Angela Franklin

Proposed BLM Interim Guidance to Provide Relief for Oil & Gas Operators

Oil and Gas Regulations,

Lease Suspension and Reduction of Royalty Rates Available

Late on April 21, 2020, the Bureau of Land Management (BLM) issued two separate Interim Guidance statements to help alleviate some of the industry’s and BLM’s hardships created by the COVID-19 pandemic and the dramatic collapse of oil prices.

Interim Guidance for Lease Suspension Requests During the COVID-19 National Emergency

Federal oil and gas leases may qualify for a suspension of production or a suspension of operations due to force majeure provision of Section 17 of the Mineral Lease Act of 1920. Both types of suspensions toll the lease term, but the lessee must continue to pay any rental or minimum royalty payments that are due during the suspension.

  • Suspension of Operations (SO) suspends the operational obligations of the lessee on a lease where operations have begun. No operations can be conducted on the lease during the suspension. However, we note that casual uses that do not require a permit or routine maintenance are allowed.
  • Suspension of Production (SP) suspends the production obligation of the lessee on a lease where production has already been established. A lessee may continue to conduct operations on the lease.

To apply for the SO or SP under this Interim Guidance, the application must be executed by all operating rights owners and include the following:

  • Statement of the circumstances that render such relief necessary relative to the COVID-19 national emergency, despite the lessee’s due care and diligence (i.e., shelter-in-place mandates, quarantines, curtailment of travel, promoting social distance has caused lack of contractor and employees available to access and operate well sites, safety concerns, etc.);
  • Lease numbers;
  • Lease expiration and/or held by production dates;
  • Current lessee(s) and operating rights owners; and
  • Supporting evidence of the COVID-19 impact.

The application must be submitted to the appropriate BLM State Office.

If requesting the SO or SP for the suspension of operation or production obligations for an approved federal unit, the application may be executed by the unit operator on behalf of operating rights owners of the unitized tracts. Note, a unit SO or SP only suspends the obligations under the unit agreement not the obligations of individual federal leases. A separate application must be separately requested for a suspension of the specific committed lease.

BLM will have five business days to review the application. Once approved, it will be effective on the first day of the month the completed application is filed, or the date specified by BLM.

The SO or SP will expire one year from the date BLM approves the suspension or earlier if the operator resumes operations or production prior to the one-year date.

The Interim Guidance specifically does not apply to Indian leases.

Interim Guidance for Royalty Rate Reduction Requests for Oil and Gas Leases during the COVID-19 national emergency

Due to the COVID-19 national emergency and collapse of oil price, federal oil and gas leases may qualify for a royalty reduction under 43 CFR Subpart 3103.4-1.

To apply for a temporary royalty rate reduction under this Interim Guidance, the application must be executed by the operator/payor and include the following:

  • A self-certification statement with supporting documentation from the operator that the lease would be capable of production in paying quantities were it not for the extreme circumstances presented due to COVID-19 pandemic.
  • A simple economic analysis table that shows the lease(s) that is/are uneconomic at the current royalty rate, but would be economic with a royalty rate reduction, including:
    • Relevant market oil price (i.e., West Texas Intermediate spot price or basin level price);
    • Royalty rate;
    • Production capability; and
    • Operating costs (summarized for the lease)
  • The requested temporary royalty rate (i.e. reduction from 12½ to 0.5%)

All trade secrets or other proprietary data – operating costs and related data – should be marked as “confidential/proprietary.”

This Interim Guidance and application process described above also applies a reduction for Class II reinstated leases as provided for in 43 CFR 3103 and 3108.2-3(f).

BLM will have five business days to review the application. Once approved, the royalty reduction will be effective on the first day of the month the completed application is filed, or the date specified by BLM.

The royalty rate reduction will terminate one year from the date BLM approves the application; thereafter, the lease will revert to its original rate.

The Interim Guidance specifically does not apply to Indian leases.

We encourage you to visit Holland & Hart’s Coronavirus Resource Site, a consolidated informational resource offering practical guidelines and proactive solutions to help companies protect their business interests and their workforce. The dynamic Resource Site is regularly refreshed with new topics and updates as the COVID-19 outbreak and the legal and regulatory responses continue to evolve. Sign up to receive updates and for upcoming webinars.

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

FAQs of Federal Oil and Gas Leases, , , ,

By Angela Franklin and Andy LeMieux

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

Lease Bonds Generally

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

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

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

Assignments and Bonding Requirements

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

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

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

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

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

Unit Operator’s Bonds

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

Conclusion

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

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

[2] 43 CFR § 3104.1.

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

[4] 43 CFR §§ 3104.2, 3104.4.

[5] Id. § 3100.0-5.

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

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

[8] 43 CFR § 3104.1.

[9] Id. § 3104.2.

[10] Id. § 3104.3

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

[12] 43 CFR § 3104.6.

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

[14] 43 CFR § 3106.2.

[15] Id. § 3106.6-1.

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

[17] Except as to individual lease bond.

[18] Id. § 3106.7-2.

[19] 43 CFR § 3106.6-1.

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

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

[22] 43 CFR § 3104.4.

BLM Directives Rein In the Federal APD Environmental Review Process

Federal Lands, Oil and Gas Regulations

This article was also authored by Nils Lofgren, a law clerk at Holland & Hart.

In the first two weeks of June 2018, the Bureau of Land Management (BLM) issued two directives streamlining and clarifying the environmental review process undertaken by the BLM to approve an application for permit to drill (APD). The first directive was issued on June 6, 2018, as Information Bulletin (IB)1 2018-061, NEPA Efficiencies for Oil and Gas Development, found at https://www.blm.gov/policy/ib-2018-061. IB 2018-061 prioritizes the creation of efficiencies to meet the BLM’s requirements under the National Environmental Policy Act (NEPA),2 from using existing environmental analyses to evaluating groups of APDs under a Master Development Plan.

The second directive was issued on June 12, 2018, as Permanent Instruction Memorandum (PIM)3 2018-014, Directional Drilling into Federal Mineral Estate from Well Pads on Non-Federal Locations, found at https://www.blm.gov/policy/pim-2018-014. PIM 2018-014 supersedes IM 2009-078 and emphasizes that the BLM’s regulatory jurisdiction is limited to Federal lands and Federal actions. To the extent surface facilities are located on non-Federal lands, the BLM’s jurisdiction extends mainly to ensure production accountability for royalties from Federal and Indian oil and gas.

1. IB 2018-061 NEPA Efficiencies for Oil and Gas Development

On July 5, 2017, the Secretary of Interior issued Order No. 3354, Supporting and Improving the Federal Onshore Oil and Gas Leasing Program and Federal Solid Mineral Leasing Program, directing the BLM to develop a strategy to address approving APDs efficiently and effectively as well as reducing the processing time. In response, IB 2018-061 was issued on June 6, 2018 “to remind BLM offices of the existing procedures for streamlining NEPA review under applicable statutes, regulations, and guidance and to encourage BLM offices to use these tools consistently and effectively.”

The IB first directs the BLM to consider whether it can rely on existing NEPA analyses for assessing the impacts of a proposed action and possible alternatives. If so, the BLM should: document its reliance on the existing analyses in a Determination of NEPA Adequacy (DNA); incorporate the analyses into a new NEPA document; or tier the new analysis so that the existing analyses are effectively used as support for the new proposed action. This is the BLM’s new preferred option of NEPA compliance for APDs. If there are no existing NEPA analyses, the BLM is directed to consider using an applicable categorical exclusion (CX), such as those identified in the Energy Policy Act of 2005, Federal regulations, and the Departmental Manual. Thereafter, the BLM is directed to use other methods in its effort to streamline NEPA compliance. For instance, APDs and applicable infrastructure should be grouped into a Master Development Plan (MDP) and evaluated in one NEPA document. Additionally, NEPA reviews should be tiered to existing NEPA documents when available.

Of particular note regarding the NEPA public review requirement, the IB emphasizes the discretion of decision-makers in determining public involvement. It states that public review may be necessary when: (1) the proposal is borderline; (2) it is an unusual case, a new kind of action, or a precedent-setting case, such as a first intrusion of even a minor development into a pristine area; (3) a scientific or public controversy exists over the effects of the proposal; or (4) it involves a proposal that is similar to one that normally requires preparation of an environmental impact statement. The IB clearly points out that a public review may not be necessary outside of these situations and the decision-maker can avoid unnecessary reviews through his or her discretion.

2. PIM 2018-014 Directional Drilling into Federal Mineral Estate from Well Pads on Non-Federal Locations

In 2009, IM 2009-078 was issued establishing procedures for processing a Federal APD for a well to be directionally drilled into Federal minerals from a multi-well pad located on fee5 surface and minerals and when the Federal minerals are located outside of the well pad location (Fee/Fee/Fed well).6 This IM found that although the BLM had no jurisdiction over the construction, operation, and reclamation of the well pad and infrastructure on the fee lands, Federal environmental laws applied, including NEPA, the National Historic Preservation Act (NHPA), and the Endangered Species Act (ESA) (collectively, the Acts). In approving an APD, the BLM had the responsibility to comply with the Acts and to consider the direct, indirect, and cumulative effects of the construction and operation of the well pad and infrastructure even though occurring on fee lands. Accordingly, the BLM could require that pre-drilling onsite inspections be undertaken and that additional information be provided to comply with the Acts. Furthermore, the operator was required to obtain permission from the fee owner granting the BLM access to perform surveys and inspections for its analysis under the Acts.

On June 12, 2018, the BLM issued PIM 2018-014, superseding IM 2009-078, again addressing the environmental analysis to be conducted by the BLM under the Acts in the APD review process for Fee/Fee/Fed wells. The PIM emphasizes that the Federal action to be analyzed is the approval of the APD and the BLM’s environmental analysis should be focused accordingly. It addresses the application of the Acts in processing an APD for a Fee/Fee/Fed well under the following three situations:

Situation 1: Pre-existing well pad with no new surface disturbances. As to NEPA, the BLM should follow the guidance set forth in IB 2018-061 above, and determine whether a DNA or CX is appropriate. If neither is available, an EA or EIS will be required. For all of the Acts, the environmental analysis should be limited to the environmental effects of the downhole operations to be approved, such as: the proposed casing and cementing program and potential effects on aquifers and other subsurface resources; potential of drilling, completion, or production fluids migrating outside of the production zone; and the effects related to drilling and operating the Federal wellbore (e.g., dust, noise, and traffic). The cumulative effects on resources affected by approving the APD should include acknowledgment of any ongoing or future environmental effects of other actions, if the effects are relevant to assessing how the Federal action will affect specific resources. For example, if APD approval is expected to result in additional dust, noise, and traffic associated with drilling the Federal wellbore, the dust, noise, and traffic associated with the non-Federal drilling occurring from the well pad should be acknowledged in the cumulative effects analysis.

Situation 2: Pre-existing well pad with additional new surface disturbances (e.g., well pad expansion). Same as Situation 1. Additionally, the environmental analysis should consider the potential effects of the additional disturbance that would result from the approval of the APD. For example, where an existing pit is to be used, the environmental analysis should consider the potential environmental effects of operating the pit in support of the Federal well, but should not consider the pre-existing pit structure as an environmental effect of approving the APD.

Situation 3: New proposed well pad for Federal well(s), no existing surface disturbances. If it appears the new pad will be built as proposed even without a Federal APD, then the environmental analysis should be the same as Situation 1, focused on downhole disturbances. If the well pad will be built only if the Federal APD is approved, then all environmental effects associated with construction and operation of the well, including the well pad, access roads, pipelines, or other infrastructure, as appropriate, must be considered.

Additionally, the PIM provides the BLM with general guidance for processing APDs for Fee/Fee/Fed lands. The following is a brief overview:

  1. APD Submission: At a minimum, the BLM field office will require the submission of the APD using the Automated Fluid Minerals Support System, the processing fee, drilling plan, well plat, operator certification, and evidence of a 3104 performance bond coverage. No other APD submission provisions of Onshore Order No. 17 or 43 CFR § 3162.3-1 will apply. The BLM has no jurisdiction to require an APD before an operator begins pad and road construction or drilling on the non-Federal land. However, an approved APD is necessary before an operator drills into the Federal minerals.
  2. Bonding: The BLM has no authority to require a bond to protect the fee surface owner’s interests. Federal oil and gas bonds for Fee/Fee/Fed wells should be used to address downhole concerns only.
  3. Surface Access: The BLM has no authority to enter the fee lands without the surface owner’s consent. The inability to access the well pad surface is not a sufficient reason to deny an APD; however, the BLM may deny the APD if the lack of access prevents it from meeting its obligation under the Acts. After the APD is approved, the BLM must have access to the wellsite to perform necessary inspections. If access is denied, the BLM may order federally approved operations halted and the well shut-in.
  4. NEPA: See IB 2018-061 and descriptions of the Situations above. After the APD is approved, if the BLM becomes aware of new facilities, activities, or surface disturbances for which no BLM approval was required, the BLM has no obligation to evaluate these new facilities.
  5. ESA: See descriptions of the Situations above. Compliance with Section 7 of the ESA will be required if the BLM determines that the Federal action, approval of the APD, “may affect” listed species or critical habitat (e.g., the dust from drilling the Federal well might interfere with nesting of a listed species).
  6. NHPA: See descriptions of the Situations above. Under NPHA Section 106 (54 U.S.C. 306108), the BLM is required to consider the effect of a Federal undertaking on any “historic property.” Approval of an APD is a Federal undertaking even when the impacts are on fee lands. The BLM’s level of effort in identifying historic properties should reflect the circumstances surrounding the APD. If the BLM is unable to gain access to the fee lands, it should employ alternative methods of gathering information. The BLM may impose a condition of approval on the APD that requires the operator to inform the BLM if the operator discovers any historic properties during operations approved under the APD.
  7. Resource Management Plan Conformance: Resource Management Plans (RMPs) do not govern the use of non-Federal lands. Management actions in an RMP should only apply to the extent the activities authorized under the APD will impact Federal lands.
  8. Inspection and Enforcement: The BLM’s inspection and enforcement authority is generally limited to downhole operations, wellbore integrity, and production accountability directly related to the production of Federal minerals. Regarding the disposition of Federal production, the BLM retains full authority and responsibility for inspections, including those pertaining to measurement and handling of production from lands committed to a federally approved unit. Inspection and enforcement authority does not extend to the drilling of non-Federal wells or the handling and storage of non-Federal production. Generally, the BLM’s inspection and enforcement authority does not extend to surface operations without production accountability implications.

To the extent IB 2018-061 and PIM 2018-014 can create efficiencies and a pathway to the timely processing of APDs for the development of Federal minerals, they are a welcome relief to the oil and gas industry.

If you have any questions about these cases two directives, please contact Angela Franklin or a member of Holland & Hart’s Oil and Gas team.

1IBs are temporary directives that supplement the BLM manual sections but do not contain new BLM policy, procedures, or instructional material.
2NEPA requires every federal agency to consider the effect of its proposed actions before approving “major Federal actions significantly affecting the quality of the human environment.” 40 CFR § 1500.1(a). NEPA sets forth the procedural process to be followed by the agency prior to reaching a decision on such proposed actions. Among other things, it must consider the environmental impacts of the proposed action, any unavoidable adverse environmental effects, and reasonable alternatives to the proposed action. NEPA only applies when the agency has discretion over a proposed action to either approve or disapprove. Major Federal actions that trigger NEPA include leasing of federal, Indian, and allotted lands, APDs, access roads, pipelines, and typically any type of surface disturbance.
3Instruction memoranda (IMs) are directives that supplement the BLM manual sections and handbook with new policies or procedures, interpret existing policies, or provide one-time instructions. IMs can be either permanent or temporary. Permanent IMs provide lasting guidance and remain in effect until superseded or deleted. Temporary IMs are operational, incident-specific, projected related, or one-time policy or guidance for evolving activities and expire at the end of the third fiscal year following issuance.
4Federal including federal, Tribal, and allotted.
5Fee including private, state, and other non-Federal governmental entities.
6This does not apply to split-estate situations where the surface estate is fee and the mineral estate in the same lands is Federal.
7Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Onshore Oil and Gas Order Number, 1, Approval of Operations, 72 F.R. 10308 (March 7, 2007), as amended.

What Are the Types of Interests in Federal Oil and Gas Leases and How Are They Assigned?

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

Federal oil and gas leases are administered by the Bureau of Land Management (“BLM”) pursuant to the Mineral Leasing Act of 1920, as amended (“MLA”), and the implementing federal regulations. Federal leases have a slightly different ownership scheme than fee oil and gas leases. As to fee leases, the lessee owns a leasehold interest that includes the right to drill for and produce the leased substances, subject to royalty payments to the lessor. The term “working interest” is commonly used and is generally considered synonymous with the lessee’s interest and the term “leasehold interest.” As to federal leases, the lessee’s leasehold interest includes both record title and operating rights. Initially, these two types of interests are merged together as  the record title interest, but the operating rights interest can be severed from the record title interest by assignment.  The record title interest includes the obligation to pay rent and the rights to assign and relinquish the lease.[1] The operating rights interest authorizes the holder to drill for and conduct operations and produce the leased substances.[2] When all or a portion of the operating rights have been severed from the record title, the operating rights interest owner is primarily liable for its pro rata share of payment obligations under the lease while the record title interest owner is secondarily liable.[3] At the extreme, if all of the operating rights as to all depths are severed by assignment from the record title interest, the lessee owns “bare” record title interest and has no rights to drill for and produce the leased substances. The term “working interest” is generically associated with the operating rights interest unless said operating rights interest has not been severed from the record title interest, then it is associated with the record title interest. Otherwise, the range of interests that may be created out of federal leases is nearly the same as fee leases.

The interests in federal leases are generally conveyed by a “transfer,” being defined in the federal regulations as “any conveyance of an interest in a lease by assignment, sublease or otherwise.”[4] Set forth below is a discussion of the different types of interests that may be transferred in federal leases and whether the instrument transferring the interest must be filed with and approved by the BLM.[5]

Record Title Interests

The MLA and federal regulations use the term “assignment” for a transfer of all or a portion of the lessee’s record title interest in a lease.[6] All assignments of record title interests must be on the currently approved BLM form Assignment of Record Title Interest in a Lease for Oil and Gas or Geothermal Resources, Form 3000-003.[7] Record title interests may be transferred as to all or part of the acreage in the lease or as to either a divided or undivided interest therein.[8] Record title interests may not be transferred as to limited depths or horizons, separately as to either oil or gas, less than part of a legal subdivision,[9] or less than 640 acres (outside of Alaska).[10]

Upon receipt of the assignment, the BLM will engage in an “adjudication” process whereby the BLM will determine and identify the owners of interests and their percentage interest in the lease as a consequence of the assignment and approve the assignment if it meets all statutory and regulatory requirements. The rights of the assignee will not be recognized by the BLM until the assignment has been approved.[11]

Operating Rights Interests

The MLA and federal regulations use the term “sublease” for a transfer of a non-record title interest in a lease, including a transfer of operating rights. All transfers of operating rights interests must be on the currently approved BLM form Transfer of Operating Rights (Sublease) in a Lease for Oil and Gas or Geothermal Resources, Form 3000-3a.[12] For transfers of operating rights interests, the MLA and federal regulations do not contain any limitations on such transfers other than it must be as to “all or part of the acreage in the lease.”[13]

Upon receipt of the transfer, the BLM will engage in the adjudication process to determine and identify the owners of interests and their percentage interest in the lease as a consequence of the transfer and approve the assignment if it meets all statutory and regulatory requirements. The rights of the transferee will not be recognized by the BLM until the transfer has been approved.[14]  However there was a period of time where most state offices of the BLM did not adjudicate transfers of operating rights.

Beginning in 1985, the BLM issued internal guidance, Washington Office Instruction Memorandum No. 1986-175 (Dec. 30, 1985) (“IM 1986-175”), stating that it was not necessary for the BLM to “adjudicate” operating rights assignments[15] on the grounds that they are third-party contracts. The BLM adjudicators were instructed to stop adjudicating operating rights transfers, and to instead “rubber stamp” them within 30 days of their submission when there was no “evidence to the contrary regarding qualifications and proper bonding.”[16] Accordingly, most BLM offices began accepting transfers of operating rights and “approved” the transfers without confirming and determining the ownership of the operating rights interests. In 2013, the BLM issued Instruction Memorandum No. 2013-105 (April 4, 2013) (“IM 2013-105”), directing all BLM offices to immediately begin again adjudicate transfers of operating rights interests.[17]  Understanding that there would be a backlog to carry this out this directive, IM 2013-105 provides a priority schedule for adjudicating existing and future transfers of operating rights as follows: if first production occurs on or after October 1, 2012, adjudicate all transfers of operating rights immediately; if first production occurred prior to October 1, 2012, adjudicate as necessary to enable the Office of Natural Resources Revenue (“ONRR”) to issue appropriate orders to the owners; and adjudicate all remaining unadjudicated operating rights transfers when time and staffing allows.

Obviously, the BLM offices are faced with trying to adjudicate and determine the current operating rights interest owners based on over thirty years of potentially incomplete and possibly erroneous transfers contained in the BLM lease files. A survey was conducted in 2017 of the following BLM State Offices to determine how they were implementing IM 2013-105 and adjudicating transfers of operating rights.[18]

Colorado

For leases occurring prior to 2012, the Colorado State Office is only conducting reviews for leases with production at the request of ONRR. When it discovers discrepancies, it considers those transfers null and void from their inception and does not provide or send out unapproved operating rights decision letters because the transfers were never adjudicated. Colorado is not willing to accept county records or other outside sources to assist in curing title deficiencies. For leases occurring after October 1, 2012, the Colorado Office will adjudicate all transfers accordingly.

Montana, North Dakota, South Dakota, and Utah[19]

The Montana and Utah State Office never stopped adjudicating transfers of operating rights; accordingly, IM 2013-105 did not change how they are adjudicating such transfers.

New Mexico, Kansas, Oklahoma, and Texas[20]

The New Mexico State Office is conducting a piecemeal review of its lease files. Initially, when the New Mexico State Office received a new assignment and could not account for the purported interest to be assigned, they retroactively denied previously approved transfers either (a) all the way back until the title examiner could account for the purported interest; or (b) through 1991. It appears that recently, the New Mexico State Office has become willing to consider outside records in examining title to fill in gaps in currently filed assignments, such as recorded assignments, evidence of corporate successions, etc.

Wyoming

The Wyoming State Office adjudicates operating rights for all new leases, as well as any adjudications requested by ONRR. It also has plans to adjudicate operating rights for all producing leases according to staff availability. The Wyoming State Office is currently using the Lease Interest Worksheet to chain title retroactively and adjudicate operating rights at the request of the ONRR. During this review, and when any new transfer is filed, if the State Office examiner cannot account for the purported interest to be assigned, they stamp the Lease Interest Worksheet “discrepancy.” Thereafter, the Wyoming State Office will not approve any subsequent transfer until the problem in the chain of title is resolved. No notice of the discrepancy is provided to the parties who received interests through transfers now marked with a discrepancy, so without review of the current BLM case file for each lease or subsequently denied transfer, parties who believed they previously owned operating rights are not aware their rights have been called into question. This requires the Wyoming State Office to deny any subsequent transfers for leases containing a discrepancy, and to disregard any assignments occurring before the discrepancy that were previously approved.

In an attempt to complete a chain of title, bring current its files, and resolve any discrepancies, the Wyoming State Office is accepting a certified copy of an assignment recorded in the county records and attached to a BLM form Transfer of Operating Rights that is completed by general references to the attached county assignment. The Wyoming State Office will issue a decision stating that its records are incomplete and in order to complete its records, it is accepting and approving the assignment.

Overriding Royalty Interests, Production Payments, and Other Interests

The federal regulations make specific reference to only two other types of interests, overriding royalty interests and production payments.[21] Transfers of these interests must be filed with the BLM and will be included in the lease file, but are not subject to BLM approval.[22] While they can be filed on either a BLM form assignment,[23] any form of assignment may be used.

While net profits interests and carried interests are not expressly mentioned in the regulations governing assignments of interests, such interests are included in the definition of “interest.”[24] The usual practice is to follow the same filing procedures prescribed from assignments of overriding royalty interests and production payments above.

Liens and Security Interests under Mortgages and Other Financing Instruments

Liens and security interests in federal leases created under mortgages and other financing instruments do not fall within the definition of “interests” under the regulations and are not required to be accepted for filing under the regulations. Most BLM offices will discourage or even reject the filing of mortgages and other financing instruments. As a result, mortgages and other financing instruments are typically only filed in the county records.

Transfers by Operation of Law

The regulations identify two types of transfers by operation of law: death and corporate reorganization. When an owner dies, his or her rights will be recognized as having been transferred to the heirs, devisees, executor, or administrator of the estate, upon the filing of a statement that all parties are qualified to hold an interest in a federal lease.[25] The BLM office will typically also require, along with the statement, supporting information concerning the demise of the owner.

In the case of corporate name change, merger, or conversion, no assignment is required unless otherwise required by state law. The regulations require that notification of the name change, merger, or conversion be furnished in the proper BLM office.[26]

_____________________

Prior to filing any transfer with the BLM, it is always to the advantage of the parties to the transfer to make inquiry of the oil and gas adjudication personnel at the applicable BLM office to confirm that the parties have prepared the transfer in compliance with the office’s policies and procedures.

[1] 43 CFR § 3100.0-5(c). Record title is the ownership in a federal lease as recognized by the BLM.  Therefore, it has no connection to the title or leasehold ownership reflected in the applicable county records.

[2] 43 CFR § 3100.0-5(d). The term “operating rights” should not be confused with the right to serve as operator on the ground. An operator is the person or entity that is responsible under the terms and conditions of the lease for operations being conducted on the leased lands; it can include, but is not limited to, the lessee record title interest owner or operating rights interest owner. See 43 CFR § 3160.0-5

[3] See 43 CFR §§ 3106.7-6(b), 3216.12.

[4] Id. § 3100.0-5(e).

[5] Not addressed herein are the qualifications to own an interest in a federal lease and the specific filing requirements.

[6] Id. § 3100.0-5(e).

[7] Most recent revision date is August 1, 2015.

[8] Id. § 3106.1(a). Note, the assignment of the entire interest in a portion of the leasehold will result in a segregation of the lease.

[9] Generally, requiring all of a governmental lot or quarter-quarter section under the Public Land Survey System.

[10] 30 USC § 1987a; 43 CFR § 3106.1. The 640 acre limitation was added to Section 30A of the MLA in 1987 pursuant to the Federal Oil and Gas Onshore Leasing Reform Act. Assignments of record title of less than 640 acres will be approved if the assignment constitutes the entire lease or is demonstrated to further the development of oil and gas.

[11] 43 CFR § 3106.1(b).

[12] Most recent revision date is August 1, 2015.

[13] 43 CFR § 3106.1. There is no written guidance defining “part of the acreage” or addressing this apparent acreage requirement. It appears that at least some minimal amount of acreage must be transferred to comply. Accordingly, although some BLM State offices will accept transfers of operating rights for less than 40 acres, they will not accept for approval, or even for filing purposes only, transfers of operating rights in a wellbore only.

[14] Id. § 3106.1(b).

[15] The term “assignment” is used generically in the IM applying to an assignment of either a record title interest or an operating rights interest.

[16] IM 1986-175.

[17] IM 2013-105 was issued in direct response to the 1996 amendment to Section 102(a) of the Federal Oil and Gas Royalty Management Act, 30 USC § 1712(a), providing that the owner of the operating rights shall be primarily liable for its pro rata share of payment obligations under the lease and the owner of the record title interest (if different from the owner of the operating rights interest) became secondarily liable. The federal regulations at 43 CFR Section 3016.7-6 and 3216.12, reflect these same principals. Furthermore, the BLM form Transfer of Operating Rights (Sublease) in a Lease for Oil and Gas or Geothermal Resources specifically provides that the transferee’s signature “constitutes acceptance of all applicable terms, conditions, stipulations, and restrictions pertaining to the lease… (Part B, paragraph 3) and “upon approval of a transfer of operating rights (sublease), the sublessee is responsible for all lease obligations under the lease rights transferred to the sublessee” (Part C, paragraph 8).

[18] See Jared A. Hembree and Uriah J. Price, Holding a Wolf by the Ears – A Look into BLM’s Policy on the Retroactive Adjudication of Operating Rights, 63 Rocky Mt. Min. L. Inst., Paper 11 (2017) (not yet published).

[19] The Montana State Office administers federal lands in Montana, North Dakota, and South Dakota. The Utah State Office administers federal lands in Utah only.

[20] The New Mexico State Office administers federal lands in New Mexico, Kansas, Oklahoma, and Texas.

[21] 43 CFR § 3106.1.

[22] 43 CFR § 3106.1(b).

[23] Both of the current BLM forms include a box that can be checked to indicate that it is for an overriding royalty interest assignment.

[24] 43 CFR § 3000.0-5(1).

[25] Id. § 3106.8-1.

[26] Id. § 3106.8-3.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[6] 30 U.S.C. §§ 301 to 306.

[7] 30 U.S.C. § 301 (emphasis added).

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

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

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

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).

Force Majeure – May the Force Be With You and Save Your Oil and Gas Lease

Fee Lease 101 Series, Lease Provisions, , , , , , ,

In Star Wars, the force means an “energy field created by all living things… It binds the galaxy together.”1 In French, force majeure means superior force. In a fee oil and gas lease, the force majeure clause is designed to protect the lessee from being liable for damages or the lease from terminating for causes beyond the lessee’s control. The lease typically contains numerous clauses designed to protect the lessee and save the lease when particular events occur. Such clauses include the shut-in royalty, dry hole, cessation of production, continuous drilling, and entirety clauses. We have addressed most of these clauses in this blog, The Oil and Gas Report.2 The force majeure clause is often thought of as the savings clause of last resort. Force majeure clauses vary widely and their application depends on the specific language of the clause.

Force Majeure Events: “Judge me by my size, do you?”3

The events covered by the force majeure clause can vary from narrowly defined events to broad acts of God. Some clauses are limited to excusing performance only when it is prevented by governmental actions through laws, rules, regulations, or orders. For example:

All terms and express or implied covenants of this lease shall be subject to all Federal and State Laws, Executive Orders, Rules, or Regulations, and this lease shall not be terminated in whole or in part, nor Lessee held liable in damages, for failure to comply therewith if compliance is prevented by, or if such failure is the result of any such Law, Order, Rule or Regulation.4

Other force majeure clauses excuse performance for a comprehensive array of events. For example:

The term “force majeure” as used herein shall be Acts of God, strikes, lockouts, or other industrial disturbances, acts of the public enemy, wars, blockades, riots, epidemics, lighting, earthquakes, explosions, accidents or repairs to machinery or pipes, delays of carriers, inability to obtain materials or rights of way on reasonable terms, acts of public authorities, or any other causes, whether or not of the same kind as enumerated herein, not within the control of the lessee and which by the exercise of due diligence lessee is unable to overcome.5

Courts will carefully scrutinize the list of events identified in the clause to judge whether the subject event is covered in the force majeure clause.6 Additionally, courts have held that the force majeure event must be outside of the lessee’s control7 and the lessee cannot be the cause of the event.8

Performance Excused: “Do. Or do not. There is no try.”9

The force majeure clause will only excuse the performance identified therein. Care should be exercised in determining whether the clause applies to the performance of general or specific covenants or conditions. Generally, failure to perform a covenant will not automatically result in termination of the lease; however, failure to perform a condition will automatically cause the lease to terminate.10 Following are some examples of the types of performance that may excused in the force majeure clause:

    • all terms and express or implied covenants;
    • lessee’s obligations whether express or implied;
    • drilling operations or compliance with the provisions of this lease, both expressed and implied;
    • drilling, working or production operations; or
    • performance or operations.

The force majeure clause may only apply to part of the lease term, i.e., the primary term or secondary term. For instance, if rentals are due during the primary term and a force majeure event occurs, some forms excuse the rental payment; however, others require payments continue to be made, and others are silent on payment. If the lease is in the secondary term and a force majeure event occurs, the clause may require a royalty or a minimum royalty payment during the force majeure event to keep the lease alive without drilling or production. For example:

If after the expiration of the primary term and while the lease is in force and the lessee cannot maintain the same in effect because prevented by force majeure, then the lease will nevertheless continue, but lessee will pay to the owners as royalty an amount equal to ___ dollar per year for each acre retained hereunder.11

If payments are due after the beginning of the force majeure event, the force majeure clause should describe when the payments are due, such as a reasonable time after the occurrence of the event, with subsequent payments due on the anniversary date of the lease, and calculation of a prorated amount due if the event occurs and ends on a date other than the anniversary date.

The force majeure event typically must prevent, delay, interrupt, or make impossible performance of the specified covenants or conditions. Although performance may appear impossible, some courts are willing to look at alternatives the lessee should have attempted before invoking the force majeure clause.12 The force majeure clause comes into effect only if the performance is rendered impossible unless the subject clause contains less exacting terms, then, in some cases, it may be invoked if performance is unreasonably burdensome.13

Reconciling Lease Provisions:”Use the Force, Luke.”14

To use the force majeure clause, it must be reconciled and construed along with all the other provisions of the lease. Generally, courts will refuse to excuse performance under the force majeure clause if another clause is applicable, such as excusing production by the payment of shut-in royalties.15 Similarly, courts have been willing to find that a cessation of production for whatever reason is not relieved by the force majeure clause if the lease contained a cessation of production clause requiring commencement of operations for drilling or reworking on the leased premises within a defined amount of days and the force majeure event did not prevent commencement of drilling or reworking operations.16

The interplay of the habendum clause17 and force majeure clause was the subject of two nearly identical cases in which the lessees claimed as a force majeure event the State of New York’s highly publicized moratorium, and now ban, on high volume hydraulic fracturing (“fracking”) of horizontal wells. The lessees invoked the force majeure clause claiming that the fracking moratorium prevented them from drilling on the leased lands prior to the expiration of the primary term.18 On appeal of one of the cases to the United States Second Circuit Court of Appeals, the federal Court of Appeals asked the state court19 to answer two previously unanswered questions of state law: (1) under New York law did New York’s moratorium constitute a force majeure event; and (2) if so, does the force majeure clause modify the habendum clause and extend the leases’ primary terms?20

Each of the subject leases contained a habendum clause providing that the lease “shall remain in force for a primary term of FIVE (5) years from the date hereof and as long thereafter as the said land is operated by Lessee in the production of oil or gas.” The leases also contained the following force majeure clause:

[i]f and when drilling or other operations hereunder are delayed or interrupted … as a result of some order, rule, regulation, requisition or necessity of the government, or as a result of any other cause whatsoever beyond the control of the Lessee, the time of such delay or interruption shall not be counted against Lessee, anything in this lease to the contrary notwithstanding. All express or implied covenants of this lease shall be subject to all Federal and State laws, Executive Orders, Rules or Regulations, and this lease shall not be terminated, in whole or in part, nor Lessee held liable in damages for failure to comply therewith, if compliance is prevent by, or if such failure is the result of any such Law, Order, Rule or Regulation.

(Emphasis added)

Unfortunately, the state court punted on the first question, rendering it academic by its answer to the second question. The court stated that the force majeure clause does not modify the primary term of the habendum clause and, therefore, a force majeure event cannot be used to extend the leases’ primary terms. Importantly, the state court found that the habendum clause in the leases does not incorporate the force majeure clause by reference or contain any language expressly subjecting it to the other lease terms and the force majeure clause does not refer to the habendum clause with specificity; therefore, the habendum clause is not expressly modified or enlarged by the force majeure clause. It found that the phrase in the force majeure clause “anything in this lease to the contrary notwithstanding” does not supersede all other clauses in the lease, just those in which it is in conflict, and the habendum and force majeure clauses are not in conflict during the primary term of the lease. Additionally, the court stated that the force majeure clause pertains only to express or implied covenants (the lessee’s obligations) and, in the primary term, the covenant is to pay rentals (not drilling). As to the secondary term of the habendum clause, the court did recognize that since the force majeure clause expressly refers to a delay or interruption in drilling or production, the force majeure clause modified the secondary term of the habendum clause in which the lessee has the obligation to produce oil or gas or the lease terminated. The court stated that drilling and production operations are covenants only applicable to the secondary term of the lease. Finally, the court made the distinction between termination and expiration noting that the force majeure clause expressly deals with lease termination, something that only occurs in the secondary term, rather than lease expiration that occurs at the end of the primary term. The court stated that if the lessees intended for the habendum clause to be subject to other provisions of the contract, they could have expressly done so.21 Accordingly, the United States Second Circuit Court of Appeals applied the law as set out by the state court and held that under New York law the force majeure clause did not modify the habendum clause. Therefore, even if the moratorium was a force majeure event, it did not operate to extend the leases.22

The lesson of the Beardslee decision is that in similarly drafted leases, the force majeure clause is basically inapplicable to the primary term and, if the lessee is prevented or delayed from drilling and the force majeure clause is not applicable, the primary term of the lease will continue on and the lessee will have no way in which to extend the lease into the secondary term.

Conclusion: “The Force is strong with this one.”23

To invoke superior force, such force must be understood. In drafting the lease, careful consideration should be given to: (1) the lease play and anticipated operations; (2) defining the force majeure events in the force majeure clause in a sufficient manner; (3) defining the covenants, conditions, and obligations, with consideration to the primary and secondary terms, in the force majeure clause that will be excused upon the occurrence of a force majeure event; (4) incorporating by reference the force majeure clause in the habendum clause and any other pertinent clauses; and (5) reconciling all of the lease provisions. If dealing with the preservation of an existing lease, the safest route may be to request a ratification and amendment of the lease or other such agreement with the lessor confirming the existence and status of the lease and obtaining an extension thereto as necessary; of course, this is assuming that the lessor is willing to execute such an agreement.

Under general principles of contract interpretation, the courts will construe the lease against the party who drafted it, most often the lessee. Fracking bans and other prohibitions on oil and gas exploration and production exist across the country24 and depending on the results of the 2016 Presidential Elections,25 lawsuits claiming that the force majeure clause will not save an oil and gas lease during a fracking ban may become more prevalent. Looking ahead, the next impediment may include bans on transporting oil by rail through certain states.26 If transportation by rail is crucial to the economic viability of the play, then such a ban on the transportation of the oil should be addressed in the lease.

In all your lease endeavors, MAY THE FORCE BE WITH YOU.

1 Obi-Wan Kenobi, Star Wars (subtitled Episode IV: A New Hope) (1977).
2 Fee Lease 101 Series, www.theoilandgasreport.com.
3 Yoda, The Empire Strikes Back (1980)
4 4-6 Williams & Meyers, Oil and Gas Law § 683.1 (citations omitted).
5 Aukema v. Chesapeake Appalachia, LLC, 904 F. Supp. 2d 199 (N.D.N.Y. 2012).
6 See Allegiance Hillview, LP v. Range Texas Prod., LLC, 347 S.W.3d 855 (Tex. App. 2011); Sun Operating Ltd. Partnership v. Holt, 984 S.W.2d 277 (Tex. App. 1998); Perlman v. Pioneer Ltd. Pship, 918 F.2d 1246 (5th Cir. 1990).
7 Vortt Exploration Co., Inc. v. EOG Resources, Inc., 2009 Tex. App. LEXIS 4113 (Tex. App. – Eastland, May 29, 2009); Maralex v. Resources, Inc. v. Gilbreath, 76 P.3d 626 (N.M. 2003) (if the cessation of production was caused by the pressures in a third party pipeline, it would be beyond the control of the lessee; however, if the cessation was caused by insufficient pressure within the well, it would not be an external cause beyond the lessee’s control).
8 Schroeder v. Snoga, 1997 Tex. App. LEXIS 4030 (Tex. App.–San Antonio July 31, 1997) (Commission shut-in order was caused by the operator’s violation of the Commission’s rules); Edington v. Creek Oil Co., 690 P.2d 970 (Mont. 1984) (Commission shut-in order for a seepage issue could have been resolved by the lessee); Caddell v. Threshold Dev. Co. 609 S.W.2d 871 ( Tex. App.-Amarillo 1980) (a lockout by the lessor was within the meaning of the force majeure clause).
9 Yoda, The Empire Strikes Back (1980).
10 Older lease forms may contain conditions such as payment of rentals during the primary term or payment of shut-in royalties in the secondary term. In that case, failure to timely and appropriately make the payments will result in the lease automatically terminating.
11 4-6 Williams & Meyers, Oil and Gas Law § 683.1 (citations omitted).
12 See Logan v. Blaxton, 71 So. 2d 675 (La. Ct. App. 1954). Although the force majeure clause identified floods as an event and heavy rainfall made roads impassable and impracticable to transport crude oil to market, the court found that the rains were seasonable and could be predicted and the evidence of impossibility was not demonstrated, i.e. that roads could not be improved, alternative routes were not available, or smaller trucks could not be used to transport the oil to market.
13 Id.
14 Obi Wan Kenobi, Star Wars (subtitled Episode IV: A New Hope) (1977).
15 See Welsch v. Trivestco Energy Co., 221 P.3d 609 (Kan. App. 2009) (bankruptcy of a gas purchaser is covered by the shut-in royalty clause, not the force majeure clause. The unavailability of purchasing and transportation services did not prevent the lessee from paying shut-in royalties and the force majeure clause was not triggered).
16 Trinidad Petroleum Corp. v. Pioneer Natural Gas Co., 416 So. 2d 290 (La. Ct. App. 1982, writ denied).
17 The habendum clause sets forth the term of the lease. It typically divides the lease into the primary term of a fixed number of years and the secondary term “for so long thereafter as oil or gas is produced.” See Trent Maxwell, “The Habendum Clause – ‘Til Production Ceases Do Us Part,” The Oil and Gas Report, Fee Lease 101 Series, www.theoilandgasreport.com.
18 Aukema v. Chesapeake Appalachia, LLC, 904 F. Supp. 2d 199 (N.D.N.Y. 2012); Beardslee v. Inflection Energy, LLC, 904 F. Supp. 2d 213 (N.D.N.Y. 2012). These cases were decided on the same day, by the same judge, with the same results. The court found that the moratorium did not prevent the lessees from performing under the leases and drilling by other methods, i.e. drilling a conventional vertical well. The lessees had the right to drill, but were not required to do so; it was merely an option and “invocation of a force majeure clause to relieve them from their contractual duties is unnecessary.” Beardslee, 904 F. Supp. 2d at 220. The Beardslee decision was appealed by the lessees.
19 The New York Court of Appeals, being New York’s highest appellate state court.
20 Beardslee v. Inflection Energy, LLC, 761 F.3d 221 (2nd Cir. 2014).
21 Beardslee v. Inflection Energy LLC, 31 N.E.3d 80 (N.Y. 2015).
22 Beardslee v. Inflection Energy, LLC, 798 F.3d 90 (2nd Cir. 2015).
23 Darth Vadar, Star Wars (subtitled Episode IV: A New Hope) (1977)
24 Mora County, New Mexico was the first county in the United States to ban “any corporation to engage in the extraction of oil, natural gas, or other hydrocarbons within Mora County” and prohibiting the use of water for fracking, among other related activities. The District Court held that the ban was preempted by state law. SWEPI, LP v. Mora County, 2015 U.S. Dis. LEXIS 13496 (D.N.M. Jan. 19, 2015). Similarly, Fort Collins and Longmont, Colorado’s recent bans have also been held to be preempted by state law and outside their authority and struck down. City of Fort Collins v. Colo. Oil & Gas Assn, 2016 CO 28 (May 2, 2016); City of Longmont v. Colo Oil & Gas Assn, 2016 CO 29 (May 2, 2016).
25 Hillary Clinton outlines a series of conditions on fracking stating, “You know, I don’t support it when any locality or any state is against it…. I don’t think there will be many places in America where fracking will continue to take place.” The New York Times, “Transcript of the Democratic Presidential Debate in Flint, Mich,” March 6, 2016. Bernie Sanders advocates for a total ban on fracking, “We need to put an end to fracking not only in New York and Vermont, but all over this country.” The New York Times, “Bernie Sanders Proposes Fracking Ban and Attacks Hilary Clinton on the Environment,” April 11, 2016.
26 Canadian Business, “Leaders Ask Oregon, Washington Governors to Ban Oil-by-Train,” June 14, 2016.

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).

If It’s Wrong, You Got Nothin’ – Execution of Instruments

Title Issues/Curative, , ,

To state the obvious, one of the most important aspects of any lease, deed, assignment or any other contract is making sure the appropriate party executes it. If the wrong person signs it, it will be either invalid or voidable at best. This is exactly what happened when only one manager of a limited liability company signed a 99 year lease. Unfortunately, the articles of organization on file with the secretary of state required both of the managers identified therein to sign such a lease. The lessee did not know there were two managers or that the articles of incorporation contained such requirement. The court found that the manager who signed the lease lacked actual and apparent authority to execute the lease and the lease was declared invalid.1 To assist in determining the appropriate party to execute a lease, deed, assignment or other contract, set forth below is a list of the common entities and scenarios that may be encountered in any title examination or transaction. 2

Attorneys-in-Fact. An attorney-in-fact is one who is authorized by a power of attorney to act on behalf of the actual owner of the property. Such authority will be defined in the power of attorney and will be strictly construed. Several states require recordation of the power of attorney in the county where the property is located.3

Associations: Religious, Cooperatives, Lodges, Educational, Non-Profits. These associations may encumber or convey real property held in the association’s name through its officers as authorized by its bylaws and resolutions. Such association’s governing documents and the laws of the state in which it is organized must be reviewed to determine authority.

Contracts for Deed. Generally, the holder of a contract may convey or encumber the applicable interest, unless the contract specifically provides otherwise. The holder of a contract for deed should join in the execution of the instrument in the same way as a life tenant joins (see below).

Corporations. The laws of the state of incorporation4 and the corporation’s governing documents (articles of incorporation, bylaws or resolutions) define the appropriate officer(s) or agent to execute a contract on behalf of a corporation. Typically, the president or vice president are authorized to execute a contract. If required, the officer’s signature should be attested and a corporate seal affixed.

Estates (Personal Representatives, Executors, Administrators). Generally, the authority of the personal representative, executor, or administrator to execute a contract is granted by a court having jurisdiction over the real property. Accordingly, applicable probate proceedings must be initiated in the state in which the property is located, not the resident state of the deceased. The resulting letters testamentary evidencing the party’s authority to act must be reviewed to confirm any limitations that may be imposed on the party’s authority, including the time period for which the party’s was granted authority to represent the estate of the decedent.

General Partnerships. Typically, an instrument can be executed by any partner, if acting within the scope of his or her authority, unless otherwise restricted in the partnership agreement or the laws of the state in which the partnership is organized.

Individuals. Any competent person may execute a contract. However, a contract executed by a minor is voidable at the minor’s election either before the age of majority or within either a statutorily defined time or a reasonable time thereafter. The typical age of majority is 18 years unless otherwise emancipated. If an interest is owned by a minor or incompetent, a guardian or conservator should be appointed by a court, who then may execute on behalf of the minor or incompetent. If a person cannot sign his or her own name, he or she may execute a contract by a mark. The signature of one or more credible witnesses or the acknowledgment by a notary public is typically required. As to competency, absence actual or constructive knowledge, a person of the age of majority is presumed to be competent. A person is not considered mentally incompetent until declared as such by a court. However, there appears to be a general standard that if the person is entirely without understanding, generally such person has no power to execute a contract. Any contract executed by a mentally incompetent person is voidable at the person’s election for a reasonable time after the person is judicially declared competent and most likely void if the person is under a guardianship.

If an individual is married, a variety of laws and circumstances exist which must be considered before it can be determined if a married person can legally convey such property without a joinder by his or her spouse. Under certain circumstances, the contract may be void even as to the party who signed.5 Therefore, it is generally recommended that a contract be signed by both spouses. However, in order to prevent any unintended consequences or benefits to the non-record title owner spouse, the proposed contract should be carefully drafted to avoid any unintended consequences. The types of ownership by married individuals are as follows:

Community Property. In a community property state, the property is owned by the community or, in other words, each spouse may claim an undivided one-half interest. This type of ownership applies to most property acquired during marriage by the husband or the wife. It generally does not apply to property acquired prior to the marriage or by gift or inheritance during the marriage. After a divorce, community property is either divided equally or according to the discretion of the court. Some of the applicable community property states include Alaska6, California, Louisiana, Nevada, New Mexico, and Texas7. Unless it can be determined that the property is owned separately, both spouses must execute or be a joining party to the instrument. Generally, upon the death of one spouse, the spouse’s interest passes to his or her devisees if the decedent spouse died testate or to his or her surviving spouse if the decedent spouse died intestate. Therefore, it is recommended to have the contract executed by the heirs or devisees of the deceased spouse and by the surviving spouse until the estate of the decedent spouse has been formally probated. Most importantly, even if the real property is not located in a community property state, if the husband and wife are domiciled in a community property state, the community property laws will apply.

Tenancy by the Entirety. Tenancy by the entirety is recognized in Alaska, Michigan, Ohio, Oklahoma, and Wyoming. This type of ownership is similar to joint tenancy, except that the parties must be husband and wife and the property cannot be conveyed by only one spouse. In the event the parties divorce, the property will transform into a tenancy in common.

Joint Tenants. For a joint tenancy to be created, it must be expressly declared in the contract conveying the real property by use of such language as “joint tenants” or “with rights of survivorship.”8 In the event of the death of one of the joint tenants, the surviving joint tenants continue to own the property (as joint tenants), regardless of the will of the deceased or any intestate laws. All joint tenants will need to execute the instrument (preferably the same one) in order to convey the full interest. Execution of an instrument by less than all joint tenants will validly convey the interests of the individual interests who sign and likely sever his or her joint tenancy.

Tenants in Common. An interest in real property created in two or more owners is presumed to be a tenancy in common unless specific language or circumstances indicate otherwise. Although listed under the header “Individuals,” a business entity can also be a tenant in common. Each cotenant is generally free to convey and encumber his or her own interest without the consent of the other cotenants. Upon the death of a cotenant, title passes to the cotenant’s heirs or devisees as previously designated by will or through intestacy.

Life Tenant and Remainderman. A life estate is an estate in which the duration of interest is measured by the life of one or more persons. The measuring life is usually that of the life tenant, but can also be the life of another (pur autre vie). Although the life tenant has the right of possession, he or she cannot execute a lease or otherwise dispose of the property without being liable to the remainderman for waste. Therefore, unless otherwise provided in the instrument creating the life estate, both the life tenant and the remainderman must execute any instrument affecting the real property .

Limited Liability Companies. Typically, a manager(s) or, if there is not a manager, then any member, is the appropriate party to execute a contract.9 The state of organization’s laws may also determine who has the authority to execute a contract on behalf of the company.

Limited Partnerships. The general partner of the limited partnership is the appropriate party to execute a contract unless the authority is otherwise provided in the partnership agreement or state laws in which the partnership is organized.10

Mortgages and Deeds of Trust. Generally, a mortgagee is not required to join in the execution of a lease. However, it is recommended that the mortgage subordinate its interest to an oil and gas lease in order to protect the rights of the lessee in the event the mortgagor defaults on the mortgage. In the unusual case a mortgage or deed of trust specifically prohibits the mortgagor from performing certain acts (e.g., leasing for oil and gas), the mortgagee should remove the prohibition contemporaneously with the execution of the lease.

Perpetual or Term Royalty Interest. A royalty interest may be reserved or conveyed out of the mineral interest for a fixed or perpetual term. Typically, the mineral interest owner retains the executive rights, subject to the right of the royalty owner to participate in production. Generally, a royalty interest is owned separately from the mineral interest and the royalty owner signs only instruments relating to his or her royalty. However, the instrument creating the royalty interest should be carefully reviewed.

Proprietorships or DBA’s. A person may adopt a name in which the person acquires property and transacts business in his or her individual capacity. The sole proprietor has the sole authority to execute in behalf of such an entity. Any contract executed by a sole proprietor should recite the person’s name and also that the person is doing business as the adopted name.

Term Mineral Interest. A mineral interest may be reserved or conveyed for either a fixed term only or a fixed term and so long thereafter as minerals are produced in paying quantities. Similar to a life estate interest, a conveyance should be obtained from both the term interest owner and the reversionary interest owner. If a lease is granted by only the term interest owner, a ratification of the lease should also be obtained from the reversionary interest owner.

Trusts. An individual or entity (the trustee) may own legal title to a property for the benefit of another. Each state’s laws and the terms of the trust agreement will govern the trustee’s authority to execute any contract and any limitations on the trustee’s powers. At a minimum, the contract should describe the grantor or grantee trust by including the name of the trust, the date of the trust, and the name(s) of the trustee(s).

As stressed above, the governing state laws and the governing entity documents are critical in determining whether the appropriate party is executing the contract. Many unintended consequences may exist by failing to consult such laws and documents.

1Zions Gate R.V. Resort, LLC v. Oliphant, 362 P.3d 118 (Utah Ct. App. 2014).
2See also Landman’s Legal Handbook , Rocky Mt. Min. L. Found., 5th ed. 2013; Oil & Gas Law: Nationwide Comparison of Laws on Leasing, Exploration and Production, Am. Ass’n Prof. Landmen, 2011.
3See, e.g., Colo. Rev. Stat. § 38-30-123; Nev. Rev. Stat. § 111.450; N.D. Title Standard 2-11; N.M. Stat. Ann. § 47-1-7.
4See, e.g., Colo. Rev. Stat. § 38-30-144 (allowing the president, vice-president, or other head office of the corporation); Mont. Code Ann. § 70-21-203(1)(b) (allowing president, vice-president, secretary or assistant secretary or by any other person duly authorized by resolution).
5If the property is qualified as a homestead, both husband’s and wife’s signature is required. See N.D. Cent. Code § 47-18-05; Mont. Code Ann. § 70-32-301; Wyo. Stat. § 34-2-121. In New Mexico, if a spouse fails to join in the instrument, it is void and of no effect, unless ratified by the spouse in writing. Marquez v. Marquez, 513 P.2d 713 (N.M. 1973); Hannah v. Tennant, 589 P.2d 1035 (N.M. 1979).
6Alaska is an opt-in community property state; therefore, property is separate property unless both parties agree to make it community property through a community property agreement or a community property trust.
7Colorado, Montana, North Dakota, Oklahoma, South Dakota, Utah, and Wyoming are not community property states.
8See Cal. Civ. Code § 683; Utah Code Ann. § 57-1-5(3). Additionally, Utah statutes create a presumption in favor of a joint tenancy being created when the granting clause refers to a husband’s and wife’s marital status without further joint tenancy language. Utah Code Ann. § 57-1-5(1).
9See, e.g., Mont. Code Ann. § 35-8-301; N.M. Stat. Ann. § 53-19-30; Wyo. Stat. Ann § 17-29-407 (consent of all members required).
10See Mont. Code Ann. § 35-12-803, 806; N.M. Stat. Ann. § 54-2A-110; Nev. Rev. Stat. § 88.445; Wyo. Stat. Ann. § 17-14-503.