oil and gas

A Roadmap for Commencement of Drilling Operations: Are We There Yet?

Fee Lease 101 Series, Lease Provisions, , ,

For oil and gas lessees, the journey from signing a lease to having a producing well can be a long and arduous one. Countless turns, speedbumps and stops along the way can reasonably be expected. The habendum clause alone can quickly bring the lease to a screeching halt. Savings clauses have been inserted into modern fee oil and gas leases to prevent automatic termination of the lease while the lessee conducts certain operations. Discussed herein is the commencement of drilling operations savings clause which, in the majority of states, will permit a lease to be preserved after the expiration of the primary term without production if certain operations are being conducted.1 However, even with this savings clause, lessees should be particularly wary of the roadblock approaching at the end of the primary term when determining whether drilling operations were properly commenced before expiration of the primary term. Well-constructed language in a fee oil and gas lease can allow continued operations even if the primary term has expired and the drill bit has not yet broken ground.2

Which lease provision is the commencement of drilling operation clause?

The following is an example of a commencement of drilling operations savings clause:

Notwithstanding anything in this lease contained to the contrary, it is expressly agreed that if Lessee shall commence drilling operations at any time while this lease is in force, this lease shall remain in force ….

Such clauses may include variations such as “commence operations to drill a well,” “commence drilling or re-working operations,” “commence or cause to be commenced the drilling of a test well,” “commence the drilling of a well in search for oil or gas,” “commence to drill a well,” “if no well be commenced,” “lessee is then engaged in drilling for oil or gas,” “lessee is then engaged in drilling or reworking operations thereon,” or “start drilling for oil.” 3 The question to be answered is what operations must a lessee commence to preserve the lease?4

What does commence mean?

Generally, the majority of the states hold that, unless otherwise provided for in the lease, actual drilling is not necessary in order to reach the threshold for commencement of operations. Courts have proved willing to find commencement of operations even when only “modest” preparations for drilling have been made, such as erecting a part of an oil derrick and working on providing a water supply for drilling.5 Other preparatory activities such as obtaining drilling permit, staking and leveling the well location,6 building board roads to the drill site and a turn-around,7 moving tools and equipment onto the drill site, digging slush pits,8 and similar on-site activities have been held sufficient to be considered commencement of drilling operations.9 In order to reach the commencement of drilling operations threshold, a lessee should conduct as many on-site work activities as it can before the primary term expires. When determining adequate operations for commencement, courts favor active earthwork, clearing, construction, structure placement, etc., as opposed to gathering data, developing reports, obtaining permits, having meetings, and filing paperwork.

Courts have further required that such operations must be performed with the bona fide intention to proceed with good faith and diligence to the completion of the well.10 In a case where the preliminary commencement activities were performed by a company that had not yet acquired the rights to drill due to negotiations over the terms of a farmout agreement, the Wyoming Supreme Court held that the drilling operations were not done in good faith with the intent to complete insofar as the operator’s rights were qualified and contingent and may not ever be realized.11

When does the clause require actual drilling?

Some jurisdictions have differentiated between “commence operations” and “commence drilling operations.” California, Kansas, and Montana courts have made such distinctions and held that “commence drilling operations” or similar language required the drill bit to penetrate the ground prior to the end of the primary term.12 However, a Wyoming court held that there is no such distinction13 and “commence to drill a well” may be satisfied if preliminary commencement activities are not mere pretenses or a holding devise to retain the lease, if the acts are commenced and prosecuted with good faith and bona fide intention to drill and complete the well, and performed with diligence.14 Additionally, the Eighth Circuit Court of Appeals, applying North Dakota law, dismissed an argument that “engaged in drilling or reworking operations” meant “engaged in drilling” (meaning actual drilling was required) or “engaged in reworking operations;” rather, the court interpreted the clause as being engaged in “drilling operations” or “reworking operations.”15

What about off-lease operations?

With the advent of off-lease surface locations for horizontal wells, the question arises as to whether operations on or from off-lease surface locations will qualify as commencement of drilling operations on the leased lands. There is currently little guidance to answer this question. As suggested by other authors, we recommend that new oil and gas lease forms and existing oil and gas leases be amended to include a provision similar to one of the following:

(1) As used herein, the term Operations shall mean any activity conducted on or off the leased premises that is reasonably calculated to obtain or restore production, including without limitations, (i) drilling or any act preparatory to drilling (such as obtaining permits, surveying a drill site, staking a drill site, building roads, clearing a drill site, or hauling equipment or supplies); (ii) reworking, plugging back, deepening, treating, stimulating, refitting, installing any artificial lift or production-enhancement equipment or technique; (iii) constructing facilities related to the production, treatment, transportation and marketing of substances produced from the leased premises; (iv) contracting for marketing services and sale of Oil and Gas Substances; and (v) construction of water disposal facilities and physical movement of water produced from the leased premises;16 or

(2) All operations conducted off the leased premises that are intended to result in the completion of, or restoration of production from, a producing interval on the leased premises or lands pooled or unitized therewith shall be considered operations conducted on the leased premises for purposes of extending and/or maintaining this lease in effect under any other paragraph or provision hereof.17

The lease, of course, would need to be further reviewed to confirm that the use of either of the above suggestions does not create any inconsistencies or confusion and all capital terms (if applicable) are appropriately defined.

What should I do?

In determining whether a lease has been extended beyond its primary term by the commencement of certain operations less than spudding the well, it is critical the specific language of the lease, the specific facts, and case law for the state in which the leased lands are located are reviewed. Even then, it may be difficult to conclusively determine whether the lessee’s actions are sufficient absent actual penetration of the ground with a rig sufficient to reach a producing zone. Facing any uncertainty, if the lease and case law lack clear standards, the safest course of action, if possible, would be to get an extension of the lease.

1Williams & Meyers, Oil and Gas Law § 617 at 297 (2012).
2This article is limited to fee oil and gas leases. As to federal oil and gas leases, actual drilling operations must be commenced prior to the expiration of the primary term – the bit must be “turning to the right” prior to 11:59 p.m. on the last day of the primary term. 71 Interior Dec. 263 (July 10, 1964). Site preparation and even moving a rig onsite do not qualify as actual drilling operations. 43 C.F.R. § 3100.0-5(g).
3Williams & Meyers, supra note 1, § 618.1 at 311.
4Not addressed herein is whether the commencement of drilling operations clause in the habendum clause of the lease also has the effect of being a continuous drilling clause, i.e., if the well is drilled as a dry hole, does the lessee have the right to commence a second well?
5Williams & Meyers, supra note 1, § 618.1 at 320.
6Petersen v. Robinson Oil & Gas Co., 356 S.W.2d 217 (Tex. App. 1962).
7Breaux v. Apache Oil Co., 240 So.2d 589 (La. App. 1970).
8Walton v. Zatoff, 125 N.W.2d 365 (Mich. 1964).
9See Oelze v. Key Drilling, Inc., 135 Ill. App. 3d 6, 481 N.E.2d 801 (5th Dist. 1985) (a drilling rig was moved near the site, brush cleared and one of three pits were dug before the end of the primary term was found to be “commence operations for drilling”); Johnson v. Yates Petroleum Corp., 981 P.2d 288 (N.M. Ct. App. 1999) (any activities in preparation for, or incidental to, drilling a well).
10See Sword v. Rains, 575 F.2d 810 (10th Cir. 1978); Wold v. Zavanna, LLC , 2013 WL 6858827 (D.N.D. Dec. 31, 2013); Murphy v. Amoco Prod. Co., 590 F. Supp. 455 (D.N.D. 1984); Stoltz, Wagner & Brown v. Duncan, 417 F. Supp. 552 (W.D. Okla. 1976) (not required to cause the bit to pierce the earth before the end of the primary term, but must have the good faith intention to unqualifiedly drill the well, commence drilling the well on such date and pursued such drilling as a reasonably prudent operator); Haddock v. McClendon, 266 S.W.2d 74 (Ark. 1954); Oelze v. Key Drilling, Inc., 135 Ill. App. 3d 6, 481 N.E.2d 801 (5th Dist. 1985); Illinois Mid- Continent Co. V. Tennis, 122 Ind. App. 17, 102 N.E. 2d 390 (1951) (lessee lacked good faith); Flanigan v. Stern, 265 S.W. 324 (Ky. 1924) (requiring after spudding reasonably diligence and bona fide effort); Smirth v. Gypsy Oil Co., 265 P. 647 (Ok. 1928); Bell v. Mitchell Energy Corp., 553 S.W.2d 626, 632 (Tex. App. 1977); LeBar v. Haynie, 552 P.2d 1107, 1111 (Wyo. 1976).
11True Oil Co. v. Gibson, 392 P.2d 795 (Wyo. 1964).
12Lewis v. Nance, 20 Cal. App. 2d 71, 66 P.2d 708 (4th Dist. 1937); Hall v. JFW, Inc. 893 P.2d 837 (Kan. 1995); Soldberg v. Sunburst Oil & Gas Co., 235 P. 761 (Mont. 1925) (“commence drilling operations for oil”).
13Fast v. Whitney, 187 P. 192 (Wyo. 1920) (“commences drilling”).
14LeBar v. Haynie, 552 P.2d 1007 (Wyo. 1976) (“commence to drill a well”); True Oil Co. v. Gibson, 392 P.2d 795 (Wyo. 1964).
15Anderson v. Hess, 733 F. Supp. 2d 1100, 1106-07 (D.N.D. 2010) aff’d 649 F.3d 891, 898 (8th Cir. 2011) (insofar as the lessor conceded that the lessee was engaged in drilling operations before the primary term expired, the court did not address whether the lessee’s preparatory activities were satisfactory to constitute drilling operations.). See also Wold v. Zavanna, LLC , 2013 WL 6858827 (D.N.D. Dec. 31, 2013) (granting summary judgement in favor of the lessee based on Anderson v. Hess and finding “drilling or reworking operations” had been commenced when lessee obtained all drilling approvals, engaged in actual on-site construction, hauling of equipment and materials on site, installing culverts and cattle guards, and digging reserve pit prior to the expiration of the primary term and finding that the lessee had capability to drill the well and good faith intent to complete the well with reasonably diligence).
16Milam Randolph Pharo & Gregory R. Danielson, “The Perfect Oil and Gas Lease: Why Bother!,” 50 Rocky Mt. Min. L. Inst. 19-1, 19-18 (2004).
17John W. Broomes, “Spinning Straw Into Gold: Refining and Redefining Lease Provisions for the Realities of Resources Play Operations,” 57 Rocky Mt. Min L. Inst. 26-1, 26-12 (2011).

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

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

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

What is this thing anyway?

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

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

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

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

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

Aww shucks, the crank broke again!

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Exercising Rights to Setoff and Recoupment in Bankruptcy

Bankruptcy, Due Diligence, Oil and Gas Agreements, , , ,

Current market conditions are straining business relationships in the oil and gas industry. In a growing number of cases, distressed companies are seeking chapter 11 bankruptcy protection. In that event, a creditor-debtor relationship is formed between the bankrupt company and the performing partner. For example, in the context of a joint operating agreement, an operator (the performing partner) may seek to recapture drilling costs from a non-operator (the bankrupt company). In these bankruptcy cases, the performing partner should consider its ability to offset debts with the bankrupt company through “setoff” or “recoupment”.

Setoff is simply a creditor’s right to offset mutual debts. Setoff is captured in Section 553(a) of the Bankruptcy Code, which preserves a creditor’s right to offset the mutual debts of the creditor and debtor provided that both debts (the debt owed by the creditor to the debtor and the debt owed by the debtor to the creditor) 1) arose before commencement of the bankruptcy case and 2) are mutual, meaning that both parties owe a debt to the other.1 The mutual debt need not, however, arise out of the same transaction in order for setoff to be available under the statute. 2 In fact, debts subject to setoff generally arise from different transactions.3

For example, A and B are jointly developing two wells and A is the operator of the wells. One well, called Boom, is producing, but the other, called Bust, is not. Boom generates $500,000 a month in revenue, but B owes A $1 million for B’s share of operating costs on Bust. In this case, setoff may allow A to withhold B’s share of revenue from Boom and credit it to B’s unpaid costs from Bust. This is because the purpose of setoff is to avoid “the absurdity of making A pay B when B owes A.”4

Setoff is limited in three ways. First, setoff is not a right created by the Bankruptcy Code.5 While Section 553(a) preserves a right to setoff, that right must first exist under “applicable non-bankruptcy law” (e.g. state law).6 Second, unlike recoupment (discussed below), a creditor can only offset pre-bankruptcy (pre-petition) debts. In other words, a creditor cannot use setoff to recover a pre-bankruptcy debt out of post-bankruptcy (post-petition) payments owed to the debtor.7 Third, a creditor’s right to setoff is automatically stayed (i.e. suspended) when a debtor files for bankruptcy protection.8 Creditors seeking to setoff must first obtain relief from the automatic stay imposed by Section 362(a) of the Bankruptcy Code and should consult bankruptcy counsel to assist in that effort.

Recoupment is similar to setoff in that it recognizes the basic inequities of allowing a debtor to enjoy the benefits of a transaction without also meeting its obligations.9 But, recoupment only permits a creditor to withhold funds to offset debts arising from the same transaction.10 Claims arise from the “same transaction” when both debts arise out of a single, integrated contract or similar transaction, such as a joint operating agreement.11

For example, A operates a well and B is a non-operator with an obligation to reimburse A for 25% of the drilling costs. A incurs $1,000,000 in costs and B fails to pay its $250,000 share. If B files for bankruptcy protection, then A has a $250,000 claim against the bankruptcy estate. In this case, recoupment may allow A to withhold B’s revenues from the well and credit the revenues against the costs incurred by A. This example illustrates how recoupment functions like a security interest in that it grants priority to a creditor’s claim in the bankruptcy estate, provided that the estate has a claim against the creditor arising from the “same transaction” as the creditor’s claim.12

Recoupment has certain benefits that are unavailable under setoff. First, a creditor can exercise its right to recoupment without regard to the timing and other requirements of Section 553 of the Bankruptcy Code.13 Second, recoupment allows a creditor to recover a pre-bankruptcy debt out of post-bankruptcy payments owed to the debtor.14 Third, a creditor who properly exercises its right to recoupment will not violate the automatic stay imposed by Section 362(a) of the Bankruptcy Code.15 However, a creditor may wish to seek relief from stay to clarify its right to exercise recoupment and to avoid any uncertainty about the amount the creditor can recoup. Bankruptcy counsel can help a creditor analyze its right of recoupment and assist in seeking relief from the automatic stay.

111 U.S.C. § 553(a).
2In re Davidovich, 901 F.2d 1533, 1537 (10th Cir. 1990).
3Conoco, Inc. v. Styler (In re Peterson Distrib.), 82 F.3d 956, 959 (10th Cir. 1996).
4Citizens Bank v. Strumpf, 516 U.S. 16, 18 (1995).
5Id.
6Id.
7See 11 U.S.C. § 553(a).
811 U.S.C. § 362(a)(7).
9Peterson Distrib., 82 F.3d at 960.
10In re Adamic, 291 B.R. 175, 181-82 (Bankr. D. Colo. 2003).
11Davidovich, 901 F.2d at 1538.
12Peterson Distrib., 82 F.3d at 960.
13Davidovich, 901 F.2d at 1537.
14Beaumont v. VA (In re Beaumont), 586 F.3d 776, 780 (10th Cir. 2009).
15Id. at 777.

Fraudulent Transfer Risks in Oil and Gas Transactions

Bankruptcy, Due Diligence, , , ,

Over the past few months, the economics of the oil and gas industry have changed dramatically. As oil and gas prices have fallen, so too have profit margins and working capital. Many companies will weather this storm. A fortunate few will expand their positions and acquire additional assets, some of which will be purchased from distressed companies. In dealing with these distressed companies and their assets, landmen and other oil and gas industry professionals will need to have a working-knowledge of select bankruptcy-related laws and concepts to protect their company’s assets. In this article, we will discuss one aspect of relevant bankruptcy law: fraudulent transfers and how they may affect property transactions.1

What is a fraudulent transfer?

When a company files for bankruptcy, the bankruptcy trustee may avoid any fraudulent transfer of property made within four years of filing in most states, if certain conditions are met. Fraudulent transfers occur when: (1) there was an intent to hinder, delay, or defraud creditors; or (2) the debtor transfers property without receiving “reasonably equivalent value” in exchange for the transfer and is insolvent at the time of the transfer, becomes insolvent as a result of the transfer, or is left with an unreasonably small amount of capital to operate its business as a result of the transfer.2 If a transaction is deemed to be a fraudulent transfer, the bankruptcy trustee can recover the property or obtain a judgment for the value of the property.

The first type of fraudulent transfer involves an actual intent to defraud and is more easily identified. For example, in In re Tronox, a court found that a debtor transferred property with environmental liabilities with an intent to hinder, delay, or defraud creditors through a spinoff.3 In another case, In re ASARCO, a court found that the debtor hindered and delayed creditors by directing all of the consideration from a sale of a majority of a mining entity to one of the Debtor’s creditors, to the detriment of other creditors.4 These situations usually involve related parties.

The second type of fraudulent transfer, commonly referred to as a constructively fraudulent transfer, occurs when a company purchases an asset without paying reasonably equivalent value. This can occur when purchasing assets from a third party or, more commonly, when buying-out a partner to resolve a debt or other obligation. If the seller files for bankruptcy subsequent to the transaction, there is a risk that the bankruptcy trustee could seek to have the transaction declared to be a fraudulent transfer.

In determining “reasonably equivalent value” a bankruptcy court looks at the totality of the circumstances. Fraudulent transfer laws are designed to preserve the assets of the debtor for the benefit of creditors. When carrying out this intent, courts disregard the form of a transaction and look “instead to its substance.”5 Fraudulent conveyance law is “designed to protect creditors’ rights” and looks at transactions from “the perspective of creditors.” 6 Whether a purchaser paid reasonably equivalent value is a subjective question that depends on the facts of each individual situation.

What does this mean for landmen?

Oil and gas professionals should be aware of the risks of acquiring property from distressed companies. To avoid constructively fraudulent transfers, a purchaser should ensure that they are giving “reasonably equivalent value” for the asset. This can be difficult. Under certain circumstances, when the value of the property is enhanced by the buyer after the sale closes (through drilling or other development) the debtor may later contend that the buyer failed to pay reasonably equivalent value.

The best way to determine “reasonably equivalent value” when dealing with a distressed company is to obtain an appraisal from an independent third party. If an appraisal is not cost-effective or is impractical, the risk of a fraudulent transfer can be mitigated by conducting proper due diligence.

An awareness of the financial health of the companies you are doing business with is as important as ever. By evaluating the transaction now, you can avoid problems down the road.

1There are many tools that an oil and gas company can use to mitigate its exposure to bankruptcy risks. A full discussion of all the tools is beyond the scope of this article. If you have questions on how to mitigate bankruptcy risks, or if a business partner files for bankruptcy, we advise you to contact a bankruptcy expert immediately to protect your assets.
2 See 11 U.S.C. § 548.
3 In re Tronox Inc., 429 B.R. 73 (Bankr. S.D.N.Y. 2010).
4 See In re ASARCO, L.L.C, 702 F.3d 250 (5th Cir. 2012).
5 In re HBE Leasing Corp. v. Frank, 48 F.3d 623, 638 (2d Cir.1995) (construing the New York’s fraudulent conveyance statute).
6In re Crowthers McCall Pattern, Inc., 129 B.R. 992, 998 (S.D.N.Y.1991).

But My Husband (or Wife) Doesn’t Need to Sign: Spousal Joinder Issues

Royalty Issues, , , , , ,

When obtaining an oil and gas lease from an individual mineral owner, it is a common practice for landmen to obtain a signature on the lease not only from the record title owner but also from that person’s spouse. That is done for good reason. Given the various legal principles that may require spousal joinder – such as community property rights and homestead laws as discussed in this article – obtaining spousal joinder on a lease often is required, and is a very good precaution even in situations where it may not be required.1

Obviously, a lease isn’t the only place where spousal joinder issues crop up. The chain of title to mineral property may include a number of deeds that were executed by individuals who held record title at the time and that were not executed by the spouses, if any, of such persons. Often there is nothing in the abstract confirming whether or not the grantor was married at the time a deed was executed. When it comes to conveyances that were executed in the past, a landman doesn’t readily have the ability to cause the grantor’s spouse to execute the deed and thereby eliminate the risk that a required spousal joinder was not obtained. So when is joinder in a conveyance by the non-record title owning spouse required?

For land in a community property state, any conveyance by a married individual without joinder of that person’s spouse raises the issue of whether any potential community property interest of a non-record title owner spouse was conveyed, or even whether the conveyance by the spouse owning record title was valid. Of the western states, Arizona, California, Idaho, Nevada, New Mexico, Oregon and Washington are community property states. Statutes in several of those states specifically require joinder of a husband and wife in execution of a conveyance of community property.2 Generally speaking, when a married individual living in a community property state acquires mineral rights or other real property interests in that state using funds generated by the joint effort of both spouses, the property is community property. Both spouses have an equal, presently vested interest in such real property. On the other hand, real property interests acquired by either spouse before marriage or after entry of decree of dissolution of marriage, and real property acquired by either spouse by gift, bequest, devise or descent, is separate property. The issue of what constitutes community property or quasi-community property is state specific and fact specific and is beyond the scope of this article.

Community property issues can’t be ignored entirely with respect to real property in common law jurisdictions either. A number of western states, including Colorado,3 Montana,4 Utah5 and Wyoming,6 have adopted the Uniform Disposition of Community Property Rights at Death Act. Under these statutes, the community property rights of a surviving spouse that resided in a community property state are recognized as to real property located in the applicable common law state. If both spouses are living, these statutes are not a concern. However, execution by a non-record title owing spouse is needed when conveying real property in the common law state that was owned by a deceased resident of a community property state, except as to real property that is separate property under the laws of the community property state.7 The statutes do protect purchasers for value from a personal representative, heir or devisee of the record title holder that has apparent title to the property against claims of the surviving spouse.

Other spousal joinder requirements arise out of state laws requiring that both spouses must join in instruments affecting real property when the land is a homestead. In Montana,8 Nevada,9 South Dakota10 and Utah,11 homesteads are created by a filing or a declaration in accordance with the applicable state statute, and spousal joinder is required to convey or encumber homesteads of married persons so created.12 In other states such as Nebraska,13 New Mexico,14 North Dakota,15 and Wyoming,16 a homestead right can arise without the filing of a homestead certificate. In Colorado, homesteads created automatically under the statutory provisions can be conveyed or encumbered free and clear of homestead rights by the record owner alone, but if the owner and spouse file a homestead declaration, the signature of both spouses is required to convey or encumber the property.17

In states where a homestead filing is required, if the title data is sufficient to determine that there was no homestead filing, a landman or title examiner can conclude that no spousal joinder was required in a conveyance. In jurisdictions where a homestead can be created without filing, spousal joinder generally should be obtained due to the difficulty of determining whether the land falls within the statutory definition of a homestead such that spousal joinder is required.18 However, given the provisions of the various homestead statutes, an out of state owner or the owner of a severed mineral interest would not be in a position to assert a homestead claim. As a result, the lack of joinder by the spouse of the record owner on a deed conveying such an interest would not be a title defect unless spousal joinder was needed for reasons other than the homestead statute.

In addition to the statutes discussed above, most states have adopted probate laws which guarantee that a surviving spouse will receive a fraction of the total value of the spouse’s estate. These statutes also permit the surviving spouse to attack certain conveyances made prior to death if the reduced estate and other assets are not there to satisfy the survivor’s share. The most common form of forced share provision is the augmented estate provision of the Uniform Probate Code (UPC). In order to protect the surviving spouse against transfers made before death, the effect of which is to reduce the estate and therefore the statutory guaranteed share, the UPC allows augmenting the estate to include certain property dispositions made by the decedent alone during a specified period (usually two years) before death. The augmented estate provisions of the UPC have been adopted in various forms in Colorado,19 Montana,20 Nebraska,21 North Dakota22 and Utah.23 These statutes are relevant only as to conveyances that were made by a married record owner without spousal joinder during the specified period before his or her death, when the issue has not been rendered moot by subsequent probate or intestacy proceedings which clarify that the surviving spouse did not elect to take under the augmented estate provisions.

As the discussion above indicates, there is no simple, across-the-board answer to the question of when spousal joinder is required in a conveyance. Whether the lack of spousal joinder in a deed in the chain of title resulted in an outstanding interest that was not conveyed may depend on facts not available in an abstract examined. Clearly one needs to understand the statutes and case law of the applicable state as the starting point in making that determination.

1If an individual executes a lease alone, the lessee frequently includes a recital stating the reason given by the lessor as to why joinder by a spouse was not needed. For example, the lease may recite that the lessor is a single person, or is a widow or widower. When the spouse of a record owner who is married does not sign a lease, the lease may recite that the lessor is dealing with his or her separate property. Inclusion of self-serving recitals such as these may make a company more comfortable in accepting a lease that has not been executed by the record owner’s spouse, but there is a risk in relying on such recitals without further confirmation since they are not proof of the facts stated. The “facts” recited may be incorrect. At most, they qualify the recited facts as prima facie evidence or create a rebuttable presumption that they are true. See, e.g., Colo. Rev. Stat. § 38-35-107 (recitals instruments recorded for 20 years are prima facie evidence of facts recited therein); S.D. Codified Laws § 43-28-19 (recitals are prima facia evidence on questions of marital status, homestead and identity when recorded); N.D. Title Standards 2-03 (permits reliance upon a recitation of single status, including widow or widower, if no evidence of marriage appears in the record).
2Ariz. Rev. Stat. Ann. § 33-452; Ida. Code § 32-912; N.M. Stat. Ann. § 40-3-13 (also applies to leases if the initial term, together with any option or extension, exceeds 5 years, or if the term is indefinite); and Rev. Code Wash. Ann. § 26.16.030(3). Under New Mexico law, for example, if a spouse fails to join in the conveyance, mortgage, assignment, or lease of community property, the instrument is void and of no effect, unless ratified by the spouse in writing. N.M. Stat. Ann. § 40-3-13; Hannah v. Tennant, 589 P.2d 1035 (N.M. 1979). In fact, an instrument purporting to convey a community property interest that is signed by only one of the spouses may not even be effective as to the spouse who signed the instrument. Either the joining or non-joining spouse can subsequently assert a claim that the conveyance was void. See Marquez v. Marquez, 513 P.2d 713 (N.M. 1973); McGrail v. Fields, 203 P.2d 1000 (N.M. 1949).
3Colo. Rev. Stat. § 15-20-101 et seq.
4Mont. Code Ann. § 72-9-101 et seq.
5Utah Code Ann. § 75-2b-101 et seq.
6Wyo. Stat. Ann. § 2-7-720 et seq.
7The statutes list rebuttable presumptions relating to community property and separate property.
8Mont. Code Ann. § 70-32-105.
9Nev. Rev. Stat. § 115.020.
10S.D. Codified Laws § 43-31-8.
11Utah Code Ann. § 78B-5-504.
12See Mont. Code Ann. § 70-32-301; Nev. Rev. Stat. § 115.040; S.D. Codified Laws § 43-31-17; Utah Code Ann. § 78B-5-504(4).
13Neb. Rev. Stat. § 40-104.
14N.M. Stat. Ann. § 42-10-9.
15While N.D. Cent. Code §§ 47-18-19 through 20 provide for execution and recording of a homestead declaration, N.D. Cent. Code § 47-18-17 provides that failure to make such a declaration shall not impair the homestead right.
16Wyo. Stat. Ann. § 34-2-121 (in addition to spousal joinder, requires language stating: “Hereby releasing and waiving all rights under and by virtue of the homestead exemption laws of this state” to convey or encumber homestead). Under Wyo. Stat. Ann. § 34-8-101 et seq., a defective deed is cured by operation of law after it has been of record for 10 years, however. 17Colo. Rev. Stat. § 38-41-202.
18As noted above, homesteads created automatically in Colorado are the exception since the record owner alone can convey or encumber the property.
19Colo. Rev. Stat. § 15-11-201 et seq.
20Mont. Code Ann. § 72-2-222.
21Neb. Rev. Stat. §§ 30-2313 – 2314 (period extended to 3 years).
22N.D. Cent. Code § 30.1-05-01.
23Utah Code Ann. § 75-1-201 et seq.

The Habendum Clause – ‘Til Production Ceases Do Us Part

Fee Lease 101 Series, Lease Provisions, , , ,

The habendum clause is a fundamental provision of oil and gas leases. This clause (also called the term clause) sets forth the time period that the rights granted to the lessee under the lease are extended—i.e. how long the lease will be active.1

Basics

An habendum clause in an oil and gas lease typically contains two separate terms, the primary term and the secondary term. The primary term is a fixed period of time during which the lessee has the option, but not the obligation, to pay delay rentals and/or explore for and produce oil and gas. No actual production is necessary to keep the lease active during the primary term. Ten years used to be a common primary term; however, shorter primary terms (e.g. 1 to 5 years) are often seen in areas with proven fields or anticipated drilling.2 As with other lease terms, its length can be negotiated by the lessor and lessee; the relative bargaining power between the parties and the amount of bonus a lessee is willing to pay are important in determining term length.3

At the expiration of the primary term, the lease terminates as a matter of law unless production4 is achieved during the primary term. The time period under the secondary term is indefinite—so long as lease substances are produced, the lease remains in effect. While many leases expire at the end of the primary term without production, if production is achieved, it is not uncommon for oil and gas leases to be held by production for many years.

In having both a primary and secondary term, the interests of both lessors and lessees are represented. The fixed primary term protects lessors from having their mineral interests endlessly tied up without production and encourages development on the land. If production is not achieved by the lessee within the primary term, the lease terminates (unless otherwise extended, such as by other lease terms) and the lessor is free to re-lease his or her mineral interests. Conversely, if production is achieved, the lessee’s risk in expending substantial sums to develop the land is rewarded by extending the lease so long as production continues.5

Formulation

Although there are numerous variations of habendum clauses, a typical habendum clause will read substantially as follows:

[T]his lease shall remain in force for a term of ___ years from this date, and as long thereafter as oil or gas or either of them is produced from said lands.6

Additionally, the phrase “produced in paying quantities” or “produced in commercial quantities” is commonly included in the clause, along with phrases allowing for production to come from lands pooled or unitized with the leased lands.7

Meaning of “Produced”

As noted above, the typical habendum clause requires that oil or gas be “produced” from the leased land to extend the lease beyond its primary term. In most states, “produced” means exactly that—oil or gas must actually be produced from the leased land. A minority of states, including Oklahoma and West Virginia, hold that discovery of oil or gas is sufficient—no production is actually necessary—to extend the lease beyond its primary term, although the well must be completed and capable of production, and the lessee must make diligent efforts to market.8 Another minority of states, including Montana and Wyoming, appear to differentiate between oil and gas, with the discovery of gas being sufficient to extend the lease beyond the primary term, while actual production for oil is necessary to extend.9 The distinction arises because oil can be produced and stored economically while gas generally cannot be stored economically above the ground.10

Some habendum clauses include language that the lease will be extended “so long as oil or gas is capable of being produced in paying quantities.” In such instances, actual production is not necessary to extend the lease beyond its primary term, but may require a well that can be turned “on” to produce in paying quantities without the addition of extra equipment or repair.11

Once the lease is extended into the secondary term, if production ceases the lease automatically terminates (unless otherwise extended by a different provision in the lease).12 However, courts have held that it is not required that production be entirely continuous throughout the extended term to hold the lease. Courts recognize that production may temporarily cease due to repairs, breakdowns, and reworking operations.13 Where the lease is silent, and cessation in production is litigated, the burden of proof rests on the lessee to show that the cessation was for a reasonable reason and for a reasonable amount of time. Courts vary in what constitutes a reasonable amount of time.14 For example, one court held that a four-year cessation in production was “temporary,” while another court held that a six-month cessation was “permanent.” To provide more certainty in the face of inconsistent court rulings, modern oil and gas leases often include a “cessation of production” clause that specifies when production must be continued after cessation for the lease to not terminate.15

Meaning of “Produced in Paying Quantities”

A question that frequently arises when construing an habendum clause is how much production is necessary—i.e. is any amount of production sufficient to hold the lease, or must the production reach a certain level? As noted above, modern oil and gas leases commonly include the qualification that production be in “paying” or “commercial” quantities. For leases that only state “production” is required, courts generally have construed the clause to include this qualification. Thus, regardless of whether the lease includes the qualification “in paying quantities,” the term “produced” typically means “produced in paying quantities.”16

The question then becomes what constitutes “produced in paying quantities.” The Kansas Court of Appeals stated the general rule:

[T]he phrase “in paying quantities” as used in an oil and gas lease habendum clause means production of quantities of oil or gas sufficient to yield a profit to the lessee over operating expenses, even though the drilling costs or equipping costs are never recovered, and even though the undertaking as a whole may thus result in a loss to the lessee.17

Put simply, a lease is considered “producing in paying quantities” if production revenue is greater than operating expenses.

In determining production revenue, any royalty paid to the lessor is excluded, although any payment to overriding royalty owners generally are included as revenue.18 For operating expenses, any direct costs to operate, such as labor costs, electricity for pumping units, taxes (but not income taxes) payable by the working interest owner(s), and day-to-day maintenance cost are included.19 There is some dispute among courts whether depreciation and overhead costs should be included as operating expenses.20 Initial expenditures, such as the costs of drilling, equipping, and completing are not included as operating expenses.21 Such analysis makes economic sense—after these initial expenditures, an operator will continue to operate so long as the production on a lease is marginally profitable in order to recover as much of these costs as possible.22

It is important to have a reasonable time period when evaluating production revenues against operating expenses. Leases may operate negatively in the short-term, but profitably in the long-term. One source notes that in almost every instance, a time period of at least a year was used by the courts to evaluate profitability, and frequently a time period of eighteen months to three years was used.23 In times of distressed market conditions, courts have used longer time periods or have assessed whether the lease would have been profitable under normal market conditions.24

Conclusion

An understanding of the habendum clause is crucial when negotiating a lease or when evaluating whether a lease has been held by production past its primary term. As you do so, keep in mind that other lease provisions not discussed in this article may also affect lease duration, such as shut-in royalty, pooling, unitization, Pugh, continuous operations, delay rental, and cessation of production clauses, among others. Additionally, be aware that the law varies from jurisdiction to jurisdiction, and may be different from the general principles discussed in this article.

1See PEC Minerals LP v. Chevron U.S.A., Inc., 439 F. App’x 413, 416 (5th Cir. 2011).
2John S. Lowe, Oil and Gas Law in a Nutshell (6th ed. 2014).
3Id.
4Or a lease provision that serves as a substitution for actual production such as continuous drilling operations or payment of shut-in royalty.
5Lowe, supra note 2.
63 Patrick H. Martin & Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § 603.3 (2014).
7Id.
8See McVicker v. Horn, 322 P.2d 410 (Okla. 1958); Eastern Oil Co. v. Coulehan, 64 S.E. 836 ( W. Va. 1909).
9See Severson v. Barstow, 63 P.2d 1022 (Mont. 1936); Pryor Mt. Oil & Gas Co. v. Cross, 222 P. 570 (1924).
10See 2 Eugene Kuntz, A Treatise on the Law of Oil and Gas § 26.6 (rev. ed. 2014). See also Lowe, supra note 2.
11Martin & Kramer, supra note 6.
12See Anadarko Petroleum Corp. v. Thompson, 94 S.W.3d 550, 554 (Tex. 2002).
13Martin & Kramer, supra note 6, at § 604.4.
14Id.
15Id. See also Dave Hatch, Potential Pitfalls of Continuous Drilling Provisions in HBP Fee Leases (Apr. 10, 2014), available at: http://www.hollandhart.com/pitfalls-of-continuous-drilling-provisions-in-hbp-fee-leases/.
161 Earl A. Brown, Earl A. Brown, Jr., & Lawrence T. Gillaspia, The Law of Oil and Gas Leases § 5.03 (2d ed. 2014).
17Avien Corp. v. First National Oil, Inc., 79 P.3d 223, 230 (Kan. Ct. App. 2003); see also Maralex Res., Inc. v. Gilbreath, 76 P.3d 626, 630 (N.M. 2003) (“To satisfy the habendum clause production must be in ‘paying quantities,’ such that the income generated from oil and gas production exceeds the operating costs.”).
18Lowe, supra note 2.
19Id. See also Martin & Kramer, supra note 6, at § 604.6(b).
20Martin & Kramer, supra note 6, at § 604.6(b).
21Kuntz, supra note 10, at § 26.7.
22Martin & Kramer, supra note 6, at § 604.6(b).
23Lowe, supra note 2.
24Id. See also Kuntz, supra note 10, at § 26.7.

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

Royalty Issues, ,

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

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

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

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

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

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

 

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

How Online Genealogical Tools Can Make a Landman’s Life Easier

Title Issues/Curative, , ,

The drilling rig is en route to your location and your land manager is breathing down your neck to lease the last remaining fee owners. The only problem: the owners cannot be found because they are likely deceased. Now what do you do? Carry the interests? Force pool? Drilling delays can be costly and carrying interests can be risky, so time is of the essence. Fortunately, there are a number of online genealogical tools available that might help you track down the heirs or devisees of the deceased owners.

Surprisingly, Google searches are a great starting point. In particular, rare names or unique spellings are helpful to locate information and, oftentimes, an obituary can be located by searching a decedent’s name and last known city or state of residence. Obituaries are generally accurate and provide a list of possible heirs or devisees. If an obituary is not located by a Google search, it might be found using another search engine, such as Yahoo or Bing.

If you know the decedent’s place of death and approximate date of death, you can search probate records. Some states, such as Colorado1, Montana2, New Mexico3, North Dakota4, Texas5, and Utah6, have websites which provide probate or other genealogical resources online. Individual counties typically maintain their own probate files. Where resources are not available online, you may ask the county court if there is a probate file for the decedent and, if so, request a copy of the file.

What about the more difficult searches? GenealogyBank.com, a subscription-based site, has a database of 6,500 newspapers with some newspapers going as far back as 1690. Generally, the earlier the date of death, the more difficult it is to find an obituary for the decedent. However, GenealogyBank.com may provide a death notice (indicating when and where the decedent died), a social security number, newsworthy stories, or birth or marriage announcements. If a social security number is located, it can be used to search the Social Security Death Index (free on several online genealogical websites, see below) to identify the date of the decedent’s birth and death, the town in which the decedent’s social security card was issued, and the decedent’s last place of residence. Any information gathered about the decedent, including relatives, dates of life events, places of life events, etc., can be used on other genealogical websites to locate potential heirs or devisees.

Obituaries and genealogical information may also be available on FindAGrave.com. However, this website is best known for its vast library of headstone images. These images generally include the name of the decedent’s spouse and the decedent’s and his or her spouse’s birth and death dates (as well as the location where the decedent was buried).

The largest of all the genealogical websites is Ancestry.com, which claims to have over 6 billion records available online. Another genealogical website, FamilySearch.org, is particularly helpful for decedents who resided in Utah, Idaho, and Wyoming. There are countless other genealogical blogs and websites to search, many of which focus on a particularly feature such as religion, national origin, ethnic background, etc. The larger genealogical websites, including Ancestry.com and FamilySearch.org, have census records available up until 1940.7 These websites also include marriage records, birth records, military records, and family trees. Family trees are created by individuals, which means they are not always accurate or complete. However, they are a great source for locating possible heirs or devisees because they may include names of descendants, biographies, and family histories. As an added feature, some websites allow communication with the person who provided the genealogical information to the website.

The more information that you can use in a search, the better the chance that: (i) you will find the decedent’s heirs or devisees and (ii) they will be the right persons. With any luck, you will gather enough information to track down possible heirs or devisees to obtain leases or send participation letters prior to drilling. Although these online genealogical resources may not finish the job, since title curative will likely be required, they can start you down the right path.

1https://www.colorado.gov/pacific/archives/archives-search.
2http://www.montana-genealogy.com/Montana-Probate-Records.htm. No subscription required, but the website links to third-party subscription websites.
3http://caselookup.nmcourts.gov/.
4http://publicsearch.ndcourts.gov/.
5http://www.texas.gov/en/discover/Pages/topic.aspx?topicid=/records. Records available for select counties only.
6http://www.utcourts.gov/xchange. Subscription required.
7Census records are sealed for 72 years after the census is taken, which means they are currently available for the 1940s and back.

The Nuts and Bolts of Farmout Agreements

Royalty Issues,

An oil and gas farmout agreement is an agreement by the owner of an oil and gas lease (the “farmor”) to assign all or part of the working interest in that lease to another party (the “farmee”), who agrees to drill a well and do testing on the property in exchange for the opportunity to earn a formal assignment of working interest. The farmout agreement usually requires the farmee to drill a well to a certain depth, at a specified location, and within a certain time frame, at the farmee’s own risk and expense. Typically, the farmee must complete the well as a commercial producer to earn an assignment, because the farmor desires to preserve the lease (although some farmouts require only drilling to earn). Generally speaking, the greater the risks a farmee takes, the greater the area in which the farmee will earn an interest.

In a farmout, the farmor usually reserves an overriding royalty interest, with the option to convert the overriding royalty interest to a working interest in the lease upon payout of drilling and production expenses, otherwise known as a back-in after payout (BIAPO). As an example, the agreement may provide for:

Before Payout of Well Cost (“BPO”)
3% overriding royalty		 After Payout of Well Costs (“APO”)
Option to keep 3% ORRI or convert to 25% working interest subject to royalty burden

Payout occurs when the farmee has recovered all of its drilling costs out of its share of production after deducting its operating costs, certain taxes, and other expenses. The farmout should include a complete definition of “payout” by stating exactly what will be deducted in calculating the payout amount.

Farmouts can present a number of potential issues for land departments and title examiners. First, the parties often fail to record notice of the farmout. As a result, the farmee’s rights under the farmout may not be protected against a third-party bona fide purchaser or the bankruptcy of the farmor. It is critical for a farmee to provide notice of the farmout and protect its operator’s lien rights by perfecting its interest under the farmout. Fortunately, this issue can be easily resolved by recording a memorandum of the farmout agreement in the county where the lands are located.

Second, a farmout is different than a lease assignment in that the farmor retains leasehold title until the farmee has completed the required drilling and testing of the property and has earned an assignment. Without a formal assignment of interest from the farmor, the records may not be clear as to whether the farmee has in fact earned an interest under a farmout agreement, and a factual inquiry and careful analysis is required. To aid this analysis, the conditions for earning an assignment and when the assignment will be delivered to the farmee should be clearly drafted in the farmout. Once the farmee receives the assignment, it should be timely recorded in the county where the lands are located for the same reasons as discussed above.

Third, the election of the farmor to retain an overriding royalty interest or convert it to a BIAPO working interest affects the rights of both parties and their successors-in-interest. Therefore, the farmor’s election must be clear from the records. The election should be reflected either in the recorded assignment or in a subsequently recorded instrument.

Other farmout provisions of note include the formation of an AMI, or “area of mutual interest,” which obligates one party to the farmout to offer the other party a certain percentage of the interest the first party acquires in oil and gas rights within the defined geographic boundary of the AMI. Additionally, a farmout may contain a call on production clause, under which the farmor has a continuing preferential right to purchase all oil and gas production from the farmout acreage.

Farmouts are negotiated agreements taking many different forms that often include complex provisions. The parties would be wise to carefully review the terms and conditions of the farmout to ensure their rights and obligations. In addition, the parties should protect their rights under the farmout by recording a memorandum of the farmout, the interest earned by the farmee, and the elections of the farmor.

If It’s Wrong, You Got Nothin’ – Execution of Instruments

Title Issues/Curative, , ,

To state the obvious, one of the most important aspects of any lease, deed, assignment or any other contract is making sure the appropriate party executes it. If the wrong person signs it, it will be either invalid or voidable at best. This is exactly what happened when only one manager of a limited liability company signed a 99 year lease. Unfortunately, the articles of organization on file with the secretary of state required both of the managers identified therein to sign such a lease. The lessee did not know there were two managers or that the articles of incorporation contained such requirement. The court found that the manager who signed the lease lacked actual and apparent authority to execute the lease and the lease was declared invalid.1 To assist in determining the appropriate party to execute a lease, deed, assignment or other contract, set forth below is a list of the common entities and scenarios that may be encountered in any title examination or transaction. 2

Attorneys-in-Fact. An attorney-in-fact is one who is authorized by a power of attorney to act on behalf of the actual owner of the property. Such authority will be defined in the power of attorney and will be strictly construed. Several states require recordation of the power of attorney in the county where the property is located.3

Associations: Religious, Cooperatives, Lodges, Educational, Non-Profits. These associations may encumber or convey real property held in the association’s name through its officers as authorized by its bylaws and resolutions. Such association’s governing documents and the laws of the state in which it is organized must be reviewed to determine authority.

Contracts for Deed. Generally, the holder of a contract may convey or encumber the applicable interest, unless the contract specifically provides otherwise. The holder of a contract for deed should join in the execution of the instrument in the same way as a life tenant joins (see below).

Corporations. The laws of the state of incorporation4 and the corporation’s governing documents (articles of incorporation, bylaws or resolutions) define the appropriate officer(s) or agent to execute a contract on behalf of a corporation. Typically, the president or vice president are authorized to execute a contract. If required, the officer’s signature should be attested and a corporate seal affixed.

Estates (Personal Representatives, Executors, Administrators). Generally, the authority of the personal representative, executor, or administrator to execute a contract is granted by a court having jurisdiction over the real property. Accordingly, applicable probate proceedings must be initiated in the state in which the property is located, not the resident state of the deceased. The resulting letters testamentary evidencing the party’s authority to act must be reviewed to confirm any limitations that may be imposed on the party’s authority, including the time period for which the party’s was granted authority to represent the estate of the decedent.

General Partnerships. Typically, an instrument can be executed by any partner, if acting within the scope of his or her authority, unless otherwise restricted in the partnership agreement or the laws of the state in which the partnership is organized.

Individuals. Any competent person may execute a contract. However, a contract executed by a minor is voidable at the minor’s election either before the age of majority or within either a statutorily defined time or a reasonable time thereafter. The typical age of majority is 18 years unless otherwise emancipated. If an interest is owned by a minor or incompetent, a guardian or conservator should be appointed by a court, who then may execute on behalf of the minor or incompetent. If a person cannot sign his or her own name, he or she may execute a contract by a mark. The signature of one or more credible witnesses or the acknowledgment by a notary public is typically required. As to competency, absence actual or constructive knowledge, a person of the age of majority is presumed to be competent. A person is not considered mentally incompetent until declared as such by a court. However, there appears to be a general standard that if the person is entirely without understanding, generally such person has no power to execute a contract. Any contract executed by a mentally incompetent person is voidable at the person’s election for a reasonable time after the person is judicially declared competent and most likely void if the person is under a guardianship.

If an individual is married, a variety of laws and circumstances exist which must be considered before it can be determined if a married person can legally convey such property without a joinder by his or her spouse. Under certain circumstances, the contract may be void even as to the party who signed.5 Therefore, it is generally recommended that a contract be signed by both spouses. However, in order to prevent any unintended consequences or benefits to the non-record title owner spouse, the proposed contract should be carefully drafted to avoid any unintended consequences. The types of ownership by married individuals are as follows:

Community Property. In a community property state, the property is owned by the community or, in other words, each spouse may claim an undivided one-half interest. This type of ownership applies to most property acquired during marriage by the husband or the wife. It generally does not apply to property acquired prior to the marriage or by gift or inheritance during the marriage. After a divorce, community property is either divided equally or according to the discretion of the court. Some of the applicable community property states include Alaska6, California, Louisiana, Nevada, New Mexico, and Texas7. Unless it can be determined that the property is owned separately, both spouses must execute or be a joining party to the instrument. Generally, upon the death of one spouse, the spouse’s interest passes to his or her devisees if the decedent spouse died testate or to his or her surviving spouse if the decedent spouse died intestate. Therefore, it is recommended to have the contract executed by the heirs or devisees of the deceased spouse and by the surviving spouse until the estate of the decedent spouse has been formally probated. Most importantly, even if the real property is not located in a community property state, if the husband and wife are domiciled in a community property state, the community property laws will apply.

Tenancy by the Entirety. Tenancy by the entirety is recognized in Alaska, Michigan, Ohio, Oklahoma, and Wyoming. This type of ownership is similar to joint tenancy, except that the parties must be husband and wife and the property cannot be conveyed by only one spouse. In the event the parties divorce, the property will transform into a tenancy in common.

Joint Tenants. For a joint tenancy to be created, it must be expressly declared in the contract conveying the real property by use of such language as “joint tenants” or “with rights of survivorship.”8 In the event of the death of one of the joint tenants, the surviving joint tenants continue to own the property (as joint tenants), regardless of the will of the deceased or any intestate laws. All joint tenants will need to execute the instrument (preferably the same one) in order to convey the full interest. Execution of an instrument by less than all joint tenants will validly convey the interests of the individual interests who sign and likely sever his or her joint tenancy.

Tenants in Common. An interest in real property created in two or more owners is presumed to be a tenancy in common unless specific language or circumstances indicate otherwise. Although listed under the header “Individuals,” a business entity can also be a tenant in common. Each cotenant is generally free to convey and encumber his or her own interest without the consent of the other cotenants. Upon the death of a cotenant, title passes to the cotenant’s heirs or devisees as previously designated by will or through intestacy.

Life Tenant and Remainderman. A life estate is an estate in which the duration of interest is measured by the life of one or more persons. The measuring life is usually that of the life tenant, but can also be the life of another (pur autre vie). Although the life tenant has the right of possession, he or she cannot execute a lease or otherwise dispose of the property without being liable to the remainderman for waste. Therefore, unless otherwise provided in the instrument creating the life estate, both the life tenant and the remainderman must execute any instrument affecting the real property .

Limited Liability Companies. Typically, a manager(s) or, if there is not a manager, then any member, is the appropriate party to execute a contract.9 The state of organization’s laws may also determine who has the authority to execute a contract on behalf of the company.

Limited Partnerships. The general partner of the limited partnership is the appropriate party to execute a contract unless the authority is otherwise provided in the partnership agreement or state laws in which the partnership is organized.10

Mortgages and Deeds of Trust. Generally, a mortgagee is not required to join in the execution of a lease. However, it is recommended that the mortgage subordinate its interest to an oil and gas lease in order to protect the rights of the lessee in the event the mortgagor defaults on the mortgage. In the unusual case a mortgage or deed of trust specifically prohibits the mortgagor from performing certain acts (e.g., leasing for oil and gas), the mortgagee should remove the prohibition contemporaneously with the execution of the lease.

Perpetual or Term Royalty Interest. A royalty interest may be reserved or conveyed out of the mineral interest for a fixed or perpetual term. Typically, the mineral interest owner retains the executive rights, subject to the right of the royalty owner to participate in production. Generally, a royalty interest is owned separately from the mineral interest and the royalty owner signs only instruments relating to his or her royalty. However, the instrument creating the royalty interest should be carefully reviewed.

Proprietorships or DBA’s. A person may adopt a name in which the person acquires property and transacts business in his or her individual capacity. The sole proprietor has the sole authority to execute in behalf of such an entity. Any contract executed by a sole proprietor should recite the person’s name and also that the person is doing business as the adopted name.

Term Mineral Interest. A mineral interest may be reserved or conveyed for either a fixed term only or a fixed term and so long thereafter as minerals are produced in paying quantities. Similar to a life estate interest, a conveyance should be obtained from both the term interest owner and the reversionary interest owner. If a lease is granted by only the term interest owner, a ratification of the lease should also be obtained from the reversionary interest owner.

Trusts. An individual or entity (the trustee) may own legal title to a property for the benefit of another. Each state’s laws and the terms of the trust agreement will govern the trustee’s authority to execute any contract and any limitations on the trustee’s powers. At a minimum, the contract should describe the grantor or grantee trust by including the name of the trust, the date of the trust, and the name(s) of the trustee(s).

As stressed above, the governing state laws and the governing entity documents are critical in determining whether the appropriate party is executing the contract. Many unintended consequences may exist by failing to consult such laws and documents.

1Zions Gate R.V. Resort, LLC v. Oliphant, 362 P.3d 118 (Utah Ct. App. 2014).
2See also Landman’s Legal Handbook , Rocky Mt. Min. L. Found., 5th ed. 2013; Oil & Gas Law: Nationwide Comparison of Laws on Leasing, Exploration and Production, Am. Ass’n Prof. Landmen, 2011.
3See, e.g., Colo. Rev. Stat. § 38-30-123; Nev. Rev. Stat. § 111.450; N.D. Title Standard 2-11; N.M. Stat. Ann. § 47-1-7.
4See, e.g., Colo. Rev. Stat. § 38-30-144 (allowing the president, vice-president, or other head office of the corporation); Mont. Code Ann. § 70-21-203(1)(b) (allowing president, vice-president, secretary or assistant secretary or by any other person duly authorized by resolution).
5If the property is qualified as a homestead, both husband’s and wife’s signature is required. See N.D. Cent. Code § 47-18-05; Mont. Code Ann. § 70-32-301; Wyo. Stat. § 34-2-121. In New Mexico, if a spouse fails to join in the instrument, it is void and of no effect, unless ratified by the spouse in writing. Marquez v. Marquez, 513 P.2d 713 (N.M. 1973); Hannah v. Tennant, 589 P.2d 1035 (N.M. 1979).
6Alaska is an opt-in community property state; therefore, property is separate property unless both parties agree to make it community property through a community property agreement or a community property trust.
7Colorado, Montana, North Dakota, Oklahoma, South Dakota, Utah, and Wyoming are not community property states.
8See Cal. Civ. Code § 683; Utah Code Ann. § 57-1-5(3). Additionally, Utah statutes create a presumption in favor of a joint tenancy being created when the granting clause refers to a husband’s and wife’s marital status without further joint tenancy language. Utah Code Ann. § 57-1-5(1).
9See, e.g., Mont. Code Ann. § 35-8-301; N.M. Stat. Ann. § 53-19-30; Wyo. Stat. Ann § 17-29-407 (consent of all members required).
10See Mont. Code Ann. § 35-12-803, 806; N.M. Stat. Ann. § 54-2A-110; Nev. Rev. Stat. § 88.445; Wyo. Stat. Ann. § 17-14-503.