FAQs of Federal Oil and Gas Leases

Can a Terminated Lease Be Reinstated?

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

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: https://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?

FAQs of Federal Oil and Gas Leases, Federal Lands, Royalty Issues, , , , ,

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?

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[6] 30 U.S.C. §§ 301 to 306.

[7] 30 U.S.C. § 301 (emphasis added).

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

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

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

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.