Chris Jones

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.

Top Leases: Assessing (and Avoiding) the Risks of Novation

You only have three more months on the primary term of an oil and gas lease that was issued nearly five years ago with a 1/6th royalty.  A drilling permit should be issued any day now, and you anticipate commencing operations to drill a well in sufficient time to hold the lease.  You instruct your landman to obtain a top lease from the mineral owner just in case there is a hiccup and you can’t start operations in time to hold the existing lease. Your landman negotiates a new lease from the mineral owner covering the same lands but has to agree to a 3/16ths royalty in order to obtain the top lease.  But, the top lease fails to expressly state that it is a top lease to the existing lease and doesn’t contain any other language clarifying that the top lease will only be effective if and when the underlying existing lease expires.  Despite the precautionary top lease, the well permit is issued when expected and you are able to commence drilling a well in time to hold the prior existing lease.

After the well is drilled and completed, is there a risk that the mineral owner could successfully argue that the new top lease is a replacement of the existing lease and you are required to pay a 3/16ths royalty instead of a 1/6th royalty? In the oil and gas industry, you often hear landmen and attorneys frame the question as whether or not the top lease will be deemed a “novation” of the prior existing lease. But what is the standard to prove a novation? How likely is it that the mineral owner above could successfully argue that the top lease is a novation of the prior lease, even though the well was drilled in time to hold the prior existing lease? This article will provide a brief overview of the elements and burden of proof to establish a novation.

A recent 2015 case out of Pennsylvania provides an excellent overview and example of the novation analysis in the context of oil and gas leases. In Mason v. Range Resources-Appalachia LLC, 120 F. Supp. 3d 425, 433 (W.D. Pa. 2015), an oil and gas lease was issued in 1961 in Western Pennsylvania and was arguably held by gas storage operations on the property (and by the payment of rentals). Years later, during the Marcellus shale boom, a landman working for Range Resources obtained an oil and gas lease in 2007 from the same mineral owners and covering the same lands as the 1961 lease. Range Resources only later discovered that it already owned the existing 1961 lease. Testimony in the case indicated that the leasing environment at that time was “chaotic,” that Range Resources did not have a good process for evaluating lease validity, and that landmen were taking leases without conducting complete due diligence of possible existing leases. Range Resources did not drill a well within the term of the 2007 lease, and the mineral owners asserted that the 2007 lease was a novation of the 1961 lease (which had unique provisions allowing the lease to be held by rental payments for gas storage), and that the 2007 lease then expired.

The Pennsylvania court set forth four elements to show a novation, which elements are the same or similar in other jurisdictions that have undertaken a discussion of novation:

“(1) the displacement and extinction of a prior contract, (2) the substitution of a valid new contract for the prior contract, (3) sufficient legal consideration for the new contract, and (4) the consent of the parties.”1

The Pennsylvania court further stated that “whether a contract has the effect of a novation primarily depends upon the parties’ intent” and “the party claiming the existence of a novation bears the burden of demonstrating the parties had a meeting of the minds.” The court stated that evidence of the parties’ intent to enter in to a novation can be shown “by other writings, or by words, or by conduct, or by all three.” Courts in other states have similarly emphasized that a party claiming a novation has the burden of proof, and that the party asserting the claim of novation has the burden of proving all of the required elements for a novation.2 A novation is never presumed. Instead the presumption is that the new contract was taken conditionally or as additional security, absent evidence of intention to the contrary.3 In the Pennsylvania case, the court determined that the mineral owners continued to accept rentals under the 1961 lease even during the term of the 2007 lease, and there was no evidence that the parties expressly intended to replace the 1961 lease with the 2007 lease.

Returning to our example above, the case law suggests that a mineral owner attempting to argue that the top lease was a novation of the base lease would have a very challenging case. But there is still a risk of such a claim, even if the claim is ultimately for nuisance value only. How can an operator protect itself from novation claims? Obviously, the best approach is to always put language in any top lease that makes it clear that the lease will only go into effect if and when the base lease expires by its terms, and make that intent clear in any other written correspondence to a landowner (such as an initial offer letter).

But what if an operator accidentally obtains a standard lease with no top lease language when it already owns an existing lease? For drilling purposes, the mineral interest will be leased either way. But an operator should ideally take steps to address any ambiguity resulting from the top lease and clarify the intent of the parties. If the well is successfully completed in time to hold the existing lease, the best approach would be to have the mineral owner (and operator) sign and record a ratification document where the parties acknowledge that the base lease was held by the drilling of the well, and that the top lease will remain of record as a top lease only in the event the well ceases operations.

Another approach (with attendant risks) would be to send an informative letter to a landowner prior to drilling, informing them of the pending well, stating that the operator will deem the base lease as held by the drilling of the well. That would at least set up an estoppel argument, and the operator will know prior to drilling the well whether or not the landowner objects and claims a novation. Or, an operator may simply pay proceeds on the prior existing lease, see if the landowner accepts royalty payments under that lease, and simply run the risk of a future novation claim. There may also be facts that make an operator more confident that a novation argument will be unsuccessful that justifies a riskier wait-and-see approach.4

Each fact scenario will be different, and an oil and gas lessee must evaluate the facts and risks to determine what level of clarification and curative action it requires to address risks of novation claims when there are overlapping leases.


1 Another novation case in the oil and gas context, Warrior Drilling & Eng’g Co. v. King, 446 So. 2d 31, 33-34 (Ala. 1984), framed the elements as: “[T]o establish a novation there must be: (1) a previous valid obligation, (2) an agreement of the parties thereto to a new contract or obligation, (3) an agreement that is an extinguishment of the old contract or obligation, and (4) the new contract or obligation must be a valid one between the parties thereto.”
2 In re United Display & Box, Inc., 198 B.R. 829, 831 (Bankr. M.D. Fla. 1996). See also Fusco v. City of Union City, 618 A.2d 914 (App. Div. 1993); Alexander v. Angel, 236 P.2d 561 (1951); Scott v. Bank of Coushatta, 512 So. 2d 356 (La. 1987); Credit Bureaus Adjustment Dep’t, Inc. v. Cox Bros., 295 P.2d 1107 (1956).
3 For example, a Utah court conducting a novation analysis stated: “The burden of proof as to a novation by the transaction in question rests upon the party who asserts it; … an intention to effect a novation will not be presumed; … in the absence of evidence indicating a contrary intention, it will be presumed, prima facie, that the new obligation was accepted merely as additional or collateral security, or conditionally, subject to the payment thereof; and the intention to effect a novation must be clearly shown.” First Am. Commerce v. Washington Mut., 743 P.2d 1193 (Utah 1987); see also Tri-State Oil Tool Indus., Inc. v. EMC Energies, Inc., 561 P.2d 714, 716 (Wyo. 1977).
4 For example, if the existing lease covers multiple parcels in several drilling units, and the new lease only covers one parcel, that may make an argument for a novation more difficult. Also, if there are unrecorded documents that evidence clear intent that the second lease was intended only as a top lease, that fact may make an operator more confident that a novation claim would be unsuccessful.

Beyond Six Feet Under: Mineral Ownership and Development Issues Involving Cemeteries

Recent news coverage has spurred discussion on the rights that burial plot owners have in cemeteries and whether or not drilling for oil and gas should be prohibited on or under lands reserved for the dead.1 As horizontal drilling brings oil and gas development closer to population centers, the oil and gas industry will need to address some of the unique title and public policy issues surrounding mineral development under cemeteries.

Often, individual burial plot deeds read like warranty deeds and do not contain mineral reservations. However, burial plot deeds may contain a qualifier that the deed is granted for the sole purpose of the burial of human remains. If a burial plot deed grants fee title and contains no mineral reservations, it is conceivable that the burial plot owner (or his or her estate) could attempt to make a claim to the minerals underneath. Under general rules of deed interpretation in most states, a deed with no mineral reservations is deemed to convey fee title, including mineral rights.

On the other hand, burial plot transactions are not typical real property transactions. It is arguable that burial plot deeds are not intended to grant fee simple title to the land. The general rule is that “one who owns or has an interest in a cemetery for burial purposes does not acquire any title to the soil, but only an easement or license for the use intended.”2 Case law suggests that a burial plot deed should be interpreted as conveying only such interests in the burial plot that are necessary for the purpose of burying human remains (in other words not mineral rights). However, it is not clear that this rule applies in each state.3 From a public policy standpoint, it could be very difficult to track down the heirs or devisees of burial plot owners who died centuries ago.

If burial plot owners do not have a valid mineral claim, then who does? Public entities, common-law dedicators, and cemetery operators are likely candidates. For example, if a parcel of land is owned in fee simple by a public entity and dedicated for a cemetery, then the public entity (such as the city) would own the fee title, including mineral rights. If a parcel of land is privately owned in fee simple and dedicated on a subdivision plat or conveyed as a common-law dedication for use as a cemetery, then arguably the mineral title remains with the dedicator.4 If a cemetery operator acquired fee simple title, including minerals, by conveyance, then the operator may be deemed to own the minerals after deeding out the burial plots under the general rule discussed above.

Although the value of mineral rights under individual burial plots are likely to be economically miniscule, particularly if a cemetery is contained within a large drilling and spacing unit, there are risks involved if the proper mineral owners are not identified. Unfortunately, because of the small amount of oil and gas development near cemeteries to date, there are very few states that have addressed issues of mineral title in cemeteries. Therefore, title examiners and land departments should carefully examine burial plot deeds and thoroughly analyze the applicable state’s law in order to determine the correct mineral ownership under cemeteries.

Knowing who owns the minerals is only part of the issue if an operator intends to drill within the boundaries of a cemetery. Conducting drilling operations on actual cemetery land will likely be against public policy in many states. For example, inChas. E. Knox Oil Co. v. McKee, a church signed a lease with the operator for the purpose of drilling for oil and gas.5 Some of the church congregation members had family members buried in the cemetery and filed an injunction against the operator. The court held that it was against public policy to permit an operator to drill for oil and gas in a cemetery.6

Today with technological advancements in horizontal drilling, operators now have the ability to drill for minerals underneath cemeteries without having to conduct surface activities on the surface of the cemeteries. Arguably, the public policy rule established in cases like McKee would not apply to horizontal drilling. However, there have been recent oil and gas opposition groups claiming that underground fracking would disturb gravesites and not allow the dead to effectively “rest in peace.”7 Although mineral extraction occurs at depths that would likely never have any impact on gravesites, operators should be prepared to discuss and address these concerns when electing to drill for minerals on or beneath cemeteries.


*The author would like to acknowledge Scott T. Swallow for his contribution to this article.
1Manny Fernandez, Drilling for Gas Under Cemeteries Raises Concerns, N.Y. TIMES, July 8, 2012, available athttp://www.nytimes.com/2012/07/09/us/drilling-for-natural-gas-under-cemeteries-raises-concerns.html; see also Julie Carr Smyth, PRESSCONNECTS, Gas Drilling under Cemeteries Raises Money, Moral Questions, July 3, 2012, http://archive.pressconnects.com/article/20120704/NEWS01/207040337/Gas-drilling-under-cemeteries-raises-money-moral-questions.
2Walker v. Georgia Power Co., 177 Ga. App. 493, 496 (1986); see also Heiligman v. Chambers, 338 P.2d 144, 148 (Okla. 1959); Evergreen-Washelli Memorial Park Co. v. Dep’t of Revenue, 574 P.2d 735 (Wash. 1978); Petition of First Trinity Evangelical Lutheran Church in City of Pittsburg, 251 A.2d 685 (Pa. 1969).
3See, e.g., Wyo. Stat. Ann. §§ 35-8-102; Colo. Rev. Stat. Ann. § 12-12-116 (2006).
4See Taylor v. Con’t S. Corp., 280 P.2d 514 (Cal. App. 2d 1955).
5Chas. E. Knox Oil Co. v. McKee, 223 P. 880 (Okla. 1924).
6Id. at 882.
7See infra note 1.

Recording JOAs In the Face of Looming Bankruptcies: Better Now Than Never

While the oil and gas industry has experienced a significant downturn as a result of the collapse of global and regional oil prices, it wasn’t so long ago that times were booming and wells were being drilled at a rapid pace. During the recent boom years, everyone in the industry was scrambling to keep ahead of the curve, and some tasks previously viewed as routine fell to the way side. One action item that has been increasingly overlooked in recent years is the recording of a joint operating agreement, or a memorandum thereof (generally herein, including the recording of a memorandum applicable, a “JOA”) to provide notice of the operator’s lien rights. Considering the current downturn, the failure to record a JOA could come back to bite operators as defaults and bankruptcies appear to be looming for many players in the industry. As an operator, there still may be time to repent and record those agreements in order to protect your rights and interests.

The most current 1989 A.A.P.L Model Form of Operating Agreement, and most other commonly used agreements for joint operations, contains provisions whereby each party to the JOA grants a lien upon any interest it owns or acquires in real or personal property in the contract area covered by the agreement to secure such party’s obligations under the JOA.1 The form JOA contains provisions allowing for the recording of a memorandum (or “recording supplement”) of the JOA, or the agreement itself, which is acceptable in most states, to perfect the liens granted in the agreement.

It is generally well known that recording the JOA acts to perfect the operator’s lien of record as to competing lienholders. For example, if a JOA is recorded and there is later recorded a judgment lien against a non-operator, the operator’s lien would be superior to the claims of the later judgment creditor. As the current industry slowdown continues, and the risks of bankruptcies of non-operators looms, what is the impact of the failure to record a JOA upon the filing of Chapter 11 bankruptcy by the non-operator?

Upon filing for bankruptcy under Chapter 11 of the bankruptcy code, the appointed bankruptcy trustee of the debtor has the authority to either accept or reject “executory contracts.” 11 U.S.C. 365. An executory contract is a contract wherein there are ongoing or unperformed obligations on both sides. It is generally held and expected that JOAs will most likely be deemed executory contracts under the bankruptcy code. If a bankruptcy trustee accepts an executory contract, that will mean that the debtor, as an ongoing concern, will cure past defaults under the contract, compensate for default damages or losses, and give assurances for future performance. However, a bankrupt debtor that is a non-operator under a JOA will often have an incentive to reject a JOA as an executory contract. If a JOA is rejected, then ongoing rights and obligations of operators and non-operators, including the non-operator debtor, will likely be governed by common law tenants-in-common principles. If a bankruptcy trustee rejects an executory contract, then that is treated as a breach of the contract and the creditor party to the executory contract is granted damages resulting from the default under the rejected contract. Whether a JOA is recorded or not will not impact whether a JOA is an executory contract, but it will impact whether or not the damages granted to the operator under the rejected JOA will be secured or unsecured. If a JOA was never recorded, then the operator will be deemed an unsecured creditor and join the pool of other unsecured creditors (which creditors will either not get paid at all or may get pennies on the dollar for outstanding debts). But if the JOA was properly placed of record to perfect lien rights, then the damages afforded to the operator upon rejection of the JOA as an executory contract will give the operator a secured lien.

Of course, just because a recorded JOA perfects an operator’s lien, that does not mean it is necessarily first in time and has a superior lien position. For example, a non-operator may have granted a prior recorded mortgage or deed of trust for the benefit of a bank, which first-recorded lien could trump a later-recorded JOA (or memorandum thereof). Ideally, operators should obtain subordinations to the JOA from holders of outstanding mortgages or deeds of trust (much like operators do for important oil and gas leases or surface use agreements), but in practice this rarely occurs. But certainly recording the JOA will perfect the operator’s lien as to subsequently recorded liens (and remove the operator from the general unsecured creditor pool in bankruptcy).

The question facing land departments now is: what if we didn’t record a JOA at the time of execution – is it too late? The answer, as most other answers offered by attorneys, is: it depends. Within 90 days of filing for bankruptcy, any payments made for prior debts by a debtor in bankruptcy to certain creditors, but not others, can be held to be preferential transfers under the bankruptcy code. A preferential transfer is most typically a payment made to and for the benefit of one creditor, to the detriment of other creditors, within 90 days of the bankruptcy filing. A Texas bankruptcy court has held that recording a JOA within 90 days prior to the bankruptcy filing was a preference that benefited a single creditor to the detriment of other creditors and was thus invalid.2 You cannot forecast if and when a non-operator will file for bankruptcy. But one thing is certain – it doesn’t hurt to record the JOA. If you record and a non-operator does file for bankruptcy within 90 days, the recording may be invalidated. But if the non-operator files for bankruptcy on the 91st day, you may have been fortunate enough to perfect your operator’s lien. Also, while you may have lost lien priority during any delay in failing to promptly record the JOA, you might still have time to perfect your lien as to other subsequent lien claimants down the road (and you may still have time to secure a first-position lien). Being a second position lienholder on oil and gas assets under a JOA behind the first lien of, for example, a non-operator/debtor’s bank, will still grant you certain advantages in terms of negotiating an acquisition of those assets or preserving some rights to proceeds (certainly over and above the rights of unsecured creditors).

So in the face of potential loan defaults, judgment liens, bankruptcies, and all the other unfortunate events that result from oil and gas downturn cycles, operators should act soon to record JOAs. Obviously, priority should be given to agreements where there are sizeable and mounting debts by certain non-operators. While there may be findings down the road that the late recording of a JOA fails to perfect lien rights, there are no good reasons not to simply record JOAs today.


1See Article VII.B of 1989 Model Form Operating Agreement.
2See In Re Wilson, 69 B.R. 960 (Bankr. N.D. Tex. 1987).