PAUL M. WARNER, United States Magistrate Judge.
All parties in this case have consented to having United States Magistrate Judge Paul M. Warner conduct all proceedings in this matter, including entry of final judgment, with appeal to the United States Court of Appeals for the Tenth Circuit.
Coastal is a Texas corporation which holds various oil and gas leases and operates producing natural gas wells in Emery County, Utah, on property known as the Ferron Field. Emery is a limited liability company comprised of ten individuals ("Emery's Members") who hold royalty mineral interests in the Ferron Field that are leased to Coastal for oil and gas development. Coastal and Emery's Members are not the original parties to the leases; Coastal is the successor lessee and Emery's Members are the successor lessors.
Between approximately 1952 and 1982, the original individual lessors entered into the nine
In 2002, Coastal purchased the Ferron Field Wells and associated working interests in the Subject Leases from Questar Exploration and Production Company. In June of that year, Coastal assumed operation of the Ferron Field Wells. During
After the natural gas has been extracted from the well, it flows through a wellhead separator, which separates water from the gas stream. The gas gathering system includes the natural gas meters located near each well. The meters receive the gas downstream of Coastal's wellhead separators and connect to four-inch lateral pipelines that transport the gas from each well to a six-inch gathering trunk line. The trunk line runs about four miles to a building that contains gas-fired compressors. Compression of the gas is necessary for it to enter into and be transported on the interstate pipeline owned by Questar Pipeline Company ("Questar Pipeline") and regulated by the Federal Energy Regulatory Commission. After compression, the gas flows through a dehydrator to remove water vapor and then into a meter at an interconnection to the Questar Pipeline.
Once Coastal assumed operation of the Ferron Field Wells, it sold all of the gas it produced to Wasatch Energy, LLC ("Wasatch"). Coastal's contract with Wasatch specified that Coastal was to deliver the gas to Wasatch at the wellhead facilities for an agreed wellhead price. From June 2002 through May 2004, Wasatch arranged with Questar Gas Management Company to provide the gas gathering services to make the gas suitable for entry into the Questar Pipeline. The contract between Coastal and Wasatch also provided that all gas delivered by Coastal must meet the quality and pressure specifications of the receiving pipeline. Wasatch paid Coastal a wellhead price calculated as an agreed mainline price, less 100% of the gathering charges Wasatch would have to pay Questar Gas Management Company and less a service fee. During that same time frame, Coastal paid the royalty owners their respective decimal interest shares of the actual proceeds that Coastal received from Wasatch under this wellhead sales agreement.
Effective with June 2004 production, Coastal began operating the Ferron Field gas gathering system that it and other working interest owners purchased from Questar Gas Management Company. Upon purchase of the gas gathering system, the owners, including Coastal as operator, invested money to design and install a more efficient replacement gas-fired compressor. Then, in 2008, Coastal purchased a replacement electric natural gas compressor. These upgrades helped to increase revenue first by reducing gas fuel use and then by eliminating gas fuel use altogether. After Coastal purchased the gas gathering system, its sales of gas to Wasatch continued, but Wasatch no longer handled or paid for gathering and compression services. As such, Wasatch paid Coastal a negotiated mainline price for the gas (less production taxes and fees), rather than a wellhead price.
Since it purchased the Ferron Field Wells, Coastal has been calculating the royalty owed to Emery's Members based on the condition and value of the gas as it flowed from the wellhead separators. Coastal employed a "work back" method from the mainline value by deducting a gathering rate to arrive at a royalty value at the place of production. The amount of the gathering rate set by Coastal has varied over time with fluctuations in gas prices. The gathering rate as set by
The royalty provisions in the Subject Leases fall into three types, although two of them are notably similar. The various royalty clauses provide as follows:
Coastal and Emery filed cross-motions for partial summary judgment. Coastal seeks judgment as a matter of law on the following two issues: (1) the Subject Leases require gas royalty to be valued at the well or on the leased premises and not at a point downstream and (2) Coastal is entitled to deduct from the royalty value of gas produced from the Ferron Field Emery's Members' proportionate share of Utah ad valorem taxes, Utah conservation taxes, and Utah severance taxes. In its motion, Emery seeks judgment as a matter of law that the Subject Leases do not authorize Coastal to take deductions for Coastal's gathering and processing costs from production royalties owed to Emery's Members. Emery also moves this court for an order striking the affidavits and testimony of Coastal's experts, David E. Pierce and Jeff J. Fishman, and non-expert, Jay Neese. The court will now address the parties' respective motions.
Summary judgment is appropriate "if the movant shows that there is no genuine dispute as to any material fact and the movant is entitled to judgment as a matter of law." Fed.R.Civ.P. 56(a). "Judgment as a matter of law is appropriate when the nonmoving party has failed to make a sufficient showing on an essential element of his or her case with respect to which he or she has the burden of proof." Shero v. City of Grove, 510 F.3d 1196, 1200 (10th Cir.2007). In deciding a summary judgment motion, "`the inferences to be drawn from the underlying facts ... must be viewed in the light most favorable to the party opposing the motion.'" Id. (quoting Matsushita Elec. Indus. Co. v. Zenith Radio Corp., 475 U.S. 574, 587, 106 S.Ct. 1348, 89 L.Ed.2d 538 (1986)). But "[t]he nonmoving party `may not rest upon the mere allegations or denials of his pleadings' to avoid summary judgment." Baccus Indus., Inc. v. Arvin Indus., Inc., 939 F.2d 887, 891 (10th Cir.1991) (quoting Anderson v. Liberty Lobby, Inc., 477 U.S. 242, 249, 106 S.Ct. 2505, 91 L.Ed.2d 202 (1986)). Furthermore, the mere fact that the parties have filed cross-motions for partial summary judgment does not necessarily indicate that summary judgment is proper for either party. See Atlantic Richfield Co. v. Farm Credit Bank of
In addition, Emery's claim is premised on a novel theory of Utah oil and gas law on which the Utah Supreme Court has not previously ruled. "[W]hen presented with a novel issue of state law, a federal court must predict how the state's highest court would decide the issue.... In doing this, a federal court may examine all resources, including considered dicta, treatises, law reviews and well-reasoned authority from other jurisdictions." Schoepe v. Zions First Nat. Bank, 750 F.Supp. 1084, 1087-88 (D.Utah 1990), aff'd sub nom, Lion Hill Mines, through Schoepe v. Zions First Nat. Bank, 952 F.2d 1401 (10th Cir. 1992).
The parties agree that in this diversity case, the substantive law of Utah governs the Subject Leases. See Haberman v. Hartford Ins. Group, 443 F.3d 1257, 1264 (10th Cir.2006). Under Utah law, "[t]he general principles governing the interpretation of contracts apply to documents conveying mineral interests." Heiner v. S.J. Groves & Sons Co., 790 P.2d 107, 110 (Utah Ct.App.1990). To determine the meaning and original parties' intent under the Subject Leases, the court must first examine the language of the contracts. See Café Rio, Inc. v. Larkin-Gifford-Overton, LLC, 207 P.3d 1235, 1240 (Utah 2009). In contract interpretation, courts should "consider each contract provision... in relation to all of the others, with a view toward giving effect to all and ignoring none." Id. (quotations and citation omitted). "If the language within the four corners of the contract is unambiguous, the parties' intentions are determined from the plain meaning of the contractual language, and the contract may be interpreted as a matter of law." Green River Canal Co. v. Thayn, 84 P.3d 1134, 1141 (Utah 2003).
Extrinsic evidence of the parties' intent is considered in contract interpretation only when the language of the contract is ambiguous. See Café Rio, Inc., 207 P.3d at 1240. An ambiguous contract term or provision "is capable of more than one reasonable interpretation because of uncertain meanings of terms, missing terms, or other facial deficiencies." Id. (quotations and citation omitted). In addition, "[u]nder the well-established rule of construction ejusdem. generis, [courts shall] determine the meaning of a general contractual term based on the specific enumerations that surround that term." Id. (quotations and citation omitted).
The Utah Supreme Court has held that "contractual ambiguity can occur in two different contexts: (1) facial ambiguity with regard to the language of the contract and (2) ambiguity with regard to the intent of the contracting parties." Daines v. Vincent, 190 P.3d 1269, 1275-76 (Utah 2008). Facial ambiguity is a question of law to be determined by the court. See id. at 1276. If the court makes the initial determination that a contract is facially ambiguous, only then will parol evidence of the parties' intentions be admitted. See id. at 1276.
To determine whether a contract or provision is facially ambiguous, Utah courts employ a two part test. See id. First, "[w]hen determining whether a contract is ambiguous, any relevant evidence must be considered. Otherwise, the determination of ambiguity is inherently one-sided, namely, it is based solely on the extrinsic evidence of the judge's own linguistic education
In Ward, the Utah Supreme Court sought to establish a rational framework for determining whether a contract is facially ambiguous that would permit a court to "consider the writing in the light of the surrounding circumstances." Ward v. Intermountain Farmers Ass'n, 907 P.2d 264, 268 (1995). At the same time, a court may not "allow surrounding circumstances to create ambiguity where the language of a contract would not otherwise permit." Id. Therefore, "a finding of ambiguity after a review of relevant, extrinsic evidence is appropriate only when `reasonably supported by the language of the contract.'" Id. (quoting Ward, 907 P.2d at 268). With the foregoing in mind, the court now turns to the royalty provisions in the Subject Leases to determine whether they are ambiguous.
Four of the Subject Leases state that the lessee is
The court concludes that the "proceeds received by lessee at the well"
This sentence demonstrates that the intention of the original parties was for the lessors to be paid on the production value at the current market price of the gas at the well and not at a downstream location. The plain meaning of this language shows that the parties intended and bargained for a royalty value based on the lower wellhead value or proceeds to be obtained for gas as it was produced, and not a royalty to be based on a higher downstream value obtained by investments in transportation, compression, dehydration, or processing at the sole expense of the lessee.
Two of the Subject Leases also set forth unambiguous language regarding the royalty valuation:
The language of this provision again provides that the royalty to be paid is the "market value at the well" for "gas sold at the wells."
In three of the Subject Leases, the royalty provision provides:
While this lease language is not as clear as the royalty language contained in the first two leases, the qualifying phrase "as such, for gas from wells where gas only is found" can be reasonably and fairly construed to mean the sale of the gas "as such" or, in other words, in the condition in which the gas is found when produced "from" the wells.
The immediately preceding paragraph provides the lessee with two options for valuing oil production. Specifically,
In the first option, the parties agree that the lessee may deliver as royalty one-eighth of the oil produced in the pipeline free of cost, meaning that the lessor would be responsible for his or her share of any costs to transport, refine, or otherwise handle the one-eighth share of oil after extraction from well for entry into the pipeline. The lessor could, of course, sell the share for a lower wellhead price to a buyer willing to pay those post-production costs. The lessee's alternative option would allow a royalty payment to be made on one-eighth of "the market price for oil of like grade and gravity prevailing in the field where produced on the day such oil is run into the pipeline, or into storage tanks."
The sentence following the gas royalty provision provides that the lessee must "pay lessor for gas produced from any oil well and used off the premises or in the manufacturing of gasoline or any other product a royalty of one-eighth (1/8) of the market value, at the mouth of the well, payable monthly at the prevailing market price."
Reading the paragraphs together, the court concludes that the parties intended all products produced from the wells to be valued at the prevailing market rate at the wellhead. In light of the surrounding paragraphs, the court cannot conclude that the parties intended the royalty valuation point to be at some location downstream and away from the leased premises. The language of the Subject Leases, considered as a whole, does not support that interpretation.
Emery frames the issue in a different manner. Emery first notes that a royalty interest in an oil and gas lease is a "share of production free of the costs of production." Eugene O. Kuntz, A Treatise on the Law of Oil and Gas § 40.1 (1989); see also Flying Diamond Oil Corp. v. Newton Sheep Co., 776 P.2d 618, 629 (Utah 1989) (stating that "[a] royalty interest is a share of production, if, as and when there is production, free of the expenses of production." (quotations can citations omitted)). Emery contends that Coastal is improperly deducting from royalties amounts for gathering, dehydration, compression, and acquisition of the gathering system and that those activities are, in fact, production costs attributable solely to Coastal. To determine whether the Subject Leases allow for these deductions from royalties, Emery urges this court to examine to the language of the Subject Leases and decide whether they address the allocation of costs. Emery correctly states that the Subject Leases are silent with respect to cost allocation. Because the Subject Leases are silent with respect to deductions, Emery contends that the court must recognize the implied covenant to market that exists in oil and gas leases. The implied covenant to market provides the lessor assurance that the lessee will diligently market the gas for a reasonable price without sitting speculatively on the lease. See, e.g., Rogers v. Westerman Farm Co., 29 P.3d 887, 903 (Colo.2001).
Emery argues that this court should predict that the Utah Supreme Court would likely adopt the "first marketable product doctrine" as set forth by the Colorado Supreme Court and adopted by courts in Kansas, Oklahoma, and West Virginia. Id. at 904-06. This doctrine provides that lessees should calculate royalty payments on the basis of the value or price of the gas production at the location where the lessee first obtains a marketable product, which may be a location that is far downstream of the wellhead. See Brian C. Keeling & Karolyn King Gillespie, The First Marketable Product Doctrine: Just What is the "Product"?, 37 St. Mary's L.J. 1, 4 (2005). The doctrine "requires the lessee to pay any costs incurred in turning the unmarketable gas into a marketable product" and provides that "[o]nce the gas is marketable, additional costs incurred to enhance the products['] marketability are shared between the lessee and the lessor." Bice v. Petro-Hunt, L.L.C., 768 N.W.2d 496, 501 (N.D.2009). While a minority of states have adopted the first marketable product doctrine, those states adopting the doctrine have failed to articulate a clear standard for determining when a marketable
The majority of courts to consider the topic have found "at the well" royalty clauses to mean that natural gas is valued for royalty purposes at its wellhead location and condition. See Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 122 (Tex. 1996) ("Although it is not subject to the costs of production, royalty is usually subject to post-production costs, including taxes, treatment costs to render it marketable, and transportation costs." (quotations and citations omitted)); see also Elliott Indus. Ltd. P'ship v. BP America Prod. Co., 407 F.3d 1091, 1109-10 (10th Cir.2005) (noting that "`at the well' royalty obligations do require royalty payments based on the unprocessed gas as it emerges at the wellhead"); Piney Woods Country Life Sch. v. Shell Oil Co., 726 F.2d 225, 230-31 (5th Cir.1984) (interpreting Mississippi law and stating that "[t]he royalty compensates the lessor for the value of the gas at the well: that is, the value of the gas after the lessee fulfills its obligation under the lease to produce the gas at the surface, but before the lessee adds to the value of the gas by processing or transporting it"); Atlantic Richfield Co. v. State, 214 Cal.App.3d 533, 262 Cal.Rptr. 683, 688 (1989) ("When the term `at the well' is used in connection with `market price' ... the lessor, such as [the] State, bears its proportionate share of processing costs incurred downstream of the well."); Babin v. First Energy Corp., 693 So.2d 813, 815 (La.Ct.App.1997) (holding that the costs of severance taxes, transportation, processing, and treatment are considered to be post-production costs and are, therefore, borne proportionately by the lessee and the royalty owner); Schroeder v. Terra Energy, Ltd., 223 Mich.App. 176, 565 N.W.2d 887, 894 (1997) (adopting the "at the well" rule because it "better conforms with the parties' intent"); Montana Power Co. v. Kravik, 179 Mont. 87, 586 P.2d 298, 303 (1978) (holding that the market price is understood to mean the current market price being paid for gas at the well where it is produced). As noted by the North Dakota Supreme Court, the "at the well" rule provides that "any costs incurred by the lessee after the [gas] reaches the wellhead, whether to improve the quality of the [gas] or to transport it to a market where it may be sold may be deducted before the royalty is calculated." Bice, 768 N.W.2d at 501 (quotations and citation omitted).
States that follow the majority "at the well" rule allow a lessee to utilize one of the following two methods to calculate the market value at the wellhead: (1) the comparable sales method or (2) the work-back method. See id. In the comparable sales method, the lessee averages the comparable sales "at the same time and in the same field, for oil or gas of comparable quality, quantity, and availability." Id. (quotations and citation omitted). In the work-back method, the lessee calculates the market value at the well by deducting post-production costs that it incurred after the gas was extracted from the well. See id.
Id. at 22; see also Richardson v. Homestake Mining Co., 322 F.2d 329, 331-32 (10th Cir.1963) (applying Rimledge in a nearly identical case). Likewise, this court also concludes that the original parties to the Subject Leases intended to for the valuation point to be at the wellhead before the raw gas is gathered, dehydrated, and compressed.
The Rimledge court further noted that the plaintiffs' interpretation would entitle them "to the gross proceeds of the sale of ore, as long as it remained ore, no matter how much value had been added by the defendants, and the plaintiffs would reap the advantage of this added value created by the defendants at the latter's expense." Rimledge, 374 P.2d at 23. Similarly, if this court adopted Emery's proposed interpretation, Emery's Members would unjustly profit from the effort put forth by Coastal to get the gas to the Questar Pipeline. Like the court in Rimledge, this court concludes that it does not make sense to have a lessor and lessee agree that the royalty valuation point is at the mine or the wells (as the case may be) when sales actually occur there, only to have that point change to some other undefined downstream location if the market were to change. See id. at 22 ("To argue that the parties intended that `gross proceeds' implies a different basis at different times is quite unrealistic.").
Like the majority of states to adopt the "at the well" rule, this court concludes that if the royalty is not valued "at the wells" when gas is sold downstream, then the Subject Leases are left without a defined royalty valuation point or with a royalty
Coastal also requests a ruling that, as a matter of law, it is entitled to deduct the proportionate share of Utah taxes from the royalty value of gas produced from the Ferron Field. The Utah statutes that impose each of the three types of production tax specify: (1) the tax obligation or liability rests with the royalty interest owner as to his or her proportionate share of production; (2) the operator or producer must remit or pay the tax on behalf of the royalty interest owners; and (3) the operator or producer is to collect or deduct the amounts so paid from the royalty owners' payments. See Utah Code Ann. §§ 40-6-14, 59-5-102, and 59-2-210. Emery does not specifically address Coastal's argument regarding these deductions. Accordingly, and for good cause appearing, the court concludes that Coastal may deduct the proportionate share of the applicable Utah taxes from the royalty amount.
In summary, the court concludes that the royalty language of the Subject Leases is unambiguous and that the parties intended for the natural gas produced from the Ferron Field Wells to be valued at the prevailing market rate at the wellhead. Thus, Coastal may deduct the applicable taxes and post-production costs incurred from the wellhead separators to the Questar Pipeline to determine the market value at the well prior to calculating the royalty amount.
Emery seeks an order striking the affidavits and testimony of Coastal's experts, David E. Pierce and Jeff J. Fishman. Emery argues that the proffered testimony should be stricken because (a) it contains improper legal opinions invading the province of the court to instruct the jury, (b) it improperly attempts to testify as to industry custom, and (c) it includes irrelevant parol evidence concerning the natural gas regulatory environment for periods predating the conduct in question in this case. Emery also seeks to strike the affidavit of Coastal's non-expert, Jay Neese, on the grounds that it includes irrelevant parol evidence pertaining to the period before the deregulation of natural gas markets.
The court did not rely upon the testimony or affidavits provided by Coastal in ruling on the parties' cross-motions for summary judgment. Accordingly, the court concludes that Emery's motion to strike is moot.
Based on the foregoing, Coastal's motion for partial summary judgment
