David Hatch

Can I Drill Through Unleased Federal Lands?

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

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

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

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

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

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

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

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

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

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

What if the tract is only partially unleased federal minerals?

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

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

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

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

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

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

[3] 43 C.F.R. § 3100.2-1.

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

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

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

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

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

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

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

What Are Federal Lease Rentals and When Are They Required?

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

Federal oil and gas leases require annual rental payments until a discovery of oil or gas in paying quantities on the leased lands.  This means that, upon the completion of a well capable of producing oil and gas in paying quantities, the lease is transferred into producing status and annual rentals are no longer required.  However, thereafter in lieu of rentals, the lessee is required to make a minimum royalty payment of not less than the amount of the annual rental that would otherwise be required prior to the end of each lease year.[1]

The annual rentals required under all oil and gas leases issued since December 22, 1987 is $1.50 per acre (or partial acre) for the first five lease years and $2.00 per acre (or partial acre) thereafter.[2]  For older leases, the amount of the rental payment can be determined from the lease form and/or the regulations in effect at the time the lease was issued.[3]  Although likely well past its primary term, it is possible that annual rentals could still be required for a lease issued prior to 1987.  For example, annual rentals may be required for a lease without production on the leased premises that was recently eliminated from a federal unit or, in some cases, on a lease that is currently suspended.

The annual rentals for the first lease year are typically paid to the proper BLM office with the lease bonus and other administrative fees required at the time of the lease sale.[4]  Subsequent annual rentals, starting with the second lease year, are paid to Office of Natural Recourses Revenue (ONRR) online through the “Rental Information” tab on the ONNR eCommerce website.[5]  The website will populate a list of rental obligations due within the next 90 days according to the payor code.[6]  The list may not be all-inclusive.  A payor may add a lease for which they have a rental obligation that is not listed.  eCommerce payments must be submitted before 8:55 pm ET for the payment to post to ONRR the next business day.  Failure to submit electronically may subject the payor to civil penalties.[7]

Lessees should be aware that the BLM no longer sends courtesy notices for rental payments.  Lessees are accountable to make rental payments on time and in the correct amount.  Failure to pay annual rentals can result in automatic termination of the lease by operation of law.[8]  However, if the rental payment is made on time and deficient by no more than 5% or $100, whichever is less, ONNR will send a Notice of Deficiency to the lessee and allow the lessee 15 days or until the due date to submit the full balance due before terminating the lease.[9]

If a lease is terminated for failure to pay annual rentals on time or in the correct amount, it may be reinstated under either a Class I or a Class II reinstatement.  Class I reinstatements reinstate the lease at the existing rental and royalty rate and are only available if: (1) the rental is paid within 20 days after the anniversary date; (2) the reason for not paying on time is justified or not due to a lack of reasonable diligence; and (3) a petition for reinstatement is submitted within 60 days after receipt of Notice of Termination of Lease.[10]  Class II reinstatements reinstate the lease at a higher rental and royalty rate if the payment was not made within 20 days after the anniversary date.[11]  Specifically, terminated leases that were originally issued noncompetitively and are reinstated through a Class II reinstatement will have an annual rental of $5.00 per acre, terminated leases that were originally issued competitively and are reinstated through a Class II reinstatement will have an annual rental of $10.00 per acre, and each succeeding termination will increase the rental $5.00 and $10.00 per acre, respectively.[12]  It is important to note that reinstatement is only available if no valid lease has been issued prior to filing the petition for reinstatement and, for Class II reinstatements, additional environmental analysis may be required.

The requirement to pay annual rentals can be affected by the commitment of a lease to a federal unit.  Generally, if only a portion of the lease is committed to a unit, the lease will be segregated into two separate leases.  As for the segregated lease within the unit, annual rentals are required until the segregated lands are included in a participation area.[13]  If the lease is partially in a participation area, annual rentals are still required on the lands outside the participation area, but the lease will not automatically terminate for failure to pay the annual rentals.  As for the segregated lease outside the unit, annual rentals are required until there is a discovery of oil or gas in paying quantities on the segregated lands.[14]  If a unitized lease is subsequently eliminated from the unit and there has never been a discovery on the leased lands, the lease will revert to rental paying status, even if it was previously committed to a participation area with a producing well.[15]

Finally, lessees should be aware of some additional factors relating to annual rentals.  First, annual rentals are calculated on a per acre basis rounded up to the nearest whole acre.  Second, annual rentals are not be prorated for any lands in which the United States owns an undivided fractional (i.e., the United States owns 50% of the mineral estate).[16]  Third, the full year’s rental is due regardless of whether the lease term ends before the next anniversary date, unless the reason is because operations and production were suspended.[17]

[1] Actual royalties paid on production obtained on or allocated to the lease during the lease year will be credited against this minimum royalty obligation.

[2] 43 C.F.R. § 3103.2-2.

[3] Leases issued on or after February 19, 1982 under the former regulation at 43 C.F.R. Section 3112 are subject, after February 1, 1989, to annual rentals in the sixth and subsequent lease years of $2.00 per acre or fraction thereof and exchange and renewal leases are subject to annual rentals of $2.00 per acre or fraction thereof upon exchange or renewal. 43 C.F.R. § 3103.2-2(b).

[4] 43 C.F.R. § 3103.1-2(a).

[5] ONRR, Payments, ONRR Electronic Payment Options (Aug. 6, 2018), available at https://www.onrr.gov/ReportPay/payments.htm.

[6] ONRR, eCommerce Online Rental Payments Frequently Asked Questions (FAQ) (Aug. 6, 2018), available at https://www.onrr.gov/reportpay/PDFDocs/eCommerce%20_Online_Rental_Payments_FAQ_6-27-16.pdf.

[7] 30 C.F.R. § 1241.53.

[8] 30 U.S.C. § 188.

[9] 43 C.F.R. § 3108.2-1.

[10] 43 C.F.R. § 3108.2-2.

[11] 43 C.F.R. § 3108.2-3.

[12] 43 C.F.R. §§ 3103.2-2(d)–(f).

[13] 43 C.F.R. § 3108.2-2(a).

[14] 43 C.F.R. § 3108.2-2(a).

[15] 43 C.F.R. § 3103.2-2.

[16] 43 C.F.R. § 3103.2-1(c).

[17] 43 C.F.R. § 3103.2-2.

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 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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Unitization Clause Checklist:

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

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

Co-Authors
David Hatch and Andrew LeMieux

The Shut-in Royalty Provision: Isn’t It Just for Gas?

Fee Lease 101 Series, Lease Provisions, Royalty Issues, , , ,

With the advent of the shale oil revolution, the significance of some traditional oil and gas lease provisions, such as the shut-in royalty provision, have been recently neglected. As a result, landmen may be asking themselves, “What is the shut-in royalty provision and will it ever impact a lease taken in an oil play?” The resounding answer is YES! Although a more traditional tool for gas plays, a shut-in royalty provision may apply to either a gas or oil well depending on the language used.

What is this thing anyway?

Nearly all oil and gas leases include a habendum clause,1 which allows a lease to be held in effect for a period of time and so long thereafter as oil and gas is produced in paying quantities. However, production can cease or be temporarily suspended for a number of reasons. Without a savings clause, even a brief a cessation in production would cause a lease past its primary term to expire. In light of this, lessees developed the shut-in royalty provision, among other savings clauses. Essentially, the shut-in royalty provision allows a lessee to temporarily cease production (i.e., shut-in a well) and pay a shut-in royalty to the lessor in place of the royalty on production that is not occurring during the shut-in period. The following is a typical, older shut-in royalty provision, created specifically for a gas well:

[W]here gas from one or more wells producing gas is not sold or used, lessee may pay as royalty $500.00 per year, and upon such payment it will be considered that gas is being produced within the meaning of Paragraph 2 [the habendum clause] hereof.2

The following is another, older example, used for either an oil or gas well:

This lease shall continue in full force for so long as there is a well or wells on leased premises capable of producing oil or gas, but in the event all such wells are shut in and not produced by reason of the lack of a market at the well or wells, by reason of Federal or State laws, executive orders, rules or regulations, or for any other reason beyond the reasonable control of Lessee, then on or before such succeeding anniversary of the date hereof occurring ninety (90) or more days after all such wells are so shut in and after the expiration of the primary term and prior to the date production is commenced or resumed, or this lease surrendered by Lessee, Lessee shall pay to Lessor as royalty an amount equal to the annual rental hereinabove provided for.3

There are numerous variations of the shut-in royalty provision, many of which may not be ideal for the lessee’s operations. For example, the provision might be focused on shutting-in a well for the purpose of finding a buyer of natural gas, dewatering a coalbed methane well, or repairing broken-down equipment. Although this article cannot discuss all of the variations, there are numerous additional resources on this subject.4

Aww shucks, the crank broke again!

Although the shut-in royalty provision may have been historically created to protect a lessee in the event that there is a lack of a market for gas, a lessee might use it for numerous other reasons. Some additional causes include: governmental restrictions, inability to economically produce the leased substances, lack of available linear infrastructure, equipment failure, or Force Majeure.5 Many older shut-in royalty provisions provide specific reasons to shut-in a well, while most newer versions are silent on the matter. If silent, a court will determine whether or not the cause for the temporary cessation was reasonable. While there is comfort in expressly describing the allowed causes for the temporary cessation, this could potentially lead to an unfavorable outcome for the lessee. Unless the lessee is aware of certain circumstances that might occur, the better approach may be to choose a shut-in royalty provision that allows the lessee to use its good faith judgment. In any event, it should be noted that some courts have required a well to be physically able to produce if it were turned on, based on the historic development of this clause (but see the discussion below under shale oil).6

Uh… did we pay that shut-in royalty on time?

Many older shut-in royalty provisions require the payment of a shut-in royalty to be paid in order for the lease to be considered held by production (e.g., the first example above). Over time, lessees realized that structuring the shut-in royalty payment as a condition may cause the lease to expire if the payment is not timely made.7 As a result, newer versions structure the shut-in royalty provision as a covenant rather than a condition. In other words, the existence of a shut-in well maintains the lease in effect, not the payment of the shut-in royalty (e.g., the second example above).

If the shut-in royalty provision is silent regarding the timing of payment (e.g., the first example above), a court will determine a reasonable time.8 If the shut-in royalty provision provides the timing of payment, it typically does so by using a specific time period (e.g., within 90 days), a specified date (e.g., on the anniversary of the lease date), or a combination of both (e.g., on the next anniversary date of the lease occurring 90 days after the well is shut-in, such as in the second example above). Generally, it is more practical to expressly provide the timing of payment and for such timing to be after the well is shut-in so that the shut-in provision won’t be triggered if the well is only shut-in for a brief period of time.

Wait, you mean that “oll” company can hold my lease forever?

Arguably, a lessee is expected to resume production from a shut-in well within a reasonable time. However, in order to avoid potential disputes and to limit what is a reasonable time period, mineral owners developed additions to the shut-in royalty provision. The following examples are illustrative:

Notwithstanding the provisions of this section to the contrary, this lease shall not be continued after ten years from the date hereof for any period of more than five years by the payment of said annual royalty;

[P]rovided, however, that in no event shall Lessee’s rights be so extended by shut-in royalty payments for more than two (2) years beyond the primary term; or

[T]he Lessee may extend this lease for two (2) additional and successive periods of one (1) year each by the payment of a like sum of money each year on or before the expiration of the extended term.9

Such additions to the shut-in royalty provision may prove useful in the event the parties to the lease cannot agree on whether or not a shut-in royalty provision should be included in the lease.

I can’t use this for horizontal oil wells, can I?

Okay, it’s finally time to answer the question, “What about the shale oil revolution – can we use the shut-in royalty provision for wells awaiting completion?” Because such a well is not capable of producing, typical shut-in royalty provisions won’t apply. The good news is that this can be easily fixed by expanding the term “capable of producing quantities” (after ensuring that the provision covers oil as well as gas).10 For example, a lessee could add the following after the shut-in royalty provision:

A well that has been drilled and cased shall be deemed capable of producing oil and gas in paying quantities, notwithstanding the fact that any such well has not been perforated, fractured, or otherwise completed.11

If the parties can’t agree on this broad expansion, the timing for such uncompleted wells could be limited (e.g., “…shall be deemed capable of producing oil and gas in paying quantities for a period not to exceed 180 days…”).12 Alternatively, the parties could agree to limit the expansion to specific types of wells (e.g., shale wells, coalbed methane wells, or horizontal wells).13

Fine. Just tell me which form of shut-in royalty provision to use.

As previously discussed, there are numerous forms and variations of the shut-in royalty provision. Of course, there is no one-size-fits-all. The shut-in royalty provision used in a lease form should be carefully selected to meet the needs of the lessee’s operations and regularly modified as technology advances and oil and gas plays shift. Although it won’t apply to all scenarios, the following example appears to embrace most of the key concepts discussed in this article:

If after the primary term one or more wells on the leased premises or lands pooled or unitized therewith are capable of producing Oil and Gas Substances in paying quantities, but such well or wells are either shut in or production therefrom is not being sold by Lessee, such well or wells shall nevertheless be deemed to be producing in paying quantities for the purpose of maintaining this lease. If for a period of 90 consecutive days such well or wells are shut in or production therefrom is not sold by Lessee, then Lessee shall pay an aggregate shut-in royalty of one dollar per acre then covered by this lease. The payment shall be made to Lessor on or before the first anniversary date of the lease following the end of the 90-day period and thereafter on or before each anniversary while the well or wells are shut in or production therefrom is not being sold by Lessee; provided that if this lease is otherwise being maintained by operations under this lease, or if production is being sold by Lessee from another well or wells on the leased premises or lands pooled or unitized therewith, no shut-in royalty shall be due until the first anniversary date of the lease following the end of the 90-day period after the end of the period next following the cessation of such operations or production, as the case may be. Lessee’s failure to properly pay shut-in royalty shall render Lessee liable for the amount due, but shall not operate to terminate this lease.14

Depending on the circumstances, the parties to a lease may desire to expand the term “capable of producing quantities” for an incomplete well or limit the maximum amount of time a well may be shut-in, as each is discussed above.

1See, generally, Trent Maxwell, The Habendum Clause – ‘Til Production Ceases Do Us Part,’ available at http://www.hollandhart.com/lease-provisions-part-2/.
2From a midcontinent form discussed in Patrick H. Martin & Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § 631 (2014).
3Id.
4See Martin & Kramer, supra note 2 at §§ 631 et seq.; John S. Lowe, “Shut-in Royalty Payments,” 5 Eastern Min. L. Inst. 18 (1984); Robert E. Beck, “Shutting-In: For What Reasons and For How Long?,” 33 Washburn L.J. 749 (1994); David E. Pierce, “Incorporating a Century of Oil and Gas Jurisprudence into the ‘Modern’ Oil and Gas Lease,” 33 Washburn L.J. 786 (1994); Thomas W. Lynch, “The ‘Perfect’ Oil and Gas Lease (an Oxymoron),” 40 Rocky Mt. Min. L. Inst. 3 (1994).
5See Martin & Kramer, supra note 2 at § 632.4.
6See, e.g., Hydrocarbon Mgmt., Inc. v. Tracker Exploration, Inc., 861 S.W.2d 427 (Tex. Ct. App. 1993); see also Milam Randolph Pharo & Gregory R. Danielson, “The ‘Perfect’ Oil and Gas Lease: Why Bother,” 50 Rocky Mt. Min. L. Inst. 19 (2004).
7See, e.g., Freeman v. Magnolia Petroleum Co., 171 S.W.2d 339 (Tex. 1943); see also Pharo, supra note 6.
8See Martin & Kramer, supra note 2 at § 632.6.
9See Martin & Kramer, supra note 2 at § 632.13.
10John W. Broomes, “Spinning Straw into Gold: Refining and Redefining Lease Provisions for the Realities of Resource Play Operations,” 57 Rocky Mt. Min. L. Inst. 26, 26–5 (2011).
11Id. at 26–9.
12Id. at 26–10.
13Id.
14From the Modified Lynch Form. Pharo, supra note 6 at Appendix A.

How Online Genealogical Tools Can Make a Landman’s Life Easier

Title Issues/Curative, , ,

The drilling rig is en route to your location and your land manager is breathing down your neck to lease the last remaining fee owners. The only problem: the owners cannot be found because they are likely deceased. Now what do you do? Carry the interests? Force pool? Drilling delays can be costly and carrying interests can be risky, so time is of the essence. Fortunately, there are a number of online genealogical tools available that might help you track down the heirs or devisees of the deceased owners.

Surprisingly, Google searches are a great starting point. In particular, rare names or unique spellings are helpful to locate information and, oftentimes, an obituary can be located by searching a decedent’s name and last known city or state of residence. Obituaries are generally accurate and provide a list of possible heirs or devisees. If an obituary is not located by a Google search, it might be found using another search engine, such as Yahoo or Bing.

If you know the decedent’s place of death and approximate date of death, you can search probate records. Some states, such as Colorado1, Montana2, New Mexico3, North Dakota4, Texas5, and Utah6, have websites which provide probate or other genealogical resources online. Individual counties typically maintain their own probate files. Where resources are not available online, you may ask the county court if there is a probate file for the decedent and, if so, request a copy of the file.

What about the more difficult searches? GenealogyBank.com, a subscription-based site, has a database of 6,500 newspapers with some newspapers going as far back as 1690. Generally, the earlier the date of death, the more difficult it is to find an obituary for the decedent. However, GenealogyBank.com may provide a death notice (indicating when and where the decedent died), a social security number, newsworthy stories, or birth or marriage announcements. If a social security number is located, it can be used to search the Social Security Death Index (free on several online genealogical websites, see below) to identify the date of the decedent’s birth and death, the town in which the decedent’s social security card was issued, and the decedent’s last place of residence. Any information gathered about the decedent, including relatives, dates of life events, places of life events, etc., can be used on other genealogical websites to locate potential heirs or devisees.

Obituaries and genealogical information may also be available on FindAGrave.com. However, this website is best known for its vast library of headstone images. These images generally include the name of the decedent’s spouse and the decedent’s and his or her spouse’s birth and death dates (as well as the location where the decedent was buried).

The largest of all the genealogical websites is Ancestry.com, which claims to have over 6 billion records available online. Another genealogical website, FamilySearch.org, is particularly helpful for decedents who resided in Utah, Idaho, and Wyoming. There are countless other genealogical blogs and websites to search, many of which focus on a particularly feature such as religion, national origin, ethnic background, etc. The larger genealogical websites, including Ancestry.com and FamilySearch.org, have census records available up until 1940.7 These websites also include marriage records, birth records, military records, and family trees. Family trees are created by individuals, which means they are not always accurate or complete. However, they are a great source for locating possible heirs or devisees because they may include names of descendants, biographies, and family histories. As an added feature, some websites allow communication with the person who provided the genealogical information to the website.

The more information that you can use in a search, the better the chance that: (i) you will find the decedent’s heirs or devisees and (ii) they will be the right persons. With any luck, you will gather enough information to track down possible heirs or devisees to obtain leases or send participation letters prior to drilling. Although these online genealogical resources may not finish the job, since title curative will likely be required, they can start you down the right path.

1https://www.colorado.gov/pacific/archives/archives-search.
2http://www.montana-genealogy.com/Montana-Probate-Records.htm. No subscription required, but the website links to third-party subscription websites.
3http://caselookup.nmcourts.gov/.
4http://publicsearch.ndcourts.gov/.
5http://www.texas.gov/en/discover/Pages/topic.aspx?topicid=/records. Records available for select counties only.
6http://www.utcourts.gov/xchange. Subscription required.
7Census records are sealed for 72 years after the census is taken, which means they are currently available for the 1940s and back.

Potential Pitfalls of Continuous Drilling Provisions in HBP Fee Leases

Fee Lease 101 Series, Lease Provisions,

A common but often overlooked oil and gas lease provision is the “continuous drilling” or “continuous operations” provision. Generally, a continuous drilling provision allows a temporary cessation of production without automatically resulting in the termination of an oil and gas lease that has been extended by production. In order to qualify for the temporary cessation, certain operations (as defined in the lease or by case law) must be commenced on the leased premises or lands pooled or unitized therewith within a specified time period (typically from 30 to 120 days). Two examples are as follows:

If, at the expiration of the primary term of this lease, oil or gas is not being produced on the leased premises or on acreage pooled therewith but Lessee is then engaged in drilling or reworking operations thereon, then this lease shall continue in force so long as operations are being continually prosecuted on the leased premises or on acreage pooled therewith; and operations shall be considered to be continuously prosecuted if not more than ninety (90) days shall elapse between the completion or abandonment of one well and the beginning of operations for the drilling of a subsequent well.

If, at the expiration of the primary term, oil or gas is not being produced on said land, but lessee is then engaged in drilling or reworking operations thereon, the lease shall remain in force so long as operations are prosecuted with no cessation of more than 30 consecutive days.

Continuous drilling provisions are of particular importance when analyzing older, HBP leases. Specifically, a number of situations should be considered. Has your lease produced each and every month since the expiration of the primary term? Have you or your predecessor ceased production to rework the well or recomplete in a new formation? Have severe weather conditions caused a temporary cessation of production? Each of these situations could potentially lead to a finding that your lease has expired.

Oil and gas wells generally do not have perfect production histories. Williams & Meyers states: “Since repairs, breakdowns, and reworking operations are incidental to the normal operation of a lease, the parties must have contemplated that the temporary cessation of production caused by such events would not result in automatic termination of the lease.”1 Based upon this implied understanding, if an oil and gas lease does not contain a continuous drilling provision, the lessee may extend the lease by exercising reasonable diligence in the continuance of its operations on the leased premises. In other words, courts have held that a temporary cessation of production is allowed where no specific deadline is provided.2 What is temporary? There is no hard and fast rule. An Arkansas court found a temporary cessation where a fire destroyed a producing well and production was not resumed for four years.3 However, whether a cessation of production is temporary is a question of fact that will depend on the individual circumstances.4 Although the individual facts may vary, courts typically weigh the following factors: failure of the lessor for a substantial period of time to claim forfeiture during which time the lessee was engaged in activities on the lease, absence of drainage, intent of lessee to hold the lease, and diligence of the lessee in seeking to find a market or to resume production.5 Due to the fact-intensive nature of the analysis, each circumstance must be carefully reviewed under the applicable case law in that state.

The continuous drilling provision was created in order to provide more certainty in the face of inconsistent court rulings. While providing the parties with a more reliable test, a continuous drilling provision could prove fatal to an HBP lease. According to Williams & Meyers: “Where there are express savings provisions in a lease that specify dates [i.e., 30-120 days] by which the lessee must take certain action or the lease will terminate, the temporary cessation of production doctrine will not apply so as to extend the lease beyond those specified time limits.”6 Unlike the analysis above, the specific time periods by which a lessee must recommence operations are hard and fast.7 Absent some other lease provision, mechanical issues with the well, lack of a market, or any other delay in production could cause a lease to be deemed expired in as few as 30 days without production. Therefore, careful attention should be made to the production (and operations) history on the leased premises to ensure any continuous drilling provision has been strictly observed.

Despite a constant push for greater efficiencies in acquisition due diligence and title opinions, a thorough HBP analysis should not be forgotten. Such analysis may require obtaining well records back to the date of first production, reviewing the complete well file, and investigating the cause of any delays in production.

For More Information Contact:
David B. Hatch
Phone: 801-799-5834
Email: dbhatch@hollandhart.com

1Williams & Meyers, “Oil and Gas Law” § 604.4.
2Id.
3Saulsberry v. Siegel, 252 S.W.2d 834 (Ark. 1952).
4See Watson v. Rochmill, 155 S.W.2d 783 (Tex. 1941).
5Williams & Meyers, § 604.4 at fn. 11; see, e.g., Somont Oil Co. v. A & G Drilling, Inc., 49 P.3d 598 (Mont. 2002) (finding the intent and diligence of the operator in restoring production is a factor in determining with a cessation of production is temporary).
6Williams & Meyers, § 604.4.
7See, e.g., Greer v. Salmon, 479 P.2d 294 (N.M. 1970) (finding that where the lessee didn’t strictly comply with the 90-day cessation clause the lease terminated).