FAQs of Federal Oil and Gas Leases

Can I Drill Through Unleased Federal Lands?

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

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

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

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

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

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

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

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

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

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

What if the tract is only partially unleased federal minerals?

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

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

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

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

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

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

[3] 43 C.F.R. § 3100.2-1.

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

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

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

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

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

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

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

Operator Responsibilities Under Federal Oil and Gas Leases

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

Record title and operating rights owners each have responsibilities and liabilities under federal leases. After a transfer of operating rights, the BLM will initially look to an operating rights owner to perform primary operational obligations. However, the record title holder is ultimately responsible for complying with lease provisions (see, for example,  Petroleum, Inc., Frank H. Gower Trust, Rex Monahan, 161 IBLA 194 (2004), holding that a record title owner was liable for well plugging obligations upon the bankruptcy of the operating rights owner).  A transfer of operating rights is considered a sublease and does not affect the relationship imposed by a lease between the lessee(s) and the United States. 43 CFR § 3100.0-5.  Although transferring operating rights only does not remove the record title holder from liability, “once a lessee transfer[s] record title, the assignee and its surety bec[o]me responsible for the performance of all obligations.” Id.  It is not uncommon to find a federal oil and gas lease where a record title owner has transferred operating rights from the surface to the base of the deepest producing formation in an area, but has retained record title and operating rights to formations below such depth. That approach may not always be in the best interest of the record title owner as it may be reserving negligible or speculative economic interests in deeper formations, while also retaining potential liability for the operations of the operating rights owner in the productive formations.   

The operator must “comply with applicable laws and regulations; with the lease terms, Onshore Oil and Gas Orders, NTL’s; and with other orders and instructions of the authorized officer.”  43 C.F.R. § 3162.1(a). The following, while not an exhaustive list, is a summary of some key obligations of an operator on a federal lease. The Bureau of Land Management (BLM) also has internal manuals that supplement some of the following requirements. The failure of an operator or record title owner to comply with regulations can subject the violating party to assessments and penalties as set forth in 43 C.F.R. § 3163.

Drilling and Producing Obligations

  • The operator may drill and produce wells in conformity with the well spacing orders affecting the field that is authorized by applicable law or the authorized officer.  43 C.F.R. § 3162.2-l(a).
  • The authorized officer may reasonably require the operator to promptly drill and produce other wells on the lease to properly and timely develop the lease.  43 C.F.R. § 3162.2-l(b).
  • If economically feasible, oil and other hydrocarbons produced on the lease must be put into marketable condition.  43 C.F.R. § 3162.7-1.
  • The operator is expected to prevent avoidable loss of oil and gas, and will be liable for royalty payments on oil and gas lost or wasted. Id.

Protection from Drainage

  • The lessee may be required within a reasonable time after receiving constructive or actual notice, or a demand letter from the BLM, to drill and produce wells necessary to protect the lease from drainage.  43 C.F.R. § 3162.2-2; 43 C.F.R. § 3162.2-11.  In the alternative, the BLM may execute agreements with owners of interests in the producing well to compensate for drainage, offer for lease any qualifying unleased mineral resources, or approve a unit or communitization agreement. 43 C.F.R. § 3162.2-2.
  • The BLM may require the lessee to “pay compensatory royalties for drainage that has occurred or is occurring.”  43 C.F.R. § 3162.2-4.
  • If the lessee can prove a protective well would be uneconomic, then the lessee is not required to take certain protective actions.  43 C.F.R. § 3162.2-5.
  • “Operating rights owners are jointly and severally liable with each other and with all record title holders for drainage affecting the area and horizons in which they hold operating rights during the period they hold operating rights.”  43 C.F.R. § 3162.2-7.
  • After assigning an interest in a federal oil and gas lease interest, the assignor is only responsible for compensatory royalties until the time the BLM approves the assignment or transfer, after which, the assignee or transferee will be responsible.  43 C.F.R. § 3162.2-8.
  • Duty to Inquire of drainage:
    • A lessee must monitor the drilling of wells in the same or adjacent spacing units and gather information to determine if drainage is occurring. 43 C.F.R. § 3162.2-9.
    • The lessee must determine the amount of drainage from production of the draining well, the amount that will be drained, and whether a protective well would be uneconomic.  Id.
    • The lessee must then notify the BLM of the actions it will take within 60 days of actual or constructive notice of the draining.  Id.
    • The lessee must provide the BLM with the analysis within 60 days after it has been requested.  Id.

Conduct of Operations

  • The authorized officer must be promptly notified of an operator change and the new operator must have sufficient bond coverage.  43 C.F.R. § 3162.3.
  • A contractor is considered an agent of the operator with full responsibility to comply with the laws and regulations.  Id.
  • The operator must submit an application for permit to drill prior to commencing any drilling operations.  43 C.F.R. § 3162.3-1.  
  • The operator must submit a proposal for further well operations prior to performing subsequent well operations.  43 C.F.R. § 3162.3-2.
  • The operator must conduct work and maintain equipment in a safe and workman-like manner, and take safety precautions to protect life and property.  43 C.F.R. § 3162.5-3.
  • Wells and production facilities must be identified by a sign with information as required by law and the authorized officer 43 C.F.R. § 3162.6.

Well Abandonment

  • The operator must promptly plug and abandon any well not capable of producing oil or gas in paying quantities unless it will be used for injection.  43 C.F.R . § 3162.3-4.  Permanent abandonment may be delayed up to 12 months with prior approval from the authorized officer.  Id.
  • After abandonment, the surface must be reclaimed by the operator in accordance with a plan approved or prescribed by the authorized officer.  Id.
  • Abandoned wells must be identified by a permanent monument unless the requirement is waived by the authorized officer.  43 C.F.R. § 3162.6(e).

Reporting

  • The operator must keep records of all lease operations (drilling, producing, redrilling, repairing, plugging back, and abandonment operations, etc.), production facilities and equipment, and determining and verifying the quantity, quality, and disposition of production.  43 C.F.R. § 3162.4-1.
  • The operator must notify the authorized officer by letter, sundry notice, or orally (followed by letter or sundry notice) no later than 5 business days after production begins.  Id.
  • The operator shall conduct the required tests and report results to the authorized officer.  43 C.F.R. § 3162.4-2.

Environmental

  • The operator must conduct operations so as to protect the natural and environmental resources.  43 C.F.R. § 3162.5-1.
  • An operator must comply with orders of the authorized officer, applicable laws and regulations, lease terms and conditions, and the approved drilling/operations plan.  Id.
  • The operator must exercise due care and diligence to not cause undue surface or subsurface damage.  Id.
  • Water must be disposed of by injection, pits or in a manner approved by the authorized officer.  Id.
  • All spills, leaks or other accidents shall be reported by the operator.  Id.  The operator will then take the necessary measures to solve the issues as approved by the authorized officer.  Id.
  • The authorized officer may require a contingency plan from the operator to protect life, property, and the environment.  Id.

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.

What Are Federal Lease Rentals and When Are They Required?

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

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

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

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

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

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

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

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

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

[2] 43 C.F.R. § 3103.2-2.

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

[4] 43 C.F.R. § 3103.1-2(a).

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

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

[7] 30 C.F.R. § 1241.53.

[8] 30 U.S.C. § 188.

[9] 43 C.F.R. § 3108.2-1.

[10] 43 C.F.R. § 3108.2-2.

[11] 43 C.F.R. § 3108.2-3.

[12] 43 C.F.R. §§ 3103.2-2(d)–(f).

[13] 43 C.F.R. § 3108.2-2(a).

[14] 43 C.F.R. § 3108.2-2(a).

[15] 43 C.F.R. § 3103.2-2.

[16] 43 C.F.R. § 3103.2-1(c).

[17] 43 C.F.R. § 3103.2-2.

How Are Federal Oil and Gas Leases Pooled and Unitized?

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

In the context of federal oil and gas leases, the terms “communitization” and “unitization” are distinct concepts which are subject to different statutes, regulations, and procedures. As such, the method to “communitize” a federal oil and gas lease is different than the process used to “unitize” such leases. These respective differences are highlighted herein.

Communitization of Federal Oil and Gas Leases

Virtually all oil and gas producing states have promulgated minimum acreage requirements for the drilling of oil or gas wells.[1]  The United States recognized the importance of state conservation statutes, and accordingly passed an amendment to the Mineral Leasing Act which allowed federal lessees to conform to state well spacing orders through a communitization agreement.[2]  Communitization is the agreement to combine small tracts, of which one or more is federal or Indian lands, for the purpose of committing enough acreage to form the spacing/proration unit necessary to comply with the applicable state conservation requirement and to provide for the development of these separate tracts which cannot be independently developed in conformity with said conservation requirements.[3] In essence, communitization is the federal equivalent of pooling the lands in a spacing/proration unit under state law.  The common thread of all federal communitization agreements is that at least one federal or Indian lease or tract must be involved.[4]  That federal or Indian lease is communitized with other leases that may be federal, Indian, state, or fee.[5]

Although there is no prescribed form for a federal communitization agreement in the regulations, the regulations do require that certain information be included within the communitization agreement.  There are relatively few requirements for communitization agreements, but the applicant must usually provide sufficient information so the authorized officer can make a determination that it would be in the best interests of conservation and of the United States for the federal leasehold to be communitized.[6]  Specifically, the agreement must describe the separate tracts comprising the drilling or spacing unit, describe the apportionment of production or royalties to the parties, name the operator, contain adequate provisions for the protection of the interests of the United States, be filed prior to the expiration of the federal leases involved, and be signed by or on behalf of all necessary parties.[7]  The BLM Manual 3160-9-Communitization includes a standard or model communitization agreement form, one for federal leases and one for Indian leases, which should be used whenever possible.[8]

The necessary parties include all working interest owners and lessees of record. A communitization agreement may be approved without joinder by the royalty, overriding royalty, and production payment interest owners, but this will result in different payment scenarios depending upon the location of a successfully completed well.[9]

 If a state has them, the state’s compulsory pooling statutes may be utilized to commit a nonconsenting party’s interest to the communitization agreement; although, without the consent of the Secretary of the Interior, the state commission does not have jurisdiction to force pool unleased interests of the United States.[10]  Copies of any compulsory/force pooling order should be furnished with and be part of the communitization agreement if such interest owner does not execute the agreement.[11]  The authorized officer in the appropriate BLM office must approve, on behalf of the Secretary, the communitization agreement with respect to any included federal leases.[12]

Although not mandatory, the filing of a Preliminary Application for Approval to Communitize is recommended, particularly in instances where the model form of communitization agreement is not followed precisely.[13]  The BLM Manual provides that a request for preliminary approval to communitize may be filed at any time with the authorized officer. It is also recommended that preliminary approval be requested if there is some doubt as to whether the proposed tracts are logically subject to communitization, or if there is any doubt as to whether a communitization of multiple zones will be approved. The preliminary approval procedure will expedite final approval and may avoid the necessity of extensive revisions and re-execution of a finalized communitization agreement.[14]

The BLM will not approve an agreement that purports to communitize all horizons from the surface down to the center of the earth.[15] However, if it is anticipated that the well will be completed in multiple formations, it is important to include all formations and horizons that are producing or may produce hydrocarbons intended to be allocated pursuant to the terms of the communitization agreement.[16]  All communitized formations must be subject to the same spacing requirements and, where multiple and clearly distinct formations are covered by the same communitization agreement, the BLM Manual provides that Section 1 be amended to clearly state that the agreement shall apply separately to each formation as though a separate communitization agreement for each formation had been executed.[17]  In the event a proposed well is projected to test multiple formations that are subject to different spacing requirements, separate communitization agreements should be submitted to BLM for each formation or set of formations with the same spacing requirements.[18]

The communitization agreement must be filed prior to the expiration of the federal leases to be communitized.[19]  The regulations require that the communitization agreement be filed in triplicate with the proper BLM office.[20]  If state lands are involved one additional counterpart must be submitted.

An executed counterpart of the approved communitization agreement, duly acknowledged, should be filed of record in the county in which the land is located. When fee leases are involved, the operator should record either the communitization agreement or otherwise comply with the terms of the pooling provision of any fee lease.[21]

In order to approve a communitization agreement, the Mineral Leasing Act requires that the Secretary determine communitization is “in the public interest”[22]:

The public interest requirement for an approved communitization agreement shall be satisfied only if the well dedicated thereto has been completed for production in the communitized formation at the time the agreement is approved or, if not, that the operator thereafter commences and/or diligently continues drilling operations to a depth sufficient to test the communitized formation or establish to the satisfaction of the authorized officer that further drilling of the well would be unwarranted or impracticable.”[23]

Communitization agreements usually provide for a term of two years and so long thereafter as communitized substances are, or can be, produced from the communitized area in paying quantities.[24]  Assuming the public interest requirement is satisfied, any federal lease eliminated from an approved communitization agreement, or any federal lease in effect at the termination of the agreement, shall continue in effect for the original term of the federal lease or for two years after its elimination from the plan or termination of the agreement, whichever is longer, and for so long thereafter as oil or gas is produced in paying quantities.[25]  No lease shall be extended if the public interest requirement has not been satisfied.[26]

Unitization of Federal Oil and Gas Leases

Unitization is the agreement to jointly operate an entire producing reservoir or a prospectively productive area of oil and/or gas. The entire unit area is operated as a single entity, without regard to lease boundaries, and allows for the maximum recovery of production from the reservoir. Costs are reduced because the reservoir can be produced by utilizing the most efficient spacing pattern, separate tank batteries are not necessary, and there is no requirement to drill unnecessary offset wells. The objective of unitization is to provide for the unified development and operation of an entire geologic prospect or producing reservoir so that exploration, drilling, and production can proceed in the most efficient and economical manner by one operator.[27]

The Bureau of Land Management is the administering agency for federal onshore units and has established procedures that must be followed to unitize federal lands.[28] Although not required by the regulations, the BLM strongly encourages an informal discussion with the authorized officer of BLM office having jurisdiction over the area where the lands are located concerning the proposed area of the unit, the depth of the test well and formation to be tested, and the form of agreement.[29]  This should be done prior to filing of an application.[30] It is recommended that this is done in order to ensure the unit approval process moves smoothly.

BLM regulations provide that,  to initiate the formation of a federal unit, an application for designation of a proposed unit area be filed in duplicate.[31] The application must be accompanied by a map or diagram outlining the area sought to be designated and indicating the federal, state, privately owned, or Indian lands by symbols or colors.[32]  The plat must indicate the separate leasehold interests involved and identify them by serial number in the case of federal and Indian oil and gas leases.[33]  It is advisable to show the ownership and expiration dates of each lease involved. The application must also be accompanied by a geologic report and it must indicate the zones that are to be unitized (if all zones or formations are not to be included).[34]

The owners of any interest in the oil and gas deposits to be unitized are proper parties to the unit agreement. All such parties must be invited to join the agreement.[35] This includes royalty owners and holders of overriding royalty interests and any other non-cost bearing interests in production, as well as working interest owners. Prior to approval, notice of the proposed agreement must be given to all parties with a request to join the agreement.[36]  When state lands are to be unitized with federal lands, the unit agreement must be approved by the state prior to submission to the BLM for final approval.[37]

After the unit area has been designated and the unit agreement has been fully executed by the parties desiring to commit their interests to the unit, a minimum of four signed counterparts must be filed for approval with the proper BLM office.[38]  These instruments should be accompanied by a request from the proponent for final approval of the unit, setting forth the acreage interests fully committed, effectively committed, partially committed, and not committed and show the percentage in each category.[39]  A showing must also be made that all parties owning not committed interests within the unit area have been extended an invitation to join in the unit agreement and that a reasonable effort has been made to obtain the joinder of all such parties.[40]  The request for final approval must include a list of the overriding royalty interest owners who have executed or ratified the unit agreement.[41] A tract will be considered “fully committed” if all interest owners have joined the unit and all working interest owners have also executed the applicable operating agreement.[42] A tract will be considered “effectively committed” to the unit without joinder by overriding royalty interest owners and will be treated identically as a “fully committed” tract, but, will result in different payment scenarios depending upon the location of the successfully completed unit well.[43] A tract will be considered “partially committed” if less than all of the lessors/royalty interest owners have joined, or all operating rights owners of a federal lease have joined but the record title holder has not.[44]  Such partially committed tracts may be considered to be under the effective control of the unit operator, however, no unit benefits will accrue to the tract in the absence of actual operations on the partially committed tract or an allocation of production to that tract either from a well on the tract or from another location.[45] Finally, if any working interest owner in a tract does not commit its interest, that tract is deemed “not committed.”[46]  BLM regulations provide that a unit agreement will not be approved “unless the parties signatory to the agreement hold sufficient interests in the unit area to provide reasonably effective control of operations.”[47] Generally, 85% of the tracts in the unit must be fully, effectively or partially committed to meet this “effective control” requirement.[48]

After four signed counterparts of the executed agreement are submitted, the authorized officer approves the unit agreement upon a determination that the agreement is necessary or advisable in the public interest and is for the purpose of more properly conserving natural resources.[49] A model federal onshore unit agreement for unproven areas (hereinafter “Model Form”) is included in the BLM regulations and promulgated to help implement these provisions.[50] Section 9 of the Model Form specifically provides for the commencement of an initial test well within six months after the effective date of the unit.[51] If a discovery is not made in the initial test well, provision is made for continuous drilling on unitized lands until a discovery is made provided that not more than six months elapse between the completion of one well and the commencement of the next.[52]  Paying quantities for purposes of meeting the drilling obligations in section 9 is defined as quantities of unitized substances sufficient to repay the costs of drilling, completing, and producing operations, with a reasonable profit.[53]

Upon approval, the unit agreement becomes effective.[54]  However, the public interest requirement is satisfied only if the unit operator commences actual drilling operations and diligently prosecutes such operations in accordance with the terms of the agreement.[55]  If this requirement is not satisfied, the approval of the agreement and lease segregations and extensions shall be invalid.[56]  Evidence of the approved unit should be recorded in the county records to impart notice.

Finally, it is important to understand the interplay between the unit agreement and the unit operating agreement because both agreements, taken together, constitute the unit arrangement and establish the contractual rights and obligations of the parties.

In addition to setting forth the terms and conditions for the unit, the unit agreement prescribes the method of allocating production for purposes of determining royalties, overriding royalties, production payments, and other non-cost bearing burdens, but does not dictate the working interest owners’ respective shares of production or the allocation of costs/royalty burdens associated therewith.[57] These, and other duties and obligations among the working interest owners, are matters covered by the unit operating agreement.[58]

The BLM does not prescribe any particular form of unit operating agreement and the working interest owners are generally free to use whatever form of unit operating agreement they prefer.[59] The unit operating agreement is entered into by the working interest owners who are committing their interests to the unit in conjunction with the execution of the unit agreement.[60] The interests of the royalty owners are not affected by the form of unit operating agreement chosen by the working interest owners.[61] Two copies of the unit operating agreement are required to be filed in the proper BLM office before the unit agreement will be approved.[62]

[1] Angela L. Franklin, Communitization Agreements in the 21st Century, Federal Onshore Oil and Gas Pooling and Communitization, Paper 3-4 (Rocky Mt. Min. L. Fdn. 2006) [hereinafter Communitization Agreements].

[2] See Mineral Leasing Act, Pub. L. No. 696, § 17(b), 60 Stat. 952 (1946).

[3] See 2 Lewis C. Cox, Jr., Law of Federal Oil and Gas Leases § 18.01 (2017).

[4] Communitization Agreements, supra note 2, at 3-5.

[5] Id.

[6] 1 Bruce M. Kramer & Patrick H. Martin, The Law of Pooling and Unitization § 16.04 (3rd ed. 2017).

[7] 43 C.F.R. § 3105.2-3(a) (2018).

[8] Communitization Agreements, supra note 2, at 3-5.

[9] Id.

[10] Id. at 3-6.

[11] Id.

[12] 43 C.F.R. § 3105.2-3 (2018).

[13] Communitization Agreements, supra note 2, at 3-7.

[14] See id.

[15] Id. at 3-8.

[16] Id.

[17] Bureau of Land Management, BLM Manual 3160-9-Communitization .11M (1988) [herein after BLM Manual].

[18] Communitization Agreements, supra note 2, at 3-8.

[19] 43 C.F.R. § 3105.2-3(a) (2018).

[20] Id. § 3105.2-1.

[21] Communitization Agreements, supra note 2, at 3-10.

[22] 30 U.S.C. § 226(m) (2018).

[23] 43 C.F.R. § 3105.2-3(c) (2018).

[24] See Section 10 of Model Form of a Federal Communitization Agreement in BLM Manual app.

[25] 43 C.F.R. § 3107.4 (2018). But see, R. E. Hibbert, 8 IBLA 379 (1972), GFS (O&G) 6 (1973).

[26] 43 C.F.R. § 3107.4 (2018).

[27] Kramer & Martin, supra, § 18.01[2].

[28] Id. § 18.04[1].

[29] Kramer & Martin, supra, § 18.04[2].

[30] See id.

[31] 43 C.F.R. § 3183.2 (2018)

[32] Kramer & Martin, supra, § 18.04[3] (citing 43 C.F.R. §§ 3181.2, 3183.2).

[33] See id. § 18.04[3].

[34] See 43 C.F.R. § 3181.2 (2018).

[35] 43 C.F.R. § 3181.3 (2018).

[36] See Kramer & Martin, supra, § 18.04[4].

[37] 43 C.F.R. § 3181.4(a) (2018).

[38] 43 C.F.R. § 3183.3 (2018).

[39] See Kramer & Martin, supra, § 18.04[6].

[40] Id. (citing 43 C.F.R. § 3181.3).

[41] See Kramer & Martin, supra, § 18.04[6].

[42] See Frederick M. MacDonald, Preparing and Finalizing the Unit Agreement: Making Sure Your Exploratory Ducks are in a Row, Federal Onshore Oil and Gas Pooling and Communitization, Paper 8-23 (Rocky Mt. Min. L. Fdn. 2006).

[43] Id. at 8-24.

[44] Id.

[45] Id.

[46] Id. at 8-25.

[47] 43 C.F.R. § 3183.4(a) (2018)

[48] MacDonald, supra, at 8-16.

[49] See Kramer & Martin, supra, § 18.04[6]. (citing 43 C.F.R. § 3183.4).

[50] See Thomas W. Clawson, Paying Well Determinations, Federal Onshore Oil and Gas Pooling and Communitization, Paper 11-3 (Rocky Mt. Min. L. Fdn. 2006).

[51] See Model Form, § 9, 43 C.F.R. § 3186.1.

[52] See Kramer & Martin, supra, § 18.03[2][b][iii].

[53] Model Form, § 9, 43 C.F.R. § 3186.1.

[54] Kramer & Martin, supra, § 18.04[6] (citing Lario Oil & Gas Co., 92 IBLA 46, GFS(O&G) 54 (1986)).

[55] Kramer & Martin, supra, § 18.04[7].

[56] 43 C.F.R. § 3183.4(b) (2018).

[57] See Steven B. Richardson and Lynn P. Hendrix, The Unit Operating Agreement for Federal Exploratory Units, Oil and Gas Agreements: Joint Operations, Paper 13-3 (Rocky Mt. Min. L. Fdn. 2008).

[58] Id.

[59] Id. at 13-1.

[60] Id. at 13-3.

[61] Id.

[62] Id.

What Is the Difference Between Leasing BLM and Forest Service Lands?

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

Leasing on National Forest System lands requires coordination between the BLM and the Forest Service throughout the leasing process. The BLM and the Forest Service share the responsibility over oil and gas leasing on National Forest System lands.[1] The BLM issues the oil and gas leases on National Forest System lands with the consent of the Forest Service.[2] Generally, the Forest Service manages the surface of the lands, while the BLM manages the subsurface, and the agencies work together to develop the permitting conditions under their separate management authorities.[3]

How do I get an oil and gas lease and drill on National Forest Service lands?

Obtaining an oil and gas lease on National Forest Service lands requires the consideration of multiple applicable laws as well as coordination between the two federal agencies. First, the Forest Service must make a determination regarding which federal lands are available for leasing. Next, a prospective lessee must send an informal request to the BLM for a specific parcel to be offered for sale. Finally, if the Forest Service consents to the sale and the BLM determines that the parcel is available and suitable for leasing, the parcel is included by the BLM in a notice of competitive oil and gas lease sale in the same manner as parcels located outside a national forest.  Assuming that the parcel is sold at a competitive lease sale and the BLM issues the lease, the lessee must obtain an approved application for a drilling permit and surface use plan. Drilling can begin once the BLM and the Forest Service have issued the necessary approvals and permits.[4]

  1. The Forest Service’s Availability Decisions

The Forest Service makes availability decisions identifying minerals on National Forest System lands that are available for leasing. These decisions are made through an appropriate National Environmental Policy Act (“NEPA”) process in cooperation with the BLM.[5] The Forest Service must exclude from the analysis lands that have been withdrawn from mineral leasing, lands recommended for wilderness designation, and lands designated as wilderness study areas (unless oil and gas leasing has been specifically allowed).[6]

As part of the leasing analysis, the Forest Service identifies on maps those areas that will be either open to development under the conditions of standard oil and gas leases, open to development under lease stipulations (e.g., conditions of surface occupancy), or closed to leasing.[7] The Forest Service promptly notifies the BLM of its availability decision, who adopts the Forest Service’s leasing analysis and decision.[8]  In offering the parcel for sale, the BLM includes any lease stipulations that the Forest Service notified it were necessary, as well as any additional lease stipulations that the BLM, as manager of the subsurface, determined are necessary.

  1. Expression of Interest to the BLM

A prospective lessee will submit an expression of interest (“EOI”) to the BLM.  An EOI is an informal request that identifies land that the BLM should consider offering for oil and gas competitive lease sales.[9] The BLM must obtain the consent of the Forest Service to offer the specific lands for leasing, which will be subject to the NEPA document, the land and resource management plan, and the Forest Service’s conditions of surface occupancy.[10] The BLM will review the nominated lands to ensure that they are “available, eligible, and suitable for leasing,” and may also conduct an analysis “to identify conditions or restrictions on oil and gas activities to protect the environment” before offering the lands for sale.[11]

  1. Leasing and Development

In order to develop an oil and gas lease on National Forest System lands, a lessee must submit an Application for Permit to Drill (“APD”) to the BLM, who forwards all APDs, including the Surface Use Plan of Operations (“SUPOs”), and Notices of Staking (“NOSs”) to the Forest Service for approval.[12] Both the BLM and the Forest Service post a 30-day public notice of all APDs and NOSs.[13]

“All SUPOs are subject to a level of NEPA analysis and documentation, including public involvement . . . .”[14] In addition, the SUPOs must comply with all other applicable laws, including the Endangered Species Act, National Historic Preservation Act, and Clean Water Act.[15] After reviewing the SUPO, the Forest Service will notify the operator and the BLM of its decision either approving the SUPO, approving the SUPO with conditions, or disapproving the SUPO, and will provide public notice of the decision.[16] The BLM reviews the APD for potential subsurface impacts, and, after receiving the approved SUPO from the Forest Service, issues the final approved APD.[17] Once all approvals and permits have been received, drilling can begin.[18]

[1] Memorandum of Understanding Between United States Department of the Interior Bureau of Land Management and United States Department of Agriculture Forest Service, at 3 (eff. Apr. 14, 2006), https://www.fs.fed.us/geology/MOU_BLM_Oil_Gas.pdf (“MOU”).

[2] 30 U.S.C. § 226(h).

[3] MOU, at 3–5.

[4] U.S. Forest Serv., Stages of Oil & Gas Exploration and Development on National Forest System Lands, at 2 (Dec. 12, 2005), https://www.fs.fed.us/emc/nepa/oged/includes/stages_summary_final.pdf.

[5] 36 C.F.R. § 228.102(a)–(b); MOU, at 8.

[6] 36 C.F.R. § 228.102(b).

[7] Id. § 228.102(c).

[8] Id. § 228.102(d); MOU, at 9.

[9] U.S. Dep’t of the Interior, National Fluids Lease Sale System, https://nflss.blm.gov/importantinfo (last visited Apr. 25, 2018).

[10] 36 C.F.R. § 228.102(e).

[11] U.S. Dep’t of the Interior, National Fluids Lease Sale System.

[12] MOU, at 12.

[13] Id.; see 30 U.S.C. § 226(f).

[14] U.S. Forest Serv., Stages of Oil & Gas Exploration and Development on National Forest System Lands, at 1.

[15] Id.; see also 36 C.F.R. §§ 228.104(b)(1), 228.108.

[16] 36 C.F.R. § 107(b)(2).

[17] MOU, at 14–15; U.S. Forest Serv. Wayne National Forest Oil & Gas Leasing Process, https://www.fs.usda.gov/detail/custergallatin/landmanagement/resourcemanagement/?cid=fseprd516706 (last visited Apr. 25, 2018).

[18] U.S. Forest Serv., Stages of Oil & Gas Exploration and Development on National Forest System Lands, at 2.

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.

Will My Federal Lease Be Extended?

FAQs of Federal Oil and Gas Leases, Federal Lands, Title Issues/Curative, , , , , , ,

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[4] 43 C.F.R. §3107.2-3.

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

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

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

[8] Id.

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

[10] 43 C.F.R. § 3107.1.

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

[12] 43 C.F.R. § 3107.1.

[13] 30 U.S.C. § 226(i).

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

[15] 43 C.F.R. §§ 3107.2-2 and -3.

[16] 43 C.F.R. § 3107.5-1.

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

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

[19] 43 C.F.R. § 3107.9-1.

[20] 30 U.S.C. § 226(m).

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

[22] 43 C.F.R. § 3107.3-2.

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

[24] 43 C.F.R. § 3183.4(b).

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

[26] Id.

[27] 43 C.F.R. § 3105.2-3.

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

[29] 43 C.F.R. § 3107.1.

[30] 43 C.F.R. § 3105.2-3(a).

[31] 43 C.F.R. § 3107.4.

[32] 43 C.F.R. § 3103.4-4(b).

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

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

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

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

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

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

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

Lease Rights

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

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

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

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

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

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

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

Permitting and Approval of Lease Operations

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

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

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

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

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

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

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

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

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

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

FAQs of Federal Oil and Gas Leases

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

1.   BLM Records

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

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

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

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

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

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

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

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

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

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

3.   Other Records

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

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

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

[2] 43 CFR § 3106.4-2.

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

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