July 30, 2018
The oil and gas lease (“OGL” or “lease”) is the foundation of the relationship between the mineral owner “lessor” and the working interest owner “lessee”, defining the various rights and obligations between the two. The OGL permits the lessee to explore, drill, develop and produce oil and gas (and usually other minerals), and it sets forth the compensation that the lessee will receive on “production”. Generally the lessor’s compensation is a fraction or percentage (e.g. 1/8, 3/16, 1/4) of the production, normally free of the costs of “production”.
It is generally understood that the lessee takes the risks of development and incurs the costs of production, and the lessor receives royalties on the production free of such costs. Normally this means that the lessee will be solely responsible for the costs of drilling, completing, equipping and getting the production out of the ground and to the surface or mouth of the well where it can be sold. But what if the lessee incurs costs after it has produced the oil or gas, i.e. gotten the production out of the ground and to the mouth of the well - can such “postproduction” costs be charged proportionately to the lessor in calculating royalties? A related question is where does production end and post-production begin.
These questions have been the source of a considerable amount of royalty litigation in Oklahoma over the last fifteen to twenty years. Many of such lawsuits have been class actions involving wells on a statewide or fieldwide basis. This paper will explore the issues involved in these lawsuits and the legal principles which govern same.
The OGL Royalty Provision
Where costs are deducted by the lessee in calculating royalty, to determine the appropriateness of same, the starting point is always the OGL. Some OGLs expressly permit cost deductions.1 Other OGLs expressly prohibit certain cost deductions.2 Other OGLs neither expressly permit nor prohibit deductions3, but their provisions must be carefully examined to attempt to determine, if possible, the parties’ intent with regard to deductions. Some leases state the location at which the production will be valued for purposes of calculating royalty. For example, some leases expressly provide that the valuation point is “at the well” or “at the mouth of the well”.4 Others provide that the valuation point is at the place where the gas is sold or at the outlet of a processing plant. Courts have held that language such as “at the prevailing rate” means that the production must be valued at the well. Johnson v. Jernigan, 475 P.2d 396 (Okla. 1970).
Some leases expressly provide that the production is to be valued in its raw state as it comes out of the well, not in its improved condition downstream of the wellhead or after processing, e.g., “raw gas at the mouth of the well”.5 Some leases value royalty at the “market price” or at its “market value”.6 Others provide that royalty is to be based upon the “proceeds” received, and there are many variations of “proceeds” language. Examples include, “gross proceeds”, “gross proceeds but in no event more than the actual amount received by the lessee”, “net proceeds”, “proceeds from the sale”, “proceeds at the average wholesale price”, and “proceeds from any sale between lessee and any non-affiliated company negotiated in good faith and at arms-length shall be deemed to be market value”.7
The applicable royalty provision in the OGL often depends upon the type of production, i.e., whether the gas is from an oil well (casinghead gas) or a gas well. In other instances the applicable provision depends upon whether the gas is used or processed off the lease. All of these OGL provisions must be carefully examined in attempting to ascertain the parties’ intent with regard to the deduction of costs in calculating royalties and whether the royalties paid complied with the lessee’s obligations.
New Developments: Chieftain Royalty Company v. XTO Energy, Inc., 528 Fed. Appx. 938 (10th Cir. 2013); Wallace B. Roderick Revocable Living Trust v. XTO Energy, Inc., 725 F.3d 1213 (10th Cir. 2013); Fitzgerald v. Chesapeake Operating, Inc., Case No. 111,566, Opinion Issued by the Oklahoma Court of Civil Appeals on February 14, 2014.
These cases reaffirm the importance of examining the OGL royalty provisions in the context of class certification. Chieftain arose out of the Eastern District of Oklahoma and Roderick arose out of the District of Kansas. In Fitzgerald the Oklahoma Court of Civil Appeals (“COCA”) cited Chieftain and Roderick with approval. In both Chieftain and Roderick the district courts had certified royalty underpayment classes in spite of widespread differences in the OGL royalty provisions. The district courts accepted the Plaintiffs’ argument that, because the Defendant had treated all of the royalty owners the same in calculating royalties, this uniform payment methodology satisfied the class certification requirements of commonality, typicality, adequacy and predominance, and rendered immaterial the differences in the lease royalty provisions for class certification purposes.
The Tenth Circuit held that the district courts abused their discretion in certifying the royalty claims as class actions because they failed to adequately examine the variations in the lease royalty provisions and how such variations might impact the ability to resolve the case on a classwide basis. The Tenth Circuit observed that, while the Defendant’s uniform payment methodology might raise a common question as to all of the royalty owners, this did not necessarily mean that all of the claims had to be resolved the same. Stated differently, just because the Defendant treated all of the royalty owners the same doesn’t answer the question whether such treatment was improper as to any particular royalty owner. Ultimately the question that must be answered is whether the royalty owner was underpaid. To answer that question, the Tenth Circuit recognized that the OGL royalty provisions must be examined, i.e., did the amount paid satisfy the OGL royalty provision. The Tenth Circuit recognized that the answer might vary as between royalty owners depending upon the applicable OGL royalty provision. The Tenth Circuit reversed both class certification rulings, and remanded with instructions for the district courts to carefully consider the differences in the lease royalty provisions in ruling upon class certification.
In Fitzgerald the district court certified a statewide class involving up to 10,000 wells. The COCA reversed the class certification in part because of the differences in lease royalty provisions, which included “raw gas”, “at the mouth of the well”, “market value at the well” and “gross proceeds” provisions. Fitzgerald at ¶9. Quoting from Panola Independent School Dist. No. 4 v. Unit Petroleum Co., 2012 OK CIV APP 94, 287 P.3d 1033, at ¶20 (cert. denied), the COCA held that these differences precluded certification:
[e]ach of these types requires a different inquiry in determining the royalty owner’s claim for underpayment of royalties based on deduction of postproduction costs. Therefore, each lease type would require the definition of a separate sub-class. We are unable to find a class action combining claimants from all lease types is a superior method to adjudicate these claims. Fitzgerald at ¶9.
The COCA rejected the contention that class treatment was proper because the defendant allegedly treated all of the royalty owners the same under a uniform payment methodology, citing with approval Roderick and Chieftain and their reliance upon Wal-Mart Stores, Inc. v. Dukes, __ U.S. __, 131 S. Ct. 2541, 180 L.Ed.2d 374 (2011). As explained in Dukes, again, the critical inquiry is not whether a common question is raised, but whether a common answer exists. Fitzgerald also cited Chieftain for the proposition that it is improper to shift the burden to the defendant to prove that differences in lease language do not preclude class certification, since the plaintiff has the burden of proving all of the prerequisites for class certification. Given the statewide scope of the proposed class and the fact that the proposed class wells were in different oil and gas fields and on different gathering systems, Fitzgerald also held that class certification was improper because it would be necessary to review wells on an individual basis to determine when the gas first became marketable in order to apply Mittelstaedt (see Mittelstaedt discussion below). This ruling echoed similar concerns raised in Chieftain and Roderick.
The Implied Covenant to Market
Unless the OGL specifically addresses the lessee’s duty to market or otherwise negates an implied duty, OGLs in Oklahoma are subject to the implied covenant to market. McVicker v. Horn, Robinson & Nathan, 1958 OK 49, 322 P.2d 410; Gazin v. Pan-American Petroleum Corporation, 1961 OK 300, 367 P.2d 1010; Wood v. TXO Production Corp., 1992 OK 100, 854 P.2d 880. Thus, if the express terms of the OGL do not resolve the question as to whether costs can be deducted against royalties, the implied covenant to market should be considered next. In Mittelstaedt v. Santa Fe Minerals, Inc., 1998 OK 7, 954 P.2d 1203, 1208, the Oklahoma Supreme Court amplified upon the implied covenant to market, stating: The lessee has a duty to provide a marketable product available to market at the wellhead or leased premises.
When the production is not sold at the well or on the lease premises, but rather is sold off-lease at a downstream location or market, the Mittelstaedt court explained that the costs incurred downstream can be charged against royalties if certain criteria are met: We conclude that the lessor must bear a proportionate share of such costs (transportation, compression, dehydration, blending) if the lessee can show (1) that the costs enhanced the value of an already marketable product (2) that such costs are reasonable, and (3) the actual royalty revenues increased in proportion with the costs assessed against the non-working interest. Thus, in some cases a royalty interest may be burdened with post-production costs, and in other cases it may not.
Mittelstaedt emphasized that, “post-production costs must be examined on an individual basis to determine if they are within the class of costs shared by a royalty interest”. 954 P.2d at 1208. Prior to Mittelstaedt, the Oklahoma Supreme Court had already held that, if a market for production does not exist at the well or lease, the lessee can charge against royalties the cost of transporting the gas to a downstream market. Johnson v. Jernigan, 1970 OK 80, 475 P.2d 396. The Mittelstaedt court affirmed that this is still good law: In Johnson v. Jernigan, 475 P.2d 396 (Okla. 1970) we explained that gross proceeds ‘has reference to the value of the gas on the lease property without deducting any of the expense involved in developing and marketing the dry gas to this point of delivery.’ Id., 475 P.2d at 399. Thus, ‘gross proceeds’ does indicate an amount without deduction from, or charge against, the royalty, but only when the sale occurs at the leased premises…We explained in CLO (TXO ProductionCorp. v. Commissioners of the Land Office, 1994 OK 131, 903 P.2d 259) that our ruling in Johnson v. Jernigan, 475 P.2d 396 (Okla. 1970) was still good, and that a lessor may be required to pay its proportionate share of transportation costs when the sale occurs off the leased premises. 954 P.2d at 1206-1207. In New Dominion, L.L.C. v. Parks Family Co., L.L.C., 2008 OK CIV APP 112, 216 P.3d 292, the court held that the implied covenant to market did not apply to Oklahoma Corporation Commission (“OCC”) pooling orders issued pursuant to 52 O.S. § 87.1(e). In 2012 the Oklahoma Legislature amended 52 O.S. Supp. 2011 § 87.1(e) to provide that a force-pooled mineral owner “shall be considered a lessor, subject to the judicially recognized implied covenant to market.” 2012 Okla. Sess. Law Serv. Ch. 201 (H.B. 2654) (emerg. eff. May 8, 2012).
In Panola Independent School District No. 4 v. Unit Petroleum Company, 2012 OK CIV APP 94, 287 P.3d 1033, the court held that the 2012 law which extended the implied covenant to market to pooling orders had prospective application only because it changed “existing law by imposing on the operator a duty to market product for the benefit of the non-participating owners on unleased mineral interests in a force-pooled tract”. Id. at 1036. Based upon this ruling, because the proposed class of royalty owners in Panola included some whose rights were governed by pooling orders, both before and after the law change, and some whose rights were governed by OGL’s with differing royalty provisions, the Panola court held that class certification was not proper (reversing the district court’s ruling on class certification). The court held that the Plaintiffs failed to prove that a class action was a superior method for adjudicating the claims. The Oklahoma Supreme Court denied certiorari on October 8, 2012.
Panola also held that, where an implied duty to market does exist under a pooling order (under the 2012 law), disputes regarding such duty must be resolved by the OCC - not by the district courts. 287 P.3d at 1036, “[w]hile the district court has jurisdiction to enforce the Commission’s orders and to resolve the private rights of the parties, the Commission has exclusive jurisdiction to interpret, clarify, amend and supplement its own orders. This includes the power to define and describe the rights of a force-pooled owner. The class definition as proposed by Class Representatives and certified by the trial court includes force-pooled royalty owners. Not only do the claims of these owners relating to post-production costs differ markedly from the rest of the class, they must be resolved by a different tribunal”, (citations omitted). This jurisdictional issue further precludes class certification where the proposed class includes royalty owners under both OGL’s and pooling orders. Id.
Most OGL’s allow the lessee to establish units that are larger than the size of the leased premises. Often they allow for 640 acre gas units and 40 acre oil units. Primary production drilling and spacing units can be established through spacing orders issued pursuant to 52 O.S. § 87.1(a). Secondary (enhanced) production units are created through unitization orders issue pursuant to 52 O.S. § 287.1. What is the effect, if any, of unitization orders upon the relationship of the lessor and lessee and the lessee’s obligation to pay royalty?
In 1954, the Oklahoma Supreme Court held that a secondary production unit created under the predecessor statute to §287.1 (52 O.S. 1949, § 286.1) has a fiduciary or quasi-fiduciary duty to the unit royalty owners, at least with respect to properly valuing and paying royalty. Young v. West Edmond Hunton Lime Unit (Young I), 1954 OK 195, 275 P.2d 304; see also, West Edmond Hunton Lime Unit v. Young (Young II), 1958 OK 19, 325 P.2d 1047, in which the court stated that Young I held that the “unit operator” also breached the fiduciary duty even though the unit operator was not a party to the lawsuit; see also, Leck v. Continental Oil Co., 1989 OK 173, 800 P.2d 224, 229, in which the court stated that the unit and the unit operator have a relationship with the royalty owners which is fiduciary in nature.
The context of the Young decision is important. In Young, the unit operator sold unit production to itself and others at $2.65/barrel, whereas the evidence showed that a purchaser in the field was offering $3/barrel and actually purchased a portion of the unit production at such price. The Plan of Unitization specifically required the unit operator to sell at the “market prevailing price”. The royalty owners claimed that, by selling production at $2.65 instead of $3.00, the unit operator violated its duty to sell at the prevailing market price and that the unit was liable for the resulting underpayment.
In ruling in favor of the royalty owners, the Young court stated: The unit organization with its operator stands in a position similar to that of a trustee for all who are interested in the oil production either as lessees or royalty owners. The law applicable to this unitization (52 O.S. § 287.1, et seq.) required no notice to royalty owners, and afforded them no voice in the organization or management of the unit or in the selection of unit operator. Id. at 309.
It is well-settled rule that a trustee can make no profit out of his trust. The rule in such cases springs from his duty to protect the interests of the estate, and not to permit his personal interest to in any way conflict with his duty in that respect. The intention is to provide against any possible selfish interest exercising an influence which can interfere with the faithful discharge of the duty which is owing in a fiduciary capacity. It therefore prohibits a party from purchasing on his own account that which his duty and trust require him to sell on account of another and from purchasing on account of another that which he sells on his own account. In effect, his is not allowed to unite the two opposite characters of buyer and seller, because his interests, when he is the seller or buyer on his own account, are directly conflicting with those of the person on whose account he buys or sells. Id., quoting from Magruder v. Drury, 235 U.S. 106, 120, 35 S.Ct. 77, 82, 59 L.Ed. 151, 156 (1914).
One of the commonest illustrations where a conflict of interest appears is a sale of trust property to the trustee individually. In such situations, the trustee should be attempting to sell the property for as much as possible to benefit the trust estate, while at the same time, as an individual, he probably would be attempting to buy the property for as little as possible. Id. at 309-310, quoting from Bruen v. Hanson, 103 F.2d 685, 698 (9th Cir. 1939).
The Young court made much of the fact that the unit operator was selling unit production to itself at a price lower than what was otherwise readily available. It was in this context of selfdealing that Young analogized the trustee-like duties. Today these concerns are also addressed through the affiliate sales rule announced in Howell v. Texaco, 2004 OK 92, 112 P.3d 1154 (see Affiliate Sales section below).
The Young court also made much of the fact that, under the secondary unitization statutes, 52 O.S. § 287.1, “the owners of the mineral rights and interests in a particular tract of land are compelled to surrender all right to produce and take oil from a particular tract, and in lieu thereof they become entitled to share in the total production by the unit organization from the common source of supply of which the particular tract is part.” The court held that, because the secondary unit statutes deprived the royalty owners of their right to separately dispose of their own share of oil, a heightened duty was imposed upon the unit and unit operator. This ruling appears erroneous in part because secondary plans of unitization typically allow the royalty owners to separately take in-kind and market their own share of oil. Moreover, because the court had already held that the duty to sell at the prevailing market price had been breached, it was unnecessary to impose a fiduciary duty simply because the police powers were implicated. In Hebble v. Shell Western E&P, Inc., 2010 OK CIV APP 61, 238 P.3d 939, the court was asked to determine whether the fiduciary duty applicable to secondary units also applies to primary production drilling and spacing units created by spacing orders under 52 O.S. § 87.1. The Hebble court held that it does:
The fiduciary duty of the unit operator arises not only from the creation of fieldwide units for secondary recovery under 52 O.S. 2001 §§ 287.1 - 287.15, but also from the creation of drilling and spacing units under 5 O.S. Supp. 2007 § 87.1…The critical factor is the resort to the police powers of the state on the part of the lessee in unitization proceedings which modify and amend existing legal rights. Id. at 943.
Shell’s (i.e. the unit operator’s) duty to Owners arose from the Commission’s exercise of its police power on the lessee’s behalf. Owners’ right to payment from the oil proceeds in the unit was communitized as royalty within the meaning of the term as used in § 87.1 and the Commission’s order. Accordingly, Shell as the unit operator owed a fiduciary duty to Owners. Id. The Oklahoma Supreme Court denied certiorari.
The significance of whether a fiduciary duty exists or not is often related to the statute of limitations. The statute of limitations applicable to written OGL’s and claims for underpayment of royalties is five years. 12 O.S. § 95; 52 O.S. § 570.14(D). The statute of limitations applicable to a breach of fiduciary duty claim is two years, however, Hebble held that the two years does not begin to run until the royalty owner is aware that the unit operator has repudiated its fiduciary duty or otherwise discovers that the operator owes the royalty owner money. Id. At 943-944. New Development: Krug v. Helmerich & Payne, Inc., 2013 OK 104, --- P.3d ---, 2013 WL 6452587.
On December 10, 2013, The Oklahoma Supreme Court held in Krug that, where the royalty owner’s relationship with the unit operator arises under an OGL, communitization agreement and/or spacing order, the unit operator does not have a fiduciary duty to the royalty owner:
H&P (the unit operator) is entitled to separate its interest from that of the plaintiffs (royalty owners). H&P does not owe undivided loyalty; there is no special trust as a manager or agent. The duty required by the implied covenant to protect against drainage is that required of a reasonable and prudent operator, not that of an agent to a principal, nor of a partner to a partnership, nor of a trustee to a cestui que trust. Any former cases of this Court using terms suggesting a fiduciary duty of a lessee to its lessor should not be so construed. Id. at ¶ 19. It is not readily apparent from the face of the decision that Krug held that spacing orders do not give rise to a fiduciary duty. However, a §87.1(a) spacing order was involved in Krug, and the argument that a spacing order gives rise to a fiduciary duty was fully briefed in the appeal. By rejecting this argument, Krug held that a §87.1 spacing order does not give rise to a fiduciary duty, thus implicitly overruling Hebble. But see, Leck v. Continental Oil Co., 1989 OK 173, 800 P.2d 224, in which the court held, where both a §87.1(a) spacing order and a §87.1(e) pooling order were involved, that the unspecified “unitization order” gave rise to a fiduciary duty. In Howell v. Texaco, Inc., 2004 OK 92, 112 P.2d 1154, the Oklahoma Supreme held that voluntary communization agreements do not create a fiduciary duty.
Krug also addressed another issue which had frequently arisen in royalty underpayment lawsuits. Often the plaintiff argued that the defendant was unjustly enriched by the royalty underpayment, and that the profit the defendant allegedly received from the underpayment should take into account the defendant’s internal rate of return on investments. In some cases this amounted to applying a 40%, 50% or greater interest rate, far in excess of the 12% compound interest rate allowed under 52 O.S. § 570.10, sometimes resulting in staggering claim amounts. The plaintiffs contended that the defendant should be compelled to “disgorge” these alleged ill-gotten profits.
Krug rejected these types of claims, holding that claims for unjust enrichment seeking disgorgement of alleged profits and quasi-contract claims for constructive fraud are claims for equitable relief, and that equitable relief is not available where an adequate remedy at law exists. The court held that the plaintiff had an adequate remedy at law under its OGL contract claim and, therefore, these remedies were not available.
The Energy Litigation Reform Act
What remedies are available on a royalty underpayment claim? Krug addressed the fact that equitable remedies such as unjust enrichment and constructive fraud are not available on OGL breach of contract claims. Prior to Krug, effective May 8, 2012, the Oklahoma Legislature adopted the Energy Litigation Reform Act (“ELRA”) which addresses the remedies available on royalty underpayment claims. 52 O.S. §§ 901-903.
The ELRA provides that the “actual damages” on a royalty underpayment claim shall be the underpayment amount which is due plus interest as set forth in 52 O.S. § 570.10 (12% compound or 6% compound where marketable title problems exist) unless the parties have expressly agreed otherwise. 52 O.S. § 903. The ELRA states that this is the “exclusive remedy” and that punitive damages and disgorgement of profit remedies are not available. Id. The exception to this rule is where the finder of fact determines upon clear and convincing evidence that the defendant failed to pay with “actual, knowing and willful intent: (a) to deceive the person to whom the proceeds were due, or (b) to deprive proceeds from the person the holder knows, or is aware, is legally entitled thereto.” Id.
The purpose of the ELRA was to make clear that the remedies set forth in the PRSA, i.e. the underpayment amount, interest, attorney fees and allowable litigation expenses (52 O.S. § 570.14), and subject to the PRSA five year statute of limitations, are adequate and shall be the exclusive remedy in royalty underpayment lawsuits absent extraordinary circumstances. The ELRA also addressed another issue that frequently arises in royalty underpayment litigation, i.e., the nature of the relationship between the royalty owners and the well operator. The ELRA makes clear that, except in instances involving §287.1 secondary recovery units (i.e., as in Young, supra), the well operator’s duty to the royalty owners is governed solely by the “prudent operator rule” (i.e. to do what an operator acting reasonably would do under the same circumstances), and that the operator does not have a fiduciary or quasi-fiduciary duty under OGL’s or pooling orders (unless the parties have expressly agreed otherwise in writing). 52 O.S. § 902.
Some royalty underpayment lawsuits, like Young, supra, involve sales by the lessee to itself or to an affiliated entity. Where the sale is not an arms-length sale to an unaffiliated entity, what price should be used to value royalties?
The Oklahoma Supreme Court addressed this question in Howell v. Texaco, 2004 OK 92, 112 P.3d 1154. In Howell, Texaco’s production division sold the well production to Texaco’s plant division, which then processed the gas and sold the resulting natural gas liquids and residue gas to third parties, presumably at a price higher than what the processing division paid the production division.
Under these circumstances, the Howell court held that and “intra-company gas sale cannot be the basis for calculating royalty payments.” 112 P.3d at 1160. The court further held:
Wherever a producer is paying based on one price but is selling the gas for a higher price, the royalty owners are entitled to have their payments calculated based on the higher price (citing Tara Petroleum Corp. v. Hughey, 1981 OK 65, 630 P.2d 1269). The plaintiffs here are entitled to have their royalty payments based on the prevailing market price (at the well) or the work-back method (subtracting allowable costs and expenses from the first downstream, arms-length sale), whichever one results in the higher market value. Id. (emphasis added)
Every royalty claim involves a myriad of individual questions, particularly where allegations of improper cost deductions are made. These questions include:
• What does the OGL royalty clause provide with respect to how royalties are to be calculated?
• Does the OGL royalty clause expressly allow or disallow the deduction of costs?
• What does the OGL royalty clause provide in terms of where (e.g. “at the wellhead”) or in what condition (e.g. “raw gas”) the production is to be valued for purposes of calculating royalties?
• Does the implied covenant to market apply?
• If so, when did the gas first become marketable?
• As to costs incurred after the gas became marketable, what are the facts applicable to the Mittelstaedt factors?
• What type of unitization orders apply, if any, and how do such orders affect the duties and relationship between the lessor and the lessee (or unit operator), i.e. does a fiduciary duty exist?
1 See, e.g., Lease Royalty Provision Nos. 1 and 2 on Attachment 1 hereto; these lease royalty provision examples are found in the Memorandum Opinion and Order on Plaintiff’s Motion for Class Certification entered on May 14, 2012 by the Honorable Stephen P. Friot in Lois Foster v. Merit Energy Company, Case No. CIV-10-758-F, in the United States District Court for the
Western District of Oklahoma, at pp. 15-21.
2 See, e.g., Lease Royalty Provision No. 3 on Attachment 1 hereto.
3 See, e.g., Lease Royalty Provision Nos. 4 and 11 on Attachment 1 hereto.
4 See, e.g., Lease Royalty Provision Nos. 4 and 5 on Attachment 1 hereto.
5 See, e.g., Lease Royalty Provision No. 9 on Attachment 1 hereto.
6 See, e.g., Lease Royalty Provision Nos. 5 and 8 on Attachment 1 hereto.
7 See, e.g., Lease Royalty Provision Nos. 1, 3, 4 and 11 on Attachment 1 hereto.