kathryn-aylor-bowden-beulah-poorman-vick-omer-f-poorman-monte-cluck ( 2008 )

IN THE SUPREME COURT OF TEXAS

IN THE SUPREME COURT OF TEXAS

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No. 03-0824

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Kathryn Aylor Bowden, Beulah Poorman Vick, Omer F. Poorman, Monte Cluck, Royce Yarbrough, and Benny Ted Powell, Petitioners,

v.

Phillips Petroleum Company, GPM Gas Corporation, Phillips Gas Marketing Company, Phillips Gas Company, and GPM Gas Trading Company, Respondents

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On Petition for Review from the

Court of Appeals for the Fourteenth District of Texas

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Argued December 1, 2004

Justice Wainwright delivered the opinion of the Court.

Justice Brister did not participate in this decision.

This is an interlocutory appeal challenging the certification of a class of oil and gas royalty owners under former rule 42(b)(4) of the Texas Rules of Civil Procedure.[1]     The royalty owner class representatives—Kathryn Aylor Bowden, Beulah Poorman Vick, Omer F. Poorman, Royce Yarbrough, Benny Ted Powell, and Monte Cluck—allege that Phillips Petroleum Company underpaid royalties due under oil and gas production leases through its inter-affiliate transactions. The trial court certified three subclasses of royalty owners for breach of lease claims against Phillips and its subsidiaries and affiliates: GPM Gas Corporation, Phillips Gas Marketing Company, Phillips Gas Company, and GPM Gas Trading Company (collectively, Phillips). Phillips brought an interlocutory appeal challenging the class certification order. The court of appeals held that the trial court abused its discretion in certifying the three subclasses because each subclass failed to meet several requirements for certification under Rule 42. 108 S.W.3d 385. The court of appeals held the class representatives impermissibly failed to assert all claims for damages under the leases and the unasserted claims would be barred from subsequent litigation by res judicata. Id. at 402–04. The court of appeals also held that individual issues of liability would predominate over common issues for all three subclasses, and that the class representatives for Subclasses 2 and 3 were inadequate. Id. at 396–403. We affirm on different grounds the court of appeals’ judgment decertifying Subclasses 1 and 3, but reverse the judgment decertifying Subclass 2, and remand the case for further proceedings consistent with this opinion.

I. FACTUAL AND PROCEDURAL BACKGROUND

This is an appeal of the second attempt to certify the claims of three subclasses of royalty owners against Phillips. See Phillips Petroleum Co. v. Bowden, No. 14-00-01184-CV, 2001 Tex. App. LEXIS 7027 (Tex. App.—Houston [14th Dist.] Oct. 18, 2001, no pet.) (not designated for publication) (Bowden I). The class members are Texas royalty owners who leased their property to Phillips for oil and gas production. They allege Phillips underpaid royalties due under the leases through self-dealing transactions.

In September 2000, the trial court signed its first order certifying three subclasses and shortly thereafter signed a trial plan pursuant to our holding in Southwest Refining Co. v. Bernal, 22 S.W.3d 425 (Tex. 2000). Subclass 1 royalty owners alleged Phillips breached an implied covenant to market under the leases. Subclass 2 royalty owners alleged Phillips breached their Gas Royalty Agreements (GRAs) by paying royalties based on the dry residue gas component of natural gas petroleum but not on the liquid components of the gas produced, and by using a measurement system which failed to include the heat content of the gas. Subclass 3 royalty owners alleged Phillips breached the implied covenant to market by assessing an unreasonably high service fee to its marketing affiliate through percentage of the proceeds (POP) contracts, thereby reducing income to the royalty owners.

In Phillips’ first interlocutory appeal, the court of appeals reversed the certification order and remanded the case to the trial court to resolve deficiencies in the class action certification. Bowden I, 2001 Tex. App. LEXIS 7027, at *2–3. The deficiencies of Subclasses 1 and 3 related to changes in oil and gas law. While Bowden I was pending in the court of appeals, we held in Yzaguirre v. KCS Resources, Inc. that there is no implied covenant to market oil and gas for royalty owners paid under express market value royalty provisions. 53 S.W.3d 368, 373–74 (Tex. 2001). Thus, the court of appeals reasoned that only some royalty owners in Subclasses 1 and 3 were entitled to royalties under an amount-realized or proceeds basis with an implied covenant to market. Bowden I, 2001 Tex. App. LEXIS 7027, at *15–16. The court of appeals then held that this distinction among royalty owners undermined typicality for Subclasses 1 and 3. Id. at *16–17. For Subclass 2, the court of appeals held the trial court abused its discretion by finding that class representative Monte Cluck satisfied the typicality and adequacy of representation requirements because there was no evidence in the record that Cluck’s GRA was substantially similar to the GRAs of Subclass 2 members. Id. at *17–21.

On remand, the royalty owners filed an amended motion for class certification and attempted to address the court of appeals’ concerns. In June 2002, the trial court granted class certification after a second hearing, certifying the following three subclasses:

Subclass 1: Royalty owners who own or owned royalty interests under leases located in the state of Texas; where Phillips Petroleum Company is the lessee; under the terms of the lease, the payment of royalty of natural gas production is based on proceeds or amount realized; from which Phillips Petroleum produced natural gas (including natural gas liquids) that was directly sold or indirectly sold or transferred to Phillips Gas Marketing for marketing or resale; and during the period February 1995 through the present.

Subclass 2: Royalty owners who own or owned royalty interests under leases located in the state of Texas; where Phillips Petroleum Company is the lessee; the royalty is paid pursuant to a Gas Royalty Agreement containing language substantially identical to the language bracketed in the Gas Royalty Agreement attached as Exhibit 1 and incorporated herein by reference; the Gas Royalty Agreement has no additional language relating to processing gas or the payment of royalty on natural gas liquids; and during the period February 1995 through the present.

Subclass 3: Royalty owners who own or owned royalty interests under leases located in the Panhandle of the state of Texas; where Phillips Petroleum Company is the lessee; the leases provide for payment of royalties on natural gas production on an amount realized/proceeds basis or market value/market price basis; from which Phillips Petroleum produced natural gas (including natural gas liquids) that was directly or indirectly sold or transferred to GPM (or any successor entity) for marketing or resale; Phillips Petroleum Company was paid on the basis of a gas purchase contract between Phillips and GPM (or any successor entity); and during the period February 1995 through the present.

The revised Subclass 1 only includes claims from royalty owners paid on an amount-realized or proceeds basis and who assert claims for breach of an implied covenant or express covenant to market. In the revised Subclass 2, Royce Yarbrough and Ted Powell were substituted as representatives in lieu of Cluck. The revised Subclass 3 now includes a claim that Phillips breached the implied covenant to manage and administer the lease by entering into POP contracts with one of its marketing affiliates, paying it an unreasonably high fee to process the gas. Although all three subclasses involve lease agreements, the class representatives, on behalf of the royalty owners, did not assert all claims involving the lease agreements at issue, choosing to assert only those claims they believed likely to meet the predominance requirement of Rule 42(b)(3). The second certification order excluded the claims the class representatives decided not to pursue, stating “this class does not include claims by class members that are not based on the foregoing class claims.”

Phillips filed a second interlocutory appeal challenging the second class certification order. The court of appeals reversed and remanded the certification order. 108 S.W.3d at 404. We granted the royalty owners’ petition for review.

II. JURISDICTION AND STANDARD OF REVIEW

This Court has jurisdiction to review an interlocutory appeal of an order certifying or denying certification of a class action without regard to whether a conflict exists between courts of appeals. Tex. Civ. Prac. & Rem. Code § 51.014(a)(3); Tex. Gov’t Code § 22.225(d).

We review a class certification order for abuse of discretion. Compaq Computer Corp. v. Lapray, 135 S.W.3d 657, 671 (Tex. 2004). A trial court abuses its discretion if it acts arbitrarily, unreasonably, or without reference to any guiding principles. Walker v. Packer, 827 S.W.2d 833, 839 (Tex. 1992). We do not, however, indulge every presumption in the trial court’s favor, as compliance with class action requirements must be demonstrated rather than presumed. Henry Schein, Inc. v. Stromboe, 102 S.W.3d 675, 691 (Tex. 2002). Although a trial court generally has broad discretion to determine whether to certify a class action, it must apply a rigorous analysis to determine whether all certification requirements have been satisfied. Compaq, 135 S.W.3d at 663; Bernal, 22 S.W.3d at 435.

III. RES JUDICATA

The class representatives argue the court of appeals erred in concluding they “must bring all claims relating to the breach of the lease agreements in the same action or they will be subject to res judicata’s preclusive effect.” 108 S.W.3d at 403. In their motion to certify, the class representatives strategically chose not to assert all claims arising from the oil and gas leases and GRAs. The class representatives alleged a single breach of contract claim on behalf of each respective subclass rather than including the various implied or express obligations under the leases and agreements in the suit. The court of appeals, agreeing with Phillips, held the certification order impermissibly split the class members’ causes of action, suggesting such splitting of claims was inappropriate under Rule 42(d). Id. at 404. Rejecting other courts of appeals’ decisions, the court of appeals held the unasserted claims were subject to res judicata’s preclusive effect and that the class representatives’ willingness to abandon those claims rendered them inadequate representatives. Id.

The class representatives argue their abandoned claims may not be precluded in future litigation, even under the transactional approach to res judicata. They agree the transactional approach precludes the relitigation of those claims that could have or should have been asserted in prior litigation, but contend that res judicata should not preclude those claims which are not subject to classwide treatment. Citing our holding in Amstadt v. United States Brass Corp., the class representatives argue the unasserted claims do not meet the three prerequisites for barring claims by res judicata: “1) a prior final judgment on the merits by a court of competent jurisdiction; 2) identity of parties or those in privity with them; and 3) a second action based on the same claims as were raised or could have been raised in the first action.” 919 S.W.2d 644, 652 (Tex. 1996). Specifically the class representatives argue such claims cannot be certified in a class action and, therefore, are not subject to claim preclusion in future litigation.

As we held in Citizens Insurance Co. v. Daccach, to apply res judicata to class actions in this manner would produce inconsistent results between class actions and other forms of litigation. 217 S.W.3d 430, 451 (Tex. 2007). Class suits remain subject to the same claim preclusion rules as other procedural forms of litigation. Id.; see also Bernal, 22 S.W.3d at 432 (holding class actions are subject to the same punitive damages rules as other forms of litigation). Applying Texas’s transactional approach to res judicata, class members will be barred only from asserting claims in subsequent individual litigation which arose from the same transaction or subject matter and either could have been or were litigated in the prior suit. Daccach, 217 S.W.3d at 450, 455 (citing Barr v. Resolution Trust Corp., 837 S.W.2d 627, 631 (Tex. 1992)).

We disagree with the court of appeals’ holding that class representatives who split the claims of the class are per se inadequate. 108 S.W.3d at 404. As for the application of res judicata to class suits, we crossed this bridge in Daccach. 217 S.W.3d at 457. Courts do not dictate the strategies parties must follow in litigation nor do they instruct litigants which claims or defenses they should, or should not, bring. As in other legal actions, however, class litigants are subject to the consequences of their choices and the doctrine of claim preclusion may bar future litigation of claims that they decide not to pursue in the current suit. Daccach, 217 S.W.3d at 451. If the class representatives do not assert at the trial court all claims for damages arising from the leases which could have been litigated before the trial court, the unasserted claims may be precluded by res judicata in subsequent litigation. Id. The tactical and strategic decisions to structure the lawsuit are theirs; the implications of their actions are established by law.

The court of appeals summarily concluded the “willingness of the class representatives to abandon claims for the sake of achieving commonality” means the representatives cannot adequately represent the class, and thus the trial court abused its discretion in certifying the class. 108 S.W.3d at 404. Under that approach, class representatives would always risk being inadequate representatives if they did not assert all possible claims for each individual class member. At the same time, though, class representatives bringing excessive numbers of individual claims may burden their ability to satisfy the typicality and predominance requirements.

We previously explained that a class representative’s decision to assert certain claims and abandon others affects the certification determination. The choice of claims to pursue or abandon is one relevant factor in evaluating the requirements for class certification such as typicality, superiority, and adequacy of representation. Daccach, 217 S.W.3d at 448. A proper analysis requires the trial court to venture beyond the pleadings and to “‘understand the claims, defenses, relevant facts, and applicable substantive law in order to make a meaningful determination of the certification issues.’” Bernal, 22 S.W.3d at 435 (quoting Castano v. Am. Tobacco Co., 84 F.3d 734, 744 (5th Cir. 1996)). Trial courts should assess the Rule 42 requirements in light of res judicata’s preclusive effect on abandoned claims when considering whether to certify a class.

In the second certification order, the trial court acknowledged that the class limited its suit to a single claim for each subclass. On remand, it should consider the applicability of res judicata in future proceedings to abandoned claims in evaluating certifiability, as we explain in Daccach, as part of its determination of the prerequisites of commonality, typicality, superiority, adequacy of representation, and predominance. Tex. R. Civ. P. 42(a),(b).

IV. SUBCLASSES

The substance of the class claims, and in turn their certifiability, depends on the royalty agreements the class entered into with Phillips over sixty years ago. The 1940s was a different era in the oil and gas industry. It was not uncommon at the time for natural gas to be viewed as a potentially dangerous complication or bothersome waste product in the production of valuable oil. See Bruce M. Kramer, Interpreting the Royalty Obligation by Looking at the Express Language: What a Novel Idea?, 35 Tex. Tech L. Rev. 223, 231–32 (2004). Consequently, oil and gas leases traditionally have included little guidance on the methods for measuring gas production for royalty calculations. Id.

The federal government began to regulate natural gas prices in 1954 and later, in 1978, gas pricing was deregulated, as it is now. William F. Fox, Jr., Transforming an Industry by Agency Rulemaking: Regulation of Natural Gas by the Federal Energy Regulatory Commission, 23 Land & Water L. Rev. 113, 114 (1988). Adding to these regulatory changes, the revolution in technology that allows real-time trading of commodities, and with pipelines no longer purchasing gas but charging to transport it, gas is now being “marketed in ways never imagined when most leases and their [royalty] provisions” were drafted. Dick Watt et al., Royalty Litigation—Key Issues: Part I, 19-1 Texas Oil and Gas Law Journal 1, 4 (2005). Although the dispute in this lawsuit arose in modern times, we interpret the obligations and rights of the parties according to their expressed intent when they entered the agreement. Fortis Benefits v. Cantu, 234 S.W.3d 642, 647 (Tex. 2007); Lenape Res. Corp. v. Tenn. Gas Pipeline Co., 925 S.W.2d 565, 574 (Tex. 1996) (“In construing a written contract, our primary concern is to ascertain the true intentions of the parties expressed in the written instrument.”).

A. Subclass 1

Subclass 1 is comprised of royalty owners who have natural gas leases with Phillips, which in turn produces natural gas and sells it to its affiliate Phillips Gas Marketing Company (PGM). Specifically, this subclass only includes royalty owners with gas royalty clauses requiring Phillips to calculate the royalty as a percentage of the proceeds Phillips receives for selling the gas. “Proceeds” or “amount realized” clauses require measurement of the royalty based on the amount the lessee in fact receives under its sales contract for the gas. Union Pac. Res. Group v. Hankins, 111 S.W.3d 69, 72 (Tex. 2003) (citing Yzaguirre, 53 S.W.3d at 372). By contrast, a “market value” or “market price” clause requires payment of royalties based on the prevailing market price for gas in the vicinity at the time of sale, irrespective of the actual sale price. Yzaguirre, 53 S.W.3d at 372. The market price may or may not be reflective of the price the operator actually obtains for the gas. Id. at 372–73.

Subclass 1 consists primarily of royalty owners in Fort Bend and Brazoria counties where Phillips sells gas to PGM. According to the royalty owners, there are approximately 2,330 oil and gas leases in Fort Bend County and 538 leases in Brazoria County eligible for membership in Subclass 1. These leases are not all identical. Some of the leases, including leases for the named representatives, contain gas royalty clauses providing for an amount-realized basis if the gas is sold at the well by Phillips and a market-value basis if Phillips sells or consumes the gas off the premises or uses the gas to manufacture gasoline.[2]     This provision is called a “two-pronged” clause and provides different methods for calculating gas royalties for the same well depending on the circumstances of the sale. Additionally, many of the leases, including the named representatives’ leases for Subclass 1, have a separate express clause requiring Phillips to exercise reasonable diligence to market the gas it produces.[3]    

Although the leases contain different royalty clauses, including some express duty to market provisions, the royalty owners argue there is a common question for Subclass 1: whether Phillips failed to reasonably market the gas. Specifically, they argue Phillips failed to act as a reasonably prudent operator when it entered into a gas purchase agreement with its wholly-owned affiliate PGM.[4]     The royalty owners allege Phillips, by selling gas at a lower price to PGM, failed to diligently market and achieve the higher price it received or could receive for arms-length transactions to third parties. In other words, they claim Phillips paid the subclass royalties based on gas sales to its affiliate PGM rather than paying higher royalties based on higher sales prices for gas it could sell in an arms-length transaction with a non-affiliate. The royalty owners claim that PGM earned higher profits at its expense and Phillips paid lower royalties by bringing its affiliate into the transaction.

The court of appeals held that individual issues regarding duty and breach predominated over the common issues for Subclass 1. 108 S.W.3d at 396. The predominance requirement is intended to preclude class action litigation when the sheer complexity and diversity of the individual issues would overwhelm or confuse a jury. Schein, 102 S.W.3d at 690; Bernal, 22 S.W.3d at 434. First, the court of appeals reasoned that because only leases paying royalties on an amount-realized or proceeds basis, rather than a market-value basis, are included in Subclass 1, a jury would need to determine the point of sale for gas from each well in the subclass to ascertain which method of calculating royalties in the two-pronged clauses applied. 108 S.W.3d at 396. The court of appeals held these individual determinations for each well would prevent the class from satisfying the predominance requirement. Id. The royalty owners argue that because Phillips has computer records containing detailed information on each lease agreement and the point of sale for each well, a jury will not need to determine class membership based on the variety of sales factors. Phillips’ database, they assert, could identify the points of sale for each well and calculate the sale price and royalty for each royalty owner’s well.

Phillips produces natural gas from the wells and sells that gas at or near the wells to PGM. PGM then gathers the gas from the points of sale, processes the gas, and sells it under contract to the City of Garland, Texas, and to Phillips’ refinery near Sweeney, Texas. Some of the gas is sold after processing into the Texas intrastate pipeline system. It may be, then, that all the leases in Subclass 1 would qualify as “proceeds” leases. Even assuming, however, that all Subclass 1 class members have “proceeds” leases, or that Phillips’ database can be easily used to identify those royalty owners that do, that assumption does not by itself qualify the subclass for certification. There are other conditions necessary for certification of the subclass.

The royalty owners argue that in Union Pacific Resource Group, Inc. v. Hankins, this Court confirmed that a class of royalty owners consisting solely of proceeds leaseholders is properly certifiable, focusing on our statement that there was a common legal question as to whether the proceeds actually received by the lessee were a fraud or a sham. 111 S.W.3d at 70. Arguing that this case is similar to Hankins on both the law and the facts, the royalty owners conclude our holding in Hankins means we should reverse the court of appeals’ holding that Subclass 1 failed predominance.

Hankins did not establish that a class of proceeds leaseholders is always certifiable. While Hankins did involve similar allegations that the lessee’s intra-affiliate sale transactions were a sham, the issue before the Court was whether there was a common legal question within a class consisting of market value and proceeds leases. Id. We rejected the contention that market value and proceeds leases both required a lessee to obtain the best price reasonably attainable and decertified the Hankins class because it failed to meet the Rule 42 commonality requirement. Id. at 74–75. While Hankins suggests class certification of a proceeds-only class is possible, it did not certify such a class, and did not further consider other certification prerequisites. See id. Accordingly, Hankins does not compel certification of this subclass.

Turning to the predominance issue, the court of appeals also held that Phillips would owe each royalty owner a different duty to market depending on the terms of the lease due to the existence of express provisions in some of the leases on the duty to market. 108 S.W.3d at 395. There is no implied covenant if a lease contains an express covenant on the same subject matter. Yzaguirre, 53 S.W.3d at 373. Implied covenants in oil and gas law protect against lessee self-dealing and negligence, and they are unnecessary where the parties have expressly agreed on the duties owed in writing. Id. at 374. For leases with an express clause, Phillips’ duty would be determined by that clause rather than an implied covenant to market as a reasonably prudent operator. Of the nearly 3,000 leases, some contain express clauses and some do not, and many of the express clauses contain different language. For these reasons, the court of appeals concluded individual issues would predominate, and the trial court had abused its discretion in certifying Subclass 1. 108 S.W.3d at 396.

The royalty owners rely on Hankins and Yzaguirre for their position that a covenant to market is implied in all proceeds leases and, therefore, there is a common question of whether Phillips breached its duty to market for all royalty owners with proceeds-based leases. Neither Hankins nor Yzaguirre, however, suggest the duty to market is implied in all proceeds leases. In both cases we concluded that a duty to market can be implied in a proceeds lease and not in a market value lease, but this does not mean there is an implied duty in all proceeds leases. In fact, we held in Yzaguirre that there is no implied covenant when the oil and gas lease expressly addresses the subject matter of an asserted implied covenant. Yzaguirre, 53 S.W.3d at 373. Thus, for the proceeds-based leases in Subclass 1 that contain an express covenant requiring a duty to market, there is no implied duty to market. The royalty owners’ assertions to the contrary misread our holdings in Hankins and Yzaguirre. Certainly Phillips owes a duty to market to the members of Subclass 1, but it owes each royalty owner either an express or an implied duty, not both.

The court of appeals emphasizes the differences among the leases and concludes there is no common liability question discernible without examining each lease—particularly because those leases with express clauses would require a different duty than the implied duty to market. 108 S.W.3d at 395–96. While this is a possibility, it is not clear from the record that any of the express duty to market clauses would in practice require different conduct from the duty in the implied covenant to market. However, for different reasons than the court of appeals, we agree that Subclass 1 has not met Rule 42’s predominance requirement.

Even if we were to assume that Phillips owes identical duties to market to all of the Subclass 1 royalty owners, whether under an express or implied duty, the task for the jury would be to determine the price a reasonably prudent operator would have received at the wellhead. In this case, the variations in well locations, quality of production, and field regulations, among other factors, will require the jury to conduct a well-by-well analysis, defeating predominance unless the class offers particular evidence that the gas price at the wells can be evaluated classwide.

In an attempt to show such classwide evidence of Phillips’ breach, the royalty owners point to the higher prices obtained by PGM in sales to third parties off the premises as compared to the prices Phillips charges PGM at the wellhead. Following the sale from Phillips, however, PGM gathers gas from the wells and sells it under contracts with delivery points miles away from the wells. The higher prices obtained by PGM from the sale of gas to the third parties include post-production costs that would not be incurred in sales at the wellhead. The royalty owners did not produce classwide evidence that would account for variations in post-production charges, such as transportation charges or other service charges, between each particular well and point of delivery. Although it might be possible under certain circumstances to show that a lessee failed to diligently market the gas and obtain a reasonable price for a class of lessors, the royalty owners in this case have not provided classwide evidence of these alleged deficiencies.[5]     Because individual issues would predominate, the trial court abused its discretion in certifying the class. For this reason, we affirm the court of appeals’ judgment as to Subclass 1.

B. Subclass 2

Subclass 2 is comprised of royalty owners whose royalties are calculated under uniform language in Gas Royalty Agreements (GRAs). The GRAs provide that the lessee, Phillips, shall pay a royalty on all gas, other than casinghead gas, produced from the leases and “sold or used off the premises.” The royalty is determined as follows:

The royalty on the total volume of sweet gas so produced and so sold or used shall never be less than four cents (4c) multiplied by one-eighth (1/8) of the total volume in M.c.f. of such sweet gas and the royalty on the total volume of sour gas so produced and so sold or used shall never be less than three and one-half cents (3 1/2c) multiplied by one-eighth (1/8) of the total volume in M.c.f. of such sour gas. Whenever the weighted average price per M.c.f. received by Lessee from all sales of gas delivered within an area comprising Moore, Hartley, Sherman and Hansford Counties, Texas and Texas County, Oklahoma, during any calendar month, exceeds four cents (4c) per M.c.f., the royalty on the total volume of sweet gas so produced and so sold or used during the succeeding month shall be an amount equal to such weighted average price less one-half cent (1/2c) multiplied by one-eighth (1/8) of the total volume in M.c.f. of such sweet gas and the royalty on the total volume of sour gas so produced and so sold or used during such succeeding month shall be an amount equal to such weighted average price less one-half cent (1/2c) multiplied by one-eighth (1/8) of the total volume in M.c.f. of such sour gas.

* * * * *

The phrase ‘weighted average price per M.c.f. received by Lessee from all sales of gas’ shall mean the weighted average price, computed as hereinafter provided, received by Lessee and its subsidiaries from the sale to others than Lessee and its subsidiaries of natural gas and any components of natural gas, excluding sales of casinghead gas sold in its natural state, delivered by Lessee in the form of gas within the above designated area. In computing weighted average price, there shall not be deducted any cost of transportation or purification incurred by Lessee, and any amount per M.c.f. received by Lessee from the purchaser for transportation or purification prior to delivery shall be deemed to be a part of the price per M.c.f. received by Lessee.

* * * * *

The term ‘weighted average price’ as used herein shall refer to weight with respect to volume and price only.

Subclass 2 includes approximately three to four thousand royalty owners in the Texas Panhandle with gas royalties governed by GRAs. Phillips produces natural gas from these leases, transports it miles away, and Phillips’ affiliate GPM Gas Corporation (GPM) processes liquid products at a processing plant from the natural gas produced from the wells. The liquid products are then sold separately from the dry residue gas.

The general formula for paying royalties is the volume of gas production multiplied by price, adjusted for the interest owned. Specifically, the GRAs provide that the royalty due is the “weighted average price” multiplied by the total volume of natural gas production in M.c.f. times the one-eighth royalty interest, for gas delivered within the defined five-county area.[6]    

These royalty owners complain that Phillips calculates their royalties based only on the dry residue natural gas production and excludes the liquid components, which are separated from the gas by Phillips’ downstream processing. See Mapco Inc. v. Pioneer Corp., 615 F.2d 297, 298 (5th Cir. 1980) (discussing separation of natural gas liquids from “dry gas”). Liquid products of natural gas can include natural gas liquids or Liquid Natural Gas (LNG). Natural gas liquids are heavier hydrocarbons (such as ethane and propane) that are separated from the lighter natural gas (methane). 8 Howard R. Williams & Charles J. Meyers, Oil and Gas Law: Manual of Oil and Gas Terms, at 600, 634, 835 (2007). Natural gas liquids are extracted from natural gas at processing plants away from the wellhead. See ConocoPhillips Co. v. Incline Energy, Inc., 189 S.W.3d 377, 379 (Tex. App.—Eastland 2006, pet. denied). LNG, by contrast, is liquid methane processed by cooling natural gas to approximately -260 degrees Fahrenheit, at which point the gas condenses to a liquid state. Rachel Clingman & Audrey Cumming, The 2005 Energy Policy Act: Analysis of the Jurisdictional Basis for Federal Siting of LNG Facilities, 2-1 Tex. J. Oil, Gas, & Energy L. 57, 60 (2007). This reduces the volume of the gas by a factor of 600 to 1, making it easier to transport and store. Id.

Phillips interprets the GRAs to require royalty payments without accounting for the prices received for natural gas liquids or LNG, which GPM processes miles away.[7]     The royalty owners argue Phillips’ practice of using only dry residue gas prices to calculate weighted average price, rather than using the prices obtained from selling the gas before the liquid components are removed, constitutes a breach of the GRAs. If sales of natural gas liquids and LNG are included in the weighted average price, the price factor of the royalty formula will be higher as “wet” gas is more valuable than dry residue natural gas. If they are not, the price factor will be lower. The royalty owners contend that the phrase “weighted average price per M.c.f. received by Lessee from all sales of gas” includes the price Phillips receives for sales to third parties of natural gas liquids and LNG.

The royalty owners also complain that the royalty formula should account for the varying heat content of the components of gas produced. Natural gas is measured in one of two ways. One method, the volumetric method, measures the volume of space the gas occupies at a specified pressure and temperature. The industry measurement unit, abbreviated as “Mcf,” for this method equals one thousand cubic feet of gas, measured at a specified pressure and temperature.[8]     Williams & Meyers, supra, at 596. In short, one Mcf is the amount of gas at a particular pressure and temperature needed to fill a cube ten feet wide by ten feet long by ten feet high. The other method for measuring natural gas values the heating content of the gas, including its components. The heating content of gas will vary from well to well, depending on the mixture of hydrocarbon and non-hydrocarbon molecules, and the mixture of simple versus complex hydrocarbons.[9]     The industry measurement unit for this method is the British thermal unit, abbreviated “Btu.” Id. at 110.

While Phillips calculates royalty payments based on the number of Mcfs, the royalty owners argue the phrase “weighted average price per M.c.f.” should account for the varying Btu content of the gas streams. The royalty owners claim their natural gas contains higher Btu components and calculating royalties based on the heating content of gas produced would require Phillips to pay higher royalties.

Of course, the method of measuring gas for the royalty formula is determined by the agreement. We first address the contention that the GRAs are ambiguous. The court of appeals held that Subclass 2 failed to meet the predominance requirement because the trial court implicitly found the GRAs were ambiguous on the issue of valuing natural gas production. 108 S.W.3d at 397–98. Notwithstanding the GRA provisions, the trial court proposed to send the issue to the jury and “require the jury to state the formula that [Phillips] should have used to compute royalty payments under the [GRAs].” The trial court, in essence, instructed the jury to interpret the phrase “weighted average price per M.c.f.” in the GRA as either a volumetric measurement or a measure of both volume and heat content. The jury would have to hear evidence to decide the intentions of thousands of individual royalty owners who executed GRAs and determine whether the parties reached a “meeting of the minds” on the formula for calculating royalties. See Lenape Res. Corp., 925 S.W.2d at 574 (stating the intentions of the parties control a contract’s meaning).

The court of appeals thus held that individual issues would predominate over common issues, making the claims inappropriate for class certification. See Schein, 102 S.W.3d at 693. We agree with the court of appeals that by sending the interpretation of the GRAs to the jury, the trial court implicitly held the GRAs were ambiguous. See Thomas v. Long, 207 S.W.3d 334, 339–40 (Tex. 2006) (holding that court of appeals was correct to consider appeal of trial court’s implicit ruling).

However, we disagree that the GRA provisions at issue are ambiguous. Whether a contract is ambiguous is a question of law, subject to de novo review. Heritage Res., Inc. v. Nationsbank, 939 S.W.2d 118, 121 (Tex. 1996); see Coker v. Coker, 650 S.W.2d 391, 393 (Tex. 1983). The royalty sections of the GRAs state with specificity how the royalty should be determined and define various terms used in the calculation. The GRAs state that Phillips must pay a royalty “on all sweet gas and sour gas, including all the components thereof, produced from said land and sold or used off the premises.” (Emphasis added.) The GRAs then provide that this volume of gas will be multiplied by a price of no less than four cents or a “weighted average price” if it is more than four cents. The GRAs define the phrase “weighted average price per M.c.f. received by [Phillips] from all sales of gas” to mean “the weighted average price . . . received by [Phillips] and its subsidiaries from the sale to others than [Phillips] and its subsidiaries of natural gas and any components of natural gas, excluding sales of casinghead gas sold in its natural state, delivered by [Phillips] in the form of gas within the [listed counties].” (Emphasis added.) The GRAs require Phillips to pay a royalty on the natural gas produced “including all the components thereof” (or alternatively phrased as “any components of natural gas”). Liquid products are originally constituent parts of the natural gas produced by Phillips and delivered to GPM. This indicates that when determining the prices of natural gas to include in the weighted average price factor in the royalty formula, all the natural gas metered at the royalty owners’ wells should be included, before any later extraction of natural gas liquids or LNG. In sum, the royalty owners are entitled to a royalty based on the value of the natural gas, including all of its components.

Phillips argues that the phrase “delivered by [Phillips] in the form of gas” should limit the weighted average price to only the prices received for the sale of natural gas in the form of gas. Although sophisticated parties in today’s market might enter a contract that distinguishes the forms and components of natural gas, the GRAs in the present case were entered long before extraction and sale of natural gas liquids was commonplace. The GRAs evidence the parties’ intent to base a royalty on the value of the natural gas before separation of liquid components has occurred.

On the other hand, the royalty owners are incorrect insofar as they suggest the royalty should be based on the average of prices Phillips receives for the separate sales of dry residue gas and liquid components. The GRAs specifically state that “amount[s] per M.c.f.” received for transportation and purification of the gas shall not be deducted from the sales prices when averaging prices for royalty purposes. The GRAs do not state that similar premiums received for any voluntary processing Phillips undertakes may also not be deducted from the sales price when averaging. In other words, just as the GRAs do not contemplate Phillips separating liquid components from dry residue gas before calculating a royalty, they do not evidence the intent to give the royalty owners the benefit of the value added by further processing. To read the GRAs otherwise would give the royalty owners the benefit of costs and risks Phillips voluntarily undertook.

This interpretation not only adheres to the terms of the agreement, it also comports with industry practice. Subject to their agreements, royalty owners generally are entitled to a royalty on the total amount of minerals they sell from their mineral estate, including all components of those minerals—no less and no more. Sowell, 789 F.2d at 1158. This principle is limited, however, by other considerations. Unless otherwise specified in the mineral lease, generally, the lessee or producer will bear both the cost and benefits from processing and treatment of those minerals after the initial production. We have explained that “[h]aving bought and paid for such gas [the lessee] owned the same, including all of its constituent elements, and therefore had the lawful right to make such use of it as it might deem proper.” Lone Star Gas Co. v. Stine, 41 S.W.2d 48, 49 (Tex. Comm’n App. 1931, judgm’t adopted); Lone Star Gas Co. v. Harris, 45 S.W.2d 664, 667 (Tex. Civ. App.—Eastland 1931, writ ref’d) (same); see also ConocoPhillips Co., 189 S.W.3d at 381 (holding royalty calculation not required to include natural gas liquids production when agreement calls for metering before liquids are removed); Carter v. Exxon Corp., 842 S.W.2d 393, 394, 397 (Tex. App.—Eastland 1992, writ denied) (holding production of natural gas liquids not included in royalty for “gas, including casinghead gas or other gaseous substance”). Nothing in the GRAs at issue indicate an intent to change these common principles.

The royalty owners’ second argument—that the royalty formula should account for the Btu content of the natural gas—finds no support in the language of the GRA provisions. To the contrary, the GRAs expressly state the “weighted average price” refers to “weight with respect to volume and price only” and make no mention of the heating content in determining the royalty. (Emphasis added.) Thus the GRAs do not provide for an adjustment for heating content or value or an incorporation of Btus as a measurement.

We therefore conclude that the pricing provisions of the GRAs are unambiguous and may be construed classwide for royalty owners who executed substantially identical GRAs. The GRAs in Subclass 2 require royalties to be paid based on the volume of natural gas metered at the wells multiplied by a price averaged from sales to third parties, before liquid products are extracted or processed. The trial court erred in its trial plan by proposing to send the interpretation of the GRAs to the jury and, accordingly, the court of appeals erred in decertifying Subclass 2 on predominance grounds.

The court of appeals also decertified Subclass 2 on another ground, holding that representatives Royce Yarbrough and Ted Powell were not adequate representatives. 108 S.W.3d at 398–401. It is the trial court’s duty to ensure that “the class representative is adequately representing the rights of absent class members in all aspects of the class litigation.” Daccach, 217 S.W.3d at 447. The class representative has the burden of proving adequacy. See Compaq, 135 S.W.3d at 672. One component of adequacy is the absence of conflict between a class representative and the class members. See State Farm Mut. Auto. Ins. Co. v. Lopez, 156 S.W.3d 550, 556 (Tex. 2004) (“[A] class representative whose interests conflict with those of other class members may not adequately represent a class.”). In the case of Yarbrough, Phillips contends that a royalty calculation formula including adjustments for heat content would actually lower the royalties Yarbrough receives due to the poorer composition of gas from her well. As we have determined that the GRAs do not include any adjustments for heat content of various wells, Yarbrough’s interests do not conflict with the class. The court of appeals erred in finding her an inadequate class representative on this basis.

The second class representative is Ted Powell. The court of appeals determined that there was no evidence before the trial court on which it could conclude that Powell was an adequate representative. 108 S.W.3d at 400–01. At the certification hearing in March 2002, Phillips challenged Yarbrough’s adequacy. The royalty owners then added Powell as a representative for Subclass 2 and his deposition was taken in May 2002. In a letter dated June 14, 2002, which was hand-delivered to the trial court, the royalty owners stated that the transcript of Powell’s deposition was attached to the letter and provided evidence to support his adequacy as a class representative. Phillips does not contend that the evidence in the deposition is insufficient to support a finding of adequacy, and we do not reach that issue. Instead, Phillips asserts that there is no proof that Powell’s deposition was before the trial court when it signed the certification order on June 14, 2002. Although the June 14th letter is file-stamped June 14, 2002, the deposition is stamped “filed” on June 23, 2002, one week after the certification order was signed. If the trial court did not have the deposition on June 14th when it signed its order, the trial court would have abused its discretion in certifying the class with Powell as a representative as there would be no evidence to establish his adequacy. The royalty owners have not established that the deposition was available to the trial court when it signed the order. See Compaq, 135 S.W.3d at 672 (stating class representative has the burden at the trial court to establish the prerequisites for class certification). Accordingly, there is no evidence on which to base a determination that Powell carried his burden to establish his adequacy as a class representative.

For the foregoing reasons, we conclude that the court of appeals erred in finding that the GRAs were ambiguous. We agree that Powell has not shown that he is an adequate representative for Subclass 2, but hold that Yarbrough’s interests are not in conflict with the class. Therefore we reverse the court of appeals’ judgment decertifying Subclass 2.

C. Subclass 3

Subclass 3 is comprised of royalty owners in the Texas Panhandle whose leases provide for royalties, either under an amount-realized/proceeds basis or under a market-value basis, in which Phillips has sold gas under a “percentage of the proceeds” (POP) contract with its affiliate GPM. A POP contract is a gas purchase contract providing payment to the purchaser as a percentage of the proceeds realized by the purchaser upon the resale of the gas. Williams & Meyers, supra, at 751. The POP contracts here provide for Phillips to receive a price for the raw natural gas based on the volume of residue gas and natural gas liquids after GPM gathers and processes the gas. A typical POP contract includes an “80/20” split between the lessee and subsequent purchaser, similar to the percentages in the contracts at issue for Subclass 3. In such a contract, Phillips would receive a gas price calculated by adding eighty percent of the proceeds GPM receives for residue gas times the volume and eighty percent of the published prices for liquids times the volume. Thus, GPM would retain for itself twenty percent of the proceeds from the resale of the gas.

The royalty owners argue the 80/20 split, or other similar percentages, constitutes an unreasonable and fraudulent post-production fee for GPM. They argue Phillips breached its covenant “to manage and administer the leases as a reasonably prudent operator” based on this “excessive” processing charge. Holding Subclass 3 failed to meet the predominance requirement, the court of appeals reversed certification based on the numerous individual factors the jury would need to consider to determine if Phillips breached its duty by paying unreasonable fees to GPM. The court of appeals did not address Phillips’ argument that there is no recognized implied covenant to manage and administer the lease properly. We address the royalty owners’ claim that Texas recognizes an implied duty to manage and administer gas leases, as well as the reasons expressed by the court of appeals for decertification.

In their brief, the royalty owners do not address the potential individual factors, but instead focus on the question common to the subclass: whether the fees under the POP contracts are unreasonable. The royalty owners emphasize the legal issue common to the subclass is Phillips’ duty to manage and administer the lease as a reasonably prudent operator, which they allege we recognized in Yzaguirre. This duty, they argue, applies to all members of the subclass, whether they have a proceeds-based or market-value based lease.

The royalty owners, however, provide no comprehensive explanation of a broad implied “duty to manage and administer the lease,” nor do they distinguish this duty from the recognized duty to market as a reasonably prudent operator. As we discussed in Amoco, the “duty to manage and administer” the lease is one of three broad categories of implied covenants recognized by law and gas treatises. Amoco Prod. Co., 622 S.W.2d at 567. In Yzaguirre, we recognized the implied duty to manage and administer the lease included the duty to market the oil and gas reasonably, citing our holding in Amoco. Yzaguirre, 53 S.W.3d at 373 (citing Amoco Prod. Co., 622 S.W.3d at 567). Thus, the royalty owners misread our holding in Yzaguirre to suggest we have recognized a “duty to manage and administer the lease as a reasonably prudent operator” distinct from a duty to market as a reasonably prudent operator. In addition, the royalty owners have failed to provide support for the proposition that, at its core, Subclass 3 concerns anything more than Phillips’ alleged failure to diligently market the gas and obtain a higher price, subject to the same limitations we have already expressed for that implied duty.

Whether brought under the broad duty to manage and administer the lease or under the specific duty to market, Subclass 3 may not be certified because it expressly includes both proceeds/amount realized and market value leases. As we discussed in Hankins, a class such as Subclass 3 would fail the Rule 42 commonality requirement by including both types of leases. 111 S.W.3d at 74–75. Like Hankins, the inquiry under a market value lease would be different than under a proceeds lease. Market value leases provide an objective basis for calculating royalties independent of the price the lessee actually obtains, and thus we do not recognize an implied covenant to obtain a better price for such oil and gas leases. Yzaguirre, 53 S.W.3d at 374. Since market value leases do not have such an implied covenant, while proceeds leases do, Subclass 3 does not satisfy the commonality requirement of Rule 42. See Hankins, 111 S.W.3d at 74–75 (holding that even under the commonality requirement’s low threshold, a class with both proceeds leases and market value leases would fail).

Finally, the royalty owners fail to explain how a reasonable processing fee can be proven classwide, even for proceeds leases only. Subclass 3 involves POP contracts for gas processed at three different GPM processing plants in the Panhandle. Many of the contracts have percentages different from the general 80/20 ratio. A factual analysis of the circumstances surrounding each POP contract would be necessary to ascertain if the production fee was reasonable or if Phillips breached any duties owed. Like Subclass 1, individual issues would predominate. Thus, the trial court abused its discretion by certifying Subclass 3.

V. CONCLUSION

For these reasons, we conclude the trial court abused its discretion in certifying Subclasses 1 and 3 of royalty owners. We affirm on different grounds the court of appeals’ judgment decertifying Subclasses 1 and 3, but reverse the judgment decertifying Subclass 2, and remand the case to the trial court for further proceedings consistent with this opinion.

________________________________________

J. Dale Wainwright

Justice

OPINION DELIVERED: February 15, 2008

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^[1]     The language of the former Rule 42(b)(4), adopted from the revised Federal Rule of Civil Procedure 23(b)(3), is now codified as Rule 42(b)(3), effective January 1, 2004. BMG Direct Mktg., Inc. v. Peake, 178 S.W.3d 763, 777 n.10 (Tex. 2005). For ease of reference, we will refer to (b)(3) as including the former (b)(4) paragraph.

^[2]     The following is an example of such a clause:

As royalty, lessee covenants and agrees: . . . [t]o pay lessor on gas and casinghead gas produced from said land (1) when sold by lessee, one-eighth of the amount realized by lessee, computed at the mouth of the well, or (2) when used by said lessee off said land or in the manufacture of gasoline or other products, the market value, at the mouth of the well, of one-eighth of such gas and casinghead gas.

^[3]     An example of such an express clause, found in the Bowden family leases, provides:

Lessee covenants and agrees to use reasonable diligence to produce, utilize, or market the minerals capable of being produced from said wells, but in the exercise of such diligence, lessee shall not be obligated to install or furnish facilities other than well facilities and ordinary lease facilities of flow lines, separator, and lease tank, and shall not be required to settle labor trouble or to market gas upon terms unacceptable to lessee.

^[4]     The reasonably prudent operator concept is infused into every implied covenant in the oilfield. “Every claim of improper operation by a lessor against a lessee should be tested against the general duty of the lessee to conduct operations as a reasonably prudent operator in order to carry out the purposes of the oil and gas lease.” Amoco Prod. Co. v. Alexander, 622 S.W.2d 563, 568 (Tex. 1981). Specifically, “the standard of care in testing the performance of implied covenants by lessees is that of a reasonably prudent operator under the same or similar facts and circumstances.” Id. at 567–68; Shell Oil Co. v. Stansbury, 410 S.W.2d 187, 188 (Tex. 1966).

^[5]     For example, if a class produced evidence that wells substantially identical to the class wells were being marketed at the wellhead to third parties for a greater price than Phillips was receiving, such evidence might satisfy the predominance requirement. Or if a class offered evidence that Phillips was artificially lowering the prices it charged PGM for gas sales across the board or that Phillips was systematically miscalculating the royalty payments, such claims might be more susceptible to certification. See, e.g., Duhe v. Texaco, Inc., 99-2002 (La. App. 3 Cir. 02/07/01); 779 So. 2d 1070, 1082 (holding there was a common class question on whether the lessor’s royalty formula correctly reflected market value).

^[6]     There are different minimum weighted average prices, not relevant here, for the production of sweet gas compared to sour gas. Sweet gas generally is natural gas not contaminated with impurities, such as sulfur compounds. As opposed to sour gas, it is ready for commercial and domestic use once liquid constituents have been removed. Gas is considered sour when it is “contaminated with chemical impurities, notably hydrogen sulphide or other sulfur compounds, which impart to the gas a foul odor. Such compounds must be removed before the gas can be used for commercial and domestic purposes.” 8 Howard R. Williams & Charles J. Meyers, Oil and Gas Law: Manual of Oil and Gas Terms, 986 (2007).

^[7]     We note that the royalty owners do not complain about a third type of liquid product found in natural gas production called condensate. Condensate is hydrocarbons that exist in the form of gas when contained in the natural gas reservoir underground, which condense into a liquid form when released from the reservoir’s higher pressure and temperature. Williams & Meyers, supra, at 186.1. Condensate is typically collected prior to metering at the wellhead and is therefore considered separately from liquids processed after metering. See Sowell v. Nat. Gas Pipeline Co. of Am., 789 F.2d 1151, 1153, 1158 (5th Cir. 1986) (holding plaintiffs were not entitled to royalties for liquids that condense after metering). The royalty owners in the present case complain only of Phillips’ removal of liquid products at processing plants after metering has occurred. Accordingly, this opinion considers only natural gas liquids and LNG production, rather than condensate production.

^[8]     The GRAs provide that the term “‘M.c.f.’ shall mean one thousand (1,000) cubic feet of gas computed to a base pressure of sixteen and four-tenths (16.4) pounds per square inch absolute and a base temperature of sixty (60) degrees Fahrenheit.”

^[9]     Natural gas from a well can be composed of both hydrocarbons, which are combustible, and non-hydrocarbons, which are inert. Williams & Meyers, supra, at 633. Hydrocarbons can vary in chemical makeup, from simple methane to the very complex octane, and in form, from a pure gaseous state to condensate. Id. at 480. The non-hydrocarbon makeup of natural gas can include gases such as helium, sulfur, and nitrogen. Id. at 633.