royalties

Can I Drill Through Unleased Federal Lands?

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

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

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

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

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

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

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

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

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

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

What if the tract is only partially unleased federal minerals?

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

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

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

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

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

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

[3] 43 C.F.R. § 3100.2-1.

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

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

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

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

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

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

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

What Are Sliding-Scale Royalties?

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

Most leases on federal lands administered by the Bureau of Land Management (“BLM”) have flat royalties of 12.5% (evidenced by the use of the standard Schedule A to the BLM oil and gas lease form).[1]  However, certain leases issued by the BLM have “sliding-scale” or “step-scale” royalties for average daily production of oil or gas per well on the leased lands.  The most common sliding-scale royalty is evidenced by the use of Schedule B.  It is applicable to all leases issued between May 3, 1945 and August 8, 1946, as well as, all competitive leases issued after August 8, 1946 and prior to December 22, 1987.[2] There are two other sliding-scale royalty schedules, Schedule C and Schedule D, that are used for certain renewal and exchange leases, but those schedules are even less common.  The form of Schedule B is set forth below:

HOW TO CALCULATE SLIDING-SCALE ROYALTIES:

The regulations for calculating sliding-scale royalties for the “the average production per month in barrels per well per day” are found in 43 CFR § 3162.7-4 (“SSR Rules”).  The Office of Natural Resources Revenue (“ONRR”) provides guidelines and explanations for calculating sliding-scale Schedule B royalties on its website (at https://www.onrr.gov/ReportPay/PDFDocs/stepscale.pdf; the “ONRR Guidelines”).   Per the SSR Rules, the “average daily production per well for a lease is computed on the basis of a 28-, 29-, 30-, or 31-day month (as the case may be), the number of wells on the leasehold counted as producing, and the gross production from the leasehold.”  “Gross production,” is defined in the ONRR Guidelines to be “all production from the lease excluding any production used on the lease or unavoidably lost.”  For specific circumstances, the foregoing resources should always be consulted.  But as a general rule for operated wells, the following wells shall be “counted as producing” under the rules above: (1) existing wells on a lease (i.e., wells that were producing in the previous month) must produce at least 15 days in the month, (2) new oil wells drilled during the month must produce at least 10 days, and (3) for gas wells, any wells that produce during the month are counted.  For injection wells, we refer you to the rules but note that injection wells must operate at least 15 days to be counted.  Subparagraph (e) of the SSR Rules provide that “head wells” will be counted which “make their best production by intermittent pumping or flowing as producing every day of the month, provided they are regularly operated in this manner with approval of the authorized officer.”  Wells that predominately produce oil but have some gas production would be “counted as producing” under the royalty rates for oil in Schedule B, and not for gas (and vice versa for primarily gas wells that produce some oil).  For leases that had production for the previous month, but no wells produced for 15 days in the current month, the royalty is calculated on actual days produced, and for previously productive leases where no well produces for a month but oil was shipped, the previous calendar month’s royalty rate is used.

The SSR Rules and ONRR Guidelines provide the following example for calculated sliding-scale royalties for a hypothetical federal lease with Schedule B that has eight wells located on the leased lands in the month of June:

Well No. and record Count (marked X)
1. Produced full time for 30 days X
2. Produced for 26 days; down 4 days for repairs X
3. Produced for 28 days; down June 5, 12 hours, rods; June 14, 6 hours, engine down; June 26, 24 hours, pulling rods and tubing X
4. Produced for 12 days; down June 13 to 30
5. Produced for 8 hours every day (head well) X
6. Idle producer (not operated)
7. New well, completed June 17; produced for 14 days X
8. New well, completed June 22; produced for 9 days

In this example, there are eight wells on the leasehold, but wells 4, 6, and 8 are not counted in computing royalties. Wells 1, 2, 3, 5, and 7 are counted as producing for 30 days. The average production per well per day is determined by dividing the total production of the leasehold for the month (including the oil produced by wells 4 and 8) by five (the number of wells counted as producing), and dividing the answer by the number of days in the month.

For the foregoing example, the 1,000 bbls produced in June would be divided by the five counted wells and then divided by 30 calendar days in June, which equals 6.67 (and falls under 12.5% royalty rate on Schedule B for oil). As noted above, this includes production from all wells, even those that are not counted under the rules.

Finally, the ONRR Guidelines provide that the applicable royalty rate is based on monthly production (and not on monthly sales), and the “first in first out” method applies.  For the lease above, if 1,000 bbls are produced in June but only 700 bbls are sold in June, the 12.5% royalty applies to the 700 bbls sold in June.  If July has higher production, resulting in a royalty rate of 13% under Schedule B for the month of July, the first 300 bbls sold out of inventory in July will be attributed a 12.5% royalty from the remaining 300 bbls of unsold production from the month of June.

PRACTICE TIPS FOR DRAFTING DOCUMENTS INVOLVING FEDERAL LEASES WITH SLIDING-SCALE ROYALTIES:

In certain transactions, the failure to account for a federal lease with a sliding-scale royalty can result in ambiguities, which can then lead to unintended consequences or disputes.   For example, it is common for assignments of oil and gas leases to have a reserved overriding royalty interest that is calculated as the positive difference between existing burdens and a set percentage.  For example, consider an assignment where the assignor conveys all oil and gas leases described on Exhibit A and reserves an overriding royalty interest equal to the positive difference between existing burdens and 20% and there was a previous overriding royalty interest of record of a flat 5%.  For a lease with a sliding-scale royalty, it may not be clear how the reserved overriding royalty interest should be calculated if the sliding-scale royalty moves up from 12.5%.  The parties could indicate that the assignment is intended to convey a flat net revenue interest to the assignee (i.e., 80%), but that could create an ambiguity if there is not enough net revenue interest to satisfy the purportedly assigned net revenue interest (i.e., if the sliding-scale royalty moves above 20%).  As a result, it is necessary to include a statement that the existing burdens include a sliding-scale royalty and indicate how the reserved overriding royalty interest is to be calculated.  The complexity of the chain of title can be compounded when there are multiple assignments with this structure (i.e., an assignment first reserving an overriding royalty interest of the difference between existing burdens and 20%, followed by an overriding royalty interest of a flat 1%, followed by a later assignment reserving an overriding royalty interest of the difference between existing burdens and 22%).  Generally, if there are ambiguities in recorded assignments and no other extrinsic evidence of intent, courts can turn to rules of construction such as the rule that a document will be construed against the party who prepared the document.  As a result, any party preparing an assignment of a sliding-scale royalty lease with a reserved overriding royalty interest equal to the positive difference between existing burdens and a set percentage should take care to remove any ambiguities in the interests created by the assignment.

Other common industry documents could be impacted by federal leases with sliding-scale royalties, such as the joint operating agreement (“JOA”).  Most forms of JOA have a provision which sets a baseline royalty burden for all parties contributing leases to the contract area.  For example, the 1989 form A.A.P.L. JOA, in Article III(A) provides that: “Regardless of which party has contributed any Oil and Gas Lease or Oil and Gas Interest on which royalty or other burdens may be payable and except as otherwise expressly provided in this agreement, each party shall pay or deliver, or cause to be paid or delivered, all burdens on its share of the production from the Contract Area up to, but not in excess of, _______% and shall indemnify, defend and hold the other parties free from any liability therefor.”   To the extent leases are contributed which exceed the baseline burden amount the such party contributing that lease “shall assume and alone bear all such excess obligations and shall indemnify, defend and hold the other parties hereto harmless from any and all claims attributable to such excess burden.”  A party to a JOA that owns a federal lease with a sliding-scale royalty should carefully consider the potential economic impacts of this provision (in particular where the contractual interests of the parties under the JOA do not match their respective interests of record), and provide additional terms to address potential adverse impacts or ambiguities.

It is common for title examiners, whether landman providing lease reports, title attorneys providing drilling or division order title opinions, or division order analysts preparing revenue decks to provide ownership tables for federal sliding-scale royalty leases with an assumed royalty of 12.5%.  However, if not properly noted, subsequent parties relying on such tables could over-look that a sliding-scale royalty lease is involved.  It is important for landmen, title attorneys, and division order analysts to provide conspicuous statements in all ownership tables, noting the applicable sliding-scale royalty schedule.

[1] Applies to noncompetitive leases issued subsequent to the Act of August 8, 1946, and competitive and noncompetitive leases issued pursuant to the Federal Onshore Oil and Gas Leasing Reform Act of 1987.

[2] Leases issued between August 1, 1935 and May 3, 1945, also have royalty Schedule B, except the maximum rate for oil is 32% when daily production exceeds 2,000 barrels per well.

What Are the Types of Federal Oil and Gas Leases?

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

An Introduction to Federal Oil and Gas Leasing

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

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

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

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

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

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

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

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

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)

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

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

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

What is this thing anyway?

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

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

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

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

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

Aww shucks, the crank broke again!

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Deducting Post-Production Costs From Fee Royalty

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

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

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

Production Costs vs. Post-Production Costs

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

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

Lease Provisions

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

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

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

“At the Well”

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

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

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

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

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

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

Conclusion

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


How to increase attention to detail in title examination.

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

Proceeds from Production: You Have to Know When to Hold ‘Em

Royalty Issues, ,

Once an oil or gas well has been drilled and begins producing, one of the critical title decisions that a landman or division order analyst must make is when to hold proceeds in suspense. Most oil and gas producing states have a statute requiring that proceeds be paid to owners within a set amount of time after the date of first production or a penalty is imposed on the operator.1 If it is determined by a court or administrative agency that proceeds were not timely paid and were instead held in suspense improperly, the penalty on the operator can be imposed retroactively and can be substantial.2

As an initial matter, it is important to distinguish between proceeds that are not paid because they are suspended and proceeds that are not paid because the owner cannot be located to receive the payment. In the event an owner entitled to proceeds cannot be located, the proceeds are technically deemed unclaimed, not suspended. If the last address of record for the payee is no longer current, the operator is required to conduct an inquiry reasonably calculated to locate the owner. This should include a review of both traditional and online databases. Evidence of this search should be maintained in case there is a future challenge. If the owner remains unlocatable after completing a diligent search, the proceeds should be treated as unclaimed and the ultimate disposition of the funds will be governed by the unclaimed property statutes within the state of the last known address. Suspended funds, on the other hand, are not subject to the unclaimed property statute and it is not uncommon for suspense accounts to continue to accrue proceeds for many years. It is also possible to have proceeds attributable to an owner who are both in suspense and are unclaimed. This is often the case for unlocatable heirs or devisees of a decedent when there is no completed probate proceeding. In this case, because the proceeds are subject to potential multiple claims, they are suspended until the probate action is concluded and then, if the interest is vested but the owner is unlocatable, the proceeds become unclaimed property. We note that it is also possible for an owner to change from unlocatable to suspended. For example, if further research discloses that a payee is deceased, the proceeds should then be held in suspense until the necessary curative is recorded to properly vest title in the decedent’s heirs or devisees.

An operator may choose to obtain a division order title opinion to assist it in confirming the title of the owners, locating the last address of record for the owners, and making the decision for which owners, if any, to hold proceeds in suspense. Several oil and gas producing states provide a measure of legal protection to an operator if it acts in accordance with a title opinion when deciding to suspend proceeds.3

One recent decision from North Dakota highlights the potential danger in making the decision to suspend proceeds. In the unreported decision of Tank v. Burlington Res. Oil and Gas Co., LP,4 the U.S. District Court ruled that an operator unjustifiably held in suspense the proceeds payable to a royalty owner whose mineral interest was subject to an existing mortgage that predated the oil and gas lease. First, the title attorney indicated that that there was a risk in having the lease invalidated upon a foreclosure and required a subordination of the mortgage to the lease. Second, because the mortgage contained what appeared to be an absolute assignment of production proceeds, the title attorney indicated that confirmation should be made as to who should receive the proceeds. Both of the requirements appear to be reasonably necessary to protect the operator from potential liability. The court, however, determined that neither issue qualified as an “existing” dispute that justified holding the proceeds in suspense. As to the presence of the existing mortgage, the court said that until there was an actual foreclosure there was no title dispute. As to the uncertainty of which party was entitled to receive proceeds, the court said that a determination should have been made based on the records and a check cut to someone.

The standard set forth in this case reaffirms the need to have a division order title opinion that clearly articulates the owners whose proceeds should be suspended and sets forth the nature of the dispute which authorizes the suspension. The dispute should be one that is not easily resolved and contains the potential for the operator to be exposed to multiple liability. Operators should insist that their title examiners provide clear instructions as to the nature and scope of the title defect, the exact portion of the owner’s interest that should be held in suspense, and include detailed guidance as to the curative required to be completed before the proceeds should be paid. By law in some states (or, as a matter of good practice, in those states without a statutory requirement), a copy of the title opinion requirement (but only that requirement) outlining the issue causing the suspension should be provided to the owner. This information should be provided to the owner prior to the statutory deadline to make the first payment.

Finally, whether to suspend proceeds for any owner is ultimately the decision of the operator, and not the title attorney. The business risk of a potential challenge can always be assumed and payments made even though a title examiner instructed that proceeds should be suspended. As a practical matter, there may be situations where there is a legal defect in title that authorizes suspension, but the real risk of a challenge is remote and the operator may elect to assume the risk and not hold the interest in suspense, particularly where the operator’s interest is derived from the potentially disputed interest. If the division order title opinion does not provide sufficient facts to enable an operator to make this decision, the operator should inquire of the title examiner to fully understand and analyze the risk that would be assumed if the payments were made with the title defect outstanding.

 

1See Colo. Rev. Stat. Ann. §§ 34-60-118 and -118.5; Mont. Code. Ann. § 82-10-110; Nev. Rev. Stat. Ann. § 522.024; N.M. Stat. Ann. § 48-9-6; N.D. Cent. Code Ann. § 47-16-39.3; Tex. Bus. & Com. Code Ann. § 9.319; Tex. Nat. Res. Code Ann. §§ 91.401, 91.402, and 91.403; Utah Code Ann. §§ 40-6-8 and -9; Wyo. Stat. Ann. § 30-5-305.
2The possibility of a retroactive penalty adds to the risk for a new operator that assumes responsibility for distributing proceeds already held in suspense when it acquires a prior operator’s property.
3In New Mexico and Utah the protection is limited to the opinion of an attorney licensed in the state. See N.M. Stat. Ann. § 70-10-5; Utah Code Ann. § 40-6-9(8).
4No. 4:10-CV-088, 2013 WL 3766526 (D.N.D. July 16, 2013).

Entireties Clauses in Oil and Gas Leases: Are Mineral Owners Outside Your Unit Entitled to Proceeds?

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

Most oil and gas leases, with certain conditions, permit the lessee to develop the leasehold as a whole, so that drilling one well on one tract covered by the lease will satisfy drilling obligations for all tracts covered by the lease. The language typically reads as follows: “if the leased premises are now or hereafter owned in severalty or in separate tracts, the tracts, nevertheless, may be developed and operated as an entirety.” Known fittingly as the “entireties clause,” by treating the lease as a whole, even if certain tracts are later carved off and sold to others, the clause relieves the lessee of the obligation to drill offset wells to protect owners of the other non-producing tracts from internal drainage.

How are royalty payments treated? Early court decisions developed what is known as the non-apportionment rule, which holds that if the tracts covered by a lease were owned by different parties, and a producing well was drilled, for example, in Bob’s tract, then Jill, who owns a neighboring tract, is not entitled to any proceeds from production from the well on Bob’s tract. The basic principle is that each separate is owner is entitled to production from his or her own tract, free from the claims of the others. The non-apportionment rule was soon recognized as unfair, especially if the lessee was under no obligation to drill offset wells. The rule left landowners like Jill receiving no benefits from production on the leasehold. To avoid the unfair result, language was inserted into the entireties clause to allow for the apportionment of royalty payments. Typical language reads as follows: “royalties shall be paid to each separate owner in the proportion that the acreage owned by him bears to the entire leased area.” Thus a balance was introduced: lessees were allowed to develop the leased premises as a whole while all lessors benefited from production from anywhere within the whole.

Entireties clauses can take any variety of forms, but the form of concern here contains royalty apportionment language. For example:

If the leased premises are now or hereafter owned in severalty or in separate tracts, the premises, nevertheless, may be developed and operated as an entirety, and the royalties shall be paid to each separate owner in the proportion that the acreage owned by him bears to the entire leased area. There shall be no obligation on the part of the lessee to offset wells on separate tracts into which the land covered by this lease may hereafter be divided by sale, devise, or otherwise, or to furnish separate measuring or receiving tanks for the oil produced from such separate tracts.

Now suppose that Bob owned an undivided fractional mineral interest in two 640-acre sections of land, and that he leased his interest in both sections to XYZ Oil in 1985. The lease included the entireties clause above. In 1990, just before the lease expired, XYZ Oil drilled a prolific well (the Titan I well) in the north section, and the well continues to produce today. The lease did not have a Pugh clause, and thus the Titan I well held both the north section and the south section by continuous production. Meanwhile, in 1995, Bob conveyed all of his interest in the south section to his sister Jill by mineral deed. In accordance with the entireties clause, Bob and Jill updated ownership of the lease with XYZ Oil, and Jill thereafter enjoyed her apportioned royalty proceeds from the Titan I well.

To continue the story, in 2014, ABC Oil leased up the remaining undivided mineral owners in the south section, and drilled the Minerva I well on a 640-acre unit basis. XYZ Oil, as lessee of Bob’s and Jill’s lease, participates in the well. A title examination is ordered for the south section, and the examiner confirms not only that Bob’s and Jill’s lease is held by production from the Titan I well, but also that the entireties clause in the lease provides for the apportionment of royalties. At this point the examiner alerts ABC Oil that title to the north section covered by the lease will need to be examined in order to confirm the party or parties entitled to royalty proceeds from the Minerva I well. Perhaps Bob conveyed his interest in the north section to his children and grandchildren. By virtue of the entireties clause, such new owners will be entitled to their apportioned share of royalties, even though production is from a well located in the south section of the lease. Confirming such ownership will require a potentially burdensome title examination of land outside of the subject drilling unit. The title examination problem intensifies when a lease containing an entireties clause covers multiple tracts spread across multiple sections.

Entireties clauses with the type of royalty apportionment language discussed here are not ordinarily found in leases of recent vintage (their use having fallen out of favor), and appear most often in leases dating from the 1950s to 1970s. Importantly, such leases often contain no Pugh clause. Thus, particular care should be taken when reviewing the provisions of leases that have been held by production for multiple decades. Even when certain tracts of leases with royalty apportionment clauses have been released, some have argued that the lessors of released tracts remain entitled to proceeds from actively producing tracts. The entireties clause should also be carefully reviewed in the context of the other lease provisions, which may impact the application of the entireties clause. Further, any lease amendments should be carefully scrutinized because in some instances entireties clauses will have been deleted and replaced with a form of Pugh clause.

The entireties clause deserves the attention of operators, especially considering the many different forms in which the clause is drafted. The royalty apportionment-type clause treated here is just one variant with critical implications for the proper distribution of proceeds, but each lease needs to be examined in its own right with attention paid to the particular language used, in order to determine what issues might arise out of its application beyond royalty apportionment.

Sources:
1-7 Law of Pooling and Unitization § 7.04 (3d ed.).
4-6 Williams & Meyers, Oil and Gas Law § 678.
1-XII The Law of Oil and Gas Leases § 12.01 (2d ed.).
Gene L. McCoy, The Entirety Clause—Its Current Use and Interpretation, 12 Rocky Mt. Min. L. Inst. 10 (1967).
William S. Livingston, The Entirety Clause and the Drafting of Division Orders, 5 Rocky Mt. Min. L. Inst. 12 (1960).