production

Will My Federal Lease Be Extended?

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[4] 43 C.F.R. §3107.2-3.

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

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

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

[8] Id.

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

[10] 43 C.F.R. § 3107.1.

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

[12] 43 C.F.R. § 3107.1.

[13] 30 U.S.C. § 226(i).

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

[15] 43 C.F.R. §§ 3107.2-2 and -3.

[16] 43 C.F.R. § 3107.5-1.

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

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

[19] 43 C.F.R. § 3107.9-1.

[20] 30 U.S.C. § 226(m).

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

[22] 43 C.F.R. § 3107.3-2.

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

[24] 43 C.F.R. § 3183.4(b).

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

[26] Id.

[27] 43 C.F.R. § 3105.2-3.

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

[29] 43 C.F.R. § 3107.1.

[30] 43 C.F.R. § 3105.2-3(a).

[31] 43 C.F.R. § 3107.4.

[32] 43 C.F.R. § 3103.4-4(b).

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

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

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

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

What Are Sliding-Scale Royalties?

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.

Utah Supreme Court Invalidates Tax Title as to Severed Minerals on Due Process Grounds

Can Utah’s four-year statute of limitations for challenging a tax sale prevent a property owner who never received notice of the sale from contesting it?  In prior years, the answer may have been “yes.”  In Jordan v. Jensen, 2017 UT 1, 2017 WL 104642, however, the Utah Supreme Court held that the answer is an unequivocal “no.”

In Jordan, the owners of the surface and mineral estates conveyed the surface and reserved the minerals in a deed recorded in early 1995, prior to levy and assessment of the property taxes by Uintah County.  The new surface owner failed to fully pay the property taxes levied by the County for 1995, and as a result, the County sold the property at a tax sale in 2000, without notifying the mineral interest owners.  Id. ¶¶ 4-6.  Years later, an oil and gas company seeking to develop the mineral estate obtained a title opinion that indicated that there was a question whether the severed minerals passed at the tax sale because the tax deed did not contain any language reserving the mineral interest.  The mineral interest owners unsuccessfully tried to obtain a quitclaim deed from the surface owners and eventually sued to quiet title to the minerals.  Id. ¶¶ 9-10.

The surface owners argued, among other things, that the County’s general property tax assessment included the nonproducing mineral estate and that the failure to give notice to the mineral owners did not void the tax deed as to the mineral interest because Utah has a four-year statute of limitations that bars challenges to a tax deed.  See id. ¶¶ 13-14.  (Under Utah law, the authority to tax minerals has been delegated exclusively to the Utah State Tax Commission.  The surface owners argued that his delegation was limited to producing minerals and that the counties had the authority to tax the nonproducing minerals).  The district court rejected the surface owners’ arguments and entered summary judgment in favor of the mineral owners.  The surface owners appealed.  Id. ¶ 11.

In its decision in Jordan, the Utah Supreme Court did not address the issue of whether a county has the authority to assess the nonproducing mineral interest, instead limiting its holding to the due process issue.  Id. ¶ 12.

Specifically, the court analyzed whether the four-year statute of limitations provided by Utah Code Ann. § 78B-2-206 prevented a challenge to the tax title even though the mineral owners never received notice of the County’s tax sale as required by the Due Process Clause of the Fourteenth Amendment to the U.S. Constitution.  Jordan, 2017 UT 1, ¶ 16.  In Hansen v. Morris, 283 P.2d 884 (Utah 1955), the Utah Supreme Court rejected a challenge to a tax sale based on the predecessor to section 206.  The court in Hansen stated that “a failure to provide notice or a due process violation does not prevent section 206 from applying to ‘validate tax titles.’”  Jordan, 2017 UT 1, ¶ 22 (quoting Hansen, 283 P.2d at 885).

In overturning Hansen, the Jordan court noted that subsequent U.S. Supreme Court cases have taken a different approach, finding that a statute of limitations “will not apply when it is triggered by constitutionally defective state action.”  Id. ¶ 23 (citing Schroeder v. City of N.Y., 371 U.S. 208 (1962); Mennonite Bd. of Missions v. Adams, 462 U.S. 791 (1983); Tulsa Prof’l Collection Servs., Inc. v. Pope, 485 U.S. 478 (1988)).  Applying these cases, the Jordan court held that section 206 requires state action—the conducting of a tax sale—before it takes effect, and that section 206 will not prevent a party from challenging a tax sale if constitutionally adequate notice is not provided to that party.  Id. ¶ 34.  The court also noted that constructive notice by recording a tax title is insufficient where the mineral owners’ names and addresses are “reasonably ascertainable and known to the county,” as was the case here.  Id. ¶ 38; see id. ¶ 37.  Rather, notice to such owners must be mailed to their last known address of record or otherwise given in a manner that ensures its delivery.  Id. ¶ 37.

The court concluded that because the mineral owners did not receive constitutionally adequate notice, the County did not have jurisdiction over the mineral interest, thus voiding the tax title to the extent it purported to convey the mineral interest.  Id. ¶ 42.  In doing so, the court overruled Hansen “[t]o the extent [it] states that section 206 can apply where a state or county fails to provide constitutionally adequate notice to an interested party of a tax sale….”  Id. ¶ 40.

(Re-printed from Andrew J. LeMieux, Utah Oil & Gas, Rocky Mountain Mineral Law Foundation Mineral Law Newsletter, Volume XXXIV, Number 1, 2017)

Utah Oil & Gas Update

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)

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

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

So What Is It?

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

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

Horizontal and Vertical Pugh Clauses

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

Give Me An Example

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

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

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

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

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

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

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

Be Careful

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

 


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

Deducting Post-Production Costs From Fee Royalty

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 Rogerssee Pierce, supra, at 358-364; see also Martin & Kramer,supra, at § 645.

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

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).

The Implied Covenant to Drill and Develop in Montana

In Montana, there are many older oil and gas leases held by production, particularly in eastern Montana. These leases often times cover several tracts of land and do not contain a Pugh Clause. Although one or more of the tracts of the lease may be part of a producing unit, other tracts are not. Because there is no Pugh Clause in the lease, there is no explicit contractual right to a release of the nonproducing tracts. Given the recent development of the Bakken, the fact that a mineral owner may have nonproducing tracts of land held by an older lease with unfavorable royalty provisions is an undesirable situation for the owner. Mineral owners are, therefore, turning towards common law and unique mechanisms under Montana law to gain releases of these lands.

According to Montana Code Annotated Section 82-1-201, when an executed and recorded oil or gas lease is forfeited, cancelled, or expires, the lessee is required to have the lease released from record in the county where the leased land is situated within 60 days from the forfeiture. If the lessor sends a written notice requesting a release and the lessee fails to record the release within 30 days of the notice, then the lessee is guilty of a misdemeanor punishable by a fine of up to $250.1 Additionally, if, “by its terms,” an oil or gas lease has expired and is subject to forfeiture for nonperformance andmore than 3 years have elapsed since expiration, the mineral owner may serve written notice on the lessee pursuant to Section 82-1-202(2) demanding a release. The notice must inform the lessee that unless it files an affidavit stating that the lease is in effect within 60 days of the date of service of the notice, the lease must be terminated and is of no effect.2 After this 60-day period has expired, the mineral owner may file an affidavit of service of the notice in the county clerk’s office and from the filing of this notice the lands are released from the lien of the lease.3

Mineral rights owners have been increasingly using these statutes to demand partial releases of oil and gas leases pursuant to the implied covenant to drill and develop in Montana. Many times, the owners will send notice pursuant to Section 82-1-202(2) asserting that a lease has been expired for more than three years as to a tract or tracts of land because the lessee has failed to develop these tracts. The mineral owners cannot demand a release under an express provision of the lease because another tract in the lease is part of a producing unit and there is no Pugh Clause. Thus, the lease is technically held by production. Mineral owners, therefore, have turned to the implied covenant to drill and develop in order to gain releases of nonproducing tracts. If a lessee fails to respond to this notice because it believes the mineral owner had no right to send it, then the mineral owner proceeds to record an affidavit of service pursuant to Section 82-1-202(4) asserting that the lands are released. Whether the affidavit actually does release the lands may hinge on whether the owner had the right to demand a release as to certain tracts of land pursuant to the implied covenant to drill and develop.

Forfeitures of oil and gas leases are favored by the law and will be strictly enforced in Montana.4 In Sundheim v. Reef Oil Corp., mineral owners brought an action based partially upon a breach of an implied covenant to reasonably and prudently develop the leasehold.5 The Montana Supreme Court analyzed this covenant, but refused to consider it beyond the terms of the lease.6 The Court specifically found that pursuant to two express provisions in the lease, the operator had a duty to explore for or produce oil and gas from the leasehold.7 If the producer failed, the terms of the lease allowed the lessors to terminate the lease.8 The operator also had the option to make delay rentals, which it did.9 The acceptance of these delay rentals excused the lessee from fulfilling the duty to develop the leasehold.10 The Court specifically stated that it “will not look beyond these express provisions in order to impose a duty upon [the lessee] which is in contravention of their terms.”11

In Berthelote v. Loy Oil Co., the Court considered the implied covenant to produce and market gas and noted that “if a lease is terminated by the breach of implied covenants, it is forfeited.”12 Although neither Sundheim nor Bertheloteanalyzed whether an oil and gas lease should be partially released based upon the implied covenant to drill and develop the leasehold, both cases appear to lay the groundwork for such a claim. However, when analyzing a Pugh Clause in a lease, the Court has noted that absent a Pugh Clause “the lease would remain in effect as to the entire leased premises.”13 Given this statement by the Court and the Court’s reluctance in Sundheim to look beyond the express provisions of a lease to impose a duty which is in contravention of the lease terms, there is a good argument that a court will not impose an implied duty to develop a lease which is already held by production, even if certain tracts are not part of a producing unit. Unless there is an express provision (Pugh Clause) in the lease requiring the lessee to develop every tract or risk forfeiture, it is unlikely that a Montana court will afford a remedy based upon this implied covenant.

However, it is still important that a lessee not ignore a demand sent pursuant to Section 82-1-202. According to the statute, if a lessee fails to respond to this notice, then the mineral owner can record an affidavit of service pursuant to Section 82-1-202(4) and the lands are released. If a lessee does not timely response and the lessor files an affidavit of service, the lessee may be left trying to figure out how to make it clear in the county records that the lease has not in fact been released. Thus, it is best to consult with an attorney immediately upon receipt of such a notice if the lessee believes that the tracts are not subject to forfeiture.


1Mont. Code Ann. § 82-1-201(3). 
2Mont. Code Ann. § 82-1-202(2). 
3Mont. Code Ann. § 82-1-202(4).
4Stanolind Oil & Gas Co. v. Guertzgen, 100 F.2d 299, 300–01 (Mont. 1938). 
5Sundheim v. Reef Oil Corp., 806 P.2d 503 (1991).
6Id. at 509–10.
7Id. at 509. 
8Id. 
9Id. at 509–10. 
10Id. 
11Id. at 510.
12Berthelote v. Loy Oil Co., 28 P.2d 187, 190 (Mont. 1933).
13Fed. Land Bank of Spokane v. Texaco Inc., 820 P.2d 1269, 1272 (Mont. 1991).