Oil and Gas Regulations

Utah Board of Oil, Gas & Mining Amends Force Pooling Rules

Oil and Gas Regulations

Effective June 1, 2020, the Utah Board of Oil, Gas & Mining (the “Board”) approved significant revisions to the state’s force pooling rules. The prior rules gave an operator little certainty and direction on how to force pool interests in Utah. The new rules include procedures for handling disputes over the governing terms of the imposed operating agreement, treatment of unidentifiable or unlocatable owners, and application of the initial force pooling order to subsequently drilled wells.

Definitions for “Authority for Expenditure,”1 “Joint Operating Agreement,”2 and “Notice of Opportunity to Participate”3 are now included in Section R649-1-1. Importantly, definition for “Notice of Opportunity to Participate” contains a list of 10 items that must be included in the written notice of opportunity to participate provided to each “owner.”4

The newly adopted Section R649-2-8a replaces most of Section R649-2-9 and sets forth conditions under which an owner will be deemed to be a “nonconsenting owner” or “consenting owner” for the drilling and operation of a well. An owner will be deemed to be nonconsenting if, within 30 days from the date the notice of opportunity to participate is received, the owner does not execute and return to the operator the proposed AFE and JOA. The new rule allows for the owner to object to certain provisions contained in the proposed JOA and still be deemed consenting if they execute and return the proposed AFE to the operator and provide written objections, in good faith, specifying the provisions they find objectionable and proposing modifications or alternative provisions. Similar to above, this must be done within 30 days from the date the notice of opportunity to participate is received by the owner or such later date as specified in the notice or separate written agreement; otherwise, the owner will be deemed to be nonconsenting. The new rule further provides that an objecting owner, or an operator who in good faith rejects the owner’s proposed modifications to the JOA, may request the Board to determine the disputed terms of the JOA (and also challenge costs charged, if applicable). If no request is timely filed within the stated deadlines, the JOA terms proposed by the operator in the notice of opportunity to participate will govern and the actual costs incurred will be deemed to be reasonable. Moreover, Articles VII.A through D of the standard, unmodified A.A.P.L. Form 610-2015 Model Form Operating Agreement are deemed to be just and reasonable under all circumstances, provided the “risk penalty” will be set by the Board. If these provisions are contained in the proposed JOA without modification, any objection to them will be summarily rejected by the Board. Lastly, a nonconsenting owner is subject to the Board’s determination of a risk compensation award.

The prior rules did not address the treatment of owners that are either not identifiable or not locatable. Under the terms of newly adopted Section R649-2-9a, an operator can file a motion, concurrent with a force pooling request, to provide notification by publication to such owners that are not identifiable or not locatable. The notice must be acceptable to the Board and contain certain minimum specified information. Additionally, the operator must file an affidavit outlining its efforts to identify and locate these owners, which the Board must determine to be reasonable, diligent, and in good faith. If these requirements are met and no response from any such owner is received by the operator before the force pooling hearing, the owner will be deemed to be nonconsenting.

When determining a risk compensation award, newly adopted Section R649-2-9b directs the Board to consider certain factors, which pursuant to statute can range from 150% to 400%. Among other factors, the Board should consider the “geologic and engineering uncertainties and difficulties in drilling the well, the availability of information from prior and current drilling and development in the area, and the unique specified costs of the well.”

Finally, newly adopted Section R649-2-13 specifies that the initial force-pooling order for a drilling unit (including the terms and conditions of a JOA as adopted by the Board) will apply to any subsequently drilled well in the drilling unit, subject to compliance with the specified procedure. This procedure includes, for example, the operator filing a motion to modify the initial order and executing an affidavit containing, among other information, a description of the proposed, subsequent well, and identifying which owners are consenting and nonconsenting for the subsequent well. A party may object to this motion within 30 days after a copy of the motion is mailed to all alleged nonconsenting owners. If so, the Board will hold a hearing to address the objections. If no objections are received, the Board may enter an order extending the initial force-pooling order to the subsequent well.

For full details of the recent changes, the entire text of the revised rules should be reviewed. As of the drafting of this article, the online Utah Administrative Code has not been updated with the adopted changes.5 However, a copy of the final proposed rules, redlined against the previous rules, can be found at the following:

https://rules.utah.gov/publicat/bull_pdf/2020/b20200415.pdf (see pages 115 through 125).

1“Authority for Expenditure” or “AFE” is a detailed written statement made in good faith by an operator memorializing the total estimated costs to be incurred in the drilling, testing, completion, and equipping of a well for oil and gas operations.

2 “Joint Operating Agreement” or “JOA” is an agreement for the exploration, development, and production for oil, gas, or other minerals between parties entitled to participate pursuant to the ownership of said minerals or leaseholds covering said minerals, which are subject to the contract area, which may be inclusive of a drilling unit, described therein.

3 “Notice of Opportunity to Participate” means the written notice of opportunity to participate in a well for oil and gas operations required under Section 40-6-2(11) to be provided to an owner and which includes an offer to lease if the owner is an unleased owner, and an offer for the owner to directly participate financially, in proportion to the owner’s interest in the drilling, testing, completion, equipping, and operation of the subject well and which includes:

  1. the approximate surface and bottom hole location of the subject well by county, township, range, section, quarter-quarter section, or substantially equivalent lot, and footages from directional section lines;
  2. the proposed well name;
  3. the proposed total distance from the surface of the ground to the terminus measured along the vertical and lateral components if the well is a horizontal well;
  4. the proposed total depth;
  5. the objective productive zone and the approximate depth and locations of producing intervals in the borehole;
  6. the approximate date upon which the subject well was or will be spud;
  7. a joint operating agreement proposed in good faith by the operator for operation of the drilling unit upon which the subject well is to be drilled;
  8. an AFE for the subject well;
  9. a statement that a refusal to agree to either lease or participate in the subject well may result in the imposition of the statutory risk compensation award allowed under Section 40-6-6.5(4)(d)(i)(D) of between 150% and 400% as determined by the board; and
  10. a statement that any initial compulsory pooling order may apply to subsequent wells within the drilling unit including any statutory risk compensation award imposed under Utah law pursuant to Section 40-6-6.5(12).

We note the reference to Utah Code Ann. Section 40-6-2(11), which defines “natural gas liquids,” is presumably intended instead to be a reference to Section 40-6-2(12), which defines a “nonconsenting owner” as “an owner who does not, after written notice and in the manner and within the time frame established by the board in rule, consent to the drilling and operation of a well or agree to bear the owner’s proportionate share of the costs.” (emphasis added)

4 An “owner” is defined as “the person who has the right to drill into and produce from a reservoir and to appropriate the oil and gas that he produces, either for himself or for himself and others.” Section R649-1-1.

5 Available at: https://rules.utah.gov/publicat/code/r649/r649.htm.

NDIC To Hold Special Hearing on Potential Output Restrictions

Oil and Gas Regulations

Last month, North Dakota adopted a waiver program that allowed O&G producers to keep wells in non-completed or inactive status longer than regulations typically permitted. The policy was designed to prevent producers from either bringing more unwanted crude to market or being forced to abandon wells.

Now, North Dakota is looking into requiring oil and natural gas production cuts. The North Dakota Industrial Commission (“NDIC”) has announced the Oil and Gas Division of the Department of Mineral Resources has scheduled a special hearing for May 20 on whether or not the current production of oil and natural gas at low prices is a waste of energy pursuant to North Dakota Century Code § 38-08-02(19); the consequences of determining that waste is occurring, and what relief may be appropriate and necessary to prevent the waste of North Dakota crude oil production.

Under N.D.C.C. § 38-08-03, waste of oil and gas is prohibited. Section § 38-08-04, N.D.C.C., provides that the commission has authority to determine whether waste exists or is imminent, and to limit and allocate production of oil and gas from any field, pool, or area and to establish and define as separate marketing districts those contiguous areas within the state which supply oil and gas to different markets, and to limit and allocate the production of oil and gas for each separate marketing district. Section § 38-08-06 provides further guidelines for determining market demand and regulate the amount of production in marketing districts:

The commission shall determine market demand for each marketing district and regulate the amount of production as follows:

1. The commission shall limit the production of oil and gas within each marketing district to that amount which can be produced without waste, and which does not exceed the reasonable market demand.

2. Whenever the commission limits the total amount of oil or gas which may be produced in the state or a marketing district, the commission shall allocate or distribute the allowable production among the pools therein on a reasonable basis, giving, where reasonable under the circumstances to each pool with small wells of settled production, an allowable production which prevents the general premature abandonment of such wells in the pool.

. . . .

5. . . . The commission shall allocate the total allowable for the state in such manner as prevents undue discrimination between marketing districts, fields, pools, or portions thereof resulting from selective buying or nomination by purchasers.

In the past, the above statutes have rarely been utilized by the NDIC; however, the May 20 special hearing by the NDIC could potentially lead to output restrictions. Lynn Helms, director of the Oil and Gas Division of the state’s Department of Mineral Resources, previously advised against a decision to order output pro-rationing. The commission has asked oil and natural gas producers to weigh in on a wide array of oil market issues and the challenges of cutting or shutting in production. Written comments are due to the commission by May 15.

North Dakota will join Oklahoma in considering a similar proposal. Oklahoma regulators have enabled producers to voluntarily shut in their wells, but will revisit that decision and consider issuing an additional order in May that could force operators to limit oil production rates to prevent waste. A similar order was proposed in Texas that would have required oil companies operating in Texas to cut production by 20 percent, but after a month-long debate, Texas energy regulators on Tuesday said they will not wade into global oil politics to mandate oil production cuts for the first time in 50 years, despite crude oil’s plummet to historic lows.

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

Oil and Gas Regulations,

Lease Suspension and Reduction of Royalty Rates Available

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

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

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

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

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

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

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

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

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

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

The Interim Guidance specifically does not apply to Indian leases.

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

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

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

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

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

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

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

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

The Interim Guidance specifically does not apply to Indian leases.

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

EPA Issues Temporary Policy for Violations Caused By COVID-19

Oil and Gas Regulations, , , ,

On March 26, 2020 EPA issued a temporary policy for enforcement of environmental legal obligations during the COVID-19 pandemic. The policy provides the framework for the agency’s use of its enforcement discretion where COVID-19 related worker shortages and governmental restrictions affect facility operations and impede the ability of regulated entities to comply with EPA requirements. The policy does not extend to Superfund or Resource Conservation and Recovery Act (“RCRA”) corrective actions, which will be subject to forthcoming guidance, or pesticide imports under the Federal Insecticide, Fungicide, and Rodenticide Act (“FIFRA”).

Broadly speaking, the policy states that EPA will forego enforcement of certain civil violations where compliance is not reasonably practicable due to the COVID-19 pandemic, subject to compliance with specified reporting and documentation requirements. The application of enforcement discretion does not apply to criminal violations of environmental statutes and EPA indicates it will distinguish between unavoidable violations that result from COVID-19 restrictions and violations resulting from intentional disregard of legal requirements.

EPA’s policy applies different standards based on the category of potential noncompliance. If compliance with routine monitoring and reporting—such as stack testing, water and effluent sampling, inspections or training—is not reasonably practicable due to COVID-19, entities should report noncompliance using existing procedures as set forth in permit or statute. If such procedures do not exist, facilities must develop documentation and maintain noncompliance information internally. Ultimately, the better a facility’s documentation of how COVID-19 exigencies made compliance reasonably impracticable, the more likely EPA will be to forego enforcement.

The policy likewise provides guidelines for the following situations:

  • settlement agreement and consent decree reporting obligations and milestones;
  • facility operations impacted by COVID-19 that create an acute risk or imminent threat to human health or the environment;
  • facilities suffering from failure of air emission control, wastewater or waste treatment systems, or other equipment that may result in exceedances;
  • hazardous waste generators;
  • animal feeding operations;
  • public water systems regulated under the Safe Drinking Water Act; and
  • critical infrastructure.

Regardless of the situation, entities must first make every effort to comply with environmental compliance obligations. If compliance is not reasonably practicable because of circumstances caused by COVID-19, entities must do the following to be covered by the policy:

  1. Minimize effects and duration of any noncompliance caused by COVID-19;
  2. Identify the specific nature and dates of noncompliance;
  3. Identify how COVID-19 was the cause of noncompliance and decisions and actions taken in response;
  4. Return to compliance ASAP;
  5. Document the information and actions in 1–4.

Compliance with steps 1–5 is a condition of coverage under the policy.

Effective Period Starting March 13. The policy is retroactive—it applies to noncompliance events occurring from March 13 until the policy is terminated. During the effective period, the policy applies in lieu of otherwise applicable EPA policies. Even after the policy is revoked, noncompliance events that occurred during the effective period will be covered by the policy.

Caution! State Enforcement. The policy applies only to EPA enforcement actions—authorized states and tribes may take a different approach. It is likely that state agencies will issue their own parallel guidance in the coming days and weeks, and permittees should look to those policies in states that have delegated authority to administer environmental programs.

What Is Excluded? The policy does not apply to:

  • activities carried out under Superfund and RCRA Corrective Action enforcement instruments, although EPA indicated that separate guidance will be issued to address these programs;
  • pesticides and related imports;
  • requirements for preventing, responding to, and reporting accidental releases of oil and hazardous substances;
  • on-going enforcement matters.

This article was authored by Emily Schilling, Ashley Peck, Chris LeCates, and Hayley Siltanen.

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

Utah Clarifies Who Is Entitled to Proceeds of Unclaimed Mineral Interests

Oil and Gas Regulations, Royalty Issues, Title Issues/Curative, ,

On March 1, 2019, the Utah State Legislature passed a law clarifying what happens to unclaimed mineral interests located in the state of Utah.  The text of S.B. 78 and information about its passing can be found here.  This new law doesn’t change who owns unclaimed mineral interests, but it does streamline the process for transferring ownership and dealing with any proceeds derived from the interests.

The Utah Uniform Probate Code, Utah Code § 75-1-101, et seq., governs what happens to a person’s property at his death.  If a person dies without a will, then his property passes to his heirs by intestate succession.  Ordinarily, when a person dies without a will, his property passes to his immediate or extended family—beginning with his closest relationship and moving more distant until a taker is found.  If, however, a person has no family to whom his property can pass, his property will pass to the state of Utah.  That includes personal property, like bank accounts, furniture, and cars, as well as real property, like land and buildings.

A person’s ownership in real property is really a number of rights in the real property.  Normally, all of those rights remain intact and owned by a single person or in a familiar form such as “joint tenants.”  A “mineral interest” includes any interest in oil, gas, coal, gravel, or any substance that is “ordinarily and naturally considered a mineral.”  Often, a person who owns land will separate his ownership interest in the land’s minerals from the rest of his ownership interest in the land.  That means that he may sell his house and his land to one person, but sell the right to drill for oil or mine for coal to someone else.  Unless there is active drilling or mining on a property, it may not be obvious that the ownership rights have been separated.  In fact, it is not uncommon to discover many years after a property owner has died, that the person who owns the house and surface land does not own the underlying mineral interest in the land.

Mineral interests can be very valuable.  When a potentially valuable mineral interest is identified, the only person who can authorize drilling or mining on the land containing the interest is the owner of the mineral interest.  If the owner shown in the records of the county in which the land is located has died, then a person seeking to make use of the land’s minerals must find the current owner.  For property located in Utah, when the deceased owner of record has no family members, the current owner is the state of Utah.  S.B. 78 now clarifies the process by which a person who wants to make use of unclaimed mineral interests can go about getting permission. 

Under the new law, the Utah School and Institutional Trust Lands Administration (“SITLA”) has been charged with administering unclaimed mineral interests and their proceeds for the benefit of Utah’s public education.  Now, when an unclaimed mineral interest is identified, SITLA may bring an action in district court to be named the owner of record for the interest.  By becoming the owner of record, SITLA can deal with the mineral interest in the best way it sees fit.  That is, SITLA can hold the property and do nothing, it can sell the property, or it can lease the property to an “operator” to make use of the mineral interest.

As you can imagine, SITLA’s ability to determine what mineral interests may become subject to its administration is limited.  Because it would be nearly impossible for SITLA to find unclaimed mineral interests on its own, S.B. 78 requires “operators,” “owners,” and “payors” to notify SITLA that it has found a mineral interest that is potentially owned by the state.  That requirement does not impose a duty on every person who comes across an unclaimed mineral interest to report it to the state.  On the contrary, “operators,” “owners,” and “payors,” in this context, generally already have a stake in the mineral interest and owe some duty to the owner of the mineral interest.  For example, a “payor” is a person who undertakes to distribute oil and gas proceeds to the persons entitled to them.  Under the new law, the payor is not allowed to keep proceeds for himself under the guise that he cannot find to whom the proceeds should be paid.  Rather, the payor must notify SITLA that it is probably entitled to receive the unpaid proceeds to enable SITLA to perfect its right and receive the oil and gas proceeds for the benefit of Utah’s public education.

This new law benefits Utah public education because it streamlines the state’s ability to administer unclaimed mineral interests that the state owns by law.  It also benefits those who seek to make use of mineral interests because there is a clear process by which actual ownership of a mineral interest can be recorded and acted upon. 

Passage of the law highlights, however, that there may be a significant number of mineral interests in the state of Utah whose owner of record is deceased.  That leads to at least two lessons we can learn: (1) a person who owns a mineral interest should develop an estate plan that adequately passes his property to those of his choosing, whether it is family, friends, or otherwise, and (2) when administering an estate, pay attention to real property.  Whether a decedent dies intestate or has a valid will at death, a mineral interest that remains titled in the decedent’s name may not be discovered for many years.  When the mineral interest is finally discovered, if the decedent’s heirs cannot be located, that interest will pass to the state—probably not the result the decedent intended.

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.

BLM Directives Rein In the Federal APD Environmental Review Process

Federal Lands, Oil and Gas Regulations

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Lease Rights

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

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

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

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

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

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

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

Permitting and Approval of Lease Operations

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[6] 30 U.S.C. §§ 301 to 306.

[7] 30 U.S.C. § 301 (emphasis added).

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

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

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

Utah Oil & Gas Update

Oil and Gas Regulations, Royalty Issues, Title Issues/Curative, , , , , , , , , , , , , ,

UTAH COURT OF APPEALS APPLIES THE OPEN MINES DOCTRINE, REJECTS PETITION TO CONSTRUE WILL IN FAVOR OF LIFE TENANTS

In re Estate of Womack, 2016 UT App 83, 2016 WL 1729528, involved a decedent whose formally probated Will devised a 160-acre parcel to his three children, in equal shares. See id. ¶ 2. In his Will, the decedent specified that “the oil, gas and mineral rights under the said property . . . are devised to each of my children, share and share alike, for life,” remainder to the decedent’s grandchildren. Id. In 1990, the district court entered an estate closing order that named the decedent’s three children as the owners of the 160-acre parcel outright. Id. ¶ 3. In 1992, the district court amended the estate closing order “to conform to the Will” and provide for the grandchildren’s remainder in the minerals, which had been incorrectly omitted in the prior order. Id. ¶ 4. In 2008, an oil and gas company leased the minerals underlying the 160-acre parcel, but a question arose as to who was entitled to the proceeds of production. Id. ¶ 5.

In an effort to clarify who was entitled to the proceeds of production, one of the life tenants petitioned the district court to reopen the decedent’s estate and construe the Will in favor of the life tenants. According to the life tenant, the prior order’s lack of specificity resulted in an ambiguity that should be resolved in favor of the life tenants, based on an affidavit from the drafting attorney regarding the decedent’s intent. Id. ¶¶ 5 and 6. Two of the remaindermen challenged the petition, asserting that the requested relief would require the court to re-construe a provision of the Will that had already been construed, and that the court would be required to vacate or modify its prior order. This, the remaindermen contended, was barred by a six-month statute of limitations. Id. ¶ 14 (citing Utah Code Ann. § 75-3-412). The district court agreed with the remaindermen and denied the life tenant’s petition to construe the Will.

The life tenant appealed, claiming that the district court had misinterpreted the nature of the petition, and that the petition only sought clarification of the prior estate closing order, which was not subject to the six-month limitations period. The Court of Appeals affirmed the district court’s decision. The Court cited the open mines doctrine and concluded that the remaindermen were entitled to the proceeds of production because the Will did not specify otherwise. The Court found that the prior estate closing order had already construed the Will as creating life estates in mineral rights, and “[l]ife estates in mineral rights, by default, do not encompass a right to any proceeds from new mineral extraction.” Id. ¶ 17 (citing Hynson v. Jeffries, 697 So.2d 792, 797 (Miss. Ct. App. 1997). In the Court’s view, the Will was not ambiguous, and clarification was not necessary. Id. The Court found that the prior estate closing order “implicitly granted extraction proceeds to the [remaindermen] (albeit by default).” Id. ¶ 19. Because the petition sought to prove the decedent’s intent for the life tenants to receive income from the minerals, “rather than letting such proceeds default to the holders of the remainder” under common law, the Court found that the six-month time limit for vacations and modifications of prior orders applied, and the petition was time-barred. Id.

UTAH LEGISLATURE CONFIRMS THAT FEDERAL, STATE, AND TRIBAL INTERESTS MUST BE EXCLUDED WHEN CALCULATING SEVERANCE TAX ON OIL AND GAS

In the May 2015 edition of the Rocky Mountain Mineral Law Foundation Mineral Law Newsletter, we reported on the Utah Supreme Court’s decision in Anadarko Petroleum Corporation v. Utah State Tax Comm’n, 2015 UT 25, 345 P.3d 648 (Utah 2015). In Anadarko, the Court held that an oil and gas operator may exclude federal, state, and tribal interests when calculating its severance tax rate.

The Utah legislature recently codified the rule established by Anadarko. See S.B. 17, ch. 324, 2016 Utah Laws (amending Utah Code Ann. §§ 59-5-102 and 59-5-103.1). S.B. 17 confirms that the severance tax on oil and gas does not apply to federal, state, or tribal interests in oil and gas. As such, for purposes of determining the amount of severance tax, these exempt interests should be excluded when calculating the value of oil and gas and the tax rate. S.B. 17 applies to a taxable year beginning on or after January 1, 2015, as well as to severance taxes “for any taxable year, including a taxable year beginning before January 1, 2015, that is the subject of an appeal that was filed or pending on or after January 1, 2016.” Id.

(Re-printed from Andrew J. LeMieux, Utah Oil & Gas, Rocky Mountain Mineral Law Foundation Mineral Law Newsletter, May 2016)