lease provisions

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

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

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

Lease Rights

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

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

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

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

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

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

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

Permitting and Approval of Lease Operations

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

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

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

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

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

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

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

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

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

What Are the Types of Federal Oil and Gas Leases?

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

An Introduction to Federal Oil and Gas Leasing

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

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

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

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

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

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

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

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

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

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

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

I.      Assignment Clause

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

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

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

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

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

II.       Proportionate Reduction3

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

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

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

The following example makes a distinction between rentals and royalties:

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

III.       Warranty Clause4

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

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

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

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

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

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

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

IV.       Surrender or Release Clause8

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

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

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

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

V.       Preferential Rights to Purchase and Options10

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

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

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

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

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

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

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

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

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

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

You only have three more months on the primary term of an oil and gas lease that was issued nearly five years ago with a 1/6th royalty.  A drilling permit should be issued any day now, and you anticipate commencing operations to drill a well in sufficient time to hold the lease.  You instruct your landman to obtain a top lease from the mineral owner just in case there is a hiccup and you can’t start operations in time to hold the existing lease. Your landman negotiates a new lease from the mineral owner covering the same lands but has to agree to a 3/16ths royalty in order to obtain the top lease.  But, the top lease fails to expressly state that it is a top lease to the existing lease and doesn’t contain any other language clarifying that the top lease will only be effective if and when the underlying existing lease expires.  Despite the precautionary top lease, the well permit is issued when expected and you are able to commence drilling a well in time to hold the prior existing lease.

After the well is drilled and completed, is there a risk that the mineral owner could successfully argue that the new top lease is a replacement of the existing lease and you are required to pay a 3/16ths royalty instead of a 1/6th royalty? In the oil and gas industry, you often hear landmen and attorneys frame the question as whether or not the top lease will be deemed a “novation” of the prior existing lease. But what is the standard to prove a novation? How likely is it that the mineral owner above could successfully argue that the top lease is a novation of the prior lease, even though the well was drilled in time to hold the prior existing lease? This article will provide a brief overview of the elements and burden of proof to establish a novation.

A recent 2015 case out of Pennsylvania provides an excellent overview and example of the novation analysis in the context of oil and gas leases. In Mason v. Range Resources-Appalachia LLC, 120 F. Supp. 3d 425, 433 (W.D. Pa. 2015), an oil and gas lease was issued in 1961 in Western Pennsylvania and was arguably held by gas storage operations on the property (and by the payment of rentals). Years later, during the Marcellus shale boom, a landman working for Range Resources obtained an oil and gas lease in 2007 from the same mineral owners and covering the same lands as the 1961 lease. Range Resources only later discovered that it already owned the existing 1961 lease. Testimony in the case indicated that the leasing environment at that time was “chaotic,” that Range Resources did not have a good process for evaluating lease validity, and that landmen were taking leases without conducting complete due diligence of possible existing leases. Range Resources did not drill a well within the term of the 2007 lease, and the mineral owners asserted that the 2007 lease was a novation of the 1961 lease (which had unique provisions allowing the lease to be held by rental payments for gas storage), and that the 2007 lease then expired.

The Pennsylvania court set forth four elements to show a novation, which elements are the same or similar in other jurisdictions that have undertaken a discussion of novation:

“(1) the displacement and extinction of a prior contract, (2) the substitution of a valid new contract for the prior contract, (3) sufficient legal consideration for the new contract, and (4) the consent of the parties.”1

The Pennsylvania court further stated that “whether a contract has the effect of a novation primarily depends upon the parties’ intent” and “the party claiming the existence of a novation bears the burden of demonstrating the parties had a meeting of the minds.” The court stated that evidence of the parties’ intent to enter in to a novation can be shown “by other writings, or by words, or by conduct, or by all three.” Courts in other states have similarly emphasized that a party claiming a novation has the burden of proof, and that the party asserting the claim of novation has the burden of proving all of the required elements for a novation.2 A novation is never presumed. Instead the presumption is that the new contract was taken conditionally or as additional security, absent evidence of intention to the contrary.3 In the Pennsylvania case, the court determined that the mineral owners continued to accept rentals under the 1961 lease even during the term of the 2007 lease, and there was no evidence that the parties expressly intended to replace the 1961 lease with the 2007 lease.

Returning to our example above, the case law suggests that a mineral owner attempting to argue that the top lease was a novation of the base lease would have a very challenging case. But there is still a risk of such a claim, even if the claim is ultimately for nuisance value only. How can an operator protect itself from novation claims? Obviously, the best approach is to always put language in any top lease that makes it clear that the lease will only go into effect if and when the base lease expires by its terms, and make that intent clear in any other written correspondence to a landowner (such as an initial offer letter).

But what if an operator accidentally obtains a standard lease with no top lease language when it already owns an existing lease? For drilling purposes, the mineral interest will be leased either way. But an operator should ideally take steps to address any ambiguity resulting from the top lease and clarify the intent of the parties. If the well is successfully completed in time to hold the existing lease, the best approach would be to have the mineral owner (and operator) sign and record a ratification document where the parties acknowledge that the base lease was held by the drilling of the well, and that the top lease will remain of record as a top lease only in the event the well ceases operations.

Another approach (with attendant risks) would be to send an informative letter to a landowner prior to drilling, informing them of the pending well, stating that the operator will deem the base lease as held by the drilling of the well. That would at least set up an estoppel argument, and the operator will know prior to drilling the well whether or not the landowner objects and claims a novation. Or, an operator may simply pay proceeds on the prior existing lease, see if the landowner accepts royalty payments under that lease, and simply run the risk of a future novation claim. There may also be facts that make an operator more confident that a novation argument will be unsuccessful that justifies a riskier wait-and-see approach.4

Each fact scenario will be different, and an oil and gas lessee must evaluate the facts and risks to determine what level of clarification and curative action it requires to address risks of novation claims when there are overlapping leases.

1 Another novation case in the oil and gas context, Warrior Drilling & Eng’g Co. v. King, 446 So. 2d 31, 33-34 (Ala. 1984), framed the elements as: “[T]o establish a novation there must be: (1) a previous valid obligation, (2) an agreement of the parties thereto to a new contract or obligation, (3) an agreement that is an extinguishment of the old contract or obligation, and (4) the new contract or obligation must be a valid one between the parties thereto.”
2 In re United Display & Box, Inc., 198 B.R. 829, 831 (Bankr. M.D. Fla. 1996). See also Fusco v. City of Union City, 618 A.2d 914 (App. Div. 1993); Alexander v. Angel, 236 P.2d 561 (1951); Scott v. Bank of Coushatta, 512 So. 2d 356 (La. 1987); Credit Bureaus Adjustment Dep’t, Inc. v. Cox Bros., 295 P.2d 1107 (1956).
3 For example, a Utah court conducting a novation analysis stated: “The burden of proof as to a novation by the transaction in question rests upon the party who asserts it; … an intention to effect a novation will not be presumed; … in the absence of evidence indicating a contrary intention, it will be presumed, prima facie, that the new obligation was accepted merely as additional or collateral security, or conditionally, subject to the payment thereof; and the intention to effect a novation must be clearly shown.” First Am. Commerce v. Washington Mut., 743 P.2d 1193 (Utah 1987); see also Tri-State Oil Tool Indus., Inc. v. EMC Energies, Inc., 561 P.2d 714, 716 (Wyo. 1977).
4 For example, if the existing lease covers multiple parcels in several drilling units, and the new lease only covers one parcel, that may make an argument for a novation more difficult. Also, if there are unrecorded documents that evidence clear intent that the second lease was intended only as a top lease, that fact may make an operator more confident that a novation claim would be unsuccessful.

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

Pugh(eee)…Get Those Lands Outta Here: A Look at the Pugh Clause

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

For the unwary, Pugh clauses (pronounced “Pew”) can sometimes stink.  Although it is a fairly common provision in many fee oil and gas leases today, there is no industry standard Pugh clause.[1] As a result, the many variations of the Pugh clause can provide unpleasant surprises to both lessors and lessees who assume that all Pugh clauses operate similarly.  From an industry perspective, it is essential for landmen negotiating oil and gas leases to understand how a Pugh clause will operate an­­­­d potentially affect other provisions in the lease.  Additionally, with the sharp decrease in oil prices, many oil and gas companies have pushed drilling schedules into the indefinite future.  The delay in drilling necessitates a careful review of the underlying lease portfolios to determine when certain leases will expire. A thorough understanding of the effect of a  Pugh clause’s on a lease is vital to this review.

So What Is It?

As a general rule, production, or other operations, on “any part of the land, included in an oil and gas lease will perpetuate the lease beyond the primary term as to all of the land covered by the lease.”[2] Moreover, if lands are pooled or unitized, production or operations on any of the lands within the unit can extend all leases committed in whole, or in part, to the drilling or spacing unit.[3] This means that an oil and gas lease can be held past its primary term by production on only a small portion of the leased lands or on lands outside of the leased lands that are located in a drilling or spacing unit. Understandably, lessors can be less than thrilled to discover that all of their lands are locked-up by a lease when only a small portion of their lands are included within a drilling or spacing unit—preventing them from re-leasing their non-producing lands so that they can receive additional bonus payments, rentals, or production royalties from these lands. Without an “express provision in the lease, the lessor only has recourse to the implied covenant of reasonable development (or further exploration in a state that recognizes such a covenant)” to force additional development on the lessor’s lands or allow them to re-lease the lands altogether.[4]

A Pugh clause can prevent this scenario. Named after a Louisiana lawyer named Lawrence Pugh,[5]  the Pugh clause operates to sever the non-producing lands or interval based on some defined criteria, such as acreage or depth.[6] The impact of a Pugh clause “increases the burdens on the lessee who must take additional steps to maintain the lease as to the [non-producing portion]; this may include a return to delay rentals,” (if the lease is not a paid-up lease), “or initiation of drilling operations within a specified period.”[7] In other words, by including a Pugh clause in a lease, any production located on or attributed to leased lands will no longer be sufficient to extend the primary term for the entire leasehold. If the lessee takes no actions to extend the lease excluded by operation of the Pugh clause, the lease will expire as to these excluded lands. This provides an obvious benefit to lessors, who can once again make the forfeited lands available for lease. Since Pugh clauses are decidedly pro-lessor, they are “virtually always inserted into or attached to a lease at the insistence of the lessor’s attorney.”[8]

Horizontal and Vertical Pugh Clauses

It is important to note that Pugh clauses can be horizontal, vertical, or both.  A horizontal Pugh clause “has the effect of severing a leasehold as to the pooled and non-pooled portions on the basis of horizontal planes,” while a vertical Pugh clause “has the effect of severing a leasehold on the basis of vertical planes only.”[9] This means a Pugh clause can be structured by depth (e.g., severing all lands below 100 feet of a drilled well or the bottom of the producing zone), or by acreage.

Give Me An Example

Because there is no industry standard Pugh clause, there can be as many different forms of the clause as there are people drafting the clause.  The following is an example of a generic Pugh clause:

A producing well, or well capable of producing, will perpetuate this lease beyond its Primary Term ONLY as to those lands as are located within, or committed to, a producing or spacing unit established by Government authority having jurisdiction.[10]

This provision in an oil and gas lease operates to segregate the lease at the end of the primary term according to whether the leased lands were within a drilling or spacing unit established by the appropriate government agency. Any lands not located within a drilling or spacing unit would not be extended by production (keeping in mind, of course, that these lands could be extended by other provisions in the lease, such as those pertaining to drilling operations). As a title examiner, it’s not uncommon to see other triggering criteria in a Pugh Clause—such as one or two years after the end of the primary term, or when drilling operations on any portion of the leased lands cease for a specified amount of time.

It’s crucial to clearly specify how and when the clause will come into play, as illustrated by the following real-life Pugh clause:

Notwithstanding anything to the contrary herein, this lease shall terminate after the primary term as to all the lands not included within a drill site spaced unit as provided by the proper Governmental Authority….

This Pugh clause is poorly drafted because it segregates the leased lands only on the basis of whether they are within a “drill site spaced unit,” without clearly specifying that the spaced units must also be producing in order for the lease to be extended beyond its primary term for those lands.  Read literally, the provision raises the question of whether a lease would be extended for lands that are merely subject to a spacing order (and thus presumably within a drill site spaced unit) when there is no production within the drilling or spacing unit, assuming that there is production elsewhere on the lease lands, as was the case in this instance.[11] Although it’s likely that the parties to the lease intended that the clause include a production requirement, it’s uncertain how a court would rule if this clause was litigated, particularly since Pugh clauses tend to be strictly construed.[12]

Problematic Pugh clauses, such as the example above, often arise when the Pugh clause is merely copied and pasted from another oil and gas lease, which can result in omitted words or phrases, or inconsistencies with other provisions of the lease. Problems can also arise when a Pugh clause is drafted by a person who does not fully understand the impact of words or phrases included in, or excluded from, the provision.

Be Careful

As illustrated by the poorly drafted Pugh clause above, not all Pugh clauses are created equal, and it’s important to review and understand the specifics of a Pugh clause when negotiating an oil and gas lease, or when later evaluating how a Pugh clause affects the extension of a lease.

 

[1] 1 Bruce M. Kramer and Patrick H. Martin, The Law of Pooling and Unitization, § 9.01 (LexisNexis Matthew Bender 2015), hereinafter referred to as “Pooling and Unitization,” citing Robin Forte, “Helpful Hints: The ‘Pugh’ Clause,” 42 Landman 9 (May/June 1997) (“Just as there is no standard oil and gas lease, today there is no standard ‘Pugh’ clause.”).
[2] Adams, James W., Jr., “Lease Issues for Opinion Purposes,” Nuts and Bolts of Mineral Title Examination, Paper 11, Page No. 517 (Rocky Mt. Min. L. Fdn. 2015), hereinafter referred to as “Lease Issues”.
[3] Id.
[4] Pooling and Unitization § 9.01.  For a discussion on the implied covenant to develop as it relates to Montana law, see Miller, Adrian, “The Implied Covenant to Drill and Develop in Montana,” available at:  https://www.hollandhart.com/implied-covenant-to-drill-and-develop-in-montana.
[5] Pooling and Unitization § 9.01, ft. 3.
[6] Patrick H. Martin and Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § 669 (LexisNexis Matthew Bender 2015), hereinafter referred to as “Oil and Gas Law.”
[7] Pooling and Unitization § 9.01.
[8] Pooling and Unitization § 9.04.
[9] Oil and Gas Law § H Terms. According to one commentator, the terms “horizontal Pugh clause” and “vertical Pugh clause” are often mistaken with one another and, as a result, are used somewhat interchangeably within the industry.  Consequently, the commentator suggests that Pugh clause should clarify whether the provision affects depth or acreage. See http://landmaninsider.com/pugh-clauses/.
[10] This example is given in Lease Issues, p. 518.
[11] The question regarding this Pugh clause’s operation might be even more muddled in some states, such as New Mexico, which have standard spacing requirements.  See N.M. Admin. Code 19.15.15.
[12] Pooling and Unitization § 9.01. The treatise notes, however, that “strict construction is by no means uniform,” and “a few courts have seemed almost eager to interpret such provisions in favor of the lessor through readings that do not appear entirely reasonable.”  Id.

The Mother Hubbard Clause

Fee Lease 101 Series, Lease Provisions, , , ,

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

What is a Mother Hubbard Clause?

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

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

A Roadmap for Commencement of Drilling Operations: Are We There Yet?

Fee Lease 101 Series, Lease Provisions, , ,

For oil and gas lessees, the journey from signing a lease to having a producing well can be a long and arduous one. Countless turns, speedbumps and stops along the way can reasonably be expected. The habendum clause alone can quickly bring the lease to a screeching halt. Savings clauses have been inserted into modern fee oil and gas leases to prevent automatic termination of the lease while the lessee conducts certain operations. Discussed herein is the commencement of drilling operations savings clause which, in the majority of states, will permit a lease to be preserved after the expiration of the primary term without production if certain operations are being conducted.1 However, even with this savings clause, lessees should be particularly wary of the roadblock approaching at the end of the primary term when determining whether drilling operations were properly commenced before expiration of the primary term. Well-constructed language in a fee oil and gas lease can allow continued operations even if the primary term has expired and the drill bit has not yet broken ground.2

Which lease provision is the commencement of drilling operation clause?

The following is an example of a commencement of drilling operations savings clause:

Notwithstanding anything in this lease contained to the contrary, it is expressly agreed that if Lessee shall commence drilling operations at any time while this lease is in force, this lease shall remain in force ….

Such clauses may include variations such as “commence operations to drill a well,” “commence drilling or re-working operations,” “commence or cause to be commenced the drilling of a test well,” “commence the drilling of a well in search for oil or gas,” “commence to drill a well,” “if no well be commenced,” “lessee is then engaged in drilling for oil or gas,” “lessee is then engaged in drilling or reworking operations thereon,” or “start drilling for oil.” 3 The question to be answered is what operations must a lessee commence to preserve the lease?4

What does commence mean?

Generally, the majority of the states hold that, unless otherwise provided for in the lease, actual drilling is not necessary in order to reach the threshold for commencement of operations. Courts have proved willing to find commencement of operations even when only “modest” preparations for drilling have been made, such as erecting a part of an oil derrick and working on providing a water supply for drilling.5 Other preparatory activities such as obtaining drilling permit, staking and leveling the well location,6 building board roads to the drill site and a turn-around,7 moving tools and equipment onto the drill site, digging slush pits,8 and similar on-site activities have been held sufficient to be considered commencement of drilling operations.9 In order to reach the commencement of drilling operations threshold, a lessee should conduct as many on-site work activities as it can before the primary term expires. When determining adequate operations for commencement, courts favor active earthwork, clearing, construction, structure placement, etc., as opposed to gathering data, developing reports, obtaining permits, having meetings, and filing paperwork.

Courts have further required that such operations must be performed with the bona fide intention to proceed with good faith and diligence to the completion of the well.10 In a case where the preliminary commencement activities were performed by a company that had not yet acquired the rights to drill due to negotiations over the terms of a farmout agreement, the Wyoming Supreme Court held that the drilling operations were not done in good faith with the intent to complete insofar as the operator’s rights were qualified and contingent and may not ever be realized.11

When does the clause require actual drilling?

Some jurisdictions have differentiated between “commence operations” and “commence drilling operations.” California, Kansas, and Montana courts have made such distinctions and held that “commence drilling operations” or similar language required the drill bit to penetrate the ground prior to the end of the primary term.12 However, a Wyoming court held that there is no such distinction13 and “commence to drill a well” may be satisfied if preliminary commencement activities are not mere pretenses or a holding devise to retain the lease, if the acts are commenced and prosecuted with good faith and bona fide intention to drill and complete the well, and performed with diligence.14 Additionally, the Eighth Circuit Court of Appeals, applying North Dakota law, dismissed an argument that “engaged in drilling or reworking operations” meant “engaged in drilling” (meaning actual drilling was required) or “engaged in reworking operations;” rather, the court interpreted the clause as being engaged in “drilling operations” or “reworking operations.”15

What about off-lease operations?

With the advent of off-lease surface locations for horizontal wells, the question arises as to whether operations on or from off-lease surface locations will qualify as commencement of drilling operations on the leased lands. There is currently little guidance to answer this question. As suggested by other authors, we recommend that new oil and gas lease forms and existing oil and gas leases be amended to include a provision similar to one of the following:

(1) As used herein, the term Operations shall mean any activity conducted on or off the leased premises that is reasonably calculated to obtain or restore production, including without limitations, (i) drilling or any act preparatory to drilling (such as obtaining permits, surveying a drill site, staking a drill site, building roads, clearing a drill site, or hauling equipment or supplies); (ii) reworking, plugging back, deepening, treating, stimulating, refitting, installing any artificial lift or production-enhancement equipment or technique; (iii) constructing facilities related to the production, treatment, transportation and marketing of substances produced from the leased premises; (iv) contracting for marketing services and sale of Oil and Gas Substances; and (v) construction of water disposal facilities and physical movement of water produced from the leased premises;16 or

(2) All operations conducted off the leased premises that are intended to result in the completion of, or restoration of production from, a producing interval on the leased premises or lands pooled or unitized therewith shall be considered operations conducted on the leased premises for purposes of extending and/or maintaining this lease in effect under any other paragraph or provision hereof.17

The lease, of course, would need to be further reviewed to confirm that the use of either of the above suggestions does not create any inconsistencies or confusion and all capital terms (if applicable) are appropriately defined.

What should I do?

In determining whether a lease has been extended beyond its primary term by the commencement of certain operations less than spudding the well, it is critical the specific language of the lease, the specific facts, and case law for the state in which the leased lands are located are reviewed. Even then, it may be difficult to conclusively determine whether the lessee’s actions are sufficient absent actual penetration of the ground with a rig sufficient to reach a producing zone. Facing any uncertainty, if the lease and case law lack clear standards, the safest course of action, if possible, would be to get an extension of the lease.

1Williams & Meyers, Oil and Gas Law § 617 at 297 (2012).
2This article is limited to fee oil and gas leases. As to federal oil and gas leases, actual drilling operations must be commenced prior to the expiration of the primary term – the bit must be “turning to the right” prior to 11:59 p.m. on the last day of the primary term. 71 Interior Dec. 263 (July 10, 1964). Site preparation and even moving a rig onsite do not qualify as actual drilling operations. 43 C.F.R. § 3100.0-5(g).
3Williams & Meyers, supra note 1, § 618.1 at 311.
4Not addressed herein is whether the commencement of drilling operations clause in the habendum clause of the lease also has the effect of being a continuous drilling clause, i.e., if the well is drilled as a dry hole, does the lessee have the right to commence a second well?
5Williams & Meyers, supra note 1, § 618.1 at 320.
6Petersen v. Robinson Oil & Gas Co., 356 S.W.2d 217 (Tex. App. 1962).
7Breaux v. Apache Oil Co., 240 So.2d 589 (La. App. 1970).
8Walton v. Zatoff, 125 N.W.2d 365 (Mich. 1964).
9See Oelze v. Key Drilling, Inc., 135 Ill. App. 3d 6, 481 N.E.2d 801 (5th Dist. 1985) (a drilling rig was moved near the site, brush cleared and one of three pits were dug before the end of the primary term was found to be “commence operations for drilling”); Johnson v. Yates Petroleum Corp., 981 P.2d 288 (N.M. Ct. App. 1999) (any activities in preparation for, or incidental to, drilling a well).
10See Sword v. Rains, 575 F.2d 810 (10th Cir. 1978); Wold v. Zavanna, LLC , 2013 WL 6858827 (D.N.D. Dec. 31, 2013); Murphy v. Amoco Prod. Co., 590 F. Supp. 455 (D.N.D. 1984); Stoltz, Wagner & Brown v. Duncan, 417 F. Supp. 552 (W.D. Okla. 1976) (not required to cause the bit to pierce the earth before the end of the primary term, but must have the good faith intention to unqualifiedly drill the well, commence drilling the well on such date and pursued such drilling as a reasonably prudent operator); Haddock v. McClendon, 266 S.W.2d 74 (Ark. 1954); Oelze v. Key Drilling, Inc., 135 Ill. App. 3d 6, 481 N.E.2d 801 (5th Dist. 1985); Illinois Mid- Continent Co. V. Tennis, 122 Ind. App. 17, 102 N.E. 2d 390 (1951) (lessee lacked good faith); Flanigan v. Stern, 265 S.W. 324 (Ky. 1924) (requiring after spudding reasonably diligence and bona fide effort); Smirth v. Gypsy Oil Co., 265 P. 647 (Ok. 1928); Bell v. Mitchell Energy Corp., 553 S.W.2d 626, 632 (Tex. App. 1977); LeBar v. Haynie, 552 P.2d 1107, 1111 (Wyo. 1976).
11True Oil Co. v. Gibson, 392 P.2d 795 (Wyo. 1964).
12Lewis v. Nance, 20 Cal. App. 2d 71, 66 P.2d 708 (4th Dist. 1937); Hall v. JFW, Inc. 893 P.2d 837 (Kan. 1995); Soldberg v. Sunburst Oil & Gas Co., 235 P. 761 (Mont. 1925) (“commence drilling operations for oil”).
13Fast v. Whitney, 187 P. 192 (Wyo. 1920) (“commences drilling”).
14LeBar v. Haynie, 552 P.2d 1007 (Wyo. 1976) (“commence to drill a well”); True Oil Co. v. Gibson, 392 P.2d 795 (Wyo. 1964).
15Anderson v. Hess, 733 F. Supp. 2d 1100, 1106-07 (D.N.D. 2010) aff’d 649 F.3d 891, 898 (8th Cir. 2011) (insofar as the lessor conceded that the lessee was engaged in drilling operations before the primary term expired, the court did not address whether the lessee’s preparatory activities were satisfactory to constitute drilling operations.). See also Wold v. Zavanna, LLC , 2013 WL 6858827 (D.N.D. Dec. 31, 2013) (granting summary judgement in favor of the lessee based on Anderson v. Hess and finding “drilling or reworking operations” had been commenced when lessee obtained all drilling approvals, engaged in actual on-site construction, hauling of equipment and materials on site, installing culverts and cattle guards, and digging reserve pit prior to the expiration of the primary term and finding that the lessee had capability to drill the well and good faith intent to complete the well with reasonably diligence).
16Milam Randolph Pharo & Gregory R. Danielson, “The Perfect Oil and Gas Lease: Why Bother!,” 50 Rocky Mt. Min. L. Inst. 19-1, 19-18 (2004).
17John W. Broomes, “Spinning Straw Into Gold: Refining and Redefining Lease Provisions for the Realities of Resources Play Operations,” 57 Rocky Mt. Min L. Inst. 26-1, 26-12 (2011).

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.

Deducting Post-Production Costs From Fee Royalty

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

The phone rings. It’s your owner relations department. They just received a call from a lessor who has been taking a closer look at the information provided along with the lessor’s oil and gas royalty checks. The lessor wants to know why you are deducting post-production costs, such as transportation or compression of gas, when calculating the lessor’s royalty.

The deductibility of post-production costs can have significant implications for an oil and gas lessee. Several commentators have addressed this issue in-depth over the years.1 This article is intended to provide an introduction to the deductibility of post-production costs under fee oil and gas leases.2

Production Costs vs. Post-Production Costs

Normally, the lessee under an oil and gas lease, not the lessor, is responsible for paying the expenses of exploration and production.3 These generally include the costs associated with geophysical surveying, drilling, testing, completing, and reworking a well, as well as secondary recovery.4

Post-production costs that may, or may not, be deductible when calculating the royalty generally include gross production and severance taxes, transportation costs, and the costs of dehydrating, compressing, or otherwise processing gas (such as the extraction of liquids from gas or casinghead gas).5

Lease Provisions

When determining whether post-production costs are deductible from the royalty, the lease should be carefully examined. Sometimes the lease terms will specify whether post-production costs are deductible. For example, as part of the royalty clause, a lease may provide:

Lessee shall have the right to deduct from Lessor’s royalty on any gas produced hereunder the royalty share of the cost, if any, of compression for delivery, transportation and/or delivery thereof.6

But what if the lease does not include a provision such as the one above? Or what if the lease provides for the payment of royalty based on market value or net proceeds “at the well”7 but does not spell out the types of post-production costs that are deductible before the royalty is calculated? Is that enough?

“At the Well”

The following is an example of a gas royalty provision with “at the well” language:

Royalties to be paid by Lessee are: . . . (b) on gas, including casinghead gas or other gaseous substance, produced from said land and sold or used, the market value at the well of one-eighth (1/8) of the gas so sold or used, provided that on gas sold at the well the royalty shall be one-eighth (1/8) of the amount realized from such sales[.]8

Bice v. Petro-Hunt, L.L.C.9 provides an example of the majority view on deducting post-production costs when the royalty clause contains “at the well” language.10 In Bice, the North Dakota Supreme Court determined whether processing costs for sour gas were properly deducted when calculating the royalty under oil and gas leases that contained “market value at the well” language. The Court noted that the majority of oil and gas producing states have adopted the “at the well” rule and “interpret the term ‘market value at the well’ to mean royalty is calculated based on the value of the gas at the wellhead.”11 The Court also noted that in states that have adopted the “at the well” rule,12 a lessee has the option of calculating the market value at the well through the “comparable sales method” or the “work-back” (a/k/a “net-back”) method.13 The comparable sales method involves “‘averaging the prices that the lessee and other producers are receiving, at the same time and in the same field, for oil or gas of comparable quality, quantity, and availability.’”14 Under the work-back method, the “market value at the well” is determined by deducting reasonable post-production costs (incurred after the product is extracted from the ground) from the sales price received at a downstream point of sale.15

The Court found that the gas at issue had “no discernible market value at the well before it is processed . . . .”16 The Court reasoned that “[s]ince the contracted for royalty is based on the market value of the gas at the well and the gas has no market value at the well, the only way to determine the market value of the gas at the well is to work back from where a market value exists . . . .”17 Adopting the “at the well” rule, the Court held that the operator properly deducted post-production costs for processing prior to calculating the royalty.18

A similar result was reached in Emery Resource Holdings, LLC v. Coastal Plains Energy, Inc.19 In Emery, the federal district court in Utah was asked to interpret oil and gas leases that contained “at the well” royalty clauses20 and determine whether post-production gathering and processing costs were deductible.21 The Court noted that “[t]he majority of courts . . . have found ‘at the well’ royalty clauses to mean that natural gas is valued for royalty purposes at its wellhead location and condition.”22 Predicting what a Utah court would do when faced with this situation,23 the Court inEmery held that the “at the well” language in the leases was clear and that the parties intended for the royalty to be calculated according to the market value at the well.24 Thus, the Court allowed the operator to deduct post-production costs incurred from the wellhead separators to the pipeline in determining the market value at the well prior to calculating the royalty.25

In some states, however, including the words “at the well” in the royalty provision may not be enough. For example, inRogers v. Westerman Farm Co.26 the Colorado Supreme Court determined whether post-production costs were properly deducted under leases that provided for royalty “at the well” or “at the mouth of the well.” The Court held that the leases were “silent” as to the allocation of post-production costs, even with “at the well” language.27 The Court held that “[a]bsent express lease provisions addressing allocation of costs, the lessee’s duty to market requires that the lessee bear the expenses incurred in obtaining a marketable product. Thus, the expense of getting the product to a marketable condition and location are borne by the lessee.”28 After the product is “marketable,” any further costs incurred in improving the product or transporting it may be shared by the lessor and lessee.29 The point at which the gas is “marketable” is a question of fact for the judge or jury to decide.30 Thus, in Colorado,31 lease language that defines the royalty as being payable “at the well” or “at the mouth of the well” is not enough to allocate post-production costs.32

Conclusion

Now is the time for lessees under fee oil and gas leases to carefully examine their records, on a lease-by-lease basis, and determine whether they are properly deducting post-production costs prior to calculating the royalty. The deductibility of post-production costs depends on the lease terms and the laws of the state where the leased lands are located. Lessees should not, and in some states cannot, rely on “at the well” language to provide for the deduction of post-production costs. As needed, lessees should modify their lease forms to specifically provide for the deduction of post-production costs and identify all of the post-production costs that are deductible.


How to increase attention to detail in title examination.

1See Patrick H. Martin & Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § 645, Footnote 1 (2014) for citations to such articles.
2This article is not intended to provide a comprehensive analysis of the law on the deductibility of post-production costs or the law of any particular jurisdiction. The reader should consult with competent legal counsel regarding the law that applies to any particular situation and jurisdiction.
3Patrick H. Martin & Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § 645.1 (2014).
4Id.
5Id. § 645.2.
6Id. § 643 (quoting a Mid-Continent lease form).
7The term “at the well” is often included in the royalty clause of an oil and gas lease in defining the point of valuation of the oil and gas. Patrick H. Martin & Bruce M. Kramer, Williams & Meyers, Manual of Oil and Gas Terms 63 (2009).
8Brown, The Law of Oil and Gas Leases, 2nd Edition § 6.13 (2014) (emphasis added).
9768 N.W.2d 496 (N.D. 2009).
10Id. at 499.
11Id. at 500-501 (citing Byron C. Keeling & Karolyn King Gillespie, The First Marketable Product Doctrine: Just What is the Product?, 37 St. Mary’s L.J. 1, 51 (2005); Edward B. Poitevent, II, Post-Production Deductions from Royalty, 44 S. Tex. L. Rev. 709, 716 (2003); and Brian S. Wheeler, Deducting Post-Production Costs When Calculating Royalty: What Does The Lease Provide?, 8 Appalachian J.L. 1, 7 (2008)).
12The Court noted that Louisiana, Mississippi, Texas, California, Kentucky, Montana, and New Mexico follow the “at the well” rule. Bice, at 501 (citing Babin v. First Energy Corp., 96 1232, p. 2 (La. App. 1 Cir. 3/27/97); 693 So.2d 813, 815;Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 122 (Tex. 1996); Piney Woods Country Life Sch. v. Shell Oil Co., 726 F.2d 225 (5th Cir. 1984) (interpreting Mississippi law); Elliott Indus. Ltd. P’ship v. BP America Prod. Co., 407 F.3d 1091, 1109–10 (10th Cir. 2005); Atlantic Richfield Co. v. State, 214 Cal. App. 3d 533, 262 Cal.Rptr. 683, 688 (1989);Montana Power Co. v. Kravik, 179 Mont. 87, 586 P.2d 298, 303 (1978); Reed v. Hackworth, 287 S.W.2d 912, 913 (Ky. 1956)).
13Bice, at 501.
14Id. (quoting Keeling & Gillespie, supra, at 31-32).
15Id. (quoting Keeling & Gillespie, supra, at 32).
16Id. at 502.
17Id. The Court noted that the comparable sales method was unavailable to calculate the royalty in this case because “no comparable sales exist since the gas is not saleable at the wellhead.” Id.
18Id. For an in-depth analysis of the Court’s decision in Bice, see David E. Pierce, Royalty Jurisprudence: A Tale of Two States, 49 Washburn L.J. 347, 370-374 (2009).
19915 F.Supp.2d 1231 (D. Utah 2012).
20Most of the leases included the words “at the well” in the royalty clause. Id. at 1237. Two of the leases provided for royalty on “the proceeds from the sale of the gas, as such, for gas from wells where gas only is found . . . .” Id. at 1238. The Court examined the language surrounding this clause and concluded that “the parties intended all products produced from the wells to be valued at the prevailing market rate at the wellhead” rather than “some location downstream and away from the leased premises.” Id. at 1238-39.
21Id. at 1235.
22Id. at 1240 (citations omitted).
23Noting that the Utah Supreme Court has not directly ruled on the deductibility of post-production costs in oil and gas operations, the Court in Emery looked to the Utah Supreme Court’s decision in Rimledge Uranium and Mining Corp. v. Federal Resources Corp., 374 P.2d 20 (1962). Emery, at 1241. In Rimledge, the Utah Supreme Court found that where a deed of uranium mining claims provided for a royalty of 15% “of all gross proceeds from the sale of ore,” the parties intended for the royalty to be based on the sale proceeds of raw ore, or the fair market value of raw ore in the vicinity, rather than the value of concentrated ore after processing in the mill. Emery, at 1242.
24Id.
25Id.
2629 P.3d 887 (Colo. 2001).
27Id. at 902.
28Id.
29Id.
30Rogers, at 906.
31Other states that have rejected the “at the well” rule include Arkansas, Oklahoma, Kansas and West Virginia. Bice, supra, at 501 (citing Keeling & Gillespie, supra, at 51; Wheeler, supra, at 10).
32For an in-depth analysis of the Court’s decision in Rogers, see Pierce, supra, at 358-364; see also Martin & Kramer,supra, at § 645.