, 138, GFS(O&G) 3 (1995).

[4] 43 C.F.R. §3107.2-3.

[5] See Coronado Oil Co., 164 IBLA 309, 323, GFS(O&G) 10 (2005).

[6] Int’l Metals & Petroleum Corp., 158 IBLA 15, 22-23, GFS(O&G) 1 (2003).

[7] 30 U.S.C. §226(i); 43 C.F.R. § 3107.2-3.

[8] Id.

[9] The primary term expires at midnight on the day immediately preceding the lease anniversary.

[10] 43 C.F.R. § 3107.1.

[11] Estelle Wolf, et al., 37 IBLA 195, GFS(O&G) 157 (1978).

[12] 43 C.F.R. § 3107.1.

[13] 30 U.S.C. § 226(i).

[14] 43 C.F.R. § 3107.2-2. The IBLA long has held that written notice from BLM is not required when a lease ceases producing in paying quantities and, thus, the 60-days to drill starts running upon cessation of production. While the federal district court overturned the IBLA on this point in Coronado Oil Co. v. DOI, 415 F. Supp.2d 1339, 1348 (D. Wyo. 2006), that decision is narrowly construed by the IBLA.  See e.g., Atchee CBM, LLC, 183 IBLA 389, 406-08, GFS(O&G) 6 (2013).

[15] 43 C.F.R. §§ 3107.2-2 and -3.

[16] 43 C.F.R. § 3107.5-1.

[17] See Joseph I. O’Neill, Jr., 1 IBLA 56, 62 (1970), GFS(O&G) 2 (1970).

[18] 43 C.F.R. § 3107.5-3.  However, a lease in its extended terms dated prior to September 2, 1960 may be in an extended term for any reason and still be eligible for the two-year extension.

[19] 43 C.F.R. § 3107.9-1.

[20] 30 U.S.C. § 226(m).

[21] Yates Petroleum Corp., 67 IBLA 246, 252-53, GFS (O&G) 251 (1982).  A “unit paying well” sufficient to justify the formation of a participating area requires sufficient production to repay not only the operating costs, but also the costs of drilling and completing the well with a reasonable profit.  43 C.F.R. § 3186.1.

[22] 43 C.F.R. § 3107.3-2.

[23] 43 C.F.R. § 3107.4.  If only a portion of the leased lands in a federal lease committed to a unit are eliminated, the lease is not segregated and there is no extension, but the all of the leased lands will continue in effect for so long as any of the leased lands remain committed to the unit.  Continental Oil Co., 70 I.D. 473, 474, GFS(O&G) 50-1964-19 (1963).

[24] 43 C.F.R. § 3183.4(b).

[25] Celsius Energy Co., Southland Royalty Co., 99 IBLA 53, GFS(O&G) 82 (1987).

[26] Id.

[27] 43 C.F.R. § 3105.2-3.

[28] 30 U.S.C. § 226(m); 43 C.F.R. § 3107.2-3.

[29] 43 C.F.R. § 3107.1.

[30] 43 C.F.R. § 3105.2-3(a).

[31] 43 C.F.R. § 3107.4.

[32] 43 C.F.R. § 3103.4-4(b).

[33] 30 U.S.C. § 209; 43 C.F.R. § 3103.4-4(a).

[34] See Savoy Energy, L.P., 178 IBLA 313, 323, GFS(O&G) 1 (2010).

[35] 30 U.S.C. § 226(i); 43 C.F.R. § 3103.4-4(a).

[36] See Savoy Energy, L.P., supra, at 325.

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

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.

How Do I Examine Title to a Federal Oil & Gas Lease?

For federal oil and gas leases, examination of the title documents is vital for the operator to understand the ownership and identify any title defects or other potential business risks prior to commencing drilling operations.  For a recently issued federal oil and gas lease, examining title is likely to be a straightforward and quick process.  On the other hand, examining title to a federal oil and gas lease issued several decades ago, covering multiple sections, and previously developed, is likely to be a complex and time-consuming process.  In either event, a title examiner must look at several different sources to get a complete picture of chain of title and be able to confirm the term and status of a federal oil and gas lease.  This article provides a summary of the sources necessary to examine title to a federal oil and gas lease.

1.   BLM Records

a. BLM Lease File. The most obvious source of title is the lease file maintained by the Bureau of Land Management (“BLM”).  The lease file contains documents relating to the lease sale, a copy of the lease, rental receipts, lease status notices, any filed assignments, and other documents, such as those relating to communization agreements.  Federal regulations require that an assignment of record title or a transfer of operating rights be filed on prescribed forms and approved by the BLM to be a valid conveyance recognized by the United States.[1]  Federal regulations also require that transfers of overriding royalty interest, production payments, and similar interests to be filed with the BLM,[2] although such assignments are not approved by the BLM.

The examiner should be aware that a lease may have been created by segregation from another lease—for example, by assignment of 100% of record title interest in a portion of the leased lands or by commitment of less than all of the leased lands to a federal unit.  In such instances, it is important to also examine the original lease file from inception until the time that the original lease was segregated into the new lease to understand the complete chain of title and confirm the term and status of the new lease.  For example, there could be an overriding royalty interest or other burden on production in the original lease file that is applicable to the new lease.

BLM lease files are not online and must be reviewed at the relevant BLM office.

b. Online Sources. In addition to reviewing the BLM lease file, there are several online sources that provide useful information and should also be reviewed when examining title to federal oil and gas leases. The first three sources below can be accessed on the website for BLM’s General Land Office, glorecords.blm.gov for most states (or links to the relevant state websites can be found on the website), while BLM’s LR2000 system can be accessed at www.blm.gov/lr2000/.

i. Patents. A patent search should be conducted to determine if any patents have been granted on the lands in question and, if so, to determine if any mineral and other interests were reserved.  In the case of a federal oil and gas lease, oil and gas ownership and rights should have been reserved by the United States.[3]

ii. Historical Index. The historical index for a township provides information in table form regarding all actions and authorizations for a township until a certain date in chronological order. This information includes the serial number, date, and affected lands for each authorization or use. For instance, the historical index provides information regarding land withdrawals, patents, issuance and termination of leases, and rights-of-way.

iii. Plats. The BLM maintains a master title plat in addition to other possible use plats (such as oil and gas, coal, and potash plats, etc.) for each township. These plats indicate which lands are currently owned by the federal government, agency jurisdiction, and rights reserved to the federal government on private land, such as a mineral reservation in a patent. Additionally, plats are useful tools to determine what rights may exist on the lands, such as rights-of-way, fences, land management areas, and other uses, and should include the relevant federal oil and gas lease. As a practice tip, a plat may contain notations on the side of the plat, such as secretarial orders affecting the entire township, that can be easily overlooked when examining the plat.

iv. LR2000. The BLM’s LR2000 system is a highly useful resource that provides reports on BLM authorizations. Of these reports, a geographic index report listing the authorizations for a specific section of land and serial register pages are commonly used by title examiners. Serial register pages are essentially a snapshot of the BLM authorizations, including the relevant federal oil and gas lease, and contain relevant information, such as its status (active, expired, etc.), affected lands, acreage amounts, relevant dates (e.g., the effective date and expiration date), and other useful information, such as if production was achieved and any communitizations involving the federal lease. Additionally, the serial register page indicates the current record title owner and any operating rights owner recognized by the BLM and may contain entries relating to recent assignments that have not yet been included in the lease file.

2.   County Records
County records are another necessary source to examine the complete chain of title and confirm the term and status of a federal oil and gas lease. In most states, filing documents with the BLM does not provide constructive notice. Instead, constructive notice is provided to other parties by recording the instrument in the appropriate county office. Because certain documents must be filed with the BLM (as noted above), this often results in two separate chains of title—one in the federal lease file, and the other in the county records. Frequently, these chains of title do not entirely match each other. This can be problematic if, for instance, the amount of interest assigned in an instrument included in the federal lease file contradicts the interest conveyed in a counterpart county document. Often, however, the two chains of title are useful to explain gaps that appear in the other chain of title, such as missing assignments or mergers, and to understand the intent of parties when their intent may be unclear by reviewing just one of the chains of title.

As noted previously, assignments filed with the BLM must be on prescribed forms. Because of this, parties are limited as to what can be included on these assignments. County documents have the advantage that they do not need to be in a certain form, beyond any statutory or other legal requirements and any requirements for the the document to be recorded in the county, such as signatures being acknowledged by a notary or including a legal description. This flexibility allows parties to include additional provisions in the instrument and to incorporate other documents by reference, such as an unrecorded purchase and sale agreement between the parties (although states vary in their treatment to referenced unrecorded agreements). Additionally, parties can record assignments in the county that are not recognized by the BLM, such as wellbore assignments, term assignments, or assignments containing reversionary rights. Although the BLM does not recognize these types of assignments, these documents are binding between the parties and on third parties who have constructive notice.[4]

3.   Other Records

Finally, it is important to review any relevant states regulatory or commission sources. State regulatory or commission websites vary depending on each state. Records that can be found at these sources may include administrative orders (such as pooling or spacing orders), well files, and production records. These records are an important source to understand the history and status of the lease. For example, the BLM lease file may indicate that a federal oil and gas lease achieved production during its primary term and is held past its primary term by production. In such instances, it is important to review the production records to ensure that there is still sufficient production on the leased lands (or lands communitized or unitized with the leased lands) to continue holding the lease.

In summary, whether the records are straightforward or complex, by reviewing the sources above, a title examiner can be confident that they are obtaining a full picture of the title and status of a federal lease oil and gas lease and can identify any potential pitfalls that exist.


[1] 43 CFR § 3106.4-1.  See e.g., River Gas Corp. v. Pullman, 960 F. Supp. 264, 266 (D. Utah 1997) (“It is well established that a party must receive the approval of the Secretary of the Interior in order for an assignment of a government lease to be valid.”).

[2] 43 CFR § 3106.4-2.

[3] Patents may also be recorded in the county records.  However, the BLM maintains the original copies of patents, while copies in the county were often recorded on patent “forms.”  Due to human error, at times the wrong county form was used and the county copy conflicts with the BLM copy—e.g., the copies may conflict as to what rights were reserved by the United States .  Because of this, the title examiner should rely on the patent copy maintained by the BLM.

[4] Although county documents do not need to be on prescribed forms, it is common to see BLM form assignments recorded in the county records.

Can a Terminated Lease Be Reinstated?

Federal leases can be terminated for a number of different reasons.  The question answered here is whether or not they can be reinstated.  The simple answer to that question is the same as all other legal questions: it depends. It depends on the reason the lease was terminated, how long the lease has been terminated, and what steps the lessee has taken to rectify the termination.

Three common ways that a federal lease will terminate are: (1) the expiration of the primary term, (2) the cessation of production in the extended term, or (3) the lessee’s failure to make proper rental payments.  All federal leases issued under the Mineral Leasing Act are granted for a specified period of time referred to as the primary term.  If there is no discovery of oil or gas in paying quantities, the lease will terminate automatically upon the expiration of the primary term.[1]  On the other hand, if there is a discovery, the lease will be extended past its primary term so long thereafter as there is a well capable of producing in paying quantities.  If production ceases and no reworking or drilling operations are commenced within 60 days of cessation of production, the lease will terminate automatically.  In both cases, the terminated leases may not be reinstated.

Generally, federal leases require the payment of an annual rental during the primary term and before discovery of oil and gas in paying quantities.  If the lessee fails to make proper and timely rental payments, the lease will automatically terminate. However, a federal lease terminated for failure to make proper rental payments can be reinstated under certain circumstances. The purpose of such reinstatements is to give lessees a second chance to pay the annual rental, but there are certain limitations.

Where a rental is timely paid, but the rental amount is insufficient by a nominal amount or by reliance on an incorrect bill, the lease will not automatically terminate.[2]  However, the nominal amount must be under $100 or 5% of the total rental amount, whichever is less, and must be paid within the period stated in a Notice of Deficiency issued by the supervising agency (usually 15 days).[3]  In all other cases, a lease terminated for failure to make proper and timely rental payments may only be reinstated under a Class I or Class II reinstatement.[4]

Class I Reinstatement: A lease may be reinstated as a Class I reinstatement if the following conditions are met:[5]

(1) The full rental amount must be paid within 20 days after the due date;

(2) The lessee must show that the failure to timely pay the rental amount was either justified or was not due to a lack of the lessee’s reasonable diligence;

(3) Within 60 days after receipt of a notice of termination, the lessee files a petition for reinstatement, together with a non-refundable filing fee (currently $80)[6] and the required rental, including any back rental or royalty accrued on the lease if the lease becomes productive prior to reinstatement; and

(4) The terminated lands cannot be subject to a newly-issued oil and gas lease or otherwise have been disposed of or become unavailable for leasing.

By regulation, “reasonable diligence” includes a rental payment postmarked by the U.S. Postal Service, common carrier, or their equivalent (but not by private postal meters) on or before the due date (or the next day if the agency is closed for a holiday).[7]  In most instances, where a Class I reinstatement is granted under reasonable diligence, the lessee is able to establish that the rental payment was lost in the mail or the lessee erroneously received notice from the BLM that the lease was in producing status.

Circumstances have been held “justifiable” where there are factors outside of the lessee’s control, such a death or illness of the lessee or member of his or her close family or a natural disaster occurring immediately prior to the due date cause a failure to exercise reasonable diligence.[8]  Generally, it is very difficult to demonstrate a “justifiable” cause.  For example, Class I reinstatement petitions have been denied where the lessee suffered from a chronic illness and where the lessee was in the middle of relocating offices.

If a Class I reinstatement is granted, the lease is restored as the lease existed prior to termination.  There is no change to the rental or royalty rates going forward or the primary term of the lease.

Class II Reinstatement: For leases that terminate after August 8, 2005, a lease may be reinstated as a Class II reinstatement if the following conditions are met:[9]

(1) The full rental amount is not paid within 20 days after the due date where the failure was either justified or not due to a lack of the lessee’s reasonable diligence or any time if the failure was inadvertent;

(2) On or before the earlier of 60 days after receipt of a notice of termination or 24 months after the termination of the lease, the lessee files a petition for reinstatement, together with a non-refundable filing fee of $500 and the required rental, including any back rental or royalty (at the increased rates, if applicable, see below) accrued on the lease if the lease becomes productive prior to reinstatement;

(3) Notice must be published in the Federal Register at least 30 days prior to the date of reinstatement, the cost of which shall be reimbursed by the lessee, and the authorized officer shall provide notice of the reinstatement to the Chairpersons of the Committee on Interior and Insular Affairs of the House of Representatives and of the Committee on Energy and Natural Resources of the Senate; and

(4) The terminated lands cannot be subject to a newly-issued oil and gas lease or otherwise have been disposed of or become unavailable for leasing.

Where the failure to timely pay is inadvertent generally means all circumstances where the lessee did not intentionally fail to make the rental payment.  It does not include, circumstances where the lessee was not financially able to pay or simply chose not to pay.[10]

If a Class II reinstatement is granted, the reinstatement is effective as of the date of termination.   However, for payments accruing after the termination date, the rental rate shall be increased by $5 per acre for non-competitive leases and $10 per acre for competitive leases and the royalty rate shall be increased to 16⅔% for non-competitive leases and by an additional 4% from the then-current rate for competitive leases.[11]  The increased rates are set forth in an agreement, which must be signed by all lessees.

There is no change to the primary term of the lease.  However, if the reinstatement of a lease either: (1) occurs after the expiration of the primary term or any extension thereof, or (2) will not afford the lessee a reasonable opportunity to continue operations under the lease, the authorized officer may extend the term of the reinstated lease for such period as determined reasonable, but in no event for more than 2 years from the date of the reinstatement and so long thereafter as oil or gas is produced in paying quantities.[12]

The benefit of Class II reinstatements is that, unlike Class I reinstatements, they do not require the lessee to justify when it failed to make proper rental payments.  Instead, the lessee only needs to show that the lessee did not deliberately fail to make the payment.  However, they are subject to increased rental and royalty rates.

[1] See Trent Maxwell, The Habendum Clause – ‘Til Production Ceases Do Us Part, The Oil & Gas Report, available at: http://www.theoilandgasreport.com/2015/02/05/the-habendum-clause-til-production-ceases-do-us-part-2 (explaining what it means to have a well producing in paying quantities).

[2] See PRM Exploration Co., 91 IBLA 165, GFS (O&G) 33 (1986).

[3] 43 C.F.R. § 3108.2-1(b).

[4] There is also a Class III reinstatement that deals with terminated leases stemming from a specific set of facts involving an unpatented oil placer mining claim. Although this will not be discussed at length, it is worth noting that a terminated oil placer mining claim can be converted/reinstated if it meets the necessary requirements set forth in 43 C.F.R. § 3108.2-4.

[5] 43 C.F.R. § 3108.2-2.

[6] See 43 C.F.R. § 3000.12 for up-to-date filing fees.

[7] 43 C.F.R. § 3108.2-2.

[8] See Torao Neishi, 102 IBLA 49, GFS (O&G) 41 (1988), citing Louis Samuel, 8 IBLA 268, GFS *O&G) 72 (1972), but see also William H. Siegfried, 135 IBLA 155, GFS (O&G) 11 (1996) (finding that a chronic illness is not justifiable).

[9] 43 C.F.R. § 3108.2-3.  The term for leases that terminate on or after August 8, 2005 is 15 months after the termination of the lease instead of 24 months.

[10] See Torao Neishi, 102 IBLA 49, GFS (O&G) 41 (1988).

[11] 43 C.F.R. §§ 3103.2-2(d) and (e) and 43 C.F.R. § 3103.3-1(a).

[12] 43 C.F.R. § 3108.2-3(e).

What Are Sliding-Scale Royalties?

Most leases on federal lands administered by the Bureau of Land Management (“BLM”) have flat royalties of 12.5% (evidenced by the use of the standard Schedule A to the BLM oil and gas lease form).[1]  However, certain leases issued by the BLM have “sliding-scale” or “step-scale” royalties for average daily production of oil or gas per well on the leased lands.  The most common sliding-scale royalty is evidenced by the use of Schedule B.  It is applicable to all leases issued between May 3, 1945 and August 8, 1946, as well as, all competitive leases issued after August 8, 1946 and prior to December 22, 1987.[2] There are two other sliding-scale royalty schedules, Schedule C and Schedule D, that are used for certain renewal and exchange leases, but those schedules are even less common.  The form of Schedule B is set forth below:

HOW TO CALCULATE SLIDING-SCALE ROYALTIES:

The regulations for calculating sliding-scale royalties for the “the average production per month in barrels per well per day” are found in 43 CFR § 3162.7-4 (“SSR Rules”).  The Office of Natural Resources Revenue (“ONRR”) provides guidelines and explanations for calculating sliding-scale Schedule B royalties on its website (at https://www.onrr.gov/ReportPay/PDFDocs/stepscale.pdf; the “ONRR Guidelines”).   Per the SSR Rules, the “average daily production per well for a lease is computed on the basis of a 28-, 29-, 30-, or 31-day month (as the case may be), the number of wells on the leasehold counted as producing, and the gross production from the leasehold.”  “Gross production,” is defined in the ONRR Guidelines to be “all production from the lease excluding any production used on the lease or unavoidably lost.”  For specific circumstances, the foregoing resources should always be consulted.  But as a general rule for operated wells, the following wells shall be “counted as producing” under the rules above: (1) existing wells on a lease (i.e., wells that were producing in the previous month) must produce at least 15 days in the month, (2) new oil wells drilled during the month must produce at least 10 days, and (3) for gas wells, any wells that produce during the month are counted.  For injection wells, we refer you to the rules but note that injection wells must operate at least 15 days to be counted.  Subparagraph (e) of the SSR Rules provide that “head wells” will be counted which “make their best production by intermittent pumping or flowing as producing every day of the month, provided they are regularly operated in this manner with approval of the authorized officer.”  Wells that predominately produce oil but have some gas production would be “counted as producing” under the royalty rates for oil in Schedule B, and not for gas (and vice versa for primarily gas wells that produce some oil).  For leases that had production for the previous month, but no wells produced for 15 days in the current month, the royalty is calculated on actual days produced, and for previously productive leases where no well produces for a month but oil was shipped, the previous calendar month’s royalty rate is used.

The SSR Rules and ONRR Guidelines provide the following example for calculated sliding-scale royalties for a hypothetical federal lease with Schedule B that has eight wells located on the leased lands in the month of June:

Well No. and record Count (marked X)
1. Produced full time for 30 days X
2. Produced for 26 days; down 4 days for repairs X
3. Produced for 28 days; down June 5, 12 hours, rods; June 14, 6 hours, engine down; June 26, 24 hours, pulling rods and tubing X
4. Produced for 12 days; down June 13 to 30
5. Produced for 8 hours every day (head well) X
6. Idle producer (not operated)
7. New well, completed June 17; produced for 14 days X
8. New well, completed June 22; produced for 9 days

In this example, there are eight wells on the leasehold, but wells 4, 6, and 8 are not counted in computing royalties. Wells 1, 2, 3, 5, and 7 are counted as producing for 30 days. The average production per well per day is determined by dividing the total production of the leasehold for the month (including the oil produced by wells 4 and 8) by five (the number of wells counted as producing), and dividing the answer by the number of days in the month.

For the foregoing example, the 1,000 bbls produced in June would be divided by the five counted wells and then divided by 30 calendar days in June, which equals 6.67 (and falls under 12.5% royalty rate on Schedule B for oil). As noted above, this includes production from all wells, even those that are not counted under the rules.

Finally, the ONRR Guidelines provide that the applicable royalty rate is based on monthly production (and not on monthly sales), and the “first in first out” method applies.  For the lease above, if 1,000 bbls are produced in June but only 700 bbls are sold in June, the 12.5% royalty applies to the 700 bbls sold in June.  If July has higher production, resulting in a royalty rate of 13% under Schedule B for the month of July, the first 300 bbls sold out of inventory in July will be attributed a 12.5% royalty from the remaining 300 bbls of unsold production from the month of June.

PRACTICE TIPS FOR DRAFTING DOCUMENTS INVOLVING FEDERAL LEASES WITH SLIDING-SCALE ROYALTIES:

In certain transactions, the failure to account for a federal lease with a sliding-scale royalty can result in ambiguities, which can then lead to unintended consequences or disputes.   For example, it is common for assignments of oil and gas leases to have a reserved overriding royalty interest that is calculated as the positive difference between existing burdens and a set percentage.  For example, consider an assignment where the assignor conveys all oil and gas leases described on Exhibit A and reserves an overriding royalty interest equal to the positive difference between existing burdens and 20% and there was a previous overriding royalty interest of record of a flat 5%.  For a lease with a sliding-scale royalty, it may not be clear how the reserved overriding royalty interest should be calculated if the sliding-scale royalty moves up from 12.5%.  The parties could indicate that the assignment is intended to convey a flat net revenue interest to the assignee (i.e., 80%), but that could create an ambiguity if there is not enough net revenue interest to satisfy the purportedly assigned net revenue interest (i.e., if the sliding-scale royalty moves above 20%).  As a result, it is necessary to include a statement that the existing burdens include a sliding-scale royalty and indicate how the reserved overriding royalty interest is to be calculated.  The complexity of the chain of title can be compounded when there are multiple assignments with this structure (i.e., an assignment first reserving an overriding royalty interest of the difference between existing burdens and 20%, followed by an overriding royalty interest of a flat 1%, followed by a later assignment reserving an overriding royalty interest of the difference between existing burdens and 22%).  Generally, if there are ambiguities in recorded assignments and no other extrinsic evidence of intent, courts can turn to rules of construction such as the rule that a document will be construed against the party who prepared the document.  As a result, any party preparing an assignment of a sliding-scale royalty lease with a reserved overriding royalty interest equal to the positive difference between existing burdens and a set percentage should take care to remove any ambiguities in the interests created by the assignment.

Other common industry documents could be impacted by federal leases with sliding-scale royalties, such as the joint operating agreement (“JOA”).  Most forms of JOA have a provision which sets a baseline royalty burden for all parties contributing leases to the contract area.  For example, the 1989 form A.A.P.L. JOA, in Article III(A) provides that: “Regardless of which party has contributed any Oil and Gas Lease or Oil and Gas Interest on which royalty or other burdens may be payable and except as otherwise expressly provided in this agreement, each party shall pay or deliver, or cause to be paid or delivered, all burdens on its share of the production from the Contract Area up to, but not in excess of, _______% and shall indemnify, defend and hold the other parties free from any liability therefor.”   To the extent leases are contributed which exceed the baseline burden amount the such party contributing that lease “shall assume and alone bear all such excess obligations and shall indemnify, defend and hold the other parties hereto harmless from any and all claims attributable to such excess burden.”  A party to a JOA that owns a federal lease with a sliding-scale royalty should carefully consider the potential economic impacts of this provision (in particular where the contractual interests of the parties under the JOA do not match their respective interests of record), and provide additional terms to address potential adverse impacts or ambiguities.

It is common for title examiners, whether landman providing lease reports, title attorneys providing drilling or division order title opinions, or division order analysts preparing revenue decks to provide ownership tables for federal sliding-scale royalty leases with an assumed royalty of 12.5%.  However, if not properly noted, subsequent parties relying on such tables could over-look that a sliding-scale royalty lease is involved.  It is important for landmen, title attorneys, and division order analysts to provide conspicuous statements in all ownership tables, noting the applicable sliding-scale royalty schedule.

[1] Applies to noncompetitive leases issued subsequent to the Act of August 8, 1946, and competitive and noncompetitive leases issued pursuant to the Federal Onshore Oil and Gas Leasing Reform Act of 1987.

[2] Leases issued between August 1, 1935 and May 3, 1945, also have royalty Schedule B, except the maximum rate for oil is 32% when daily production exceeds 2,000 barrels per well.

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

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).

What Are the Types of Federal Oil and Gas Leases?

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.