MEMORANDUM OPINION AND ORDER

JAMES O. BROWNING, District Judge.

THIS MATTER comes before the Court on the Plaintiffs' Motion and Supporting Brief to Determine That This Matter Proceed as a Class Action, filed January 6, 2014 (Doc. 194)("Motion"). The Court held a two-part class certification hearing with its first portion on March 10, 11, and 12, 2014, and its second portion on April 3 and 4, 2014. See Transcript of Hearing, taken March 10, 2014, filed June 26, 2014 (Doc. 254); Transcript of Hearing, taken March 11, 2014, filed June 26, 2014 (Doc. 255); Transcript of Hearing, taken March 12, 2014, filed June 26, 2014 (Doc. 256); Transcript of Hearing, taken April 3, 2014, filed June 26, 2014 (Doc. 257); Transcript of Hearing, taken April 4, 2014, filed June 26, 2014 (Doc. 258)(collectively, "Tr.").1 The primary issues are: (i) whether and to what extent textual variations among the leases within the proposed class defeat the commonality requirements of rule 23(a), or the predominance or superiority requirements of rule 23(b), of the Federal Rules of Civil Procedure; (ii) whether and to what extent ambiguity — and the need for parol evidence to resolve it — in the class leases defeats rule 23(a)'s commonality, or rule 23(b)(3)'s predominance or superiority requirements; (iii) whether and to what extent the class members' potentially varying levels of actual knowledge and reasonable diligence in uncovering their claims — which, under the discovery rule, are determinative when the statutes of limitations accrue on these claims — defeats rule 23(b)(3)'s predominance or superiority requirements; (iv) whether and to what extent any difficulty in properly assigning damages among the class members defeats the predominance or superiority requirements; (v) whether rule 23(a)'s requirements — numerosity, commonality, typicality, and adequacy — and rule 23(b)(3)'s requirements — predominance and superiority — are otherwise met with regard to the proposed class; and (vi) whom to appoint as class counsel rule 23(g). Textual variations among the leases both destroy commonality and predominance, because the central issue in this case — what royalty-payment methodology the Defendants owe the Plaintiffs — varies from lease to lease. Lease ambiguity does not destroy commonality, but it weighs against finding predominance. The class members' potentially varying levels of knowledge likewise presents individual issues that cut against predominance. Problems in assigning damages can be overcome, and damages can be determined on a classwide basis. Therefore, the Court concludes that this proposed class action satisfies the rule 23(a) prerequisites of numerosity, typicality, and adequacy, and the rule 23(b)(3) requirement of superiority, but that it fails the rule 23(a)(2) commonality prerequisite and the rule 23(b)(3) predominance requirement. The Court, thus, denies the Motion.

FINDINGS OF FACT

Both the Plaintiffs and the Defendants have submitted proposed findings of fact. See Plaintiffs' Proposed Findings of Fact and Conclusions of Law, filed May 6, 2014 (Doc 240)("Plaintiffs' PF"); Defendants' Findings of Fact and Conclusions of Law Relating to Class Certification, filed May 6, 2014 (Doc. 241)("Defendants' PF"). The parties have also stipulated to several facts for the purposes of the class certification determination. See Stipulation for the Purposes of Class Certification, filed March 10, 2014 (Doc. 223)("Stipulation"). The Court has carefully considered all proposed facts, and accepts some of them, rejects others, and finds some facts that no party brought to its attention.2 The Court also liberally judicially notices background facts. See Fed. R. Evid. 201. All of these findings of fact are authoritative only on the question of class certification, and the parties may relitigate any of them at the merits stage. See Abbott v. Lockheed Martin Corp., 725 F.3d 803, 810 (7th Cir. 2013); In re Hydrogen Peroxide Antitrust Litig., 552 F.3d 305, 313 (3d Cir. 2008); Gariety v. Grant Thornton, LLP, 368 F.3d 356, 366 (4th Cir. 2004). The Court applied the Federal Rules of Evidence at the class certification hearing, ruled on several evidentiary objections, and considered only admissible evidence in finding these facts. See note 39, infra, and accompanying text.

The Court organizes this portion of its Memorandum Opinion and Order into eight parts. First, it will define some of the more esoteric terms applicable in this case. Second, it will introduce the important players in this action: the Defendants and their corporate affiliates, the named Plaintiffs, the absent class members, and a few important independent entities. Third, the Court will explain the process of producing, gathering, and processing or treating natural gas, including the transfer-of-title process in this case. Fourth, the Court will describe the breakdown of the different textual royalty provisions in the class leases. Fifth, it will describe the different textual overriding royalty provisions among the class. Sixth, the Court will describe how the Defendants have paid royalties and overriding royalties to the class, including the costs that they have deducted and their timeliness. Seventh, it will describe the evidence that the Defendants have put forward regarding various class members' actual knowledge of or due diligence toward learning of their claims, which is relevant to the delaying of the accrual of the statutes of limitations. Eighth, and last, the Court will summarize a few key pieces of evidence relating to the parties' and the Court's ability to construct a classwide damages-distribution model.

1. Definitions: The Terminology Applicable in This Case.

1. The Court will first define the operative terms used throughout this Memorandum Opinion and Order. The Court divides the definitions into three sections: one on lease terminology, which defines the terms that relate to the legal relationship between the Plaintiff-lessors and Defendant-lessees; a second on oil and gas production, gathering, and processing, which defines the terms that relate to the working relationship between the Plaintiff-landowners and Defendant-oil companies; and a third on royalty accounting, which defines the terms that relate to the financial relationship between the Plaintiff-royalty owners and the Defendant-working interest owners. The Court will, in subsequent sections, explain how these concepts relate to this case, but includes this section as both a preface and a reference.

a. Lease Terminology.

2. A "mineral lease," is "[a] lease in which the lessee has the right to explore for and extract oil, gas, or other minerals"; it splits land into a working interest and a royalty interest. Black's Law Dictionary 971 (9th ed. 2009).

3. A "mineral deed" is "[a] conveyance of an interest in the minerals in or under the land." Black's Law Dictionary 477 (9th ed. 2009).

4. A "working interest" includes "[t]he rights to the mineral interest granted by an oil-and-gas lease, so called because the lessee acquires the right to work on the leased property to search, develop, and produce oil and gas, as well as the obligation to pay all costs"; a working interest in land entails the right to drill and remove oil and gas from the land, subject to burdening royalty interests. Black's Law Dictionary 1745 (9th ed. 2009).

5. A "royalty interest" is "[a] share of production — or the value or proceeds of production free of the costs of production — when and if there is production." Black's Law Dictionary 1466 (9th ed. 2009).

6. The word "production," generally, in the oil-and-gas industry, has numerous meanings, but they typically revolve around the well, and not around subsequent processing: a "production" can refer to the well itself, to the fresh-out-of-the-ground product that the well produces, or to the act of drawing said product out of the ground. 8 Howard R. Williams, Charles J. Meyers, Patrick H. Martin & Bruce M. Kramer, Williams & Meyers Oil and Gas Law 816-18 (2013)("Williams & Meyers").

7. "Authorities are split over what costs are the costs of production," Black's Law Dictionary 1466 (9th ed. 2009), and, under Colorado law, production "end[s] when a first-marketable product has in fact been obtained," which often only occurs after processing, Rogers v. Westerman Farm Co., 29 P.3d 887, 904 (Colo. 2001)(en banc).

8. An "overriding royalty" is "[a] share of either production or revenue from production (free of the costs of production) carved out of a lessee's interest under an oil-and-gas lease. . . . An overriding royalty interest ends when the underlying lease terminates." Black's Law Dictionary 1446 (9th ed. 2009).

9. An overriding royalty interest is considered a subcategory of royalty interest. See Garman v. Conoco, Inc., 886 P.2d 652, 657 (Colo. 1994)(en banc)("An overriding royalty is, first and foremost, a royalty interest." (quoting 2 Williams & Meyers § 418.1)).

10. A "division order" is "[a] contract for the sale of oil or gas, specifying how the payments are to be distributed." Black's Law Dictionary 549 (9th ed. 2009).

11. "Royalty owners enter into division orders to sell minerals and to instruct how payments are to be made under a mineral lease." Black's Law Dictionary 549 (9th ed. 2009).

12. "Working-interest owners also commonly sign division orders to instruct purchasers how payments are to be divided." Black's Law Dictionary 549 (9th ed. 2009).

13. A division order cannot modify the terms of the underlying mineral lease. See Tr. at 922:10-20 (McNamara, Terry).

14. A "division order is typically terminable at the will of either party." 8 Williams & Meyers at 272.

15. A "transfer order" is an instrument conveying a royalty interest to another person. Tr. at 46:20-23 (Brickell); id. at 304:24-305:2 (Westfall).

b. Natural-Gas Terminology.

16. "Hydrocarbons" are a class of chemical compounds composed exclusively of hydrogen and carbon; it is also a generic term for petroleum products such as oil and natural gas.3

17. "Natural gas" is a gaseous mixture of hydrocarbons, the primary one being methane (CH4), commonly used as fuel in homes and businesses. Glossary, United States Energy Information Administration, http://www.eia.gov/tools/glossary/index.cfm?id=N ("EIA Glossary").

18. Natural gas must generally be treated or processed — to remove waste products such as water vapor, sulfides, carbon dioxide, nitrogen, and other impurities, as well as valuable, heavier hydrocarbons such as ethane, butane, propane, and pentane — before it can be put into a pipeline system or marketed as a fungible commodity. See 30 C.F.R. § 1206.171.

19. Natural gas can be obtained as a byproduct of oil drilling, retrieved using standard drilling techniques in natural gas fields or coalbeds, or obtained through hydraulic fracturing — also known as fracking — in shale deposits. See EIA Glossary.

20. "Conventional gas" is natural gas obtained from natural-gas fields, which are typically sandstone depositions. Tr. at 79:14-19 (Reineke).

21. Conventional gas typically undergoes processing to remove impurities, separate out valuable NGLs, and render the gas into marketable condition. See Expert Witness Report of Randy Kaplin at 2 (Plaintiffs' Ex. 194).

22. "Coalbed methane" or "CBM" is natural gas obtained from coal seams. EIA Glossary.

23. Coalbed methane is typically just methane and carbon dioxide, and is generally only treated for carbon dioxide removal and possibly water-vapor removal — rather than being processed — before it is placed in a pipeline. See Tr. at 83:1-21 (Reineke, Brickell).

24. "Shale gas" is natural gas obtained — almost always by the process of hydraulic fracturing — from shale. EIA Glossary.

25. "Casinghead gas," also known as "oil well gas" or "associated gas," is natural gas obtained from an oil well. EIA Glossary.

26. The term "natural gas liquids" ("NGLs") refers to hydrocarbons heavier than methane that can — either on their own via condensation or through processing — be drawn from natural gas, converted into the liquid state, and sold as fuel. 30 C.F.R. § 1206.171.

27. The constituent "liquefiable hydrocarbons" in NGLs include propane, butane, pentane, and hexane. EIA Glossary.

28. Among NGL compounds, heavier compounds are typically more valuable than lighter ones. See Tr. at 559:1-10 (Sutphin, Emory).

29. "Heavier," in this context, refers to the compound's molecular weight, which, for alkane hydrocarbons, equates to the magnitude of the n term in the generic chemical formula CnH(2n + 2). Cf. Tr. at 559:5-10 (Emory).

30. For example, pentane (C5H12) is heavier than butane (C4H10), which is, in turn, heavier than propane (C3H8). Cf. Tr. at 559:5-10 (Emory).

31. All of the constituent compounds of NGLs are heavier than methane (CH4), which is the primary component of natural gas. Cf. Tr. at 559:5-10 (Emory).

32. NGLs are commonly entrained in — or entrapped and carried along with — natural gas. See Tr. at 104:2-4 (Brickell, Reineke).

33. "Natural gasoline" refers to a mixture of natural gas liquid products manufactured from natural gas. Tr. at 407:10-20 (Sheridan, Anderson); id. at 795:9-796:1 (Sheridan, Terry).

34. Natural gasoline is not the same substance as automotive gasoline.4 See Tr. at 795:9-796:1 (Sheridan, Terry).

35. "Wet gas" is natural gas entrained with a significant amount of NGLs. EIA Glossary.

36. "Dry gas" is natural gas that is mostly devoid of NGLs. EIA Glossary.

37. Almost all coalbed methane is dry gas. See Expert Report of Randy Kaplin at 2 (Plaintiffs' Ex. 194).

38. Gas must be in a dry state before it can be placed into an interstate pipeline; when gas is dry after being processed, it is referred to as "residue gas." EIA Glossary.

39. "Natural gas condensate," or just "condensate," refers to natural gas liquids recovered at the surface without resorting to processing. 30 C.F.R. § 1206.171.

40. "Condensation," generically, is the physical phase change where a gas is converted to a liquid. The American Heritage Dictionary of the English Language 277 (William Morris ed., New College ed. 1976).

41. "Well condensate" or "wellhead condensate" is condensate recovered at the wellhead. Tr. at 37:2-9 (Sheridan).

42. A "wellhead" is the point where hydrocarbons are taken out of the ground, but the term is sometimes used to refer to anywhere hydrocarbons go while on the lease plot. EIA Glossary.

43. A "separator" or "production unit" is a device at the wellhead that separates liquids — namely water and well condensate — from the gas. Tr. at 96:12-16 (Reineke).

44. A "facility measurement point" is the point where a "measurement device is located for determining the volume of gas removed from the lease." 30 C.F.R. § 1206.171.

45. "The facility measurement point may be on the lease or off-lease," but is intended to measure the natural gas attributable to a specific lease before it is comingled with gas from other leases in a gathering system. 30 C.F.R. § 1206.171.

46. A "`completion' refers to a well that has been completed," i.e., perforated and isolated in the well bore, such that gas is capable of being produced from the well. Emory Expert Report ¶ 23, at 13.

47. "Lease use" gas is gas that the working interest owner uses — to power machinery, fuel heaters, et cetera — on the lease. Tr. at 443:3-7 (Brickell, Emory).

48. A "gathering system" is the system of low-pressure lines that transport natural gas from the lease site, i.e., the wellhead, to a processing plant or other central point. EIA Glossary. See 30 C.F.R. § 1206.171.

49. "Drip condensate" is any natural gas condensate "recovered downstream of the facility measurement point [the wellhead] without resorting to processing." 30 C.F.R. § 1206.171.

50. "Drip condensate includes condensate recovered as a result of its becoming a liquid during the transportation of the gas removed from the lease or recovered at the inlet of a gas processing plant by mechanical means, often referred to as scrubber condensate." 30 C.F.R. § 1206.171.

51. Drip condensate, put simply, is NGLs that condense into liquid form in the gathering system, i.e., after the gas has left the wellhead, but before it gets processed. See 30 C.F.R. § 1206.171.

52. A "pig" is a term for a mechanical device that pushes drip condensate sitting in a gathering system's lines out into a receptacle for eventual sale. Tr. at 39:2-6 (Sheridan).

53. A "fractionator" is a machine that separates NGLs into their constituent parts — such as propane, butane, and pentane — after they are removed during processing. EIA Glossary

54. A "processing plant" is a facility that takes impure, unmarketable natural gas from a gathering system, and converts it — by removing impurities and NGLs — into pipeline-quality natural gas, which can then be compressed and sent into the interstate pipeline system. Tr. at 39:7-13 (Sheridan).

55. A processing plant is typically connected to a gathering system on the input end and a pipeline system on the output end. See Tr. at 99:16-100:11 (Reineke).

56. A "treatment plant" is a facility that is fundamentally similar to a processing plant — i.e., it takes impure gas from a gathering system and renders it into marketable condition — but it does not remove NGLs from the gas. See Tr. at 619:15-20 (Emory, Brickell).

57. Treatment removes carbon dioxide and often dehydrates the gas — i.e., it removes the water vapor — but, unlike processing, it does not extract NGLs. See Tr. at 619:15-20 (Emory, Brickell).

58. Gas that is relatively clean — i.e., free from impurities — and dry — i.e., free from NGLs — may need only to be treated, rather than processed. See Tr. at 619:15-20 (Emory, Brickell).

59. Coalbed methane typically requires only treatment to remove carbon dioxide, which it tends to contain in higher quantities than conventional gas. See Tr. at 83:1-21 (Reineke, Brickell).

60. "Bypassing" is when raw gas is delivered by a gathering system to a processing plant but is not processed, and instead is mixed with processed gas in such proportions that the resultant product is still of pipeline quality. Tr. at 554:15-555:4 (Emory, Sutphin).

61. In New Mexico, "the term `post-production costs' refers to costs associated with making the natural gas marketable after the gas is severed or removed from the ground." Schroeder v. Terra Energy, Ltd., 565 N.W.2d 887, 890 (Mich. Ct. App. 1997); 8 Williams & Meyers at 787. See CononoPhillips Co. v. Lyons, 2013-NMSC-009, ¶ 11, 299 P.3d 844, 850 (N.M. 2012)(endorsing this definition).

62. "Marketable condition means a condition in which lease products are sufficiently free from impurities and otherwise so conditioned that a purchaser will accept them under a sales contract typical for the field or area." 30 C.F.R. § 1206.171.

63. For the class wells, natural gas generally comes into marketable condition when it is of sufficient quality to be accepted into the interstate pipeline system.5 See Foster v. Merit Energy Co., 282 F.R.D. 541, 546 (W.D. Okla. 2012)(Friot, J.)(referring to "commercially marketable (essentially interstate pipeline quality) gas"); Rogers v. Westerman Farm Co., 29 P.3d 887, 905 (Colo. 2001)(en banc)("It may be, for all intents and purposes, that gas has reached the first-marketable product status when it is in the physical condition and location to enter the pipeline." (citing TXO Prod. Corp. v. State ex rel. Comm'rs of Land Office, 903 P.2d 259, 262-63 (Okla. 1994))); Savage v. Williams Prod. RMT Co., 140 P.3d 67, 71 (Colo. Ct. App. 2005)(holding that "the trial court applied the correct legal standard" regarding "the condition of the gas at the wellhead" when it "found that `the gas was marketable only after processing and transportation to the interstate pipeline connection in a condition that made it acceptable for delivery into said pipelines"); Amoco Prod. Co. v. N.M. Taxation & Revenue Dep't, 2003-NMCA-092, ¶¶ 11-12, 74 P.3d 96, 99 (N.M. Ct. App. 2003)("`[P]rocessing' is that which takes place in order for the gas to be marketable or acceptable to interstate pipelines."); Parry v. Amoco Prod. Co., No. CIV 94-0105, 2003 WL 23306663, at *1 (Colo. Dist. Ct. Oct. 6, 2003)("[T]he Court concludes that the gas in question is marketable only at the inlet to the interstate transmission pipeline. . . ."). But see Creson v. Amoco Prod. Co., 2000-NMCA-081, ¶ 24, 10 P.3d 853, 859 (N.M. Ct. App. 2000)(repeating the parties' undisputed agreement that gas is marketable at the wellhead where it is "actually marketed at the wellhead," circumstances which do not apply in this case).

64. "Residue gas" refers to post-processing, pipeline-quality natural gas. 30 C.F.R. § 1206.171.

65. An "MCF" is a unit of volume used to measure natural gas; it stands for 1,000 cubic feet, which is equivalent to a cube that is 10-feet high, 10-feet wide, and 10-feet deep. Frequently Asked Questions, United States Energy Information Administration, http://www.eia. gov/tools/faqs/faq.cfm?id=45&t=8 ("EIA FAQs").

66. A "Btu" is a unit of energy equal to approximately 1,055 joules;6 it is the amount of energy needed to heat — or the amount of energy released by cooling — one pound of water by one degree Fahrenheit. EIA Glossary; EIA FAQs.

67. An "MBtu" or "MMBtu" is 1,000,000 Btus.7 EIA FAQs.

68. A "Btu factor" is a ratio describing the energy per volume of natural gas. EIA Glossary; EIA FAQs.

69. In this case, Btu factors are quoted in units of MMBtus per MCFs.

70. The Btu factor of pure methane — perfectly dry natural gas — is 1.01. See Emory Expert Report ¶ 31, at 16.

71. Gas' Btu factor rises as the amount of entrained NGLs increases, and drops as the number of entrained, inert impurities — such as carbon dioxide and gaseous nitrogen — rises. See Emory Expert Report ¶¶ 30-31, at 16.

72. The average Btu factor of processed natural gas in the United States is 1.025. See EIA FAQs.

73. The Btu factors of the gas produced from the class wells in this case vary from .69 to 1.4. See Emory Expert Report ¶ 32, at 16-17.

74. As natural gas is valuable, ultimately, for its energetic potential — i.e., the amount of heat it produces when burned — its price is based not only on the volume of natural gas being sold, but also that natural gas' Btu factor. See EIA FAQs.

75. "GPM" stands for "gallons [of NGLs] per MCF [of gas]," and is a characteristic that reveals the quantity of entrained NGLs that can theoretically be extracted from the gas via condensation and processing. Natural Gas Liquids at 5, Brookings Energy Security Initiative Natural Gas Task Force (Mar. 2013), available at http://www.brookings.edu/~/media/research/files/reports/—/04/01-natural-gas-ebinger-avasarala/natural-gas-briefing-1-pdf.pdf. See Emory Expert Report ¶ 28, at 15.

76. When NGLs are removed from natural gas, it causes a "shrink" in the energy content — the number of MMBtus in — the resultant natural gas. Tr. at 194:4-7 (Ley).

c. Royalty Distribution and Accounting Terminology.

77. The "netback" or "workback" method is a method of determining the wellhead price of gas by starting with the downstream (processed) sale price of the ultimate product, and deducting the costs — such as those for transportation, processing, and manufacturing — of converting the gas from the condition at the wellhead to the condition at final sale. See 8 Williams & Meyers at 643-644; 30 C.F.R. §§ 1206.151, 1206.171.

78. The netback method "is widely accepted as the best means for estimating the market value of gas at the well where no such market exists." Abraham v. BP Am. Prod. Co., 685 F.3d 1196, 1199-1200 (10th Cir. 2012)(Kelly, J.)(joined by Murphy & Hartz, JJ.).

79. This case involves a somewhat ambiguous term: "weighted average sales price" ("WASP").

80. A "weighted average method" is a method of paying royalties in which each royalty owner is paid based on a predetermined portion — usually determined by lease acreage — of the sales revenue from several pooled leases' productions. 8 Williams & Meyers at 1139.

81. For example, if a pool of leases totaling 1,000 acres produced $1,000,000.00 in natural gas, a 250-acre lease would receive $250,000.00, regardless whether that lease actually produced $250,000.00 in natural gas.

82. "WASP," as used in this case, however, might refer, not to a pooling of royalties, but to a pooling of arm's length sales revenue on the front end — e.g., if the Defendants sold two MMBtus of residue gas to one buyer at $1.00/MMBtu and on MMBtu of residue gas to another buyer at $2.00/MMBtu, then they would pay royalties to all wells based on a WASP of $1.33/MMBtu, without attempting to break down which wells produced the gas sold for $2.00/MMBtu and which wells produced the gas sold for $1.00/MMBtu. See, e.g., Tr. at 138:15-20 (Berge, Reineke)("Q: [Y]ou know what an index is. . . . [I]t's average — weighted average compiled by a service that reflects the prevailing — the weighted average prevailing price in a particular market, right? A: Of residue gas, correct."); id. at 947:21-24 (Terry)(describing an index price as "representing a weighted average price").

83. An "index price" or "posted price" is a price for natural gas that a major industry publication publishes; royalties paid on the basis of index prices are not, themselves, based on the actual sale price of the gas, but, rather, on an average of arm's length transactions within a particular geographic area. See 8 Williams & Meyers at 496.

84. A "keep whole" contract is one that requires the processor to compensate the royalty owner for any loss in thermal potential (energy) that natural gas undergoes from processing — namely, the Btu factor of gas decreases when NGLs are removed. See 8 Williams & Meyers at 533.

85. What the Defendants call their "keep whole basis" of paying royalties is tantamount to basing royalty payments on the natural gas' energy — measured in MMBtus — at the wellhead. Tr. at 91:25-92:5 (Reineke); 199:12-200:2 (Berge, Ley)("I've heard people use the term `keep whole.' So I think it means different things to different people.").

86. "Whole stream valuation" is a manner of paying royalties in which the working interest owner compensates the lessor for entrained NGLs by paying them a fraction of the sale proceeds of the NGLs, rather than simply compensating the lessors on an MMBtu basis at the wellhead, when NGLs are still entrained.8 Tr. at 659:22-668:12 (Griffin, Berge).

87. An "arm's length" transaction is a transaction between entities that are not corporate affiliates of one another. Tr. at 87:15-23 (Reineke).

2. The Principals: The Parties and Other Important Entities.

88. The Defendants and their relationships to both one another and certain non-Defendant corporate affiliates are important in this case, because one of the Plaintiffs' contentions is that the Defendants paid their royalties on the basis of affiliate sales prices rather than on arm's length sales. See, e.g., Complaint ¶ 33, at 14.

89. The named Plaintiffs — i.e., the proposed representatives of the proposed class — are important, because they must adequately represent the entire class, and their claims must be common to and typical of those of the entire class. See Fed. R. Civ. P. 23(a).

90. The Court notes at the outset that, although it has tried to be meticulous throughout this Memorandum Opinion and Order in specifying which Defendant or corporate affiliate of a Defendant handled which functions, the precise identity of each actor is not extraordinarily important.

91. Every entity with "Williams," "WPX," or "WFS" in its name was, until 2012, a corporate affiliate of every other similarly named entity — almost always a "full-blooded" affiliate, i.e., a successor or predecessor, a wholly-owned subsidiary or parent, or a sibling subsidiary with 100% overlap in ownership.

92. Although there was a corporate spinoff in January, 2012, that broke these entities into two camps with separate public ownership, this break is not especially important to this case, both because of how late it came in the class time period and because the contracts between the now non-affiliates that cover this case were executed at a time when the parties to the contracts were corporate affiliates, and, thus, transaction under these contracts are still considered affiliate transactions even after the spinoff. See Tr. at 474:19-24 (Brickell, Ward).

a. The Defendants.

93. There are two Defendants in this case: WPX Energy Production, LLC ("WPX Production") and WPX Energy Rocky Mountain, LLC ("WPX Rocky Mountain"). See Corporate Disclosure Statement ¶¶ 1-2, at 1, filed January 27, 2012 (Doc. 8).

94. The other names listed in the caption are former names. See Complaint ¶¶ 5-6, at 3.

95. WPX Production was formerly named WPX San Juan, LLC ("WPX San Juan"), until it changed its name on January 13, 2012. See Corporate Disclosure Statement ¶ 1, at 1; Certificate of Amendment of WPX Energy San Juan, LLC at 2 (Plaintiffs' Ex. 77).

96. The former WPX San Juan was previously named Williams Production Company, LLC ("Williams Production LLC"), until it changed its name on December 31, 2011. See Corporate Disclosure Statement ¶ 1, at 1.

97. Williams Production LLC was previously named Williams Production Company ("Williams Production Co."), until it changed its name and was re-chartered as a limited-liability company in 1998.

98. WPX Production is a wholly owned subsidiary of WPX Energy, Inc. ("WPX Energy"). See Corporate Disclosure Statement ¶ 1, at 1.

99. WPX Rocky Mountain was formerly named Williams Production RMT Company, LLC ("Williams RMT"), until it changed its name on December 31, 2011. See Corporate Disclosure Statement ¶ 2, at 1.

100. WPX Rocky Mountain is a wholly owned subsidiary of WPX Energy Holdings, LLC ("WPX Holdings"). See Corporate Disclosure Statement ¶ 2, at 1.

101. WPX Holdings is a wholly owned subsidiary of WPX Energy. See Corporate Disclosure Statement ¶ 2, at 1.

102. WPX Energy ultimately wholly owns both Defendants, and has throughout the time period applicable to this case.

103. WPX Energy is a publicly held corporation. See Corporate Disclosure Statement ¶¶ 1-2, at 1.

104. WPX Production is the lessee on the class leases in New Mexico, and WPX Rocky Mountain is the lessee on the class leases in Colorado.9 See Tr. at 6:12-17 (Brickell).

105. The Court will refer to WPX Production and WPX Rocky Mountain, collectively, as "the Defendants."

b. The Defendants' Corporate Affiliates.

106. Until a January, 2012, spinoff, Williams Companies, Inc. ("Williams Companies") owned all the companies that WPX Energy currently owns. See Deposition of Morris Miller at 25:1-6 (taken December 4, 2013)(Plaintiffs' Ex. 48)(Brickell, Miller); id. at 55:8-25 (Brickell, Miller).

107. Williams Companies also owns the general partner interest and the majority of the limited partner interest in Williams Partners LP ("Williams Partners"). Form 8-K for Williams Companies, Inc., Securities and Exchange Commission (Oct. 27, 2014), available at http://biz. yahoo.com/e/141027/wmb8-k.html.

108. Williams Four Corners, LLC ("Williams Four Corners") is a wholly owned subsidiary of Williams Partners. Form 8-K for Williams Companies, Inc., Securities and Exchange Commission (Oct. 27, 2014), available at http://biz.yahoo.com/e/141027/wmb8-k.html.

109. Williams Four Corners owns all the assets that Williams Field Services Co. ("Williams Field Services") formerly owned; Williams Field Services assigned all its interest to the newly created Williams Four Corners on June 20, 2006. See Notification of Assignment (Plaintiffs' Ex. 136).

110. Williams Field Services was formerly named Northwest Pipeline Corp. ("Northwest Pipeline"), until it changed its name in 1992. See Tr. at 85:17-19 (Reineke).

111. Williams Companies acquired Northwest Pipeline in 1983. See Emory Expert Report ¶ 19, at 12.

112. WPX Gas Resources Company ("WPX Gas Resources") is a wholly owned subsidiary of WPX Energy. List of Subsidiaries of WPX Energy, Inc., Securities and Exchange Commission, available at http://www.sec.gov/Archives/edgar/data/1518832/00011931251308 4857/d448908dex211.htm.

113. WPX Gas Resources was formerly named WFS Gas Resources Company ("WFS Gas Resources"), until it changed its name on December 1, 1998. See Certificate of Amendment of Certificate of Incorporation at 2 (Plaintiffs' Ex. 60).

114. WPX Energy Marketing, LLC ("WPX Energy Marketing") is a wholly owned subsidiary of WPX Energy. List of Subsidiaries of WPX Energy, Inc., Securities and Exchange Commission, available at http://www.sec.gov/Archives/edgar/data/1518832/00011931251308 4857/d448908dex211.htm.

115. WPX Energy Marketing was formerly named Williams Gas Marketing, Inc. ("Williams Gas Marketing"), until it changed its name on June 20, 2011. See State of Delaware Certificate of Conversion from a Corporation to a Limited Liability Company Pursuant to Section 18-214 of the Limited Liability Act at 3 (Plaintiffs' Ex. 65).

116. Williams Gas Marketing was formerly named Williams Power Company, Inc. ("Williams Power"), until it changed its name on November 16, 2007. See Certificate of Amendment of Certificate of Incorporation at 3 (Plaintiffs' Ex. 66).

117. Williams Power was formerly named Williams Energy Marketing & Trading Company ("Williams EMT"), until it changed its name on August 6, 2003. See Certificate of Amendment of Certificate of Incorporation at 3 (Plaintiffs' Ex. 63).

118. Williams EMT was formerly named Williams Energy Services Company ("Williams Energy Services"), until it changed its name on October 26, 1998. See Certificate of Amendment of Certificate of Incorporation at 2 (Plaintiffs' Ex. 64).

119. Williams Energy Services was formerly named Williams Energy Derivatives and Trading Company ("Williams EDT"), until it changed its name on September 26, 1995. See Certificate of Amendment of Certificate of Incorporation at 2 (Plaintiffs' Ex. 62).

120. Any transactions between the two of the following list of entities is considered an affiliate transaction10 and not an arm's length sale: WPX Production, WPX Rocky Mountain, WPX San Juan, Williams Production LLC, Williams Production Co., WPX Energy, Williams RMT, WPX Holdings, Williams Companies, Williams Partners, Williams Four Corners, Williams Field Services, Northwest Pipeline, WPX Gas Resources, WFS Gas Resources, WPX Energy Marketing, Williams Gas Marketing, Williams Power, Williams EMT, Williams Energy Services, and Williams EDT. See Miller Depo. at 55:8-25 (Brickell, Miller).

121. The Court will refer to these entities, generically, as "WPX affiliates."

c. The Named Plaintiffs, i.e., the Proposed Class Representatives.

122. Plaintiff Anderson Living Trust ("Anderson Trust") owns royalty and overriding royalty interests that burden WPX Production's and WPX Rocky Mountain's working interests in natural gas production from the New Mexico and Colorado portions of the San Juan Basin. See Tr. at 359:7-360:23 (Anderson, Branch).

123. James Anderson is a trustee of the Anderson Trust. See Tr. at 359:7-360:22 (Anderson, Branch); Anderson Trust Creation Document at 1 (Plaintiffs' Ex. 3).

124. Anderson is willing to serve as class representative in this case and represent the class' interests as well as his own. See Tr. at 373:4-13 (Anderson).

125. Anderson has some knowledge of the oil-and-gas industry; he receives royalty payments from seven different oil-and-gas companies, has been a class member in another royalty class action, and was formerly a member of the National Association of Royalty Owners. See Tr. at 409:15-410:21 (Anderson, Sheridan).

126. Anderson's father, John Russell Anderson, who originally acquired the mineral interests that Anderson Trust currently holds, owned a company that built oil-and-gas gathering systems for large corporations such as El Pas Natural Gas Company and Pacific Northwest Pipeline. See Tr. at 400:12-402:25 (Anderson, Sheridan).

127. Based on the Court's in-person evaluation of Anderson during his testimony, Anderson appears competent and well-informed regarding the facts and the law governing this case.

128. Plaintiff Pritchett Living Trust ("Pritchett Trust") owns royalty interests burdening WPX Production's working interests in oil and natural gas production on leases in the New Mexico portion of the San Juan Basin. See Pritchett Trust Division Orders at 3-4 (Plaintiffs' Ex. 6); Pritchett Trust Check Stubs (Plaintiffs' Ex. 5).

129. Plaintiff Cynthia Sadler owns overriding royalty interests burdening WPX Production's working interests in natural gas production on leases in the New Mexico portion of the San Juan Basin, having received said interests from the Zela D. Wood Living Trust in 1993. See Title Chain for Cynthia W. Sadler Overriding Royalty Interest at 1 (Plaintiffs' Ex. 8).

130. Plaintiff Robert Westfall owns a royalty interest burdening WPX Production's working interests in natural gas production on leases in the New Mexico portion of the San Juan Basin, by virtue of mineral deeds that his father, Archie Westfall, acquired in 1952. See Tr. at 321:8-325:19 (Westfall, Aubrey); Robert Westfall WPX Check Stubs (Plaintiffs' Ex. 9).

131. Westfall is willing to serve as class representative and represent the interests of the class, as well as his own interests. See Tr. at 315:21-316:11 (Aubrey, Westfall).

132. Based on the Court's in-person evaluation of Westfall during his testimony, Westfall appears competent and well-informed regarding the facts and the law governing this case.

133. Plaintiff Lee Wiley Moncrief 1998 Trust ("Moncrief Trust") owns royalty interests burdening WPX Rocky Mountain's working interests in the Colorado portion of the San Juan Basin. See Moncrief Trust Check Stubs (Plaintiffs' Ex. 22).

134. Plaintiff Kelly Cox Testamentary Trust 7/1238401 ("Cox Trust") owns royalty interests burdening WPX Rocky Mountain's working interests in the Colorado portion of the San Juan Basin. See Cox Trust Check Stubbs (Plaintiffs' Ex. 14); Cox Trust Transfer Orders (Plaintiffs' Ex. 16).

135. Plaintiff Minnie Patton Scholarship Foundation Trust ("Patton Trust") owns royalty interests burdening WPX Rocky Mountain's working interests in the Colorado portion of the San Juan Basin. See Patton Trust Check Stubs (Plaintiffs' Ex. 25).

136. Bank of America, NA, is the Patton Trust's trustee. See Tr. at 184:16-17 (Brickell).

137. Rolando Munoz is the Bank of American representative in charge of managing the Patton Trust's oil-and-gas interests. See Munoz Depo. passim.

138. Munoz has fifteen years of experience in the oil-and-gas industry. See Oral Deposition of Rolando Munoz at 4:10:3-11:18 (taken January 23, 2014)(Plaintiffs' Ex. 276) (Munoz, Sheridan).11

139. Plaintiff SWMF Properties, Inc. ("SWMF Properties") owns royalty interests burdening WPX Rocky Mountain's working interests in the Colorado portion of the San Juan Basin. See SWMF Properties Check Stubs (Plaintiffs' Ex. 25).

140. All named Plaintiffs are within the proposed class definition, i.e., even if they were not named Plaintiffs, they would still qualify as class members. Cf. Stipulation ¶ 7, at 2.

141. The named Plaintiffs own a total of ninety-six wells, thirty-eight of which are in New Mexico and fifty-eight of which are in Colorado. See Emory Expert Report ¶ 22, at 13.

142. Nineteen of the ninety-six named-Plaintiff wells are coalbed methane, with fourteen located in New Mexico and five in Colorado. See Emory Expert Report ¶ 22, at 13.

143. Seventy-seven of the ninety-six named-Plaintiff wells are conventional wells, with twenty-four of them located in New Mexico and fifty-three in Colorado. See Emory Expert Report ¶ 22, at 13.

d. The Proposed Class Members.

144. Per the class definition, the proposed class members — a/k/a the absent Plaintiffs — are those individuals and entities, not otherwise excluded, who own wells operated by WPX Production and/or WPX Rocky Mountain in the San Juan Basin. See Motion at 3.

145. In addition to its interests in the approximately 500 private leases in which class members own royalty and overriding royalty interests, the Defendants also own working interests in 229 federal oil and gas leases and eighty-six state leases in the San Juan Basin. See Tr. at 836:17-837:9 (Terry, Sheridan).

146. The proposed class definition excludes federal leases and Indian-owned leases. See Motion at 3.

147. The proposed class definition also excludes interests encompassed by a pending class action in Colorado state court, Lindauer v. Williams Production RMT Co., No. 2006 CV 317 (Garfield Cnty., Colo.). See Motion at 3.

148. The exclusions result in 299 WPX Production-owned wells in the San Juan Basin being excluded from the class. Compare Emory Expert Report ¶ 22, at 13, and Stipulation ¶ 2, at 1, with Emory Expert Report ¶ 42, at 22.

149. The San Juan Basin covers the northwest corner of New Mexico and the southwest corner of Colorado. See Tr. at 78:19-79:3 (Reineke).

150. The proposed class definition covers approximately 3,157 wells, about 268 of which are in Colorado and roughly 2,889 of which are in New Mexico. See Emory Expert Report ¶ 22, at 13; Stipulation ¶ 2, at 1.

151. There is often more than one well on a lease. See Stipulation ¶ 2, at 1; id. ¶ 4, at 2. 152. The class definition covers 507 leases. See Stipulation ¶ 4, at 2.

153. A lease can have more than one royalty owner; there can be co-royalty owners and overriding royalty owners. See Stipulation ¶¶ 4, 6, at 2.

154. The class definition covers approximately 1,466 royalty interests and 909 overriding royalty interests. See Stipulation ¶ 6, at 2.

155. There are, thus, over 2,300 members of the class. See Stipulation ¶ 6, at 2.

156. Of the 3,157 class wells, 1,481 of them are coalbed methane wells, and 1,676 of them are conventional wells.12 See Emory Expert Report ¶ 22, at 13; Tr. at 79:21-23 (Reineke).

157. Of the 1,481 class coalbed methane wells, ninety-three of them are in Colorado and 1,388 of them are in New Mexico. See Emory Expert Report ¶ 22, at 13; Tr. at 79:21-23 (Reineke).

158. Of the ninety-three class coalbed methane wells in Colorado, 32 of them deliver their gas to the Williams Four Corners gathering system, and sixty-one of them deliver their gas to an independent, third-party gathering system. See Tr. at 79:24-80:2 (Reineke).

159. Of the 1,388 class coalbed methane wells in New Mexico, 816 of them deliver their gas to the Williams Four Corners gathering system, and 572 of them deliver their gas to an independent, third-party gathering system. See Tr. at 80:3-7 (Reineke). See also Expert Report of Barbara Ley at 10 (Plaintiffs' Ex. 195).

160. Of the 1,676 conventional class wells, 1,501 of them are in New Mexico, and 175 of them are in Colorado. See Emory Expert Report ¶ 22, at 13.

161. Of all 3,456 wells in which the Defendants own the working interest,13 2,582 of them, or 74.7%, are gathered by Williams Four Corners. See Emory Expert Report ¶ 42, at 22.

e. Independent Entities.

162. Enterprise San Juan Gathering ("Enterprise") is an independent, third-party gathering company, unrelated to the WPX affiliates. See Emory Expert Report ¶ 42, at 22.

163. Independent entities operate the gathering systems that control a number of class well gathering contracts, including Burlington 3816, Red Cedar 2584, BP 100274-A6, BP 1002474, Red Cedar 07-300, Cedar Hill 183085, Decker 148473, Burlington 3854, and Elm Ridge. See Emory Expert Report ¶ 42, at 22.

3. The Process: Natural Gas Extraction, Gathering, Processing, Transfer, and Sale.

164. Raw natural gas exiting the wellhead contains substances such as NGLs, water, carbon dioxide, nitrogen, and other contaminants, some of which must be separated before the gas is suitable for insertion into a pipeline. See Expert Report of Daniel Reineke at 2 (Plaintiffs' Ex. 196).

165. Raw natural gas is typically not of sufficient quality to be placed into an interstate pipeline; it must first be treated for removal of at least carbon dioxide, and usually water vapor and NGLs. See Tr. at 101:11-13 (Reineke).

166. All gas produced from class wells is either coalbed methane or conventional gas; none of the class wells are oil wells, and thus none of the gas is casinghead gas. See Tr. at 249:13-250:1 (Brickell, Kaplin); Stipulation ¶ 1, at 1.

167. As working-interest owner on the class leases, WPX Production and WPX Rocky Mountain — in New Mexico and Colorado, respectively — and their predecessors own title to all natural gas and NGLs as they come out of the ground. See Tr. at 95:2-25 (Reineke, Brickell). But see note 9, supra.

168. The gas is run through a separator, which removes the liquid water and NGLs. See Tr. at 96:12-20 (Reineke).

169. No gaseous-phase natural gas from the class wells — during any time period — was sold at arm's length from the wellhead; all of it goes into a gathering system. See Tr. at 86:6-10 (Brickell, Reineke).

170. Some NGLs condense at the wellhead; these are known as well condensate. See Tr. at 440:25-441:4 (Sutphin, Ward).

171. Not all of the class wells produce well condensate; coalbed methane wells, for example, never do. See Stipulation at 3 n.4.

172. For "several years," the Defendants have sold their well condensate to an independent party — currently Western Refining, and, before that, a company called "Gavalon."14 Tr. at 441:5-442:7 (Sutphin, Ward). See WPX Party Transaction Report (Defendants' Ex. 139).

173. After liquids are separated from the gas, the gas is transmitted from the wellhead to a gathering system — which, as explained earlier, is an affiliate company for some leases and an independent, third-party gatherer for others, depending purely upon location — and is metered before it leaves the lease. See Reineke Expert Report at 3.

174. No liquid — meaning free liquid, not entrained NGLs or water vapor — flows through the meter. See Tr. at 96:21-97:12 (Brickell, Reineke).

175. Metering establishes the volume of gas that the lease produces — measured in MCFs — its thermo-energetic potential — measured in MMBtus — and its NGL content — measured in GPM — as well as the carbon-dioxide content. See Emory Expert Report ¶ 28, at 15; id. ¶¶ 34-35, at 18-19; id. ¶¶ 36-37, at 19-20.

176. The meter uses ordinary mechanical mechanisms — not fundamentally unlike water meters outside a home — to measure the natural gas' volume, and gas chromatography to measure its energetic content. See generally Gas Meter, Wikipedia.org, en.wikipedia.org/wiki/Gas_meter.

177. Gas chromatography is an analytical chemical technique whereby the natural gas mixture is placed into a column filled with an inert carrier gas, and a liquid or polymer "stationary phase" coating the column's walls; the different chemical compounds in the natural gas elute — i.e., travel from one end of the column to the other — at different speeds, which correspond to their level of interaction with the stationary phase, and the various "retention times" of the different chemicals in the gas indicate the chemical identity of each compound in the gas. See, e.g., Gas Chromatography, Wake Forest University Department of Chemistry, available at http://www.wfu.edu/chemistry/courses/organic/GC/index.html. See generally Gas Chromatography, Wikipedia.org, available at en.wikipedia.org/wiki/Gas_chromatography.

178. Once each compound — and its proportion in the gas by weight and volume — is determined, the known energetic properties of each compound are multiplied by that compound's proportional presence in the gas, and the overall thermo-energetic potential of the gas is determined. See Gas Chromatography, Wake Forest University Department of Chemistry; Gas Chromatography, Wikipedia.org.

179. This metering thus makes it possible to determine the potential production value attributable to each individual lease.

180. On leases that contain free-use clauses, the working interest owner siphons off lease-use gas before metering the gas and uses it to power pumping units, heaters, and other machinery on the lease. See Tr. at 148:14-20 (Reineke).

181. The amount of gas used on a lease is typically not metered. See Tr. at 148:20-21 (Reineke).

182. In the gathering system, the natural gas — which, at this point, is still impure and not in marketable condition — is comingled with gas from other leases. See Reineke Expert Report at 4.

183. Gas is then transmitted through the gathering system — which is a network of relatively low-pressure pipes — to one of several processing or treatment plants. See Tr. at 97:19-98:2 (Reineke); See Reineke Expert Report at 4.

184. The gas is compressed in the gathering system by compressors that use a small portion of the natural gas in the lines as fuel. See Tr. at 100:12-23 (Brickell, Reineke).

185. On the way into the processing or treatment plant, the gas is first dehydrated — i.e., the water vapor is removed — and compressed to a higher pressure. See Tr. at 99:21-100:4 (Reineke).

186. Coalbed methane wells — for the most part, but not entirely — flow to the Milagro treatment plant, not to one of the processing plants, because coalbed methane lacks NGLs to extract but it does need to have carbon dioxide removed from it before being placed into the interstate pipeline system. See Tr. at 105:6-106:6 (Brickell, Reineke).

187. Conventional gas wells — for the most part, but not entirely — flow to processing plants, because conventional gas has NGLs that can be removed and sold for a greater value than the value they add to the gas as entrained NGLs, which increase the gas' Btu factor. See Tr. at 105:6-106:6 (Brickell, Reineke).

188. At a processing plant, the gas is cleaned of impurities, and any NGLs that are still entrained in the gas — i.e., those NGLs that did not condense naturally at the wellhead as well condensate or in the gathering system as drip condensate — are removed. Cf. Tr. at 619:15-20 (Emory, Brickell).

189. Processing does not create new NGLs, nor does it change their constituency — i.e., the proportion of the NGLs that are propane, butane, pentane, et cetera; it merely extracts them from the gas in which they were entrained. See note 34, infra.

190. NGLs removed during processing are sent to a fractionator and separated — or "fractionated" — into their constituent compounds. See Tr. at 104:6-21 (Reineke, Brickell).

191. The fractionated NGLs are then sold — at arm's length during some time periods and to a corporate affiliate during others. See Tr. at 104:6-21 (Reineke, Brickell).

192. At a treatment plant, the gas is cleaned and impurities are removed, and the resultant, marketable gas is pressurized and put into the interstate pipeline system. See Tr. at 619:15-20 (Emory, Brickell).

193. The only process always undergone at a treatment plant is the removal of carbon dioxide, which can cause freezing issues in piping; water vapor may or may not be removed in treatment. See Emory Expert Report ¶ 39, at 21.

194. The residue gas is then pressurized and placed into the interstate pipeline system. See Tr. at 100:5-9 (Reineke).

195. The point at which residue gas is placed into the interstate pipeline system is the point of the first arm's-length sale. See Tr. at 101:9-102:1 (Reineke).

196. When the title holder of residue gas contracts to sell a quantity of natural gas to a consumer across the country, the title holder does not place a quantity of gas into the pipeline and have the consumer wait for those specific molecules to make their way across the country; rather, the title holder places a certain number of MMBtus of residue gas into the pipeline, and the consumer takes an equivalent number of MMBtus out of it, and that is considered a transfer of natural gas, even though the actual molecules put in the pipeline are not the same ones removed. See Tr. at 101:9-102:1 (Reineke).

197. Pipeline-quality residue gas is, thus, fungible — only its volume, in MCFs, and energy content, in MMBtus, determines its value; it is not otherwise qualitatively different from other pipeline-quality residue gas. See Tr. at 101:9-102:1 (Reineke).

198. Williams Four Corners owns four plants to which class wells flow: the Lybrook processing plant, the Kutz processing plant, the Ignacio processing plant, and the Milagro treatment plant. See Tr. at 98:10-11 (Reineke); id. at 98:20-24 (Brickell, Reineke).

199. Williams Four Corners also owns the gathering lines connecting the class wells to those four plants. See Tr. at 98:25-99:1 (Brickell, Reineke).

200. Some class wells also flow to the Cedar Hill plant and the Florida River plant — both of which BP owns — and the Chaco plant and the Val Verde plant — both of which Enterprise owns. See PWM Master Well Completion Data (Defendants' Ex. 168).

201. The NGL recovery rate of each plant is different. See Emory Expert Report ¶¶ 39-40, at 21-22.

202. The operational costs and efficiency of each plant is different, and changes over time. See Tr. at 566:11-567:8 (Sutphin, Emory).

203. Not all gas that goes to a processing or treatment plant is processed or treated; some can be "bypassed" around processing or treatment and then blended with processed or treated gas in proportions that ensure that the final mixture is of pipeline quality. Emory Expert Report ¶ 41, at 22.

204. Some NGLs condense in the gathering system; these are known as drip condensate. See Tr. at 123:4-19 (Reineke).

205. The drip condensate is collected from the gathering system periodically and sold. See Tr. at 123:4-19 (Reineke).

206. Drip condensate is sold at oil prices. See Tr. at 123:4-9 (Reineke).

207. Only conventional gas, not coalbed methane, yields drip condensate, as coalbed methane is dry gas, i.e., it does not contain NGLs. See Tr. at 128:1-6 (Brickell, Reineke).

208. When the natural gas changes hands among WPX affiliates, no money changes hands; the transactions are essentially treated the same as an intra-company, inter-division transfer would be. See Tr. at 164:25-165:20 (Ley, Brickell).

209. Royalty owners have no decision-making authority with regard to what happens to hydrocarbons once they are removed from the wellhead; the working interest owner has sole authority to transport, process, and dispose of them. See Tr. at 95:16-96:3 (Brickell, Reineke).

210. The Court will now outline the process by which the title to the class' gas changed hands among WPX affiliates at various stages of the class time period for wells in the New Mexico on the Williams Four Corners gathering system.15

a. The Process from 1988 to 1995, i.e., Who Held Title on the Natural Gas at Each Stage.

211. From 1988 to 1995, Williams Production Co. was the lessee on the class leases, meaning that it held title to all natural gas produced at the wellhead. See Tr. at 85:11-86:1 (Brickell, Reineke)(referring to Plaintiffs' Demonstrative Ex. 5).

212. Williams Production Co. would transfer title to the natural gas to Williams Gas Marketing as it transferred physical possession of the gas to an affiliate gathering company, known as Northwest Pipeline until 1992, and Williams Field Services thereafter. See Tr. at 85:11-86:1 (Brickell, Reineke)(referring to Plaintiffs' Demonstrative Ex. 5).

213. During this time period, the class wells were each subject to one of six gathering contracts: J38, J99, U99, 114, 129, and K82. See Tr. at 86:17-24 (Brickell, Reineke).

214. The J99 contract covered wells connected to the Williams Four Corners gathering system. See Ley Expert Report at 10.

215. Williams Gas Marketing would then sell the gas at arm's length after the gathering affiliate finished processing it. See Tr. at 85:11-86:1 (Brickell, Reineke)(referring to Plaintiffs' Demonstrative Ex. 5).

b. The Process from 1995 to August, 2010.

216. From 1995 to 2010, Williams Production Co. and its post-1998 successor, Williams Production LLC, were the lessees on the class leases, meaning that they held title to all natural gas produced at the wellhead. See Tr. at 87:2-14 (Reineke)(referring to Plaintiffs' Demonstrative Ex. 6).

217. The lessee would transfer title to the natural gas to WFS Gas Resources as it transferred physical possession of the gas to an affiliate gathering company, Williams Field Services. See Tr. at 87:2-14 (Reineke).

218. The same five gathering contracts that existed from 1988 to 1995 continued to govern the class wells during this period, and J99 continued to govern all wells on the Williams Four Corners gathering system. See Tr. at 87:2-88:5 (Reineke, Brickell)(referring to Plaintiffs' Demonstrative Ex. 6).

219. After Williams Field Services finished processing the gas, WFS Gas Resources would then transfer title to the residue gas to Williams Gas Marketing and title to the processed NGLs to Williams Power. See Tr. at 87:2-88:5 (Brickell, Reineke)(referring to Plaintiffs' Demonstrative Ex. 6).

220. Williams Gas Marketing and Williams Power would then sell their respective products to arm's-length buyers. See Tr. at 87:2-88:5 (Brickell, Reineke)(referring to Plaintiffs' Demonstrative Ex. 6).

c. The Process from August, 2010, to July, 2011.

221. From August, 2010, to July, 2011, Williams Production LLC was the lessee on the class leases, meaning that it held title to all natural gas produced at the wellhead. See Tr. at 88:6-12 (Brickell, Reineke)(referring to Plaintiffs' Demonstrative Ex. 7).

222. The lessee would transfer title to the natural gas to WPX Gas Resources as it transferred physical possession of the gas to an affiliate gathering company. See Tr. at 88:6-20 (Brickell, Reineke)(referring to Plaintiffs' Demonstrative Ex. 7).

223. In 2011, in preparation for the upcoming spinoff of various WPX affiliates, a new set of gathering contracts were executed. See Tr. at 88:6-20 (Brickell, Reineke)(referring to Plaintiffs' Demonstrative Ex. 7).

224. Gathering agreement J99M replaced J99 and U99, and gathering agreement 170 replaced agreements 114, 129, and K82. See Tr. at 88:9-89:4 (Brickell, Reineke)(referring to Plaintiffs' Demonstrative Ex. 7).

225. These new gathering agreements run for a term of eleven-and-a-half years — from July, 2011, to December, 2022 — and, despite being executed before the spinoff, continue to bind the spunoff companies. See Tr. at 88:6-89:4 (Brickell, Reineke).

226. Transactions under the new gathering agreements are, thus, affiliate, non-arm's length transactions, because at the time they were executed, all parties to them were corporate affiliates. See Tr. at 91:16-92:19 (Brickell, Reineke).

227. After processing, WPX Gas Resources would transfer title to the gas and NGLs to Williams Gas Marketing, which would then sell the gas at arm's length. See Tr. at 88:6-20 (Brickell, Reineke)(referring to Plaintiffs' Demonstrative Ex. 7).

4. The Language in the Class Leases: The Breakdown of Textual Royalty Formulations.

228. The class leases were executed in the 1940s and early 1950s, and, in all known instances, the original lessors and the original lessee representatives — the original lessees on these leases was not WPX Production — are unavailable. See Expert Report of James Griffin ¶ 6, at 3-4 (Defendants' Ex. 135).

229. The leases were executed under competitive conditions. See Griffin Expert Report ¶ 6, at 3-4.

230. The class leases typically distribute either one-eighth or, less commonly, three-sixteenths of the value of the gas — and the terminology used to convey the concept of the "value of the gas" is spelled out in different ways in different leases — to the royalty owner, leaving either seven-eighths or thirteen-sixteenths to the Defendant-lessee. See Tr. at 94:17-95:10 (Reineke); Tr. at 238:1-5 (Kaplin).

231. Every lease has a paragraph devoted to how royalty is to be computed and paid. See Tr. at 241:12-16 (McNamara, Kaplin).

232. The class leases provide that royalty is to be valued based on the following language: (i) "gross proceeds," without reference to being "at the well," "at the wellhead," or "at the mouth of the well"; (ii) "proceeds at the mouth of the well"; (iii) "proceeds on the sale of gas, as such"; (iv) "price" or "market price" "at the well"; (v) "net proceeds at the well"; (vi) "gross proceeds received when sold at the mouth of the well, market value if not sold at the mouth of the well"; (vii) "gross proceeds received for gas sold, used off the premises or in the manufacture of products therefrom, but in no event more than the actual amount received"; (viii) "proceeds if sold at the well, or if marketed off the premises, market value at the well"; (ix) "market value at the well of the gas sold or used, provided that on gas sold the market value shall not exceed the amount received for such gas computed at the mouth of the well"; (x) "market value at the well if sold or used to manufacture products; on gas sold at the well, net proceeds realized; each after deduction of post-production costs"; and (xi) "market value at the well of the gas sold or used, provided that on gas sold the market value shall not exceed the amount received for such gas computed at the mouth of the well."16 Lease Language Chart (Defendants' Ex. 191).

233. Textual formulations (i), (ii), (iii), (iv), and (v) are "single-prong" royalty provisions, meaning that they pay the same regardless whether the gas is sold at the wellhead or off-site. Lease Language Chart (Defendants' Ex. 191).

234. Textual formulations (vi) through (xi) are "two-pronged" royalty provisions, meaning that they describe the value upon which royalty is to be paid in different terms, depending upon whether the gas is sold at the wellhead or off-site. Tr. at 793:6-794:8 (Sheridan, Terry); id. at 799:15-800:5 (Sheridan, Terry).

235. Fifty-five of the leases containing textual formulation (iii) — thirty-one of which are in Colorado and twenty-four of which are in New Mexico — contain specific, separate royalty provisions relating to casinghead gas, which the class wells, being gas wells, do not produce. See Lease Language Chart (Defendants' Ex. 191).

236. Some of the leases that refer to royalty being paid on the basis of "market value" also refer to paying on the "amount realized from such sales," but the Court cannot determine how many.17

237. The majority of the leases are form contracts — with Form 88-42 from the Kansas Blueprint Company being among the most common — altered only to include the relevant individual information — the parties' names, the location of the lease, et cetera — and are therefore textually identical within their respective textual-formulation categories. See Tr. at 239:8-18 (McNamara, Kaplin). See generally Spreadsheet of Lease Language (Plaintiffs' Ex. 428)(categorizing each lease by its form number).

238. The form contracts are identifiable — i.e., they are identifiable as being form contracts, and their corporate author and model number are identifiable — by numbers stamped on the leases, typically in the top corners. See Tr. at 241:18-242:2 (McNamara, Kaplin).

239. None of the leases expressly provide for payment on the basis of a WASP or an index price. See Tr. at 112:13-15 (Brickell, Reineke); id. at 259:9-18 (McNamara, Kaplin); Lease Language Chart (Defendants' Ex. 191).

240. The class leases contain "free use clauses" that allow the working interest owner to use gas on the lease free of charge, i.e., without paying a royalty on the gas used.18 Tr. at 148:7-149:1 (Sheridan, Reineke). See Tr. at 326:1-327:24 (Westfall, Sutphin); Selected Lease (Defendants' Ex. 7).

241. Some of the leases use two different royalty terms — e.g., "proceeds" versus "market value" — to described royalties owed on gas sold from the well and those owed on gas sold off the leased premises; these leases are referred to as "double-pronged" or "two-pronged" leases, while leases that use a single royalty term for gas are "single-pronged" or "one-pronged" leases.19 Lease Language Chart (Defendants' Ex. 191).

242. Of the 507 total class leases, 224 are single-pronged, and 256 are double-pronged; twenty-seven are illegible as to their royalty provisions. See Lease Language Chart (Defendants' Ex. 191).

243. Of the 480 leases with legible royalty provisions, 381 are in Colorado, and ninety-nine are in New Mexico. See Lease Language Chart (Defendants' Ex. 191).

a. The Royalty-Provision Breakdown of the New Mexico Leases.

244. Sixty-eight of the ninety-nine total New Mexico leases are single-pronged, and thirty-one are double-pronged. See Lease Language Chart (Defendants' Ex. 191).

245. Sixty-seven of the sixty-eight double-pronged New Mexico leases pay based on "proceeds on the sale of gas, as such" and the other lease pays on the basis of "net proceeds at the well." Lease Language Chart (Defendants' Ex. 191).

246. Twenty-four of the thirty-one double-pronged New Mexico leases pay on the basis of "proceeds if sold at the well, or if marketed off the premises, market value at the well." Lease Language Chart (Defendants' Ex. 191).

247. Six of the thirty-one double-pronged New Mexico leases pay on the basis of "gross proceeds for gas used off the premises" and, "if used in the manufacture of gasoline, prevailing market rate." Lease Language Chart (Defendants' Ex. 191).

248. One of the thirty-one double-pronged New Mexico leases pays on the basis of "market value at the well of the gas sold or used, provided that on gas sold the market value shall not exceed the amount received for such gas computed as the mouth of the well." Lease Language Chart (Defendants' Ex. 191).

b. The Royalty-Provision Breakdown of the Colorado Leases.

249. One-hundred fifty-six of the 381 total Colorado leases are single-pronged and 225 are double-pronged. See Lease Language Chart (Defendants' Ex. 191).

250. One-hundred forty-three of the 156 total single-pronged Colorado leases pay on the basis of "proceeds on the sale of gas, as such." Lease Language Chart (Defendants' Ex. 191).

251. Eight of the 156 total single-pronged Colorado leases pay on the basis of "proceeds at the mouth of the well." Lease Language Chart (Defendants' Ex. 191).

252. Four of the 156 total single-pronged Colorado leases pay on the basis of "price [or market price] at the well." Lease Language Chart (Defendants' Ex. 191).

253. One of the 156 total single-pronged Colorado leases pays on the basis of "gross proceeds," without reference to the mouth of the well. Lease Language Chart (Defendants' Ex. 191).

254. Eighty-five of the 156 total double-pronged Colorado leases pay on the basis of "proceeds if sold at the well, or if marketed off the premises, market value at the well." Lease Language Chart (Defendants' Ex. 191).

255. Seventy-five of the 156 total double-pronged Colorado leases pay on the basis of "market value at the well of the gas sold or used, provided that on gas sold the market value shall not exceed the amount received for such gas computed at the mouth of the well." Lease Language Chart (Defendants' Ex. 191).

256. Thirty-four of the 156 total double-pronged Colorado leases pay on the basis of "gross proceeds received for gas sold, used off the premises or in the manufacture of products therefrom, but in no event more than the actual amount received." Lease Language Chart (Defendants' Ex. 191).

257. Twenty-three of the 156 total double-pronged Colorado leases pay on the basis of "market value at the well if sold or used to manufacture products; on gas sold at the well, net proceeds realized; each after deduction of post-production costs." See Lease Language Chart (Defendants' Ex. 191).

258. These 23 leases are the only leases to disclaim or negate Colorado's marketable-condition rule. See Lease Language Chart (Defendants' Ex. 191).

259. Five of the 156 total double-pronged Colorado leases pay on the basis of "gross proceeds for gas used off the premises. If used in the manufacture of gasoline, prevailing market rate." Lease Language Chart (Defendants' Ex. 191).

260. Three of the 156 total double-pronged Colorado leases pay on the basis of "gross proceeds received when sold at the mouth of the well, market value if not sold at the mouth of the well." Lease Language Chart (Defendants' Ex. 191).

c. The Named Plaintiffs' Royalty Provisions.

261. Anderson Trust is the royalty owner of a lease that pays royalty on "gross proceeds . . . for the gas from each well where gas only is found . . . and if used in the manufacture of gasoline," royalties are to be paid "at the prevailing market rate for gas." Selected Lease at 1 (Defendants' Ex. 4).

262. The Anderson Trust also has overriding royalty interests paid on the "value [of gas] on the leased premises or, if marketed, of the proceeds derived from the sale, at the well or wells." Selected Assignment (Defendants' Ex. 25).

263. Westfall is a royalty owner in a lease that pays royalty on the basis of "proceeds from the sale of the gas, as such, for gas from wells where gas only is found." For "gas produced from any oil well and used by the lessee for the manufacture of gasoline or any other product," royalties are to be paid on "the market value of such gas at the mouth of the well." If the gas used to manufacture gasoline is sold by the lessee, royalties are to be paid on "the proceeds of the sale contract." Selected Lease at 2 (Defendants' Ex. 7).

264. The Patton Trust is a royalty owner in a lease that pays royalty on "the market value at the well . . . of the gas sold or used, provided that on gas sold at the wells the royalty shall be one-eighth of the amount realized." Selected Lease at 1 (Defendants' Ex. 13).

d. The Meanings of the Varying Language in the Leases.

265. As a matter of oil-and-gas industry custom and usage, "proceeds" and "gross proceeds" mean the same thing. Tr. at 247:7-248:16 (McNamara, Kaplin).

266. In the oil-and-gas industry, "proceeds" and "amount realized" mean the same thing. Tr. at 816:9-14 (Sheridan, Terry).

267. In the oil-and-gas industry, the term "gas used in the manufacture of gasoline or other product therefrom" refers to the volume of gas that is converted from the gaseous state into a liquid state through plant processing. Tr. at 787:4-20 (Terry, Sheridan); id. at 795:9-796:22 (Terry, Sheridan).

268. In the oil-and-gas industry, the terms "proceeds" and "market value" do not necessarily mean the same thing. See Tr. at 794:9-795:8 (Terry, Sheridan); id. at 816:3-817:12 (Terry, Sheridan).

269. In the oil-and-gas industry, "proceeds" refers to the amount of money realized by the lessee from the sale of gas. Tr. at 794:9-795:8 (Terry, Sheridan); id. at 816:3-817:12 (Terry, Sheridan).

270. In the oil-and-gas industry, "market value" or "prevailing market rate" refers to the price received, not by any one lessee, but by other lessees from the sale of gas of similar quality, in the same location, taking into account pressure, marketing outlets and other market factors. See Tr. at 794:9-795:8 (Terry, Sheridan); id. at 816:3-817:12 (Terry, Sheridan).

271. The market value of gas may be calculated independently of proceeds, and may be greater or less than the proceeds from sale of gas depending upon particular contract prices and changes in the market for the sale and purchase of gas. See Tr. at 794:9-795:8 (Terry, Sheridan); id. at 816:3-817:12 (Terry, Sheridan).

272. In some quarters of the oil-and-gas industry, royalty has been paid differently depending on whether it is payable on market value or proceeds. See Tr. at 817:13-16 (Terry, Sheridan).

273. The Defendants, however, used a uniform methodology to pay royalty to lessors with varying lease languages. See Stipulation ¶ 9, at 2-3; Deposition of Julie Mathis at 32:21-33:12 (taken December 6, 2013)(Plaintiffs' Ex. 52)(Brickell, Mathis); Kaplin Expert Report at 4-5.

274. In some quarters of the oil-and-gas industry, when used in a royalty clause, the term "at the well" or "at the mouth of the well," refers to the location and the condition of gas for purposes of royalty valuation, that is, at the well or on the lease, and not at a downstream sales point. See Tr. at 788:2-20 (Terry, Sheridan).

275. In some quarters of the oil-and-gas industry, the term "as such," when used with reference to royalty based on "proceeds derived from the sale of gas, as such," means from the sale of the gas in the condition that it is as it emerges from the well. See Tr. at 780:11-23 (Terry, Sheridan).

276. As most oil-and-gas leases were executed many decades ago, the industry's usage of these terms has largely developed after the leases in this case were executed. See Griffin Expert Report ¶ 6, at 3-4. Cf. Tr. at 114:24-115:10 (Brickell, Reineke)(noting that the federal government used to set gas prices).

277. The oil-and-gas industry has a self-evident incentive to develop trade usages for lease terms that are more favorable to the lessee than the lessor.

278. Often, including in this case, the lessor of an oil-and-gas lease is not someone within — or someone familiar with the trade usage of — the oil-and-gas industry. See Owen L. Anderson, Royalty Valuation: Should Royalty Obligations Be Determined Intrinsically, Theoretically, or Realistically?, 37 Nat. Resources J. 611, 611-12 (1997)("[S]eldom [could a] lessor engaged in the oil and gas business . . . be regarded as a `merchant' knowledgeable about oil and gas production and marketing practices. Typically, the lessor is a farmer or a laborer, someone engaged in an unrelated business or profession, or a retired person."). Cf. Tr. at 298:25-299:5 (Aubrey, Westfall)(describing himself as a retired owner of a small business that sells school and office supplies); Tr. at 358:19-359:1 (Branch, Anderson)(describing himself as a self-employed architectural designer).

279. The leases are, in virtually all, if not all, cases, form contracts, and are not the product of meaningful negotiation of any term except the magnitude of the fractional royalty share. See Tr. at 239:8-18 (McNamara, Kaplin); Anderson, supra, at 612 ("Regarding the lease royalty clause, about the only item negotiated may be the fraction or percentage of royalty.").

280. The magnitude of the royalty — e.g., one-eighth versus three-sixteenths — is sometimes negotiated between the parties. See Tr. at 802:24-806:1 (Terry, Sheridan)(discussing Selected Leases at 313 (Plaintiffs' Ex. 427)); Tr. at 806:2-25 (Terry, Sheridan)(discussing Selected Leases at 451 (Plaintiffs' Ex. 427D)); Tr. at 807:7-809:11 (Terry, Sheridan)(discussing Selected Leases at 211 (Plaintiffs' Ex. 427E)); Tr. at 809:12-810:22 (Terry, Sheridan)(discussing Selected Leases at 80 (Plaintiffs' Ex. 427E)); Tr. at 810:23-812:17 (Terry, Sheridan)(discussing Selected Leases at 293 (Plaintiffs' Ex. 427D)); Tr. at 812:18-813:16 (Terry, Sheridan)(discussing Selected Leases at 72 (Plaintiffs' Ex. 427D)).

281. Approximately forty of the class leases show signs of alteration from the standard form, i.e., were subject to individualized negotiation. See Tr. at 814:17-20 (Terry).

282. The federal government provides detailed instructions about how working interest owners must pay royalty interests — i.e., what costs can be deducted, how value must be calculated, et cetera — on land it owns and that Indian tribes own. See generally 30 C.F.R. § 1206 (titled "product valuation," and containing subparts on "Indian oil," "federal oil," "federal gas," and "Indian gas").

283. Some private leases have effectively adopted the federal regulations by including "same as fed" clauses in their leases. Tr. at 207:5-18 (Sheridan, Ley).

284. There do not appear to be any "same as fed" royalty provisions among the class, although there are some "same as fed" overriding royalties. See Tr. at 207:19-21 (Sheridan, Ley).

285. The Defendants operate many wells on federally owned land, and, when paying those royalties, they typically pay on the sale value of the NGLs rather than on a keep-whole basis. See Miller Depo. at 42:12-43:4 (Brickell, Miller).

286. For federal leases on the J99M gathering contract, however, the Defendants have, since 2011, begun paying federal royalty on the same keep-whole basis that they have paid the private lessors — i.e., the class — throughout the class time period. See Tr. at 520:13-521:10 (Sutphin, Miller).

287. The Defendants used to pay their federal government royalties in the same manner they pay the class — the keep-whole methodology — but a federal audit in the mid-1990s forced the Defendants to change. See Tr. at 215:5-219:14 (Brickell, Ley)(reviewing Miller Depo. at 42:12-45:20 (Brickell, Miller)).

5. The Overriding Royalty Interests.

288. Overriding royalty interests are common in New Mexico where there are numerous federal and state oil-and-gas leases. See Tr. at 830:14-24 (Terry, Sheridan).

289. Overriding royalty interests typically are created by reservations or grants contained in assignments of oil-and-gas leases. See Tr. at 830:6-13 (Terry, Sheridan).

290. Overriding royalty interests can be created a number of ways, many of which are situation-specific. See Tr. at 230:9-12 (Kaplin).

291. One common way overriding royalty interests are created is that a non-landowner will aggregate plots of land from numerous landowners and lease them to an oil company, and cut an overriding interest for itself as, effectively, payment for the aggregation. See Tr. at 229:21-230:1 (Kaplin).

292. Another common way overriding royalty interests are created is that a working interest owner on a lease will want to drill another well on a lease, but, lacking the resources to do so itself, will "farm it out to a third party and tack an override on it." Tr. at 230:3-8 (Kaplin).

293. A third common way an override can be created is that a royalty owner will assign their lease to a new lessor — or sell their land — and reserve an overriding royalty in the lease. See Tr. at 230:13-20 (McNamara, Kaplin).

294. Overriding interests can also be conveyed to, e.g., consulting geologists who assist a prospective producer, as a form of payment. See Tr. at 230:21-231:4 (McNamara, Kaplin).

295. Overriding royalty interests generally are not created through the use of form contracts. See Tr. at 830:25-831:7 (Terry, Sheridan).

296. Overriding royalty interests often are created in individualized circumstances and business transactions, and the agreements contain unique royalty valuation terms. See Tr. at 832:7-16 (Terry, Sheridan).

297. There are a wide variety of express terms among the class members' overriding royalty agreements, and there is no standardization in the overriding royalty interest terms. See Defendants' Exhibit 196; Tr. at 835:5-836:6 (Terry, Sheridan).

298. Overriding royalty instruments are "not generic like leases are," and the terms of each individual overriding royalty instrument are "unique." Tr. at 230:21-230:4 (Kaplin, McNamara)("The terms on [overriding royalties are] kind of unique.").

299. Overriding royalty instruments are "individualized agreements," and all of them are "a little bit different" from one another. Tr. at 257:10-18 (Kaplin, McNamara).

300. The Court has a list of some of the textual provisions found in the class overriding royalties, see Overriding Royalty Language Used in Various Assignments at 1-12 (Defendants' Ex. 196), the list contains far more textual permutations than the eleven that exist for royalty interests, and even that list is illustrative, not exhaustive, of all the overriding royalty provisions among the class, see Tr. at 832:3-16 (Sheridan, Terry)("I simply was trying to come up with what I believed were some examples of the type of instruments that are going to be at issue in this matter."); id. at 832:23-833:7 (Sheridan, Terry)("Did we pull every one? . . . [W]e didn't begin to get through all the files.").

301. The parties have been unable to locate many of the overriding royalty interests that the class definition would cover. See Tr. at 254:9-255:3 (McNamara, Kaplin).

302. Among the leases in Colorado in which class members own royalty and overriding royalty interests, there are leases that permit the deduction of post-production expenses in haec verba. See Tr. at 855:12-856:18 (Terry, Sheridan).

303. Overriding interests appear to entitle their owners to a smaller portion of the value of production than standard royalties do; overriding royalties exist for 0.25 percent and 2.5 percent. See Tr. at 267:12-18 (McNamara, Kaplin); id. at 268:10-15 (McNamara, Kaplin).

304. Like the royalty provisions, no overriding royalty instruments explicitly provide that the working interest owner is not required to pay royalty on NGLs. See Tr. at 268:16-21 (McNamara, Kaplin).

305. Assignments of overriding royalty interests in which class members acquired their interest subsequent to creation of the override offer contain assignment language that is inconsistent with the express terms of the instrument that created the override. See Tr. at 839:2-844:5 (Terry, Sheridan).

306. In addition to its interests in the approximately 500 private leases in which class members own royalty and overriding royalty interests, the Defendants also own working interests in 229 federal oil-and-gas leases and eighty-six state leases in the San Juan Basin. See Tr. at 836:17-837:9 (Terry, Sheridan); Database of WPX State and Federal Leases (Defendants' Ex. 200).

307. There are some "same as fed" overriding royalty interests in the class, but the Court does not know how many. See Tr. at 255:24-256:3 (McNamara, Kaplin).

308. There are also some overriding royalty interests that provide that payments be made on the same formula that the State of New Mexico uses — effectively making them "same as state" clauses. See Tr. at 255:17-23 (McNamara, Kaplin).

309. Overriding royalty interests that burden the Defendants' working interests in federal and state leases, do not necessarily provide for royalty on the same terms payable in the same manner as the royalty due the federal and state governments under such leases — except, of course, for the "same as fed" overriding royalties. See Tr. at 837:10-14 (Terry, Sheridan).

6. The Defendants' Royalty-Distribution System.

310. The Defendants use a different royalty-payment system for wells on their own gathering system, i.e., the Williams Four Corners gathering system, than the one they used for wells on an independent, third-party gathering system. See Tr. at 80:14-18 (Reineke).

311. The Defendants did not base royalties on — i.e., they did not vary their payouts to the class on the basis of — the individual leases' language. See Stipulation ¶ 9, at 2-3; Mathis Depo. at 32:21-33:12 (Brickell, Mathis); Kaplin Expert Report at 4-5.

312. The Defendants had a policy of reviewing leases only when the royalty owner for that lease makes a direct inquiry concerning his or her royalty payment. See Kaplin Expert Report at 5.

313. Even when royalty owners contacted the Defendants about their royalty, the Defendants did not ultimately adjust or individualize that royalty owner's payouts on the basis of his or her lease's language. See Tr. at 163:9-13 (Brickell, Ley); Kaplin Expert Report at 5.

314. The generally applicable master equation that the Defendants uses to determine royalty payouts is: Price • Quantity — Applicable Post-Production Deductions = Royalty Value. See Stipulation ¶ 10, at 3.

315. Before 2000, the "price" term was determined using a WASP; since 2000, it has been determined using an index price. See Tr. at 108:6-13 (Reineke);

316. The "quantity" term is determined using an MMBtu measurement at the wellhead as described above. Stipulation ¶ 13, at 3.

317. For Colorado wells, the "applicable post-production deductions" includes only taxes. See Stipulation ¶ 14, at 3.

318. For New Mexico wells, the "applicable post-production deductions" are described below. See Findings of Fact 366-384, Part 6d (Cost Deductions) supra.

a. Payments on NGLs, Including Drip Condensate.

319. The Defendants pay the class members' royalties on the basis of MMBtus at the wellhead, known as a keep-whole basis. See Stipulation ¶ 18, at 4; Tr. at 440:7-17 (Sutphin, Ward); Kaplin Expert Report at 6.

320. This practice of paying a per-MMBtu-at-the-wellhead royalty compensates the class members partially, but not fully, for the value of entrained NGLs. See Kaplin Expert Report at 6.

321. Gas with a higher NGL content has a higher MMBtu factor than gas with a low NGL content; thus, paying on the basis of MMBtus at the wellhead results in higher payments for wet gas — which will ultimately yield NGLs — than for the same volume of dry gas. See Aggregate Royalty Payments: Whole Stream Value Minus Keep Whole Value (Defendants' Ex. 149); Kaplin Expert Report at 6.

322. NGLs, however, are more valuable than a thermally equivalent quantity — i.e., an equal MMBtu amount — of natural gas, so this payment mechanism results in the class members being paid less than they would be if they were paid their royalty share of the sold NGLs and the residue natural gas separately. See Comparison of NGL and Residue Natural Gas Prices (Left Scale) and Relative Prices (Right Scale) (Defendants' Ex. 146)(graphing, over the time period 1994 to 2013, the price of NGLs, the price of San Juan Basin residue gas — i.e., the index price — and the difference between the two, in dollars per MMBtu);20 Aggregate Royalty Payments: Whole Stream Value Minus Keep Whole Value (Defendants' Ex. 149); Kaplin Expert Report at 6.

323. For example, consider a volume of gas A, which is dry gas and has 90 MMBtus of energy at the wellhead, and an identical volume of gas B, which is wet gas and has 120 MMBtus of energy at the wellhead. Gas B will, downstream of the wellhead, yield NGLs whose market value, when added to the market value of the residue — i.e., dry, post-processing — gas B, be worth greater than one-third more than gas A, despite that the gas B only had one-third more energy at the wellhead. The Defendants, however, only pay one-third more royalty for gas B than for gas A, effectively treating an MMBtu of natural gas as financially equivalent to an MMBtu of NGLs — even though the Defendants sell an MMBtu of NGLs for a higher price than they sell an MMBtu of natural gas.21

324. Unlike the Plaintiffs' issues with the WASP method — which, by definition, will pay out the appropriate total amount among all wells, even if it shorts some wells some months and overpays others — the Defendants' keep-whole methodology pays the class less overall than the whole stream methodology. See Aggregate Royalty Payments: Whole Stream Value Minus Keep Whole Value (Defendants' Ex. 149); Difference Between Whole Stream Value and Keep Whole Value (Defendants' Ex. 147).

325. If costs of NGL extraction are not passed on to the royalty owner, or if NGL extraction were costless, then the whole stream valuation method would always benefit royalty owners over the keep-whole method that the Defendants used. See Tr. at 705:8-23 (Brickell, Griffin); Difference Between Whole Stream Value and Keep Whole Value (Defendants' Ex. 147).

326. When NGL extractions — i.e., processing — costs are passed on to the royalty owner, however, a great number of the class wells — but not the majority — would get a higher royalty from the keep-whole methodology. See Aggregate Royalty Payments: Whole Stream Value Minus Keep Whole Value (Defendants' Ex. 149)(presenting data, that the Defendants' expert compiled, indicating that over the period from 1985 to present, fifty-two wells of a 100-well sample22 would have benefitted from whole stream methodology, while forty-eight wells of the sample benefitted from the use of keep-whole methodology).

327. That being said, the whole-stream approach — as the Defendants' expert, Dr. James Griffin defines it — does not pay royalty on drip condensate, see Tr. at 685:6-12 (Sutphin, Griffin), and it is not, in fact, the royalty-calculation methodology to which the Plaintiffs contend they are entitled, see Tr. at 705:25-706:6 (Brickell)("[W]e're not asking for a whole stream approach."). See also note 8, supra (describing how Dr. Griffin apparently invented the whole stream valuation method, and suggesting that it may be a strawman methodology).

328. The Defendants do not pay royalties on drip condensate — except to the extent that, when what will become drip condensate is entrained in the gas at the wellhead, it causes the gas to have a higher MMBtu factor. See Deposition of Sheryl Ward at 201:14-202:2 (taken March 1, 2013)(Plaintiffs' Ex. 29)(Brickell, Ward)("I'm not aware of any payments for drip condensate.").

329. The Defendants do not pay royalties on processed NGLs — except to the extent that, when what will become drip condensate is entrained in the gas at the wellhead, it causes the gas to have a higher MMBtu factor. See Stipulation ¶ 18, at 4; Tr. at 440:7-17 (Sutphin, Ward); Kaplin Expert Report at 6.

330. The industry practice regarding paying lessors for the value of drip condensate is in a state of flux. See Tr. at 195:1-10 (Brickell, Ley); id. at 858:15-24 (Sheridan, Terry); id. at 858:24-859:11 (Sheridan, Terry); Kaplin Expert Report at 3.

331. ConocoPhillips also has working interests in the San Juan Basin, and pays its burdening royalty owners for both gas proceeds and NGL proceeds. See Kaplin Expert Report at 3.

332. For example, Westfall, who owns royalties burdening ConocoPhillips as well as WPX Production, receives over fifty percent more per MMBtu from ConocoPhillips than he does from WPX Production. See Tr. at 195:1-10 (Brickell, Ley).

333. Enterprise has gathering contracts that provide that it — Enterprise, rather than the well-lessors — gets to keep the full value of all drip condensate recovered. See Tr. at 858:15-24 (Sheridan, Terry).

334. Arrangements such as Enterprise's "ha[ve] become more common over time." Tr. at 858:24-859:11 (Sheridan, Terry).

335. Williams Four Corners has "keep whole" contracts with producers in addition to WPX Production and WPX Rocky Mountain, including large unaffiliated producers like ConocoPhillips, BP, XTO, and Devon, as well as, with smaller independent producers. See Tr. at 580:3-16 (Emory, Sutphin); Chart of Williams Four Corners Keep Whole Agreements (Defendants' Ex. 201)(listing thirty-eight keep-whole agreements).

336. There are technical challenges associated with paying exact well-by-well royalties on drip condensate.

337. Not all class wells produce drip condensate, because coalbed methane does not produce NGLs of any kind. See Tr. at 568:3-575:25 (Emory, Sutphin). See also Tr. at 136:2-137:1 (Reineke, Berge).

338. Gas' chemical composition is also relevant to drip condensate production: only class wells that produce pentanes and heavier hydrocarbons have the potential to produce drip condensate. See Tr. at 568:3-575:25 (Emory, Sutphin). See also Tr. at 137:8-138:6 (Reineke, Berge).

339. Drip condensate production also largely depends on gas pressure and temperature in the gathering system. See Tr. at 568:3-575:25 (Emory, Sutphin).

340. Gas composition, pressure, and temperature vary over time, including during the class time period in this case. See Tr. at 568:3-575:25 (Emory, Sutphin).

341. A well's gas composition, however, does not vary by much over time. See Tr. at 210:16-211:22 (Sheridan, Ley).

342. While the total amount of drip condensate produced in a gathering system is ascertainable, a detailed engineering analysis, on a well-by-well basis, is required to accurately allocate the drip condensate quantities among the various wells involved. See Tr. at 568:3-575:25 (Emory, Sutphin).

343. Such an engineering analysis must take into account gas composition, temperature and pressure. See Tr. at 568:3-575:25 (Emory, Sutphin). See also Tr. at 642:10-643:25 Emory, Sutphin).

344. There is an exception to the general rule that the Defendants pay the class on a keep-whole basis: for "at least two wells committed to the 372K gathering contract" — which, between royalty and overriding royalty interests, affects 99 class members — the Defendants pay royalty on the basis of NGLs. See Stipulation at 4 n.6; Tr. at 452:8-18 (Sutphin, Ward).

b. Compensation for Gas Used Off the Lease.

345. Production from all wells must be compressed to enter a gathering system and/or plant. See Tr. at 577:7-580:2 (Emory, Sutphin).

346. As the raw gas travels along the gathering system, it typically passes through one or more compressor stations, which increases the pressure of the gas to levels necessary to keep it moving along the gathering system and delivers it to a treating or processing plant. See Tr. at 100:12-23 (Brickell, Reineke).

347. These compressor stations are powered by gas within the lines, i.e., gas on which the class members are owed royalty. See Tr. at 100:18-23 (Brickell, Reineke).

348. Gas is also used on the lease itself; this gas is known as "lease use" gas. Tr. at 443:3-7 (Brickell, Emory).

349. WPX Production does not pay royalty on lease use gas, nor is it required to pay anything if the lease involved has a free use clause. See Tr. at 442:8-443:15 (Ward, Sutphin).

350. The monthly check stubs issued that the Defendants issue to the class members do not report volumes of gas that the Defendant-lessees used. See Ley Expert Report at 8, 12.

351. The check stubs reflect only the quantity of gas that the Defendants actually royalty on, which has — silently built into it — a reduction from the gross production quantity to account for "used" gas. COGIS — Monthly Well Production at 1 (Plaintiffs' Ex. 231). See Tr. at 124:6-125:24 (Brickell, Reineke).

352. The result of this fact is that the royalty owners never know about the portion of gas that the Defendants use; they are only informed of, and paid on, an amount that has already had used gas deducted. See Tr. at 486:23-487:9 (Brickell, Ward).

353. The amount of produced gas deducted as being "used" is typically in the eight-and-one-half percent range. See Tr. at 126:8-17 (Reineke, Brickell).

354. There are technical challenges associated with paying exact well-by-well compensation on used gas.

355. The amount of compression required depends upon the individual well's producing pressure. See Tr. at 577:7-580:2 (Emory, Sutphin).

356. The more compression required, the more compression fuel used, and thus more compressor fuel costs. See Tr. at 577:7-580:2 (Emory, Sutphin).

357. The pressure of class wells varies significantly from well to well. See Tr. at 577:7-580:2 (Emory, Sutphin).

358. For example, some wells produce at 5 psi23 and others at 200 psi. See Tr. at 577:7-580:2 (Emory, Sutphin).

359. Compressor fuel costs cannot be determined on a class-wide basis, and such costs must be determined on a well-by-well basis, taking into account the actual volume and pressure from any given well.24 See Tr. at 577:7-580:2 (Emory, Sutphin).

c. Timeliness of Payments.

360. WPX Production has, at times, made late payments — i.e., payments outside of the NMPPA's forty-five day window — and declined to pay interest on the overdue amounts. See Tr. at 465:6-466:6.

361. Every month, WPX Production makes numerous adjustments to prior royalty and overriding royalty payments in the form of "prior-period adjustments." See Tr. at 454:9-458:12 (Ward, Sutphin).

362. Many circumstances can prompt prior-period adjustments, some of which are beyond WPX Production's control, including volume changes from the gathering systems, suspense payments, and unit expansions. See Tr. at 454:9-458:12 (Ward, Sutphin).

363. Some prior-period adjustments are occasioned by accounting errors that WPX Production makes. See Tr. at 454:9-458:12 (Ward, Sutphin).

364. WPX Production evaluates whether to pay interest on prior-period adjustments on a case-by-case basis and has, on at least some occasions, paid interest on prior-period adjustments. See Tr. at 454:9-458:12 (Ward, Sutphin); id. at 454:9-458:121 (Ward, Sutphin); id. at 463:2-21 (Ward, Brickell).

365. It is more probable than not that WPX Production has withheld interest payments on grounds other than those that justify withholding interest under the NMPPA.25 See Tr. at 465:6-14 (Ward).

d. Cost Deductions.

366. For royalties paid on New Mexico production committed to a gathering contract with parties other than Williams Four Corners, WPX Production deducts a proportionate share of actual charges assessed by the service provider for all post-production services, the amount for which is determined by contract, plus applicable state production taxes, and state and federal income tax, when required to be withheld. See Stipulation ¶ 19, at 4-5.

367. On independently gathered wells, if the gas is processed for the removal of NGLs, WPX Production deducts a proportionate share of any applicable processing fees, plant fuel, processing taxes, and costs associated with transportation and fractionation of NGLs from any royalty payment associated with said NGLs. See Stipulation ¶ 19, at 5.

368. For royalties paid on New Mexico production committed to a gathering contract with Williams Four Corners and its predecessors, WPX Production deducts a uniform cost of service ("COS") charge per MCF from each New Mexico class member on the Williams Four Corners gathering system, regardless of the actual costs attributable to each well/lease of rendering the gas into marketable condition. See Mathis Depo. at 104:1-16 (Brickell, Mathis); Kaplin Expert Report at 5.

369. The Defendants assessed a COS charge throughout the entire class period — 1985 to present — although its magnitude fluctuated throughout the period. See Mathis Depo. at 107:13-20 (Brickell, Mathis).

370. Williams Four Corners computes the COS charge and relays it to WPX Production, who assesses it against the royalty. See Tr. at 511:9-23 (Sutphin, Miller).

371. The Defendants assess the same COS charge against the federal government that they do against private lessors; the class COS charge is calculated pursuant to 30 C.F.R. § 1206.157(b), which regulates the expenses that working interests owners of federal land may deduct when the gas is sent to an affiliate. See Tr. at 504:17-22 (Sutphin, Miller).

372. Williams Four Corners recomputes the COS charge annually, and it is based on an even breakdown of: (i) the "hard" costs of gathering, compressing, treating and processing gas; and (ii) the "soft" costs of office overhead and depreciation on plant; and (iii) costs not actually sustained, i.e., profit. See Tr. at 182:23-183:14 (Brickell, Ley); id. at 476:12-15 (Brickell, Ward); Kaplin Expert Report at 5.

373. The components of the COS charge are all permissible for federal royalties, but the class members are not the federal government, and the class members' royalties are governed by their leases, and not by federal regulations. See 30 C.F.R. § 1206.157.

374. The COS charge is enumerated on the check stubs as a "gathering" charge, even though it is not limited to the costs of gathering. See Tr. at 122:14-20 (Brickell, Reineke).

375. The COS charge does not include a component for any marketing expenses that WPX Production incurs; WPX Production does not pass on marketing expenses to the royalty owners. See Tr. at 453:22-454:8 (Ward, Sutphin)("To my knowledge, we have never deducted marketing charges to San Juan royalty owners."); id. at 466:10-18 (Ward, Sutphin).

376. WPX Production deducts federal and state taxes from their royalty payouts, in keeping with the law. See Stipulation ¶ 14, at 3.

377. The Defendants calculate the profit or "rate of return" component of the COS by multiplying the undepreciated balance of gathering assets times the Triple B bond rate, by a 1.3 percent inflation factor. Tr. at 181:17-182:3 (Brickell, Ley). See Tr. at 509:17-511:8 (Miller, Sutphin). See also C.F.R. § 1206.157.

378. The COS charge's profit component comes out to around four-and-a-half percent of the total of the real-expense components. See Tr. at 510:11-20 (Sutphin, Miller).

379. The Defendants do not assess a COS charge on the Colorado wells. See Stipulation ¶ 14, at 3.

380. WPX Production does not assess a COS charge on the non-Williams Four Corners wells; rather, it passes on a proportional share of the charge that the independent gatherer invoice to it. See Tr. at 153:23-154:2 (Reineke, Brickell).

381. As a part of WPX Production's affiliate gathering contract with Williams Four Corners, WPX Production pays Williams Four Corners a gathering rate that is typically higher than the COS charge it assesses against royalty owners. See Tr. at 449:7-19 (Ward, Sutphin).

382. In one month analyzed, the contract rate for gathering was $1.39 and the COS rate was $.85, approximately sixty-one percent of the contract rate. See Tr. at 449:20-451:25 (Ward, Sutphin); Electronic Mail Transmission from Sheryl Ward to Robert Sutphin at 1 (Defendants' Ex. 131).

383. The WPX Production-Williams Four Corners contract is, however, an affiliate contract, as, even the contract now in place was executed at a time when both parties were owned by the same entity.

384. Moreover, contracts between WPX Production and a gathering company — whether Williams Four Corners or a third-party company — do not alter the royalty that WPX Production owes the class members under their leases.

e. Averaging of Payments Across Leases.

385. Before some point in 2001, the Defendants paid all royalty owners on the basis of a WASP. See Tr. at 170:10-171:2 (Brickell, Ley); Responses and Objections of WPX to Plaintiffs' "Non-Prioritized" Interrogatories at 14 (Plaintiffs' Ex. 221)(response to interrogatory no. 8); Mathis Depo. at 40:24-41:14 (Brickell, Mathis).

386. The WASP for the natural gas was based on the arm's length sales at the pipeline, and not on any preceding affiliate transaction. See Tr. at 108:6-109:13 (Reineke, Brickell); Mathis Depo. at 40:24-41:14 (Brickell, Mathis).

f. Payments of the Basis of Index Price.

387. In 2000, the Defendants switched from using a WASP to using an index price to pay royalties on both well condensate and natural gas. See Responses and Objections of WPX to Plaintiffs' "Non-Prioritized" Interrogatories at 14 (Plaintiffs' Ex. 221)(response to interrogatory no. 8).

388. The Defendants use the OPIS Mt. Belvieu index price — an oil index — for well condensate. See Stipulation ¶ 11, at 3.

389. For natural gas, the Defendants use the index price in the first-of-the-month Platt's Inside FERC San Juan Gas Market Report for El Paso Natural Gas Company. See Stipulation ¶ 11, at 3. See also Tr. at 102:6-11 (Reineke).

390. An independent company, Platt's, calculates the index and publishes it in Inside FERC Natural Gas Report. See Tr. at 817:17-823:20 (Terry, Sheridan). See also Tr. at 114:19-23 (Reineke, Brickell).

391. This index price is based upon actual reported sales and purchases of gas to be delivered by the seller at the El Paso pipeline location in the San Juan Basin in the particular month for which the index price is published. See Tr. at 817:17-823:20 (Terry, Sheridan). See also Tr. at 114:19-23 (Reineke, Brickell).

392. This price reflects the average arm's length sale price of pipeline-quality gas, rather than wellhead-quality gas. See Tr. at 296:9-16 (McNamara, Kaplin).

393. Natural gas is regularly sold and purchased by unrelated sellers and buyers at the index price. See Tr. at 821:4-13 (Terry, Sheridan).

394. Within the oil-and-gas industry, it is generally believed that the index price reflects the market value of the gas delivered at the designated location in the month of publication. See Tr. at 823:21-824:2 (Terry, Sheridan); id. at 138:15-20 (Reineke, Berge); id. at 287:1-288:4 (Kaplin, Berge); id. at 289:3-11 (Kaplin, Berge).

395. To the extent that there is a "going rate" for natural gas, the indices reflect it; the federal government used to set the price of natural gas by fiat, but those days ended before the beginning of the class period. See Tr. at 114:24-10 (Brickell, Reineke).

396. In one comparison of the index price to the WASP, the index price was approximately $0.01 higher, and in another comparison, the WASP was slightly higher or the same. See Tr. at 523:20-526:6 (Miller, Sutphin).

397. The Defendants pay their federal lease royalties on the basis of an index price. See Tr. at 525:24-526:2 (Sutphin, Miller).

g. Affiliate Versus Arms-Length Transactions.

398. The Plaintiffs' affiliate-transactions claim is not an independent claim, but rather a rephrasing of the index-price claim and the claim that the Defendants fail to pay royalty on NGLs; those claims and the evidence relating to them are summarized above. See Findings of Fact 319-344, Part 6a, supra; id. 387-396, Part 6f, supra.

399. When the Defendant-lessee — either WPX Production or WPX Rocky Mountain — transfers title to the gas to a gathering and/or processing affiliate — presently Williams Four Corners, see Findings of Fact 211-227, Part 3a-c, supra, the gathering affiliate "pays" the Defendant-lessee the index price, but no money actually changes hands, see Finding of Fact 208.

400. The Defendants never paid royalty on an affiliate sale value that is less than the value of the index price.

401. Additionally, when the Defendant-lessee transfers title to the gas to its gathering affiliate, it is transferring the unprocessed gas, which is effectively the gas on which it pays royalty when it pays via the keep-whole methodology.

402. The affiliate-transaction claim is, thus, a re-packaging of their other claims.26

7. The Named Plaintiffs' and Absent Class Members' Knowledge of, and Diligence in Discovering, Their Causes of Action.

403. The only regular correspondence between the Defendants and the class members are the check stubs that the Defendants send to the class members conveying monthly royalty payments.

404. The format of check stubs sent to each royalty and overriding royalty owner is uniform among the class, but has changed over time. See Stipulation ¶ 9, at 2-3.

405. Royalty and overriding royalty owners contact the Defendants on occasion with questions regarding their payments. See Tr. at 727:25-728:9 (Mathis, Sutphin).

406. The Defendants maintain a full-time position — currently filled by Karen Furland, a WPX Energy employee — for the purpose of receiving and resolving royalty-related questions, and maintains records detailing royalty owner inquiries regarding royalties. See Tr. at 725:3-727:8 (Mathis, Sutphin); id. at 726:4-6 (Sutphin, Mathis).

407. Class members have, at times, inquired about issues relating to their royalty payments long before the Plaintiffs filed this lawsuit, including inquiries about information on check statements, see Customer Service Hotline Inter Office Call Sheet (Defendants' Ex. 80), post-production deductions, see Customer Service Hotline Inter Office Call Sheet (Defendants' Ex. 82), transportation charges and the COS charge, see Customer Service Hotline Inter Office Call Sheet (Defendants' Ex. 85), whether condensate payments are made, whether payments are made for natural gas liquids, and the parties to whom WPX Production sells its natural gas production, see Tr. at 728:10-16 (Mathis, Sutphin); 728:17-736:19 (Mathis, Sutphin).

408. Anderson Trust never contacted WPX Production to ask about its payments, and never made an inquiry into whether it had a claim.27 See Tr. at 419:1-420:9 (Anderson, Sheridan).

409. WPX Production did not dissuade Anderson from filing an action or from filing it before October, 2011. See Tr. at 421:11-422:5 (Anderson, Sheridan).

410. Various persons from Bank of America, SWMF Properties, and Moncrief Trust called WPX Rocky Mountain seeking information, including with respect to adjustments to royalty payments, and the information contained in the check detail. See, e.g., Tr. at 729:24-730:16 (Mathis, Sutphin); Customer Service Hotline Inter Office Call Sheet (Defendants' Ex. 80).

411. Munoz — the Bank of America representative in charge of managing the Patton Trust's royalty interests — annually reviews the Patton Trust's oil-and-gas properties and provides written comments and recommendations as a part of his job. See Munoz Depo. at 13:49:8-14:50:18 (Munoz, Sheridan).

412. Bank of America also employs division order analysts, title analysts and accountants in its oil and gas group; all of whom play a role in receiving checks, reviewing check stub detail, entering the information into the Bank of America system, and ensuring that its clients are paid properly. See Munoz Depo. at 16:60:7-61:10 (Munoz, Sheridan); id. at 24:92:18-93:7.

413. Bank of America reviewed royalty payments to the trust, but did not question or object to WPX Rocky Mountain's royalty calculation methods. See Munoz Depo. at 5:15:14-17:14 (Munoz, Sheridan); id. at 25:97:7-26:98:21 (Munoz, Sheridan).

414. Over the years, Westfall communicated by telephone and by letter with WPX Production and its predecessor, Williams Production Company, and never inquired about gas pricing, post-production deductions, or any other issues which are the subject of his claims in this case. See Tr. at 307:12-308:10 (Westfall, Aubrey); id. at 312:20-24 (Westfall, Aubrey).

415. Westfall did not discover his claims until 2010, when he began working with class counsel. See Tr. at 337:15-338:10 (Westfall, Sutphin).

416. From 1999 to 2000, a Colorado royalty owner and class member, Marshal Diggs, insisted that WPX Rocky Mountain28 was prohibited from deducting post-production costs from his royalty payments. See Royalty Owner Data Sheet and Correspondence with Marshal Diggs, filed February 21, 2014 (Doc. 212-8).

417. After multiple exchanges of letters, WPX Rocky Mountain advised on September 13, 2000, that the royalty owner was paid on the value of gas at the wellhead, and that the sales price on his check stub "is with costs included." See Royalty Owner Data Sheet and Correspondence with Marshal Diggs.

8. Potential Damage-Calculation Models.

418. Computerized database records are still in existence for most, if not all, of Defendants' accounting periods herein described for potential damages calculations. See Emory Expert Report passim.

419. Metering at the wellhead enables the Court to determine the actual (i) quantity/volume of gas produced by each well, in MCFs; (ii) energy content of gas produced by each well, in MMBtus; and (iii) quantity/volume of NGLs entrained in the gas produced by each well, in GPM. See Emory Expert Report passim.

420. It is possible to determine to which plant most gas from a given well flows, but practically impossible to determine where all of the gas flows, as the gathering systems are interconnected with one another. See Emory Expert Report ¶¶ 44-49, at 23-26 .

421. There is already in existence a database that, among other things, matches each class well to the gathering system and plant to which the well's gas flows; this database also contains the proportion of gas processed at each plant. See PWM Master Well Completion Database (Defendants' Ex. 168).

422. Because not all NGLs entrained in gas at the wellhead are ultimately extracted from the gas — i.e., some of it fails to condense into drip condensate and also gets bypassed from processing, thus remaining in the residue gas when it is put in the pipeline — it would require a well-by-well flow analysis to precisely attribute NGLs, including drip condensate, to the well from which they came. See Tr. at 137:8-138:6 (Sheridan, Reineke).

423. Late payments — i.e., payments made outside of the NMPPA's forty-five day window — can be easily identified, and those late payments that might potentially be justified — i.e., those payments that are in suspense because of a title dispute — can also be identified through the use of a class-wide query. See Tr. at 178:18-179:8 (Brickell, Ley).

424. Barbara Ley — one of the Plaintiffs' experts — has performed such a class-wide late-payments query in other oil-and-gas class actions. See Tr. at 179:1-8 (Ley, Brickell).

PROCEDURAL BACKGROUND

To frame the factual determinations and legal discussion, the Court will outline — briefly and in broad strokes — the basic factual allegations and legal arguments underlying the Plaintiffs' case, as well as the Defendants' responses thereto. The Court will also briefly describe the — mostly expert — witnesses whom each side presented at the hearing, and their general topic of testimony. The Court will later make conclusions of law to rule on the Motion.

1. The Pleadings.

1. In ruling on a class certification motion, the Court does not accept the facts alleged in the pleadings as true, but must find all facts bearing on the question of certification, even if those facts also bear on the merits of the substantive claims. The Court is cognizant that it must not decide the merits at this stage of the case and expressly does not decide the merits of the case. The above findings of fact are tentative and made solely to allow the Court to decide whether class certification is appropriate.

a. The Complaint.

2. The Plaintiffs filed a proposed class action in state court on December 5, 2011, and the Defendants removed the case to federal court pursuant to the Class Action Fairness Act, 28 U.S.C. § 1332(d) ("CAFA"), just over a month later. Notice of Removal ¶ 1, at 1, filed January 12, 2012 (Doc. 1). See id. ¶ 5, at 2. The Plaintiffs did not move to remand the case to state court, and — after several rounds of amended pleadings and motions to dismiss — they filed the current iteration of their Complaint in August, 2013. See Complaint ¶ 8, at 3 (conceding that the Court has subject-matter jurisdiction over the case pursuant to CAFA). The Plaintiffs allege that they are non-cost bearing owners of oil and gas leases — landowners who leased their land to oil companies in exchange for a cut of any proceeds from hydrocarbons drilled out of the land — and that the Defendants are working interest owners — oil companies that drill on the Plaintiffs' land, and pay the Plaintiffs an amount based on the profitability of the land. See Complaint ¶¶ 9-12. They seek to obtain class status under rule 23 to represent "themselves and . . . all other owners of `non-cost bearing interests in the [class] wells.'" Complaint ¶ 13, at 6.

3. The Plaintiffs allege that the proposed class members, or their predecessors, acquired their interests in the hydrocarbon revenues from the subject wells through executing oil-and-gas mining leases or permits with the Defendants. See Complaint ¶ 11, at 4. The Plaintiffs assert that, under the leases, the Defendants owe the Plaintiffs a "duty to pay royalties on all hydrocarbons" for the value or price which the Defendants do or should receive from the "arm's length" sale of the hydrocarbons. Complaint ¶ 12, at 5. The Plaintiffs argue that the leases give them a right to royalties in the "drip condensate," a liquid product which is recovered during the Defendants' oil and gas mining processes. Complaint ¶ 28, at 12-13. The Plaintiffs assert that the leases do not provide that the Defendants may calculate the Plaintiffs' royalty payments using the average sale price of a mixture of hydrocarbons from wells in which the Plaintiffs own a royalty interest and other wells in which the Plaintiffs do not own royalty interests. See Complaint ¶ 12, at 5-6.

4. The Plaintiffs initially alleged numerous claims, but, after two partially successful motions to dismiss, see MO, 952 F.Supp.2d 979; MOO, 27 F.Supp.3d 1188, only six causes of action remain: (i) the first cause of action, "failure to pay royalty on volumes of hydrocarbons, including drip condensate," Complaint ¶¶ 22-30, at 10-13 (capitalization altered for readability); (ii) the second cause of action, "breach of the duty of good faith and fair dealing," Complaint ¶¶ 31-42, at 14-17 (capitalization altered for readability); (iii) the fourth cause of action, violation of the NMPPA and "interest due under Colorado law," Complaint ¶¶ 56-61, at 20-21 (capitalization altered for readability); (iv) the fifth cause of action, "bad faith breach of contract," Complaint ¶¶ 62-66, at 21-22 (capitalization altered for readability); (v) the sixth cause of action, a claim for declaratory relief, see Complaint ¶¶ 67-70(b), at 22-23; (vi) the eleventh cause of action, "breach of the duty to market hydrocarbons — Colorado," Complaint ¶¶ 98-101, at 30-31 (capitalization altered for readability).

b. The Answer.

5. The Defendants answered the Complaint after all briefing on the Motion was completed and the Court had already held the class certification hearing. See WPX Energy's Answer to Plaintiffs' Fourth Amended Complaint, filed June 16, 2014 (Doc. 249)("Answer"). The Defendants deny almost all of the Plaintiffs' allegations, see Answer ¶¶ 1-105, at 1-11, with the exception of a few background facts such as "that the named Plaintiffs own royalty and/or overriding royalty interests in leases on which WPX has drilled, operated and/or produced wells," Answer ¶ 23, at 5. The Defendants admit "that the putative class, as defined by Plaintiffs, contains more than 1,000 members." Answer ¶ 14, at 4.

6. The Defendants also assert thirty-five affirmative defenses. See Answer ¶¶ 1-35, at 11-13. First among them are two defenses, "failure to state a claim upon which relief can be granted," Answer ¶ 1, at 11, and "statute of limitations or the corresponding equitable doctrine of laches," Answer ¶ 2, at 11, on which the Court has already ruled in some fashion. The Court has ruled on all arguments for failure to state a claim in two prior motions under rule 12(b)(6), resulting in the dismissal of several claims not listed here. See MO at 154-55; MOO at 95. The Court also declined to dismiss any claim, in whole or in part,29 on limitations grounds, because the Plaintiffs present a plausible claim that the discovery rule delayed the accrual of the statute. See MOO at 60-61; id. at 69-81. The Court made clear, however, that the Plaintiffs carry the burden of establishing the applicability of the discovery rule at trial, and, thus, the Defendants' time bar defenses remain viable. See MOO at 78.

7. The other defenses that the Defendants plead are: (i) that "[a]ll or part of Plaintiffs' claims are barred by Plaintiffs' own breach of contract or breach of their corresponding duty of good faith and fair dealing," Answer ¶ 3, at 11; (ii) waiver doctrine, see Answer ¶ 4, at 11; (iii) estoppel, see Answer ¶ 5, at 11; (iv) that the express terms of the contract control and bar all claims, see Answer ¶ 6, at 11; (v) that the Plaintiffs "acquiesce[d] in a continuous course of dealing, industry custom and practice and/or usage of trade," Answer ¶ 7, at 12; (vi) that Plaintiffs were unjustly enriched by royalty overpayments, see Answer ¶ 8, at 12; (vii) that the Defendants are entitled to recoup royalty overpayments, see Answer ¶ 9, at 12; (viii) that the Defendants are entitled to a set-off against future payments, and presumably against any damages awarded against them, on the basis of past royalty overpayments, see Answer ¶ 10, at 12; (ix) accord and satisfaction, see Answer ¶ 11, at 12; (x) collateral estoppel and/or res judicata, see Answer ¶ 12, at 12; (xi) that the Plaintiffs failed to meet conditions precedent of their leases, see Answer ¶ 13, at 12; (xii) election of remedies, see Answer ¶ 14, at 12; (xiii) that the Plaintiffs failed to fully perform under the leases, see Answer ¶ 15, at 12; (xiv) the impossibility doctrine, see Answer ¶ 16, at 12; (xv) that the Plaintiffs "are improper party plaintiffs," Answer ¶ 17, at 12; (xvi) that the Plaintiffs lacked authority, see Answer ¶ 18, at 12; (xvii) that the Plaintiffs lacked capacity, see Answer ¶ 19, at 12; (xviii) failure of consideration, see Answer ¶ 20, at 12; (xix) lack of standing, see Answer ¶ 21, at 12; (xx) misrepresentation and/or fraud, see Answer ¶ 22, at 13; (xxi) lack of mutual consent, see Answer ¶ 23, at 13; (xxii) mistake, see Answer ¶ 24, at 13; (xxiii) "failure to name and/or join necessary and/or dispensable parties," Answer ¶ 25, at 13; (xxiv) novation, see Answer ¶ 26, at 13; (xxv) payment, see Answer ¶ 27, at 13; (xxvi) "prior breach and/or abandonment," Answer ¶ 28, at 13; (xxvii) ratification, see Answer ¶ 29, at 13; (xxviii) release, see Answer ¶ 30, at 13; (xxix) statute of frauds, see Answer ¶ 31, at 13; (xxx) unclean hands doctrine, see Answer ¶ 32, at 13; (xxxi) unconscionability, see Answer ¶ 33, at 13; (xxxii) that the request for punitive damages, specifically, is unconscionable, see Answer ¶ 34, at 13; and (xxxiii) arbitration and award, see Answer ¶ 35, at 13.

2. The Pre-Hearing Briefing on the Motion.

8. The Plaintiffs filed their Motion on January 6, 2014, and the Defendants responded a little over a month later by filing the Defendants' Response in Opposition to Plaintiffs' Motion for Class Certification, filed February 17, 2014 (Doc. 205)("Response"). The Plaintiffs replied roughly two weeks after with the Plaintiffs' Reply to Defendants' Response in Opposition to Motion for Class Certification, filed March 3, 2014 (Doc. 216)("Reply"). The Court held the class certification hearing a week after the Plaintiffs filed their Reply.

a. The Plaintiffs' Motion.

9. The Plaintiffs propose the following class definition:

The proposed Class is geographically designated and limited to the State of New Mexico and La Plata County, Colorado, and WPX's oil and gas leasehold located therein, owned by WPX, as to Plaintiffs' claims and causes of action.

Plaintiffs also propose the following subclasses:

Plaintiffs' PF ¶¶ 20-22, at 10-11 (numbering omitted). See Motion at 3-4.

10. The Plaintiffs assert twelve common questions of fact and fourteen common issues of law. See Motion at 4-7. The common questions of fact that the Plaintiffs assert are:

Motion at 4-6. The Court notes that most of these alleged "common questions of fact" are, on their face, legal questions — most obviously number 12, but also numbers 2-5 and 8-11, as interpreting the content of a contract is a legal function of the Court, and not a fact-finding function. These questions might, however, be common questions of law.

Motion at 6-7.

12. The Plaintiffs assert that the Defendants' dealings with numerous affiliates in transporting, processing, and marketing the natural gas and other hydrocarbons from Plaintiffs' and proposed class members' wells has resulted in the systemic failure to calculate either appropriate revenues from sales or any unlawful deductions from Plaintiffs' and proposed class members' royalties. See Motion at 8. The Plaintiffs contend that lessees must make diligent efforts to market production so the lessor may realize the full value of his royalty interest. See Motion at 11 (citing Darr v. Eldridge, 66 N.M. 260, 364 P.2d 1041 (1959); Libby v. DeBaca, 51 N.M. 95, 179 P.2d 263, 265 (1947)). They argue that "[n]one of the Plaintiffs' or putative class members' leases and overriding royalty assignments authorizes payment based on an `index' price[, but that] all of WPX'[s] payments since approximately 2001 have been based upon an index price[], rather than the proceeds of arm's length sales." Motion at 11. They assert that "[t]he lessee must have the interest of the lessor in mind when marketing the product," Motion at 11 (citing Elliott Indus. LP v. BP Am. Prod. Co., 407 F.3d 1091, 1113 (10th Cir. 2005)("Elliott")), but that "WPX decided that none of its sales of hydrocarbons concerned the putative class members' interests," Motion at 11 (citing Mathis Depo. at 69:13-23; id. at 71:23-24; id. at 72:1-3; id. at 72:17-22; id. at 183:15-25).

13. The Plaintiffs assert that the Defendants use a "standardized approach to payment of all putative class members." Motion at 13. They contend that this standardization renders the case comparable to two Supreme Court of New Mexico cases, Davis v. Devon Energy Corp., 2009-NMSC-048, ¶ 9, 147 N.M. 157, 161, 218 P.3d 75, 79, and Phillis Ideal v. Burlington Resources Oil & Gas Co. LP, 2010-NMSC-022, 148 N.M. 228, 233 P.3d 362, 364, in which class certifications were granted. See Motion at 13 (citing those cases). They assert that "WPX does not even review the Plaintiffs' or putative class members' lease terms prior to payment of royalty and has never made any differences in payment methodology to any of the putative class members." Motion at 13-14 (citing Mathis Depo. at 33:5-12; id. at 36:9-24; id. at 39:15-17). The Plaintiffs assert that the Defendants used a WASP method to pay all Plaintiffs and proposed class members, and that none of those leases authorize this method of payment. See Motion at 15-16. They argue that "[w]hether this methodology is appropriate and results in proper payment of royalty, is a common, predominate Class question." Motion at 16.

14. The Plaintiffs argue that every contract in New Mexico imposes a duty of good faith and fair dealing in the performance and enforcement of a contract. See Motion at 16 (citing Watson Truck and Supply, Co. v. Males, 111 N.M. 57, 801 P.2d 639, 642 (1990); Continental Potash, Inc. v. Freeport-McMoran, 1993-NMSC-039, ¶ 64, 115 N.M. 690, 706-07, 858 P.2d 66, 82-83. They assert that this duty applies to oil-and-gas leases, as well as to assignments of overriding royalty interests. See Motion at 16. They concede that a breach of this covenant requires evidence of bad faith or that one party intentionally used the agreements to the detriment of the other party. See Motion at 16. The Plaintiffs assert that, as between the Defendants and the proposed class members, the Defendants have failed to pay all proposed class members on what they received for the hydrocarbons, which they could only produce by obtaining these leases from the class member in the first place. See Motion at 16. They state that, after the Defendants obtained the benefit of valuable hydrocarbons under the putative class members' leases, they refused to pay the value it received to the very person who allowed it to produce these hydrocarbons from their mineral interests. See Motion at 16. They characterize the Defendants' testimony as not "allow[ing] the putative class members the benefit of the sales process it (and WPX affiliates) enjoys." Motion at 16 (citing Mathis Depo. at 72:22-25; id. at 73:1-7; id. at 73:17-20; id. at 183:15-25).

15. The Plaintiffs also assert that the charges shown as "`gathering'" on the Plaintiffs' and proposed class members check stubs "have nothing to do with the cost of gathering." Motion at 18 (citing Miller Depo. at 77:3-16). They quote a WPX Energy representative for the proposition that "[t]he COS charges made to the putative class members under the term `gathering' include a `profit' or rate of return and office overheard." Motion at 19 (citing Miller Depo. at 69:13-25). They also assert that the Defendants wrongfully withheld all payment for drip condensate. See Motion at 20 (citing Ward Depo. at 201:1-14; id. at 202:1-2). Last, the Plaintiffs outline the legal argument for their claims regarding the Colorado wells:

Motion at 21 (omission in original).

16. The Plaintiffs attach three exhibits to their Motion: a set of interrogatory responses, see Responses and Objections of WPX to Plaintiffs' "Non-Prioritized" Interrogatories, filed January 6, 2014 (Doc. 194-1)("Selected Interrogatories");30 a table of affiliate transactions between various WPX affiliates, see WPX Gas Title Transfer Table, filed January 6, 2014 (Doc. 194-2); and a contract between Williams Four Corners and WPX Gas Resources, see Gas Gathering, Processing, Dehydrating and Treating Agreement Between Williams Four Corners and WPX Gas Resources Company, filed January 6, 2014 (Doc. 194-3)("WFC-WPX Contract"). The Selected Interrogatories contain two responses that the Plaintiffs underline for emphasis. First, in "Interrogatory No. 5," the Plaintiffs ask the Defendants:

Selected Interrogatories at 2 (emphasis omitted).

17. After a series of objections, the Defendants respond:

Selected Interrogatories at 3 (emphasis in original)(omissions in original). The Selected Interrogatories include a second question and answer, "Interrogatory No. 8," which asks:

Selected Interrogatories at 4 (emphasis omitted).

18. After again objecting to the question, the Defendants responded:

Selected Interrogatories at 4 (emphasis in original).

19. The Plaintiffs also call the Court's attention to the following language in the WFC-WPX Contract:

1. COMMITMENTS

4. TERM

WFC-WPX Contract at 2-5 (emphases in original).

b. The Defendants' Response.

20. The Defendants open by arguing that "[t]he proposed class does not `justify a departure' from the `usual rule' against class actions." Response at 1 (citing Wal-Mart Stores, Inc. v. Dukes, 131 S.Ct. 2541, 2550 (2011)("Wal-Mart")). They argue that the proposed class lacks all of the rule 23(a) requirements of commonality, typicality, and adequacy, and also lacks the rule 23(b) requirements of predominance and superiority. See Response at 1-2. In keeping with their opening citation to Wal-Mart, the Defendants argue:

Response at 2. The Defendants also contend that the proposed class lacks predominance of common issues over individual ones, asserting that the various doctrines that the Plaintiffs assert to toll or delay the accrual of the statute of limitations involve highly individualized inquiries. See Response at 2.

21. They go on, in their statement of facts, to identify several purported differences among proposed class members: (i) that different proposed class members' — and even different named Plaintiffs' — leases contain different language governing royalty obligations, see Response at 4-6; (ii) that different wells have different gas composition and might not be connect to NGL processing plants, see Response at 6-7; (iii) that the Defendants' gathering and processing arrangements are different because "some wells cannot be processed to extract NGLs because they are on a dedicated gathering system that leads only to a plant that does not extract NGLs," Response at 7-8; (iv) that the Defendants' methods for calculating royalties vary depending upon the location of the well and the terms of the lease in question, see Response at 8-9; (v) that "[t]he entrained NGL content of the gas varies greatly from well to well," Response at 10 (citing Emory Report ¶ 32-35), and that "[d]ifferences in gas composition and processing arrangements have a direct bearing on Plaintiffs' claims," Response at 10 (citing Deposition of Dan Reineke at 46:16-24 (taken January 16, 2014)(Plaintiffs' Ex. 209)); (vi) that "[t]he only way to estimate drip condensate produced from any well or group of wells would be to prepare a detailed engineering analysis for each well," Response at 11 (citing Emory Report ¶ 52); and (vii) that the proposed class members' knowledge of, due diligence in discovering, and ability to discover the Defendants' alleged conduct varies, see Response at 11-13. The Defendants then move to their argument, first addressing the breach-of-contract claims, see Response at 15-34, and then addressing the other claims, see Response at 34-39.

22. The Defendants first argue that the breach-of-contract claims lack commonality under rule 23(a)(1), because, although there may be common questions, no single question is capable of a common answer. See Response at 15-17. They assert that the Plaintiffs "list 26 allegedly common questions — 14 questions of fact and 12 questions of law — without attempting to explain how any of them has a common answer that would resolve an issue central to all putative class members' claims." Response at 16 (citing Motion at 4-7). The Defendants argue that "evaluating whether WPX has a duty to pay royalty on extracted NGLs and condensate, or on a downstream sales price, requires a lease-by-lease evaluation of lease terms." Response at 17 (citing Wallace B. Roderick Revocable Living Trust v. XTO Energy, Inc., 725 F.3d 1213, 1219 (10th Cir. 2013)("Roderick")). They assert that the Plaintiffs' expert admitted that all class leases would have to be analyzed, although, they assert, he erroneously believed this evaluation could be deferred until a trial on the merits. See Response at 17 (citing Deposition of Randy Kaplin at 64:17-22 (taken January 9, 2014)(Plaintiffs' Ex. 241)).

Response at 17-18 (citations omitted). The Defendants contend that the Court would have to hold hearings to determine the content of each individual lease using extrinsic evidence, and thus no common issue is present. See Response at 18-19.

23. The Defendants also contend that post-production expenses will vary from well to well, and thus the question how much each well was harmed can have no common answer. See Response at 19. They argue that the use of a single methodology — WASP — does not mean that the methodology was applied to the same effect for all wells. See Response at 20-21. Their final argument on commonality grounds is that the "Plaintiffs' tolling issues raise highly individualized questions as to whether putative class members' claims extend beyond the statute of limitations period," because "many putative class members contacted WPX over the years and questioned the very royalty calculations and deductions of post-production expenses at issue," and whether and when each class member did so bears on the applicability of the tolling doctrines and the discovery rule. Response at 22 (emphasis omitted).

24. The Defendants then attack the Plaintiffs' attempt to show predominance under rule 23(b). See Response at 22-27. They argue that predominance is "`far more demanding' than the commonality standard," Response at 22 (quoting Amchem Prods., Inc. v. Windsor, 521 U.S. 591, 623-24), and "requires, among other things, that the common questions `predominate over any questions affecting only individual members,'" Response at 22 (quoting Fed. R. Civ. P. 23(b)(3)). The Defendants argue that predominance is lacking for several reasons, which mostly overlap with their commonality arguments. First, they argue that "[d]iffering lease language defeats predominance." Response at 23 (emphasis omitted). Second, they contend that "[d]iffering knowledge [on the part of different putative class members] defeats predominance." Response at 24 (emphasis omitted). Third, they argue that differing damages and the need for individualized damage determinations make class certification impossible. See Response at 25-27.

25. The Defendants next address typicality and adequacy of representation, noting that those inquiries tend to merge, because "all concern whether `the named plaintiff's claim and the class claims are so interrelated that the interests of the putative class members will be fairly and adequately protected in their absence.'" Accordingly, the Defendants mount no new arguments as to typicality, instead arguing generically — in a half-page section that references their commonality and predominance arguments — that the named Plaintiffs' claims are not typical of the class. See Response at 28. As to adequacy, the Defendants argue that the class is unavoidably conflicted, because some putative class members have benefitted from the WASP calculation method. See Response at 29. The Defendants contend that "[c]ourts consistently refuse to certify class actions where the named plaintiffs seek relief that benefits some putative class members but harms others." Response at 29 (citing Gonzales v. City of Albuquerque, 2010 WL 4053947, at *9 (D.N.M. Aug. 21, 2010)(Browning, J.)).

26. The Defendants last argue that the class-action mechanism fails the superiority requirement. See Response at 32-34. First, it argues that "[t]he plethora of individualized issues discussed above destroys superiority," just as they contend it destroys predominance. Response at 32. Second, they assert that the putative class is unmanageable because "it would require dozens if not hundreds of subclasses." Response at 32. They assert that there would have to be at least four times as many subclasses as the Plaintiffs propose — representing those wells which do and do not produce condensate, and representing those members who do and do not own interests in wells having gas that is processed for NGLs — and that there would have to be a class representative for each subclass, which is presently lacking. Third, the Defendants assert that, because "WPX's `keepwhole' contracts benefit many potential putative class members," those members "have no interest in joining Plaintiff's crusade." Response at 33-34 (emphasis in original).

27. The Defendants then address the claims that are not breach-of-contract claims. See Response at 34-39. They argue that the claim for breach of the implied duty of good faith and fair dealing must fail, because, "[u]nder New Mexico law, the implied duty of good faith and fair dealing `protects the reasonable expectations of the parties arising from an agreement.'" Response at 34 (quoting Sanders v. FedEx Ground Package Sys., Inc., 2008-NMSC-040, ¶ 27, 144 N.M. 449, 188 P.3d 1200). They contend that a good-faith-and-fair-dealing claim is uncertifiable for two reasons. First, they assert that "determining the parties' `reasonable expectations' would require an individualized inquiry into what each royalty and overriding royalty interest owner expected when entering into a particular royalty instrument, and whether their expectations were reasonable." Response at 35. Second, the Defendants contend that they would have the right to submit individualized extrinsic evidence to prove these expectations and their reasonableness. See Response at 35. The Defendants assert that "[c]ourts in jurisdictions recognizing similar duties of good faith and fair dealing have consistently refused to certify class actions for alleged breaches of the duty." Response at 35 (citing Avritt v. Reliastar Life Ins. Co., 615 F.3d 1023, 1032 (8th Cir. 2010); Stratton v. Am. Med. Sec., Inc., 266 F.R.D. 340, 353 (D. Ariz. 2009)). They assert that "`[e]vidence of the parties' justified expectations would be required to establish a breach of the duty of good faith and fair dealing,' and such `expectations are likely to vary among members of the putative class.'" Response at 36 (quoting Avritt v. Reliastar Life Ins. Co., 615 F.3d at 1032). They argue — presumably for the purpose of distinguishing cases under California law that hold that a class can be certified for breach of good faith and fair dealing — that California, unlike New Mexico, uses an objective test of good faith and fair dealing. See Response at 36 n.8 (citing Vaccarino v. Midland Life Ins. Co., 2013 WL 3200500, at *19 (C.D. Cal. June 17, 2013)).

28. The Defendants argue that the Court cannot certify the claims under Colorado law, because, although Colorado recognizes the implied covenant of good faith and fair dealing in some instances, "`the doctrine is applied only when one party has discretionary authority to determine certain terms of the contract, such as quantity, price, or time.'" Response at 36 (emphasis added by Response)(quoting City of Boulder v. Pub. Serv. Co. of Colo., 996 P.2d 198, 204 (Colo. App. Ct. 1999)). They contend that, here, even the Plaintiffs agree that the Defendants lack discretion to define terms of the contract, and, thus, the Court cannot certify the claim, because no duty of good faith and fair dealing applies. See Response at 37. The Defendants last argue that claims under the NMPPA require an underlying breach of contract, and, thus, the same non-common facts that defeat certification with regard to the breach-of-contract claims also defeat certification of the NMPPA claim. See Response at 37-38.

c. The Plaintiffs' Reply.

29. The Plaintiffs' Reply first points out the following regarding the Defendants' statement of facts:

Reply at 1-2.31

30. They next assert that "the [named] Plaintiffs have an interest in 96 of the 3,200 WPX wells at issue in the class definition." Reply at 3. They assert that the Defendants have conceded this fact to be true. See Reply at 3. The Plaintiffs contend that "[t]he types of wells include Fruitland Coal production, Conventional Gas production, wells in Colorado, wells in New Mexico, wells gathered on WFC affiliate systems and wells not gathered on affiliate systems," and, thus, "[t]he entire range of all proposed subclasses is covered by the [named] Plaintiffs' interests." Reply at 3. The Plaintiffs assert the following three points of uniformity:

Reply at 3 (emphasis omitted).

31. The Plaintiffs attempt to distinguish Roderick, arguing that "Roderick directs the district court to review all of the leases forms [sic] to determine the above issues, as well as `whether the issues we have identified have any effect on its typicality or adequacy findings.'" Reply at 4 (quotation unattributed). The Plaintiffs concede that damages will differ from well to well, but contend that the question of liability — common to all putative class members — predominates. See Reply at 5. They further contend that there is no conflict among the class, because Dr. Griffin's analysis — which the Plaintiffs assert is the only evidence suggesting that some putative class members would be better off under the WASP calculation — used hypothetical, rather than actual, sales and costs. See Reply at 5-6.

32. The Plaintiffs next defend their fraudulent concealment claim, see Reply at 7-9, which the Court will not summarize here, because it subsequently dismissed that claim, see MOO at 82-83. The Plaintiffs then expound upon their earlier contention that differing damages among the proposed class do not defeat predominance. See Reply at 9-12. They first quote the Tenth Circuit for the proposition that "`there are ways to preserve the class action model in the face of individualized damages.'" Reply at 9 (quoting Roderick, 725 F.3d at 1220). They also contend that there are some "single stroke remedies," including "that the royalties paid to all putative class members must, in the first instance, be based upon the value received in an arm's length transaction by WPX."32 Reply at 10. They discuss two cases, Chieftain Royalty Co. v. XTO Energy, Inc., 213 U.S. App. LEXIS 13837 (2013), and Butler v. Sears, Roebuck & Co., 702 F.3d 359 (7th Cir. 2012), in which classes were certified despite individualized damages. See Reply at 10-12. The test, the Plaintiffs contend, is whether the individuals damages stem from a common injury. See Reply at 10-12 (characterizing Wal-Mart).

3. The Class Certification Hearing.

33. The Court held a class certification hearing, the bulk of which was held on March 10-12, 2014, and the remainder of which was finished up on April 3-4, 2014.33 The parties first gave brief opening statements. See Tr. at 4:22-69:5 (Brickell, Court, Sheridan). The Plaintiffs called expert witness Dan Reineke, a former petroleum engineer and oil company consultant, see Tr. at 76:9-155:3 (Brickell, Reinke, Berge, Court), expert witness Ley, an accounting and auditing professional, see Tr. at 155:20-222:16 (Brickell, Ley, Berge, Court), expert witness Randy Kaplin, a former reservoir engineer for Texaco, Inc., vice president of operations for Dyco Petroleum, Inc., and petroleum consultant, see Tr. at 223:15-297:11 (McNamara, Kaplin, Berge, Court), Westfall — a putative class representative — a retired Albuquerque, New Mexico, resident who inherited mineral interests in some of the subject wells from his father, see Tr. at 298:13-357:22 (Aubrey, Westfall, Sutphin, Court), and Anderson — the beneficiary of Anderson Trust, also a proposed class representative — a self-employed architectural designer and Bluffdale, Utah resident, whose personal trust owns mineral interests in some of the subject wells, see Tr. at 358:10-434:23 (Branch, Anderson, Sheridan, Court).

34. The Defendants called Sheryl Ward, WPX Energy's "manager of revenue for the Tulsa region," Tr. at 438:22-23 (Ward); see Tr. at 438:6-498:14 (Sutphin, Ward, Brickell, Court), Morris Miller, a retired WPX Energy employee formerly responsible for "mak[ing] sure that the federal royalty payments were paid correctly, in accordance with federal regulations," Tr. at 503:24-504:2 (Miller); see Tr. at 499:5-527:18 (Sutphin, Miller, Koop, Court), expert witness John Emory, a former engineer for British Petroleum, PLC, and a consultant, see Tr. at 532:13-650:11 (Sutphin, Emory, Brickell, Court), expert witness Dr. Griffin, an economics professor at Texas A&M University, see Tr. at 650:23-722:10 (Berge, Griffin, Brickell, Court), Julie Mathis, WPX Energy's "Director of Revenue and Regulatory Accounting," Tr. at 724:9-10 (Mathis); see Tr. at 723:22-755:23 (Sutphin, Mathis, Brickell, Court), and expert witness Kris Terry, an accountant, lawyer, and gas and oil consultant, see Tr. at 770:13-952:16 (Sheridan, Terry, McNamara, Court). The Plaintiffs presented no rebuttal, and evidence closed on April 3, 2014. See Tr. at 952:21-953:2 (Court, Sheridan, Brickell). The parties gave closing arguments the next day. See generally Tr. at 967-1034. As the Court bases its findings of facts off of the hearing — and cites to the hearing transcript and the parties' exhibits for each finding — the Court will not describe the hearing in detail, but, rather, will summarize each witness' credentials and the highlights of their testimony.

a. Opening Statements.

35. The parties agreed to an hour apiece for opening statements, with the Plaintiffs presenting first and the Defendants second. See Tr. at 4:13-15 (Court). On the factual front, the Plaintiffs emphasized that the Defendants' payment methodology is and always has been the same across all class wells, and that the payouts are based on index prices rather than actual proceeds. See Tr. at 8:4-13:7 (Brickell). The Plaintiffs used Westfall as an example, and demonstrated how, if Westfall had been paid by proceeds from arms-length sales, rather than index prices, Westfall would have received a $0.40/MMBtu higher rate than he did. See Tr. at 14:12-16:13 (Brickell). The Plaintiffs asserted that the United States had its own leases with the Defendants, that it audited the Defendants, and that, after the audit, the Defendants began paying the United States on natural gas liquids. See Tr. at 21:15-21 (Brickell). On the legal front, the Plaintiffs minimized the significance of Roderick, arguing that the case chastised the district court for not considering lease variations, but did not hold that lease variations necessarily destroy commonality or predominance. See Tr. at 17:4-19:8 (Brickell). They also discussed BP America Production Co. v. Patterson, 263 P.3d 103 (Colo. 2011)(en banc)("Patterson"), arguing that it permits courts to consider fraudulent concealment, ignorance, and reliance to be common issues for class-certification purposes. See Tr. at 22:6-27:7 (Brickell).

36. The Defendants presented their opening second. See Tr. at 30:10-69:7 (Court, Sheridan). They summarized how the natural gas production and gathering processes work, as well as the Plaintiffs' case against them. See Tr. at 30:10-40:25 (Sheridan, Court). They stated that they pay royalties based on an index price — which itself is based on what the gas would sell for in an arms-length transaction, rather than in an affiliate transaction — at the well head. See Tr. at 30:10-40:25 (Court, Sheridan). They characterized the Plaintiffs' claim that they have been shorted the value of their drip condensate as follows:

Tr. at 39:23-40:25 (Sheridan).

37. The Defendants acknowledged that the Plaintiffs' basic claim has some basis in law, citing Jicarilla v. Supron Energy Corp., 782 F.2d 855 (10th Cir. 1986), but said that this claim is inapplicable here. See Tr. at 41:1-42:7 (Sheridan). They said that this claim arises from the unique fiduciary relationship between the federal government and federally recognized Indian tribes — a relationship that is absent here — and that the Plaintiffs' royalty payouts should properly be based exclusively on their lease provisions. See Tr. at 41:1-42:7 (Sheridan). The Defendants contend that the "plethora of different terms" that exist among the proposed class' leases obliterate commonality. Tr. at 46:1 (Sheridan). Last, the Defendants raised their contention that they would need to introduce extrinsic parol evidence on each of the contracts, that this parol evidence could vary from lease to lease, and that this variance defeats commonality. See Tr. at 49:12-53:10 (Sheridan, Court). The Court pressed the Defendants hard in their opening to answer whether they would or could actually present parol evidence — which would be from the 1940s — and the Defendants conceded that they lacked any such evidence. See Tr. at 49:12-53:10 (Sheridan, Court). The Defendants contended, however, that they possessed, and intended to present, parol evidence regarding the formation of various division orders. See Tr. at 53:3-20 (Sheridan, Court). At the Court's pressing, the Defendants further conceded that division orders are not often negotiated in any meaningful way, but they argued that they constitute valuable evidence of the course of conduct between the parties. See Tr. at 53:11-55:6 (Sheridan, Court).

b. The Plaintiffs' First Witness, Reineke.

38. Reinke has a bachelor's degree in petroleum engineering from the Colorado School of Mines, worked at major oil companies like ConocoPhillips and Kansas-Nebraska Natural Gas, and later worked for Sam Dean Oil Corporation in Oklahoma City, Oklahoma. See Tr. at 76:17-25 (Brickell, Reineke). Around 1980, he started his own independent consulting company doing engineering work for various independent well operators; he later became an independent well operator himself. See Tr. at 77:1-7 (Reineke). Since the mid-1990s, he has worked as an expert witness in oil-and-gas cases, and has testified in that capacity in federal cases in Oklahoma, Kansas, and Washington, D.C., and in state court in Arkansas, Wyoming, and West Virginia. See Tr. at 77:8-15 (Brickell, Reineke). He has previously testified in twelve to fifteen class certification hearings. See Tr. at 77:22-78:1 (Brickell, Reineke).

39. Reineke testified that all putative class members are paid under the same methodology. See Tr. at 76:9-155:3 (Brickell, Reinke, Berge, Court). See also Plaintiffs' Exhibit 211 at 4-6. He testified that all royalty owners are alike in that they have no active role in the operations taking place upon their mineral estate, and, therefore, they are not responsible for, nor have any control over, any of the costs, expenses or decisions associated with the production and marketing of the products from their mineral estate. He asserted that, similarly, the owners of overriding royalty interests have no active role, and typically do not bear the costs of production and marketing. Reineke also opined that the Defendants did not pay based on the price of an arm's length sale of gas at the wellhead:

Tr. at 86:2-10 (Brickell, Reineke); id. at 87:24-88:5 (Brickell, Reineke); id. at 106:22-107:17 (Brickell, Reineke).

c. The Plaintiffs' Second Witness, Ley.

40. Ley testified that she has an accounting degree from Oklahoma State University. See Tr. at 156:8-9 (Ley). After graduation, she worked at "one of the Big Four firms" as an auditor, leaving after six-and-a-half years to start her own firm with one of her partners. Tr. at 156:8-19 (Ley). She has run her firm, which has fifteen employees, for almost twenty-five years; in that time she has served as president of the Oklahoma Society of Certified Public Accountants and chairperson of the Oklahoma Accountancy Board. See Tr. at 157:2-11 (Ley). She has worked on "at least 30 class actions" before this case. Tr. at 157:18-19 (Ley).

41. Ley is a damages expert, and stated that she has calculated damages in class actions "that have many times th[is case's] number of royalty owners and may times th[is case's] number of leases." Tr. at 160:11-13 (Ley). See Tr. at 160:3-5 (Brickell)(estimating that the class contains 2,300 members and approximately 500 leases). Ley spoke in general terms about damage calculations on all of the Plaintiffs' claims, but testified with the most specificity on the late-payments claim. She said that royalty payments were, in some instances, made outside of the PPA's 45-day window. See Tr. at 178:3-14 (Ley, Brickell). She acknowledged that not every payment was made late, but that late payments were especially amenable to class-action treatment, because "[t]he calculation can be done based upon a formula or a program, or a query. . . so that th[e late] payments are identified very quickly." Tr. at 178:18-23 (Brickell, Ley).

d. The Plaintiffs' Third Witness, Kaplin.

42. Kaplin testified that he graduated from Wichita State University in 1974 with a degree in mechanical engineering, and worked for Texaco, Inc., as a production engineer in Great Bend, Kansas, where he "basically oversaw Texaco's operations in the field on oil and gas wells." Tr. at 224:1-8 (Kaplin). After working for four years in that capacity, Texaco promoted him to "reservoir engineer" and reassigned him to Tulsa, Oklahoma, where he stayed for two more years. Tr. at 224:9-16 (Kaplin). In 1980, he went to work for a company called Dyco Petroleum, Inc., where he worked as a production engineer, then as a production manager, and, later, as vice president of operations. See Tr. at 224:17-225:8 (Kaplin). In 1991, he started his own petroleum consulting company, assisting investors and providing expert testimony. See Tr. at 225:9-15 (Kaplin). He stated that he has testified as an expert in over fifty cases, primarily testifying on behalf of royalty owners, and against major oil-and-gas companies. See Tr. at 225:15-18 (Kaplin). He stated that, over the years, he has been the subject of "more than one Daubert challenge," but that he has never been disqualified or had his testimony disallowed for any reason. Tr. at 227:11-15 (Kaplin, McNamara). He also stated that he served as a consultant to the Oklahoma Tax Commission. See Tr. at 226:6-13 (McNamara, Kaplin).

43. Kaplin stated that he reviewed the class leases, but did not review the actual lease assignments or overriding lease instruments at issue in this case — instead relying on a summary of those documents that the Defendants' expert, Terry, prepared. See Tr. at 231:9-233:1 (McNamara, Kaplin); id. at 253:23-254:5 (McNamara, Kaplin); id. at 848:7-11 (Sheridan, Terry). He talked at length about the various textual provisions in the leases, noting that most of the leases are form contracts. See Tr. at 239:8-18 (McNamara, Kaplin). He presented a spreadsheet that he created which compiles the royalty provisions and categorizes them according to their text; the spreadsheet that he initially presented had numerous erroneous duplications on it, but he replaced that spreadsheet with a corrected spreadsheet with the duplications removed the next day. See Tr. at 266:15-19 (McNamara, Kaplin)(stating that Spreadsheet of Lease Language (Plaintiffs' Ex. 426), and Spreadsheet of Lease Language (Plaintiffs' Ex. 428), are identical, except that the latter "eliminate[d] the duplications" in the former). Kaplin also talked, in considerably less detail, about the overriding royalty provisions, noting that, while they tend to be more unique and less boilerplate than the royalty provisions, a few commonalities — such as the "same as fed" and "same as state" provisions — appear frequently. Tr. at 255:24-256:3 (McNamara, Kaplin).

e. The Plaintiffs' Fourth Witness, Westfall.

44. Westfall, a named Plaintiff and proposed class representative, testified next. See Tr. at 298:13-357:22 (Westfall, Aubrey, Court, Sutphin). Westfall testified that he is retired, but that, before retiring, he worked "in a family business selling school and office products." Tr. at 298:25-299:5 (Aubrey, Westfall). He stated that his father, the late Archie Westfall, purchased a tract of land in Rio Arriba County, New Mexico, in 1952, and passed it on to his son when he died in 2004. See Tr. at 299:12-300:1 (Aubrey, Westfall). Westfall stated that neither he nor his father possessed any particular expertise with regard to the oil-and-gas industry, and that he did not know anything about the history of the mineral lease. See Tr. at 300:2-4 (Aubrey, Westfall). Westfall stated that the lease already encumbered the land when his father bought it, and, thus, neither he nor his father negotiated the lease's terms. See Tr. at 300:5-10 (Aubrey, Westfall).

f. The Plaintiffs' Fifth Witness, Anderson.

45. Anderson, a named Plaintiff and proposed class representative, testified next. See Tr. at 358:12-434:23 (Anderson, Branch, Court, Sheridan). Anderson testified that he lives in Bluffdale and that he is a self-employed architectural designer. See Tr. at 358:19-359:1 (Branch, Anderson). He stated that the Anderson Trust is his personal trust, and its trustees are he and his wife. See Tr. at 359:15-18 (Anderson). He said that he obtained his royalty interests from his mother — or, more precisely, his mother's trust, the Georgia Fay Anderson Living Trust — in 2000 when she died. See Tr. at 360:3-5 (Anderson); id. at 362:10-13 (Anderson, Branch).

46. On cross-examination, the Defendants questioned Anderson regarding when he discovered his causes of action and what diligence he had taken to uncover them. Anderson stated that he did not discover them until his attorneys contacted him about becoming a class representative, and he refused to testify as to when, where, how, and why the Anderson Trust determined that it had a claim in this case, on the basis of attorney-client privilege. See Tr. at 420:20-421:10.

g. The Defendants' First Witness, Ward.

47. Ward, a revenue accountant for WPX Energy, testified first for the Defendants. See Tr. at 438:8-498:14 (Ward, Sutphin, Court, Brickell). Ward clarified that she worked for Julie Mathis, the WPX Energy executive who served as one of the Defendants' primary representatives in this litigation — and another of the Defendants' witnesses. See Tr. at 468:20-22 (Brickell, Ward). Ward testified on a variety of topics, not really going into anything in depth. She rebutted, however, the Plaintiffs' assertion that the Defendants do not pay royalty on well condensate, see Tr. at 441:5-442:7 (Sutphin, Ward), talked about how the Defendants apply prior period adjustments, see Tr. at 454:14-457:17 (Sutphin, Ward), and cast doubt on the Plaintiffs' representations that WPX Rocky Mountain, not WPX Production, owns the Colorado leases, see Tr. at 458:14-22 (Sutphin, Ward); note 9, supra, and accompanying text.

h. The Defendants' Second Witness, Miller.

48. Miller, a recently retired WPX Energy employee, testified next. See Tr. at 499:7-527:18 (Sutphin, Miller, Koop, Court). He stated that, before retiring, he was in charge of handling the Defendants' royalty payments on federally owned leases. See Tr. at 500:22-501:3 (Sutphin, Miller). Miller stated that he performed this function for WPX Energy during his eight-year career with them, see Tr. at 500:1-6 (Sutphin, Miller), and had done this job for BP, as well, before working for WPX Energy, see Tr. at 500:13-501:3 (Sutphin, Miller).

i. The Defendants' Third Witness, Emory.

49. Emory, a petroleum engineer, testified next. See Tr. at 532:15-650:11 (Emory, Sutphin, Court, Brickell). He stated that he has a bachelor's degree in mechanical engineering from Michigan State University and a master's in business administration from Cleveland State University. See Tr. at 533:1-3 (Emory); id. at 534:12-16 (Sutphin, Emory). He said that, after getting his education, he worked for BP for several years before moving to a large gas utility in Michigan, working as a project engineer on pipeline projects. See Tr. at 533:3-14 (Emory). He then worked for a power generation company developing natural gas-fueled power plants, before beginning his consulting career. See Tr. at 533:15-22 (Emory). He first worked at the consulting firm Baker & O'Brien in Texas, and then moved to his current job at Pearson Watson Millican Company in Dallas. See Tr. at 53323-534:7 (Sutphin, Emory). Emory stated that he has qualified as an expert in state-court proceedings, in the Queen's Court in Canada, and in a number of ICC and Triple-A arbitration cases, but has never, before this case, testified in federal court. See Tr. at 537:6-17 (Sutphin, Emory).

50. Emory's testimony focused on defending his opinion that this case is not amenable to a common damages model. See Tr. at 542:4-18 (Sutphin, Emory). Emory divided this main opinion into five "sub-opinions." Tr. at 541:25 (Sutphin). First, Emory stated that not all gas is processed for NGL removal, and that some gas, including all coalbed methane and some conventional gas, is merely treated for carbon dioxide removal. See Tr. at 543:1-11 (Emory). He focused on the interconnectivity of the various gathering systems, asserting that it would be impossible to identify with certainty which NGLs originated at which wells. See Tr. at 544:23-548:18 (Sutphin, Emory)(referring to WPX Pipeline Map (Defendants' Ex. 197))("You'd have to do a hydraulic simulation to determine which way these wells want to flow on the gathering systems."). Emory's second sub-opinion is that the varying production conditions — pressure, temperature, and gas composition — prevent classwide resolution of the Plaintiffs' claims. See Tr. at 557:18- (Sutphin, Emory). Emory stated that, even to the extent that the wells produce NGLs, those NGLs differ in their composition, with some containing a higher proportion of heavier, more valuable hydrocarbons than others. See Tr. at 559:1-10 (Sutphin, Emory). Emory opined that these differences go, not only to the varying production value among the class wells, but also to the varying downstream operational costs attributable to each — i.e., when the NGL content of a well rises, its production is more valuable and, at the same time, more costly to process. See Tr. at 563:4-565:11 (Sutphin, Emory). Emory's third sub-opinion is that the varying operational aspects of each plant create variances among the class in the reasonable post-production costs that can be deducted. See Tr. at 565:12-566:10 (Sutphin, Emory). Emory used, as an illustrative example, the varying fuel consumption of the different plants, and further noted that a plant's consumption changes over time. See Tr. at 566:11-567:8 (Sutphin, Emory). Emory's fourth sub-opinion was simply that the class is, under the keep-whole method, compensated for the value of drip condensate. See Tr. at 568:3-18 (Sutphin, Emory). This sub-opinion essentially just pointed out that, when drip condensate is still entrained in the gas at the wellhead, it raises the MMBtu factor of the gas, as measured at the wellhead; because the Defendants pay on the basis of MMBtus, Emory said, they effectively are paying for drip condensate. See Tr. at 568:22-23 (Sutphin, Emory). Emory's fifth and final sub-opinion is that post-production costs vary from well to well, thus making a classwide damages determination on that issue impractical. See Tr. at 576:1-13 (Sutphin, Emory).

j. The Defendants' Fourth Witness, Griffin.

51. Dr. Griffin, an endowed professor of economics at the George Bush School at Texas A&M University, testified next. See Tr. at 650:25-722:10 (Griffin, Berge, Court, Brickell). Dr. Griffin received his bachelor's degree in economics and mathematics from Southern Methodist University, and his Ph.D. in economics from the University of Pennsylvania. See Tr. at 652:11-24 (Berge, Griffin). He stated that he has written eight books in the field of economics, including a textbook on energy economics and a book on smart energy policy. See Tr. at 653:14-21 (Berge, Griffin). He has testified as an expert witness "a number of times," although never in New Mexico. Tr. at 653:22-654:9 (Berge, Griffin).

52. Dr. Griffin described the results of an economic analysis he conducted of Plaintiffs' claims. See Tr. at 660:19-662:16 (Berge, Griffin). Dr. Griffin stated that he compared, well-by-well, the royalty amounts that the Defendants actually paid on production during the proposed class period to the amounts that they would have paid under the whole stream value methodology. See Tr. at 660:19-662:16 (Berge, Griffin). Dr. Griffin's analysis began with production data from 846 wells, representing a cross-sampling of wells by formation, location, and MMBtu content. See Tr. at 660:19-662:16 (Berge, Griffin). Dr. Griffin then divided the 846 wells into ten groups of 84 or 85 wells each, based upon Btu content of the production from each well. From each group, Dr. Griffin randomly selected ten wells. See Tr. at 663:24-664:16 (Berge, Griffin). To determine the value of the production from each well, for each relevant month, under Plaintiffs' theories, Dr. Griffin first aggregated the market values of the constituent parts of the production stream, including the entrained liquefiable hydrocarbons and the residue gas. From this monthly, well-by-well aggregate value, Dr. Griffin then deducted the appropriate expenses that would have been incurred in connection with gathering, processing, and treatment of the production, applicable taxes, and transportation expenses. See Summary Count for Whole Value Vs. Keep Whole Value (Defendants' Ex. 148); Aggregate Royalty Payments: Whole Stream Value Minus Keep Whole Value (Defendants' Ex. 149). Dr. Griffin's study compared the royalty amounts that the Defendants paid under the keep-whole methodology, well-by-well and month-by-month, to the amounts that would have been owed under a whole-stream value methodology. He found that, while the royalty owners generally benefit from the whole-stream methodology, when processing costs are deducted, the difference between the two methodologies is inconsistent and relatively minor.34

k. The Defendants' Fifth Witness, Mathis.

53. Mathis, WPX Energy's director of revenue and regulatory accounting, testified next. See Tr. at 723:22-755:23 (Sutphin, Mathis, Court, Brickell). Mathis stated that she ran a division of fifty-five to sixty people, and that she was Ward's current boss and Miller's former boss. See Tr. at 724:11-725:2 (Sutphin, Mathis). Mathis testified on two issues: primarily, she testified about the "royalty hotline" that WPX Energy maintained to field questions from royalty owners, see Tr. at 725:3-11 (Sutphin, Mathis); secondarily, she briefly attempted to justify the keep-whole methodology, see Tr. at 736:22-727:17 (Sutphin, Mathis). On the first issue, Mathis stated that a full-time employee staffed the royalty hotline and that this employee fielded royalty inquiries near-daily, including from several class members. See Tr. at 725:3-736:19 (Sutphin, Mathis). Mathis discussed a small sample of these telephone calls, of which WPX Energy records and catalogues the gist. See Tr. at 725:3-736:19 (Sutphin, Mathis). On the second issue, Mathis presented a less-than-sophisticated attack on potential alternatives to the keep-whole methodology:

Tr. at 739:6-22 (Sutphin, Mathis).35

l. The Defendants' Sixth Witness, Terry.

54. Terry, an expert witness who focused her expert testimony on the language in the class leases, testified next. See Tr. at 770:15-952:16 (Terry, Sheridan, Court, McNamara). Terry is an attorney and a member of the Oklahoma and Texas bars, and graduated from the University of Oklahoma for both undergraduate and law school. See Tr. at 771:17-772:7 (Sheridan, Terry). After graduating from law school in 1979, Terry worked for Fina Oil and Chemical Company, see Tr. at 771:11-16 (Sheridan, Terry), where she worked in the legal department for four years before moving into the exploration and production department, where she became manager of their natural gas contracts, see Tr. at 772:15-25 (Terry). She worked in that capacity for two years, see Tr. at 773:11-17 (Sheridan, Terry), before becoming a consultant, see Tr. at 774:15-18 (Sheridan, Terry). Terry stated that she has testified as an expert in numerous oil-and-gas class actions, where she typically focuses on "analyzing the companies' contractual instruments with the various royalty owners and overriding royalty interest owners. So that would involve analyzing leases, assignments, [and] grants." Tr. at 774:25-775:15 (Sheridan, Terry). See Tr. at 776:10-777:12 (Sheridan, Terry). She stated that she had also provided expert testimony on "industry custom and usage" — essentially, the way that words in an oil-and-gas contract should be interpreted. Tr. at 775:22-776:4 (Sheridan, Terry). The Plaintiffs then "stipulate[d] to Ms. Terry's qualifications" to testify as an expect. Tr. at 777:13-16 (McNamara).

55. Terry testified about overseeing a review of historical lease and division order files to locate instruments creating overriding royalty interests that burden the Defendants' working interests in leases in this case. See Tr. at 831:8-832:2 (Sheridan, Terry). The review that Terry conducted took more than 100 hours, and involved a review of at least sixty file boxes. See Tr. at 832:17-22 (Sheridan, Terry); id. at 847:11-8548:6 (Sheridan, Terry). Terry selected a sample of overriding royalty instruments from the proposed class and prepared a summary of those instruments. See Overriding Royalty Language Used in Various Assignments (Defendants' Ex. 196); Tr. at 828:25-829:10 (Sheridan, Terry); id. at 832:3-16 (Sheridan, Terry); id. at 833:8-835:4 (Sheridan, Terry). Of the 507 leases that are the subject of Plaintiffs' royalty claims, Terry reviewed and classified the leases into fifteen different categories. See Lease Language Chart (Defendants' Ex. 191) Tr. at 813:17-20 (Sheridan, Terry); id. at 797:3-798:2 (Sheridan, Terry); id. at 800:25-802:12 (Sheridan, Terry); id. at 813:21-23 (Sheridan, Terry).

m. Oral Closing Arguments.

56. The Plaintiffs presented their closing argument first, immediately fielding the Court's questions about how the Plaintiffs felt they could distinguish their case from Roderick. See Tr. at 958:1-21 (Court). The Plaintiffs responded that the district court in Roderick had not considered the potentially individualized issues that the varying language in the class leases presents. See Tr. at 960:16-962:14 (Brickell)("[The Tenth Circuit] is saying that, yes, there is a standard, but you [the district judge] never looked at those leases. And you go back and you look at the leases."). The Court inquired about the different textual provisions among the class, asking if the Plaintiffs' were "hanging [their] hat on [the fact] that they're not materially different language?" Tr. at 963:1-2 (Court). The Plaintiffs responded that, no, "they're not materially different. They are the same." Tr. at 963:17-18 (Brickell). The Court also inquired about Mark V, asking how it could "manage a situation" where the Defendants "com[e] in and demand[] a Mark V on every one of these leases?" Tr. at 966:20-22 (Court). The Plaintiffs' response was to essentially point the Court to and describe the holding of Davis v. Devon Energy Corp., noting that, in that case, the Supreme Court of New Mexico reversed a state district court that denied class certification on Mark V grounds. See Tr. at 967:5-22 (Brickell).

57. The Plaintiffs then shifted to delivering their prepared remarks, first establishing that processing does not create any NGLs, but rather, NGLs that were always present in the gas are removed during processing. See note 34, supra. The Plaintiffs emphasized both their case's negative value nature and its manageability:

Tr. at 976:10-977:5 (Brickell). The Plaintiffs also walked the Court through its purported common issues, summarized earlier, before yielding the floor to the Defendants. See Tr. at 985:19-988:11 (Brickell).

58. The Defendants presented next. See Tr. at 994:12-1029:25 (Sheridan, Court). The Court asked the Defendants whether their primary argument against certification was still Mark V, and the Defendants stated that it was. See Tr. at 994:13-25 (Court, Sheridan). The Defendants stated that "[t]he royalty class actions that you see brought in these other states, particularly Kansas and Oklahoma, which have been the source of the opinion[s] in the Tenth Circuit, all arise out of claims for breach of an implied covenant" rather than for breach of contract. Tr. at 995:12-17 (Sheridan). The Defendants characterized Roderick as holding that, "because no determination had been made that the implied duty to market claim . . . would not negate express royalty terms," class certification was inappropriate. Tr. at 996:5-9 (Sheridan). The Defendants discussed ConocoPhillips Co. v. Lyons, asserting that the case's takeaway point is that "[c]ourts are not free to go around implying covenants in contracts," but, rather, must look to the express lease terms when they conflict with any implied-in-law terms the court may wish to apply. Tr. at 1002:7-1003:8 (Sheridan). Last, the Defendants discussed the relevance of division orders, conceding that division orders cannot alter the terms of the lease, but arguing that they can be introduced, under Mark V, as evidence to illuminate the meaning of a lease that the Court has found to be ambiguous:

Tr. at 1009:9-15 (Sheridan).

4. The Post-Hearing Briefing.

59. After the hearing, the parties filed several other documents. The Plaintiffs filed closing arguments, and the Defendants responded. Both parties filed post-hearing memoranda and supplemental case law in support of their positions. Every argument contained in these documents has already been made repeatedly, so the Court will summarize these documents succinctly.

a. Written Closing Argument and Response.

60. The Plaintiffs filed their closing argument roughly three weeks after the conclusion of the hearing. See Plaintiffs' Closing Argument in Support of Class Certification, filed April 25, 2014 (Doc. 234)("Plaintiffs' Closing"). They argue that Mark V does not defeat certification, for three reasons. See Plaintiffs' Closing at 1-9. First, they assert that the Defendants have not produced a significant amount of extrinsic evidence and that such evidence is generally not available in this case, even if it could theoretically be admitted. See Plaintiffs' Closing at 1-5. Second, they argue that the Colorado claims are exempt from Mark V altogether, as Colorado uses a traditional four-corners approach to contract interpretation. See Plaintiffs' Closing at 5-6. Third, they contend that, under Davis v. Devon Energy Corp., the case can be certified under an implied-covenant theory, rather than a pure breach-of-contract theory, thus circumventing Mark V. See Plaintiffs' Closing at 6-9. The Plaintiffs focus the rest of their brief on more generic rule 23 arguments, doubling down on their contention that "the implied duty to market applies to all class members." Plaintiffs' Closing at 13 (capitalization altered for readability). See id. at 9-18.

61. The Defendants responded to the Plaintiffs' Closing Argument. See Defendants' Response to Plaintiffs' Closing Argument in Support of Class Certification, filed May 6, 2014 (Doc. 238)("Defendants' Closing"). The Defendants' Closing brought up one meaningful point, which is that the Court has already dismissed the Defendants implied-duty-to-market claim — truthfully, twice. See Defendants' Closing at 1-3. They reiterated their contention that covenants can be implied only "`in the absence of any express[ term] on the subject.'" Defendants' Closing at 3 (quoting Libby v. DeBaca, 1947-NMSC-007, ¶ 6, 179 P.2d 263).

b. Supplemental Case Law.

62. The Defendants points the Court to Arkalon Grazing Association v. Chesapeake Operating, Inc., No. CIV 09-1394 CM, 2014 WL 3089556 (D. Kan. July 7, 2014)(Murguia, J.), asserting that the district court in that case, "[a]fter considering variations in the express language of the more than fifty lease forms covering the 1044 leases at issue, and questions relating to the marketability of gas produced from the more than 400 wells at issue," held that individual issue predominated and refused to certify the class. See Notice of Supplemental Authority in Support of Defendants' Post-Hearing Memorandum in Opposition to Plaintiffs' Motion for Class Certification, filed July 25, 2014 (Doc. 264). The Plaintiffs respond that that case was inapposite in two ways:

Plaintiffs' Corrected Response to Notice of Supplemental Authority, filed September 23, 2014 (Doc. 272)(replacing the initially filed Plaintiffs' Response to Notice of Supplemental Authority, filed July 30, 2014 (Doc. 265)).

63. The Defendants also point the Court to EQT Prod. Co. v. Adair, 764 F.3d 347 (4th Cir. 2014)(Diaz, J., joined by Wilkinson & Keenan, JJ.).36 See Defendants' Notice of Supplemental Authority in Support of Defendants' Response to Plaintiffs' Motion for Class Certification (Doc. No. 205) and Defendants' Post Hearing Memorandum in Opposition to Plaintiffs' Motion for Class Certification (Doc. No. 233), filed September 25, 2014 (Doc. 273)("EQT Supp."). The Defendants argue:

EQT Supp. at 1-2 (citations omitted). They argue that, "[s]econd, the court made clear that the plaintiff in a putative royalty class action is required to demonstrate how variations in the royalty language among differing class members do not defeat commonality," and, "[t]hird, the court made clear that `the need for individualized proof' on certain issues also present in this case, `strongly affects the predominance analysis of Rule 23(b).'" EQT Supp. at 2 (citations omitted).

CONCLUSIONS OF LAW

Having made its findings of fact, the Court issues the following legal conclusions, first outlining the law and then analyzing the facts at hand. Part I outlines the law regarding class certification, Part II outlines the law regarding New Mexico's statutes of limitations and the discovery rule, and Part III outlines the law regarding the implied covenant to market in New Mexico. Part IV is the analysis.

I. LAW REGARDING CERTIFYING CLASS ACTIONS UNDER RULE 23(b)(3).

1. Rule 23 sets forth the requirements for certifying a class action under the federal rules. See Fed. R. Civ. P. 23. All classes must satisfy: (i) all the requirements of rule 23(a); and (ii) one of the three sets of requirements under rule 23(b), where the three sets of requirements correspond to the three categories of classes that a court may certify. See Fed. R. Civ. P. 23(a)-(b). The plaintiff37 bears the burden of showing that the requirements are met, see Rex v. Owens ex rel. Okla., 585 F.2d 432, 435 (10th Cir. 1978); Pueblo of Zuni v. United States, 243 F.R.D. 436, 444 (D.N.M. 2007)(Johnson, J.), but, in doubtful cases, class certification is favored, see Esplin v. Hirschi, 402 F.2d 94, 101 (10th Cir. 1968)("[T]he interests of justice require that in a doubtful case, . . . any error, if there is to be one, should be committed in favor of allowing the class action."); Eisen v. Carlisle & Jacquelin, 391 F.2d 555, 563 (2d Cir. 1968)("[W]e hold that. . . rule [23] should be given a liberal rather than a restrictive interpretation, and that [denying certification] is justified only by a clear showing to that effect. . . ."). In ruling on a class certification motion, the Court need not accept the representations of either party, but must independently find the relevant facts to a preponderance of the evidence.38 See Rutstein v. Avis Rent-A-Car Sys., Inc., 211 F.3d 1228, 1234 (11th Cir. 2000)("Going beyond the pleadings is necessary, as a court must understand the claims, defenses, relevant facts, and applicable substantive law in order to make a meaningful determination of the certification issues."). "In determining the propriety of a class action, the question is not whether the plaintiff or plaintiffs have stated a cause of action or will prevail on the merits, but rather whether the requirements of Rule 23 are met." Anderson v. City of Albuquerque, 690 F.2d 796, 799 (10th Cir. 1982). See Vallario v. Vandehey, 554 F.3d 1259, 1267 (10th Cir. 2009)("We, of course, adhere to the principle that class certification does not depend on the merits of a suit."). Still, the Court must conduct a rigorous analysis of the rule 23 requirements, even if the facts that the Court finds in its analysis bear on the merits of the suit:

Wal-Mart, 131 S.Ct. 2541, 2551-52 (2011)(Scalia, J.). In a subsequent, seemingly contradictory admonition, however, the Supreme Court cautioned district courts not to decide the merits of the case at the class certification stage:

Amgen Inc. v. Conn. Ret. Plans & Trust Funds, 133 S.Ct. 1184, 1194-95 (2013)(Ginsburg, J.). To reconcile these two directives, the Court will find facts for the purposes of class certification by the preponderance of the evidence, but will allow the parties to challenge these findings during the subsequent merits stage of this case. This approach is analogous to preliminary injunction practice, and, although the Tenth Circuit has not endorsed it, other circuits have. See Abbott v. Lockheed Martin Corp., 725 F.3d 803, 810 (7th Cir. 2013); In re Hydrogen Peroxide Antitrust Litig., 552 F.3d 305, 313 (3d Cir. 2008); Gariety v. Grant Thornton, LLP, 368 F.3d 356, 366 (4th Cir. 2004). Because of the res judicata effect a class judgment has on absent parties, a court may not simply accept the named parties' stipulation that class certification is appropriate, but must conduct its own independent rule 23 analysis. See Amchem Prods., Inc. v. Windsor, 521 U.S. at 620-22. In taking evidence on the question of class certification, the Federal Rules of Evidence apply, albeit in a relaxed fashion.39

Fed. R. Civ. P. 23(a). "A party seeking to certify a class is required to show . . . that all the requirements of [rule 23(a)] are clearly met." Reed v. Bowen, 849 F.2d 1307, 1309 (10th Cir. 1988). "Although the party seeking to certify a class bears the burden of proving that all the requirements of Rule 23 are met, the district court must engage in its own `rigorous analysis' of whether `the prerequisites of Rule 23(a) have been satisfied.'" Shook v. El Paso Cnty., 386 F.3d 963, 968 (10th Cir. 2004)(quoting Gen. Tel. Co. of the S.W. v. Falcon, 457 U.S. 147, 161 (1982))(citing Reed v. Bowen, 849 F.2d at 1309). These four requirements are often referenced as numerosity, commonality, typicality, and adequacy, respectively.

a. Numerosity.

3. Rule 23(a)(1) requires that the putative class membership be sufficiently large to warrant a class action, because the alternative of joinder is impracticable. Some courts have held that numerosity may be presumed at a certain number; the Tenth Circuit, however, "has never adopted such a presumption." Trevizo v. Adams, 455 F.3d 1155, 1162 (10th Cir. 2006). "The Tenth Circuit has stated that there is `no set formula' to determine whether the numerosity requirement is met; instead, it is a fact-specific inquiry best left to the district court's discretion." Gonzales v. City of Albuquerque, No. CIV 09-0520 JB/RLP, 2010 WL 4053947, at *7 (D.N.M. Aug. 21, 2010)(Browning, J.)(quoting Rex v. Owens, 585 F.2d 432, 436 (10th Cir. 1978)). Cf. Mullen v. Treasure Chest Casino, LLC, 186 F.3d 620, 624 (5th Cir. 1999)(finding that proposed class consisting of "100 to 150 members . . . is within the range that generally satisfies the numerosity requirement"). In determining whether a proposed Class meets the numerosity requirement, "the exact number of potential members need not be shown," and a court "may make `common sense assumptions' to support a finding that joinder would be impracticable." Neiberger v. Hawkins, 208 F.R.D. 301, 313 (D. Colo. 2002)(citation omitted). See Bittinger v. Tecumseh Prods. Co., 123 F.3d 877, 884 n.1 (6th Cir. 1997)(noting that rule 23(a)(1) is not a "`strict numerical test'"; holding, however, that where class comprises over 1,100 persons, suggestion that joinder is not impractical is "frivolous")(citation omitted); Robidoux v. Celani, 987 F.2d 931, 936 (2nd Cir. 1993)("[T]he difficulty in joining as few as 40 putative class members should raise a presumption that joinder is impracticable." (citation omitted)). "Satisfaction of the numerosity requirement does not require that joinder is impossible, but only that plaintiff will suffer a strong litigational hardship or inconvenience if joinder is required." Cook v. Rockwell Int'l Corp., 151 F.R.D. 378, 384 (D. Colo. 1993). See Robidoux v. Celani, 987 F.2d 931, 935 (2d Cir. 1993)("Impracticable does not mean impossible."). The Court has previously found that joinder of "several hundred tenants and homeowners" would be impracticable, and thus the proposed class met rule 23(a)(1)'s numerosity requirement. Lowery v. City of Albuquerque, 273 F.R.D. 668, 683 (D.N.M. 2011)(Browning, J.). At the other end of the spectrum, the Court found that a class of 6,100 members, in a securities action, was so numerous that joinder was impracticable. See Lane v. Page, 272 F.R.D. 558, 574 (D.N.M. 2011)(Browning, J.). See also Thompson v. Jiffy Lube Intern., Inc., 250 F.R.D. 607, 620 (D. Kan. 2008)(Brown, J.)(finding that the numerosity requirement is met by a proposed class seeking injunctive relief that constituted "at least tens of millions of members," and by a proposed class seeking damages that constitutes at least 4,900 members).

b. Commonality.

4. Rule 23(a)(2) requires that "there are questions of law or fact common to the class." Fed. R. Civ. P. 23(a)(2) (emphasis added). Even "factual differences in the claims of the individual putative class members should not result in a denial of class certification where common questions of law exist." In re Intelcom Group Sec. Litig., 169 F.R.D. 142, 148 (D. Colo. 1996). See Adamson v. Bowen, 855 F.2d 668, 676 (10th Cir. 1988)("That the claims of individual putative class members may differ factually should not preclude certification under Rule 23(b)(2) of a claim seeking the application of a common policy."); Lopez v. City of Santa Fe, 206 F.R.D. 285, 289 (D.N.M. 2002)(Vázquez, J.)("Commonality requires only a single issue common to the class, and the fact that `the claims of individual putative class members may differ factually should not preclude certification under Rule 23(b)(2) of a claim seeking the application of a common policy." (citations omitted)). A single common question will suffice to satisfy rule 23(a)(2), but the question must be one "that is central to the validity of each one of the claims." Wal-Mart, 131 S. Ct. at 2551.

5. "The commonality requirement has been applied permissively in securities fraud litigation." In re Initial Pub. Offering Sec. Litig., 227 F.R.D. 65, 87 (S.D.N.Y. 2004). "Securities cases often involve allegations of common courses of fraudulent conduct, which can be sufficient to satisfy the commonality requirement." 5 Jerold S. Solovy, Ronald L. Marmer, Timothy J. Chorvat & David M. Feinberg, Moore's Federal Practice § 23.23[4][b], at 23-77 (3d ed. 2004). "Where the facts as alleged show that Defendants' course of conduct concealed material information from an entire putative class, the commonality requirement is met." In re Oxford Health Plans, Inc. Sec. Litig., 191 F.R.D. 369, 374 (S.D.N.Y. 2000). Accord Initial Pub. Offering, 227 F.R.D. at 87 ("In general, where putative class members have been injured by similar material misrepresentations and omissions, the commonality requirement is satisfied.").

6. The commonality requirement was widely perceived to lack teeth before the Supreme Court's decision in Wal-Mart, which grafted the following requirements onto rule 23(a)(2): (i) that the common question is central to the validity of each claim that the proposed class brings; and (ii) that the common question is capable of a common answer. See Wal-Mart, 131 S. Ct. at 2550-52. In that case, a proposed class of about 1.5 million current and former Wal-Mart employees sought damages under Title VII for Wal-Mart's alleged gender-based discrimination. See 131 S. Ct. at 2547. Wal-Mart, however, had no centralized company-wide hiring or promotion policy, instead opting to leave personnel matters to the individual store managers' discretion. See 131 S. Ct. at 2547-48. The plaintiffs argued that, although no discriminatory formal policy applied to all proposed class members, "a strong and uniform `corporate culture' permits bias against women to infect, perhaps subconsciously, the discretionary decisionmaking of each one of Wal-Mart's thousands of managers — thereby making every [proposed class member] the victim of one common discriminatory practice." 131 S. Ct. at 2548. The Supreme Court disagreed that such a theory constitutes a common question under rule 23(a)(2).

Wal-Mart, 131 S. Ct. at 2550-51 (emphasis in original)(quoting Nagareda, supra, at 132). In EQT Production Co. v. Adair, the Fourth Circuit stated:

764 F.3d at 366 (citations omitted).

7. In Wal-Mart, Justice Scalia stated: "Wal-Mart is entitled to individualized determinations of each employee's eligibility for backpay." 131 S. Ct. at 2546. From this observation, he then concluded:

Wal-Mart, 131 S. Ct. at 2561. Thus, the common question or questions cannot be "incidental" nor can the plaintiff submit a long list of "incidental" questions or issues, and say that they predominate over the real issues to be used.

c. Typicality.

8. Rule 23(a)(3) requires that the named representative's claims be typical of the class' claims. See Fed. R. Civ. P. 23(a)(3). The typicality requirement ensures that absent proposed class members are adequately represented by evaluating whether the named plaintiff's interests are sufficiently aligned with the class' interest. See Baby Neal ex rel. Kanter v. Casey, 43 F.3d 48, 57 (3d Cir. 1994); Nicodemus v. Union Pac. Corp., 204 F.R.D. 479, 490 (D. Wyo. 2001). The Supreme Court of the United States has noted that "[t]he commonality and typicality requirements of Rule 23(a) tend to merge." Gen. Tele. Co. of the Sw. v. Falcon, 457 U.S. at 157 n.13. "Provided the claims of Named Plaintiffs and putative class members are based on the same legal or remedial theory, differing fact situations of the putative class members do not defeat typicality." DG v. Devaughn, 594 F.3d 1188, 1198 (10th Cir. 2010)(citing Adamson v. Bowen, 855 F.2d 668, 676 (10th Cir. 1988)). "[L]ike commonality, typicality exists where . . . all putative class members are at risk of being subjected to the same harmful practices, regardless of any class member's individual circumstances." DG v. Devaughn, 594 F.3d at 1199. Factual differences among some of the proposed class members will "not defeat typicality under Rule 23(a)(3) so long as the claims of the class representative and putative class members are based on the same legal or remedial theory." Adamson v. Bowen, 855 F.2d 668, 676 (10th Cir. 1988). See Penn v. San Juan Hosp., Inc., 528 F.2d 1181, 1189 (10th Cir. 1975)("It is to be recognized that there may be varying fact situations among individual members of the class and this is all right so long as the claims of Plaintiffs and the other putative class members are based on the same legal or remedial theory."). Accordingly, differences in the amount of damages will not defeat typicality. See Harrington v. City of Albuquerque, 222 F.R.D. 505, 511 (D.N.M. 2004)(Hansen, J.). "The United States Court of Appeals for the Tenth Circuit has said that the typicality requirement is satisfied if there are common questions of law or fact." Gianzero v. Wal-Mart Stores Inc., No. CIV 09-00656 REB/BNB, 2010 WL 1258071, at *3 (D. Colo. Mar. 29, 2010)(citing Milonas v. Williams, 691 F.2d 931, 938 (10th Cir. 1982))("In determining whether the typicality and commonality requirements have been fulfilled, either common questions of law or fact presented by the class will be deemed sufficient."); Adamson v. Bowen, 855 F.2d at 676 ("[D]iffering fact situations of putative class members do not defeat typicality under Rule 23(a)(3) so long as the claims of the class representative and putative class members are based on the same legal or remedial theory." (citations omitted)).

d. Adequacy.

9. Rule 23(a)(4) requires that "representative parties will fairly and adequately protect the interests of the class." Fed. R. Civ. P. 23(a)(4). This requirement protects the due-process interests of unnamed proposed class members — who are bound by any judgment in the action. See Matsushita Elec. Indus. Co. v. Epstein, 516 U.S. 367, 379 n.5 (1996)(characterizing adequacy of representation as a constitutional requirement); Lile v. Simmons, 143 F.Supp.2d 1267, 1277 (D. Kan. 2001)("Due process requires that the Court `stringently' apply the competent representation requirement because putative class members are bound by the judgment (unless they opt out), even though they may not actually be aware of the proceedings."). "The requirement of fair and adequate representation is perhaps the most important of the criteria for class certification set forth in Rule 23(a)." Miller ex rel. S.M. v. Bd. of Educ., 455 F.Supp.2d 1286, 1294 (D.N.M. 2006)(Armijo, J.). See Cobb v. Avon Prods., Inc., 71 F.R.D. 652, 654 (W.D. Pa. 1976)("Adequacy of the representative is of monumental importance since representation demands undiluted loyalty to the class interests. . . ."). The Tenth Circuit has identified two questions relevant to the adequacy of representation inquiry: (i) whether the named plaintiffs and their counsel have any conflicts with other proposed class members; and (ii) whether the named plaintiffs and their counsel will vigorously prosecute the action on the class' behalf. See Rutter & Wilbanks Corp. v. Shell Oil Co., 314 F.3d 1180, 1187-88 (10th Cir. 2002). In considering this second question, the experience and competence of the attorney representing the class may inform the court's analysis. See Lopez v. City of Santa Fe, 206 F.R.D. at 289-90. Although Tenth Circuit precedent suggests that the adequacy-of-counsel analysis is conducted as a part of the rule 23(a)(4) inquiry, this analysis has likely now been moved entirely to rule 23(g).40 This difference matters little, except that now district courts should not refuse to certify a class on the basis of inadequacy of counsel alone.

10. The Supreme Court "has repeatedly held [that] a class representative must be part of the class and `possess the same interest and suffer the same injury' as the putative class members." E. Tex. Motor Freight Sys. Inc. v. Rodriguez, 431 U.S. 395, 403 (1977)(quoting Schlesinger v. Reservists Comm. to Stop the War, 418 U.S. 208, 216 (1974)). Courts have found that intra-class conflicts "may negate adequacy under Rule 23(a)(4)." Langbecker v. Elec. Data Sys. Corp., 476 F.3d 299, 315 n.28 (5th Cir. 2007)(holding that the district court erred in certifying a class without evaluating intra-class conflicts). See Pickett v. Iowa Beef Processors, 209 F.3d 1276, 1280 (11th Cir. 2000)(finding that representation was inadequate where the class included those "who claim harm from the very acts from which other putative class members benefitted"); Broussard v. Meineke Discount Muffler Shops, Inc., 155 F.3d 331, 344 (4th Cir. 1998)(holding that the current franchisees who had an interest in the continued viability of the franchiser had an inherent conflict with former franchisees whose only interest was in the maximization of damages); Alston v. Va. High Sch. League, Inc., 184 F.R.D. 574, 579 (W.D. Va. 1999)(ruling that a class of all high school female athletes could not be certified — even if the alleged conduct of the defendant school system was discriminatory — when some female athletes did not share the same goals or interests as the named female plaintiffs, because those unnamed female athletes were satisfied with and/or benefitted from the alleged discriminatory treatment).

11. On the other hand, "only a conflict that goes to the very subject matter of the litigation will defeat a party's claim of representative status. Beyond that straightforward proposition, defining the level of antagonism or conflict that should preclude class certification is a more difficult proposition." 7A Charles Alan Wright, Arthur A. Miller & Mary K. Kane, Federal Practice & Procedure § 1768, at 389-93 (3d ed. 2005). "Though a plaintiff cannot be an adequate representative if he or she has a conflict of interest with putative class members, not every potential disagreement between a class representative and the putative class members will stand in the way of a class suit." Lowery v. City of Albuquerque, 273 F.R.D. at 680 (citation omitted).

2. Different Categories of Classes: Rule 23(b).

12. Once the court finds that the threshold requirements have been met, "it must then examine whether the class falls within at least one of three categories of suits set forth in Rule 23(b)." Adamson v. Bowen, 855 F.2d at 675. See DG v. Devaughn, 594 F.3d at 1199 ("In addition to satisfying Rule 23(a)'s requirements, the class must also meet the requirements of one of the types of classes described in subsection (b) of Rule 23."). Rule 23(b) provides that a class action is appropriate if the threshold requirements are satisfied, and the case falls into one or more of three categories:

Fed. R. Civ. P. 23(b). "Only one of rule 23(b)'s subdivisions must be satisfied to meet the class-action requirements." Gonzales v. City of Albuquerque, No. CIV 09-0520 JB/RLP, 2010 WL 4053947, at *11 (D.N.M. Aug. 21, 2010)(citing Carpenter v. Boeing, Co., 456 F.3d 1183, 1187 (10th Cir. 2006)(stating that the district court must determine whether a suit "falls within one of the categories of actions maintainable as class actions")).

13. The three categories of class actions — really four, as rule 23(b)(1) contains two subcategories, known as (b)(1)(A) and (b)(1)(B) class actions — are not of equal utility. Class actions under (b)(1) can be certified only in very particular circumstances. Class actions under (b)(2) are broadly available, but are only capable of seeking injunctive or declaratory relief, and not damages. Far and away the most controversial class action category, (b)(3), can be brought for class-wide damages, injunctive relief, declaratory relief, or any combination thereof. Class actions under (b)(3) always require notice to all proposed class members of certification of the class, and those individuals must be given the opportunity to opt out if they so desire. See Fed. R. Civ. P. 23(c)(2)(B); Phillips Petrol. Co. v. Shutts, 472 U.S. at 812 ("[W]e hold that due process requires at a minimum that an absent plaintiff be provided with an opportunity to remove himself from the class by executing and returning an `opt out' or `request for exclusion' form to the court."). The other class action categories, however, are ordinarily mandatory, and neither notice nor opportunity to opt out needs to be given. See Fed. R. Civ. P. 23(c)(2)(B); Phillips Petrol. Co. v. Shutts, 472 U.S. at 811 n.3 (limiting the constitutional requirement of an opt-out notice "to those class actions which seek to bind known plaintiffs concerning claims wholly or predominately for money judgments"). The Court will focus on the most important form of class action, the (b)(3) damages class action.41

14. To satisfy rule 23(b)(3), the court must find "that the questions of law or fact common to the members of the class predominate over any questions affecting only individual members, and that a class action is superior to other available methods for the fair and efficient adjudication of the controversy." Fed. R. Civ. P. 23(b)(3) (emphases added). Rule 23(b)(3) provides that "[t]he matters pertinent to these findings include": (i) the interest of members of the class in individually controlling the prosecution or defense of separate actions; (ii) the extent and nature of any litigation concerning the controversy already commenced by or against members of the class; (iii) the desirability or undesirability of concentrating the litigation of the claims in the particular forum; and (iv) the difficulties likely to be encountered in the management of a class action. Fed. R. Civ. P. 23(b)(3)(A)-(D).

i. The Predominance Requirement.

15. Rule 23(b)(3)'s first requirement is that questions common to the class predominate over those that are individualized. See Fed. R. Civ. P. 23(b)(3). A question is common when "the same evidence will suffice for each member to make a prima facie showing," Blades v. Monsanto Co., 400 F.3d 562, 566 (8th Cir. 2005)(citing In re Visa Check/MasterMoney Antitrust Litig., 208 F.3d 124, 136-40 (2d Cir. 2001)), or when the issue is "susceptible to generalized, class-wide proof," In re Nassau Cnty. Strip Search Cases, 461 F.3d 219, 227 (2d Cir. 2006). A question is individual when "the members of a proposed class will need to present evidence that varies from member to member," Blades v. Monsanto Co., 400 F.3d at 566. Although a case need not present only common questions to merit certification, and the presence of some individual questions does not destroy predominance, the rule 23(b)(3) predominance requirement is much stricter than the rule 23(a)(1) commonality requirement: the latter requires only that a common question or questions exist; the former requires that the common question or questions predominate over the individual ones. See Amchem Prods., Inc. v. Windsor, 521 U.S. 591, 623-24; In re Thornburg Mortg., Inc. Sec. Litig., 912 F. Supp. 2d at 1225 ("The predominance criterion of rule 23(b)(3) is `far more demanding' than rule 23(a)(2)'s commonality requirement."). As the Tenth Circuit, addressing a Title VII claim, put it:

Monread v. Potter, 367 F.3d 1224, 1237 (10th Cir. 2004)(Ebel, J.)(footnote omitted).

16. The predominance question applies to both macro damages — the total class damages — and to the micro damages — the individual damages. In Comcast Corp. v. Behrend, 133 S.Ct. 1426 (2013), the Supreme Court, in a five-to-four decision, in which Justice Scalia wrote the majority opinion, held that the court could not accept as evidence that damages were susceptible of measurement across an entire class — as rule 23(b)(3) requires for certification of a class on the theory that questions of law or fact common to class members predominate over any questions affecting only individual members — the regression model which the plaintiffs' expert had developed. The plaintiffs argued four theories of antitrust violations; one theory was that Comcast Corp.'s activities had an antitrust impact, because Comcast Corp.'s activities reduced the level of competition from "overbuilders," companies that build competing cable networks in areas where an incumbent cable company already operates. The district court found, among other things, that the damages resulting from overbuilder-deterrence impact could be calculated on a classwide basis. To establish such damages, the plaintiffs relied solely on the testimony of Dr. James McClave. Dr. McClave designed a regression model which compared actual cable prices in the Philadelphia "Designated Market Area" with hypothetical prices that would have prevailed but for Comcast Corp.'s allegedly anticompetitive activities. The model calculated damages of $875,576,662.00 for the entire class. As Dr. McClave acknowledged, however, the model did not isolate damages resulting from any one theory of antitrust impact. The district court nonetheless certified the class.

17. The Third Circuit affirmed the district court decision. The Third Circuit concluded that the plaintiffs "provided a method to measure and quantify damages on a classwide basis," finding it unnecessary to decide "whether the methodology was a just and reasonable inference or speculation." 133 S. Ct. at 1433 (quoting 655 F.3d 182, 206 (3d Cir. 2011)). The Supreme Court granted certiorari on the question "[w]hether a district court may certify a class action without resolving whether the plaintiff class had introduced admissible evidence, including expert testimony, to show that the case is susceptible to awarding damages on a class-wide basis." 133 S. Ct. at 24. Justice Scalia criticized the Court of Appeals' reluctance to entertain arguments against the plaintiffs' damages model "simply because those arguments would also be pertinent to the merits determination. . . ." 133 S. Ct. at 1433. Justice Scalia said that

Comcast Corp. v. Behrend, 133 S. Ct. at 1433. Justice Scalia stated that, under the Third Circuit's logic, "at the class-certification stage, any method of measurement is acceptable so long as it can be applied classwide, no matter how arbitrary the measurements may be. Such a proposition would reduce rule 23(b)(3)'s predominance requirement to a nullity." 133 S. Ct. at 1433 (emphasis in original).

18. It is clear that Comcast Corp. v. Behrend applies to classwide damages. It is less clear that Comcast Corp. v. Behrend's language applies to the determination of individual damages. There are three ways that the Court could deal with Comcast Corp. v. Behrend and the determination of individual damage awards. First, the Court could decide that Comcast Corp. v. Behrend applies only to classwide damages and is not controlling at all in the determination of individual damages. Second, the Court could decide that everything that Justice Scalia said about classwide damages also applies to the determination of individual damages. Third, the Court could decide that Justice Scalia said some things relating to the determination of individual damages, but not the same things that apply to classwide damages. As to the first option, while much could be said of limiting Justice Scalia's opinion to classwide damages — even from the language of the opinion and from the wording of the question presented — the Court is reluctant to say that it has nothing to say that might be relevant to the determination of individual damages awards. Some of Justice Scalia's concerns about admissible evidence to determine damages — whether classwide or individual damage awards — still seems relevant to whether damages are classwide or individual. While Justice Scalia was not addressing the determination of individual damage awards, some of what he said — and how he said it — should cause the Court to be cautious in determining a methodology for calculating individual damage awards. On the other hand, the Court is not convinced that it should or even can apply Comcast Corp. v. Behrend's language to the individual determination of damages as it does to classwide damages. The dissent stated that "[r]ecognition that individual damages calculations do not preclude class certification under Rule 23(b)(3) is well nigh universal." 133 S. Ct. at 1437 (Ginsburg, J., dissenting). Justice Scalia did not refute this proposition, and the Court has no reason to think the dissent's statement — which is accurate — does not remain good law. Accordingly, just because each plaintiff and class member may get a different amount and there has to be a separate calculation of each plaintiff's damages does not defeat class certification.

19. What the Court thinks that Comcast Corp. v. Behrend says that is relevant to the individual determination of damages is threefold. First, at the class certification stage, the Court cannot ignore how individual damages, if any are appropriate, are to be decided. In other words, the Court cannot ignore the possible complexities of the individual damages determinations in making the predominance calculation. A class can have individual damage calculations, but the Court has to look at the issues of individual damages calculations at the class certification stage. Second, the methodology for all class members needs to be common or, if there are different methodologies for some plaintiffs and class members, the Court must take these differences into account at the class certification stage in the predominance analysis. In other words, if the Court is going to use different methodologies for different class members, it must decide: (i) whether these differences create questions affecting only individual members; and (ii) whether these individual questions predominate over the questions of law or fact common to the class. Third, even if the methodology is common to the class, the Court must decide whether it will operate in a consistent way for each individual class member. The law and methodology may be the same, but when applied to the class, they may create issues for one class member or group of class members that they do not create for other class members or groups. The predominance analysis must identify precisely the common issues and uncommon issues that application of the class methodology or methodologies raise, and then determine whether, in the total issue mix, the common issues predominate over the individual ones.

20. A defendant's desire to assert individual counterclaims — generally speaking, counterclaims, even common ones, are not permitted against absent class members at all — does not typically defeat predominance. See Phillips Petrol. Co. v. Shutts, 472 U.S. 797, 810 (1985); Allapattah Servs, Inc. v. Exxon Corp., 333 F.3d 1248, 1260 (11th Cir. 2003). A defendant's desire to assert individual affirmative defenses also often does not defeat predominance, see Smilow v. Sw. Bell Mobile Sys., Inc., 323 F.3d 32, 39 (1st Cir. 2003)("Courts traditionally have been reluctant to deny class action status under Rule 23(b)(3) simply because affirmative defenses may be available against individual members."), but this statement is less true after Wal-Mart.42 Other recurring individual issues present more serious challenges to predominance, such as: (i) the prima facie element of reliance or due diligence in common-law fraud and other cases;43 (ii) differences in the applicable law in a multi-state, state law-based class actions,44 see Castano v. Am. Tobacco Co., 84 F.3d 734, 741 (5th Cir. 1996); and (iii) the need to determine individual personal injury damages, which presents such a challenge to predominance that class certification of mass tort claims is now exceedingly rare, see Amchem Prods., Inc. v. Windsor, 521 U.S. at 625.

21. There is little uniform guidance on how to assess when common issues predominate over individual ones, and the Court's statements to this point have, obviously, done more to disavow various tempting but fallacious rules than they have to set forth a usable standard.

22. There is currently a split of authority between the United States Court of Appeals over the proper way to analyze predominance — with the Seventh and Sixth Circuits on one side and the Third, Tenth and Eleventh Circuits on the other. The Honorable Richard A. Posner,45 United States Circuit Judge for the Seventh Circuit, concludes that the predominance inquiry boils down to "a question of efficiency." Butler v. Sears, Roebuck & Co., 702 F.3d at 362. Judge Posner poses the predominance question as: "Is it more efficient, in terms both of economy of judicial resources and of the expense of litigation to the parties, to decide some issues on a class basis or all issues in separate trials?" Butler v. Sears, Roebuck & Co., 702 F.3d at 362. In Butler v. Sears, Roebuck & Co., the Seventh Circuit reversed a district court's denial of certification of a class of washing-machine owners who alleged that Sears' washing machines were prone to cultivate mold and affirmed the district court's certification of the same class to pursue a claim that the machines' control units were defective. See 702 F.3d at 360-61. The Seventh Circuit certified the class — which spanned six states — to pursue its mold claim under state breach-of-warranty law:

Butler v. Sears, Roebuck & Co., 702 F.3d at 362. Along with numerous other class actions pending appeal before the Supreme Court, the Supreme Court vacated Butler v. Sears, Roebuck & Co., and remanded it to the Seventh Circuit "for reconsideration in light of Comcast Corp. v. Behrend." Butler v. Sears, Roebuck & Co., 727 F.3d at 797 (7th Cir. 2013). On reconsideration, the Seventh Circuit reaffirmed its prior decision, again in an opinion written by Judge Posner:

Butler v. Sears, Roebuck & Co., 727 F.3d at 801-02.46

23. The Sixth Circuit handled essentially the same case — a class action against Sears for defective washing machines — in In re Whirlpool Corp. Front-Loading Washing Products Liability Litigation, 678 F.3d 409 (6th Cir. 2012), and also elected to certify the mold-based claim.47

In re Whirlpool Corp. Front-Loading Washing Products Liability Litigation, 678 F.3d at 421 (citation omitted). That case was also vacated after Comcast Corp. v. Behrend, and, like the Seventh Circuit, the Sixth Circuit reaffirmed its prior decision, fleshing out the predominance inquiry in more detail than it had done in its prior opinion:

In re Whirlpool Corp. Front-Loading Washing Products Liability Litigation, 722 F.3d 838, (7th Cir. 2013)(citations omitted). The Seventh Circuit and Sixth Circuit, thus, define predominance in much the same way: if the district court can design a mechanism for trying the case that is fair to the defendants and more efficient than individual litigation of the same dispute, then predominance is satisfied. See Butler v. Sears, Roebuck & Co., 727 F.3d at 802. This styling of the predominance inquiry is in keeping with that given, many years earlier, by a leading class-action treatise:

McLaughlin on Class Actions § 5:23 (11th ed.)(emphases added)(omission in original)(footnotes omitted).

24. Although the Seventh Circuit and the Sixth Circuit may agree about the definition of predominance, the Third, Tenth, and Eleventh Circuits stake out a different test.

Sacred Heart Health Sys., Inc. v. Humana Military Healthcare Serv., Inc., 601 F.3d at 1170 (11th Cir.)(emphasis in original)(citations omitted).48 The Eleventh Circuit, however, imposes a different, more rigorous, second step: the district court's trial plan must spend more time adjudicating the common questions than it does adjudicating the individual questions. The Eleventh Circuit's test may not be the greatest — the Court sees little reason why negative-value cases that can be fairly and efficiently adjudicated via class action should not be certified49 — but it is commendable in that it is a test that district courts can use, rather than yet another meaningless recitation, see CGC Holding Co. LLC v. Broad & Cassel, 773 F.3d 1076 (10th Cir. 2014)("[T]he predominance prong `asks whether the common, aggregation-enabling, issues in the case are more prevalent or important than the non-common, aggregation defeating, individual issues." (quoting Newberg § 4:49)), circular axiom, see, e.g., Amchem Prods., Inc. v. Windsor, 521 U.S. at 623 ("The Rule 23(b)(3) predominance inquiry tests whether proposed classes are sufficiently cohesive to warrant adjudication by representation."), obvious guidepost, see Reed v. Bowen, 849 F.2d at 1309 ("Each case must be decided on its own facts, on the basis of `practicalities and prudential considerations.'"), self-evident comparison, see Monreal v. Potter, 367 F.3d at 1237 ("[T]he predominance criterion of Rule 23(b)(3) [i]s `far more demanding' tha[n] the Rule 23(a) commonality requirement[.]" (quoting Amchem Prods., Inc. v. Windsor, 521 U.S. at 623-24)), or worthless slogan, see Marcus v. BMW of N. Am., LLC, 687 F.3d at 600 (exhorting district courts to examine claims "`through the prism' of Rule 23(b)(3)").

25. The Tenth Circuit followed the Eleventh Circuit's approach in CGC Holding Co., LLC v. Broad and Cassel.50

CGC Holding Co., LLC v. Broad & Cassel, 773 F.3d at 1087-94 (emphases in original)(footnotes omitted)(citations omitted). It is clear given the Tenth Circuit's repeated citations to Eleventh Circuit case law, including Klay v. Humana, that the Tenth Circuit has adopted the Eleventh Circuit's test of comparing the total time the district court most likely will spend on common versus individual questions. See CGC Holding Co., LLC v. Broad & Cassel, 773 F.3d at 1087 ("[W]e must characterize the issues in the case as common or not, and then weigh which issues predominate." (emphases in original)).51

26. The Third Circuit has adopted a similar approach. In Marcus v. BMW of North America, LLC, 687 F.3d 583 (3d Cir. 2012), the Third Circuit said:

687 F.3d at 600. The Third Circuit then set forth the claims that the plaintiffs brought:

687 F.3d at 600. The Third Circuit first addressed the common-law claims, which, like the district court, referred to the plaintiffs' breach of warranty, breach of contract, and breach of the implied covenant of good faith and fair-dealing claims.

687 F.3d at 600-01. The Third Circuit then discussed the common proof of susceptibility to road hazard damage:

687 F.3d at 601-03. After demonstrating what it expected district courts to do to decide the common proof on one element of the common-law claims, the Third Circuit then turned to the common proof of another element of the claims — proximate causation:

687 F.3d at 603-05.

27. In light of the Tenth Circuit's analysis in CGC Holding Co., LLC v. Broad & Cassel, the Court concludes that, to determine whether predominance is satisfied, it must first "characterize the issues in the case as common or not, and then weigh which issues predominate. 773 F.3d at 1087 (emphases in original). The Court also thinks that Wal-Mart and Comcast Corp. v. Behrend have changed the landscape for the predominance analysis overall. For example, there are some old cases that state that rule 23(b)(3) "does not require that common questions be dispositive or significant; it only requires that common questions predominate." In re Potash Antitrust Litig., 159 F.R.D. 682, 699 (D. Minn. 1995)(Kyle, J.). Similarly, the Second Circuit had said that the fact that the answer to a common question is not disputed — for example, if the parties have stipulated as to the answer or the court has already ruled — does not affect either its commonality or its ability to predominate. See In re Nassau Cnty. Strip Search Cases, 461 F.3d 219, 228 (2d Cir. 2006)(Straub, J.)("That the class-wide proof comes in the form of a simple concession rather than contested evidence certainly shortens the time that the court must spend adjudicating the issue, but it does nothing to alter the fundamental cohesion of the proposed class, which is the central concern of the predominance requirement."). The Court believes that the days of submitting a long list of allegedly common issues — some dispositive, some not dispositive, some significant, some not significant, some upon which the Court has already ruled, some which remain unanswered, some of which are not disputed, some of which the parties have stipulated — are over. The common issues have to be real issues — not phantom issues — or else the analysis will not meaning anything.55

ii. The Superiority Requirement.

28. The second requirement for certifying a (b)(3) class is superiority, which means that a class action would be superior to — not merely just as good as or more convenient than — all other available procedural mechanisms, including: (i) individual actions by class members; (ii) ordinary joinder rules, see Fed. R. Civ. P. 18-20; (iii) multidistrict litigation,56 see 28 U.S.C. § 1407; (iv) multiparty multiforum litigation, see 28 U.S.C. § 1369; and (v) the use of bellwether cases. The superiority requirement thus sets a high bar, but there are two ways that a proposed class can get an immediate leg up on certification, both of which involve rendering the aforementioned procedural devices impractical for the task at hand.

29. First, the suit can consist of so-called negative value claims — claims in which the cost of litigation exceeds the likely recovery, rendering them economically non-viable without aggregation. These claims are the heart and soul of the class action, as the Supreme Court recently reaffirmed:

Amchem Prods., Inc. v. Windsor, 521 U.S. at 617 (quoting Mace v. Van Ru Credit Corp., 109 F.3d 338, 344 (7th Cir. 1997)). The class action absolves absent plaintiffs of the otherwise prohibitive obligations of having to hire their own attorneys, devote time and energy to their own discovery, and potentially testify on their own behalf.

30. Second, the class may consist of such a large volume of similar cases that the judiciary would be overwhelmed if it had to treat each separately. While this consideration militates against individual treatment and counsels towards aggregation, the court must carefully consider whether another mass-aggregation form — such as multidistrict litigation — might be better suited to the task.

31. In addressing whether a proposed class action is superior to other available methods of adjudicating the controversy, courts start with the four factors that rule 23(b)(3)(A)-(D) enumerates, although those factors are not exhaustive. See Fed. R. Civ. P. 23 advisory committee's notes ("Factors (A)-(D) are listed, non-exhaustively, as pertinent to the findings."); Amchem Prods., Inc. v. Windsor, 521 U.S. at 615-16 ("Rule 23(b)(3) includes a nonexhaustive list of factors pertinent to a court's `close look' at the predominance and superiority criteria."). The first factor, "the class members' interests in individually controlling the prosecution . . . of separate actions," closely tracks the money value of the individual cases. Fed. R. Civ. P. 23(b)(3)(A). When individual actions are practical, they are preferred; the United States has a "deep-rooted historic tradition that everyone should have his own day in court," and adjudicating individual disputes is the core activity of our judicial scheme. Martin v. Wilks, 490 U.S. 755, 762 (1989)(quoting 18C Charles Alan Wright, Arthur R. Miller, Edward H. Cooper, Vikram David Amar, Richard D. Freer, Helen Hershkoff, Joan E. Steinman, Catherine T. Struve, Federal Practice Procedure, Jurisdiction & Related Matters § 4449, at 417 (1981)). The proposed class members' emotional connection to the case may also be relevant: the stronger the attachment, the more reticent the court should be to certify the case. See Vassalle v. Midland Funding, LLC, 708 F.3d 747, 758 (6th Cir. 2013); Abby v. City of Detroit, 218 F.R.D. 544, 549-50 (E.D. Mich. 2003). Another recurring issue that arises in relation to this factor is when the statute sued under provides greater remedies for individual suits than for class suits, either by imposing a damage cap for class actions which does not apply to individual actions, or by granting statutory damages to individual plaintiffs while requiring class plaintiffs to prove actual damages. See, e.g., Fair Debt Collection Practices Act, 15 U.S.C. § 1692k(2)(B) (capping individual damages at $1,000 and class action damages at $500,000); Truth in Lending Act, 15 U.S.C. § 1640(a) (capping individual damages at $5,000 and class action damages at $500,000). Although claims under these statutes may be more lucratively brought as individual actions, courts should assess the real-world likelihood that class members would bring their own actions, which implicates another factor the court should consider: the likelihood that proposed class members know they have a claim, and whether they are savvy enough to pursue it.57 See Hicks v. Client Servs., Inc., 257 F.R.D. 699, 701 (S.D. Fla. 2009)(finding superiority because "class members [most likely do not] understand the provisions well enough to know that it may be financially worthwhile to spend the time and effort to litigate these matters"). As the Honorable Loretta A. Preska, Chief United States District Judge for the Southern District of New York, wrote:

Kalish v. Karp & Kalamotousakis, LLP, 246 F.R.D. 461, 464 (S.D.N.Y. 2007). See Jancik v. Cavalry Portfolio Servs., LLC, No. CIV 06-3104 MJD/AJB, 2007 WL 1994026, at *11 (D. Minn. July 3, 2007)("[T]he truth is that the putative plaintiffs in this case are not likely to know their rights and are therefore not likely to pursue these claims on their own.").

32. The second enumerated (b)(3) factor, "the extent and nature of any litigation concerning the controversy already begun by . . . class members," is closely linked to the first factor. Fed. R. Civ. P. 23(b)(3)(B). The advisory notes to the rules state that "[t]he court is to consider the interests of individual members of the class in controlling their own litigations and carrying them on as they see fit. In this connection the court should inform itself of any litigation actually pending by or against the individuals." Fed. R. Civ. P. 23 advisory committee's notes (citations omitted). This passage suggests that the extent to which proposed class members — or individuals who would otherwise be proposed class members but for being specifically excluded from the definition by virtue of their individual claims — have already filed individual claims is probative evidence of the extent to which they will continue to file individual claims in the event of certification denial, and indicates a higher "interest[] in individually controlling the prosecution." Fed. R. Civ. P. 23(b)(3)(A). It is also probative evidence whether the claims are truly negative value or whether the plaintiffs' counsel is merely representing that they are to enhance his argument for certification.

33. In evaluating the (b)(3)(A) and (b)(3)(B) factors, the court must keep in mind a powerful fact that counsels strongly in favor of finding superiority: (b)(3) class actions give all proposed class members the opportunity to opt out of inclusion in the class. See Fed. R. Civ. P. 23(c)(2)(B). The individual actions that rule 23(b)(3)(B) directs the court to consider would not be swept under the class action's umbrella, nor would certification interfere with the litigation autonomy of any proposed class member who plans to file an individual claim but has yet to do so. The sole group that rule 23(b)(3)(A) and (b)(3)(B) protects consists only of those individuals who (i) have not yet filed an individual action, (ii) but are identifiable by proposed class counsel as having a claim, (iii) who are sent notice of their claim, (iv) who still, upon receiving notice, fail to meet with an attorney to file an individual claim or even to opt out of the class, and (v) only later develop an interest in pursuing an individual claim, and find themselves unable to do so because of the res judicata effect that a class action has on its members. As a practical matter, in most instances, this group contains few people, if any. Individuals interested in litigating their claims individually will most likely have already filed suit; at the very latest, receipt of the class notice will spur them into action, and they will opt out of the class. For this reason, the Court believes that concerns about (b)(3) class actions' intrusions into litigant autonomy are overblown and even somewhat paternalistic.

34. The Court does not write off the rule 23(b)(3)(B) factor entirely, however, as it does provide one piece of useful, specific guidance. The rule speaks not only of assessing the "extent . . . of any litigation . . . already begun" — presumably meaning the raw number of cases filed relative to the size of the proposed class — but also of the "nature of any litigation . . . already begun." Fed. R. Civ. P. 23(b)(3)(B). The Court interprets this language to mean that it must look at what procedural forms the already-filed cases have taken. For example, if a group of asbestos plaintiffs file for class certification, the court should decline to certify on the ground that asbestos cases are consolidated in multidistrict litigation in the United States District Court for the Eastern District of Pennsylvania. See In re Asbestos Prods. Liability Litig. (No. VI), MDL No. 875 (E.D. Penn.)(Robreno, J.). But see supra note 56. Furthermore, the Court concludes that, if a class has already been certified to pursue certain claims, redundant classes should generally not be certified.58 See Newberg § 4:70 ("[I]f a class action case is already pending, certification of another class suit might not be sensible or superior to the current litigation posture." (emphasis in original)). Subsequent proposed classes should either be defined to avoid class member-overlap with previously certified classes or else should assert different claims.59

35. The third rule 23(b)(3) factor is "the desirability or undesirability of concentrating the litigation of the claims in the particular forum," which can be split into two prongs: (i) whether aggregation is desirable; and (ii) whether the particular court at issue is a desirable forum to adjudicate the aggregated dispute. Fed. R. Civ. P. 23(b)(3)(C). The first prong, whether aggregation is desirable, is considered a recitation of the general superiority inquiry; all of the aforementioned factors and considerations apply, and courts should, additionally, consider the interest of judicial economy — from this perspective, the more cases that can be aggregated, the better. See Newberg § 4:71. The second prong is whether the particular court at issue is a desirable forum for the litigation. Some issues that reliably influence the determination of this prong include: (i) the geographic convenience of the parties, witnesses, or class counsel, see Zinser v. Accufix Research Inst., Inc., 253 F.3d 1180, 1191-92 (9th Cir. 2001); (ii) the locus of the harm, as well as any other events forming the basis of the action, see Winkler v. DTE, Inc., 205 F.R.D. 235, 245 (D. Ariz. 2001); (iii) the location of the bulk of the proposed class, see Macarz v. Transworld Sys., Inc., 193 F.R.D. 46, 57 (D. Conn. 2000); and (iv) whether the defendant is located in the forum state, see In re Warfarin Sodium Antitrust Litig., 391 F.3d 516, 534 (3d Cir. 2004). "The particular court at issue" does not refer only to the desirability of the United States District Court for the District of New Mexico, or even of the Albuquerque division, but, rather, the prong's inquiry extends all the way down to the level of the individual district judge. For example, if a district judge has already made several pre-certification preliminary rulings, see Klay v. Humana, Inc., 382 F.3d 1241, 1271 (11th Cir. 2004); if he or she has other, similar actions consolidated in his court, see Beaulieu v. EQ Indus. Servs., Inc., No. 5:06-CV-00400-BR, 2009 WL 2208131, at *23 (E.D.N.C. July 22, 2009); In re Relafen Antitrust Litig., 218 F.R.D. 337, 347 (D. Mass. 2003); or even if he or she possesses particular expertise at handling the claims alleged by the proposed class, the judge may weigh those facts in favor of a finding of superiority.

36. The fourth, final, and most important60 factor a court must consider in assessing superiority is the extent to which the court will be able to manage the class action, if certified, through pre-trial litigation and trial, accurately adjudicating the class' claims — in particular the individual issues — and fairly distributing relief among the class members. See Fed. R. Civ. P. 23(b)(3)(D). The manageability factor "encompasses the whole range of practical problems that may render the class action format inappropriate for a particular suit." Eisen v. Carlisle & Jacquelin, 417 U.S. at 164. The principal concern in a manageability inquiry is individualization. The size of a proposed class, on its own, does not affect manageability; increasing the size of a proposed class only hurts manageability if it introduces new proposed class members with individual issues. See Carnegie v. Household Int'l, Inc., 376 F.3d 656, 660-61 (7th Cir. 2004)(Posner, J.). As such, several courts have held that, if the predominance requirement is met, then the court should not decline to certify the class on manageability grounds alone.

Sacred Heart Health Sys., Inc. v. Humana Military Healthcare Servs., Inc., 601 F.3d 1159, 1184 (11th Cir. 2010)(internal citations and quotation marks omitted). See Klay v. Humana, Inc., 382 F.3d 1241, 1272 (11th Cir. 2004)("[W]here a court has already made a finding that common issues predominate over individualized issues, we would be hard pressed to conclude that a class action is less manageable than individual actions.").

37. When it comes to designing a fair management plan for trying a class action, district courts have myriad tools which can be customized to suit the needs of individual cases: "[W]hen a judge becomes convinced that a case is `complex,' procedural innovation often replaces procedural conservatism." Jay Tidmarsh & Roger H. Trangsrud, Modern Complex Litigation 34 (2d ed. 2010). Most techniques that are truly "procedural" are fair game: cases can be bifurcated,61 trifurcated, or polyfurcated; trials can be conducted in multiple stages or phases; and, provided that each defendant's overall monetary liability can be ascertained, the sometimes difficult question of how to distribute said damages among the class can be addressed with less formality.62

38. Techniques that merely presume away substantive elements that a plaintiff normally has to prove, or that would impair a defendant's due-process rights, however, are impermissible. But see supra note 43 (describing the fraud-on-the-market theory, which presumes satisfaction of the reliance element in securities cases). In particular, the Supreme Court has expressly disavowed "trials by statistics" or "trials by formula," either as to liability or damages. Wal-Mart, 131 S. Ct. at 2561. A trial by statistics involves a small but representative sample of class members presenting evidence on individual questions in their own cases and then inviting the jury to extrapolate its conclusions from the sample to the entire class. See, e.g., Wal-Mart, 131 S. Ct. at 2561. For example, counsel for a class of 5,000 might present fifty class members' cases in the same way he would if he or she were trying them individually. Counsel would additionally present expert testimony that those fifty class members were representative of the class — generally meaning that they were selected at random — and that both (i) the proportion of the sample to which the defendant is liable, and (ii) the damage inflicted on the average individual in the sample, could be generalized to the entire class to a certain confidence interval and level.63 The defendants might put on their own sample, attack the representativeness of the plaintiffs' sample, or put on non-randomly selected class members whose cases were weak; they would almost certainly also present evidence defending against the individual cases of the plaintiffs' sample. The jury, if it bought into the plaintiff's theory, might decide that the defendant was liable to twenty members of the sample for a total of $100,000.00, extrapolate from the sample to the entire class, and award the class ten million dollars in damages.64

39. The Supreme Court bars this method of trying cases, because it violates the defendant's right to have each element of each claim asserted against it by each class member specifically proven. See Wal-Mart, 131 S. Ct. at 2561.65 When issues are truly common, multiple class members' claims — or at least elements thereof — can be specifically proven in one fell swoop; that this common determination can be done forms the basis of the class action. Truly individual issues, on the other hand, must be adjudicated individually and not by statistical inference.66

40. In formulating a workable trial plan, the Court must also ensure that it does not run afoul of the Seventh Amendment. The Seventh Amendment contains two clauses:

U.S. Const. amend. VII.

41. These clauses are known as the trial-by-jury clause and the reexamination clause, respectively, and bifurcation has been challenged under both. Plaintiffs often dislike bifurcation, because it lowers their odds of success by excluding damages evidence from the liability phase — evidence of the plaintiff's injuries that is often evocative — and necessitating that they win two trials instead of one. See infra note 105. They have, accordingly, argued that bifurcation — a procedural innovation which post-dates the Founding — violates the trial-by-jury clause. Whatever the merits of this argument, the Supreme Court has rejected it:

Gas. Prods. Co. v. Champlin Refining Co., 283 U.S. 494, 498 (1931). The only restriction that the trial-by-jury clause places on trial-separation schemes is that, when a case contains both legal and equitable issues — the former of which must be submitted to a jury and the latter of which a judge can decide — the judge may not rule on the equitable issues before trial in such a way as to preclude the jury from trying the legal issues. See Beacon Theatres, Inc. v. Westover, 359 U.S. 500, 510-11 (1959).

Manual for Complex Litigation § 11.632, at 122.

42. The reexamination clause presents more formidable difficulties to polyfurcation. Relatively few appellate judges have invalidated lower-court judgments or class-management plans on this ground, by far the most famous being Judge Posner:

In re Rhone-Poulenc Rorer, Inc., 51 F.3d at 1302-03 (citations omitted).

d. Oil-and-Gas Class Actions.

44. Oil-and-gas wells are often drilled on land owned by entities or individuals other than the oil company that performs the drilling. The landowners execute mineral leases or deeds with the oil companies, dividing the estate up into a royalty interest, which the landowner-lessor owns, and a working interest, which the oil company-lessee owns. The lessee builds wells on the leased land and connects them to a gathering system — a system of small pipelines that collect oil and gas from a large number of wells in a region — which then carries it to a plant for treatment or processing. When the lessee sells the oil or gas, it then pays the lessors a fraction of the proceeds, known as a royalty, which effectively serves as "rent" for the use of the leased land. Royalty owners sometimes contend that their lessees are underpaying their royalty, either by deducting impermissible costs from the proceeds — a lessee can typically deduct post-production costs, but not production costs, from the sale proceeds before dividing off royalties — or by paying on an amount that does not reflect the true sale proceeds. The relationship between lessors and lessee is fundamentally a contractual one, but there is also positive law — case law and statutes — supplying default terms and contractual gap-fillers. Each lessor's monthly royalty is typically small and, thus, lessors have little practical recourse for royalty underpayment in individual litigation. They will, instead, band together with other landowner-lessors with whom a given oil company-lessor contracts — often other lessors on a single gathering system or within a region — and sue the oil company via class action. These class actions have a prodigious history in the state courts, where they were traditionally brought — because oil-and-gas royalty law is principally state law — before CAFA's passage. See, e.g., Phillips Petrol. Co. v. Shutts, 472 U.S. at 799. These actions present recurring issues, and, as certification reversals are both more common69 and more instructive than affirmances, the Court will focus on cases where appellate courts concluded that a proposed class failed to satisfy rule 23's requirements. But see Karen E. Kahle & Denielle M. Stritch, Grouping the Marcellus Payout: Use of Class Actions in Royalty Litigation Concerning Post-Production Cost Deductions, 88 N.D. L. Rev. 699 (2012).

45. The Tenth Circuit's only cases on rule 23(a) and (b)(3)'s application to oil-and-gas royalty cases70 came in two companion cases issued on July 9, 2013, Roderick and Chieftain Royalty Co. v. XTO Energy, Inc., 528 F. App'x 938 (10th Cir. 2013)(unpublished),71 which were both written by the Honorable Paul J. Kelly, Jr.,72 United States Circuit Judge for the Tenth Circuit, and joined by the Honorable Scott M. Matheson, Jr.,73 United States Circuit Judge for the Tenth Circuit, and the Honorable Monroe G. McKay, Senior United States Circuit Judge for the Tenth Circuit. In Roderick, a class of individuals owning interests in a total of roughly 650 leases and over 300 wells across ten well fields in Kansas brought a class action against XTO Energy for breach of contract, unjust enrichment, and an accounting. See 725 F.3d at 1215. The district court certified the class on the basis of a single common issue, "whether XTO's uniform payment methodology breached the implied duty of marketability under Kansas law," which the district court deemed to predominate over individual issues. 725 F.3d at 1217. On appeal, the Tenth Circuit decertified the class on two grounds. First, Judge Kelly stated that the district court had failed to consider variations in lease language at all, relying instead on the implied duty of marketability. See 725 F.3d at 1216. This failure constituted an abuse of discretion, because the duty of marketability obtains only "[a]bsent a contract providing to the contrary," and, thus, can be negated by express lease language. 725 F.3d at 1216 (alteration in original)(quoting Sternberger v. Marathon Oil Co., 894 P.2d 788, 800 (Kan. 1995)). The plaintiffs had not reviewed any of the class leases, and XTO Energy reviewed only one-fifth of them, categorizing them by royalty type, "several of which negate[d] the IDM [implied duty of marketability] completely or in part (i.e., by providing for certain express deductions)." 725 F.3d at 1216. Second, the Tenth Circuit held that applying Kansas' implied duty to market requires determining the point at which gas from each well becomes marketable, declaring that "[o]nce gas is in marketable condition, the IDM is satisfied — regardless of whether a market exists at that location . . . [and] gas may be marketable at the well." 725 F.3d at 1219 (emphasis in original). Importantly, the Tenth Circuit did not hold that the class could not be certified, and, to the extent that the Court reads such things into judicial opinions, it implied the opposite. Rather, it held that the district court's inquiry — and the form in which it certified the class — was inadequate, and gave the district court multiple leads for conducting a new rule 23 analysis on remand. See 725 F.3d at 1219 ("On remand, the [plaintiffs] could, for example, create a chart classifying lease types, and although we express no opinion as to the merits, the district court could decide that no lease type negates the IDM." (citing Foster v. Merit Energy Co., 282 F.R.D. 541, 551 n.12 (W.D. Okla. 2012))); id. at 1219 ("On remand, the district court should consider whether and to what extent marketability affects commonality." (footnote omitted)).

46. In the unpublished companion case, Chieftain Royalty v. XTO Energy, Inc., the Tenth Circuit applied Roderick's holding to a much larger class action composed of lessors for 14,300 leases and 2,300 wells in Oklahoma. See 528 F. App'x at 940. Again, Judge Kelly noted that "approximately 13,568 leases have yet to be examined by XTO Energy — let alone by Chieftain or the district court," and that this omission was "particularly significant because unlike the plaintiff in Roderick, Chieftain admits that some leases expressly abrogate — and one even negates — the IDM." 528 F. App'x at 942-43. Judge Kelly added one interesting elaboration on the Roderick holding:

528 F. App'x at 942 (alteration in original)(emphasis in original)(citations omitted).

47. Other Circuits have also analyzed oil-and-gas royalty class actions, although, interestingly given its own lack of precedent, the Tenth Circuit did not cite any of them in the companion cases discussed above. The Court suspects that the Tenth Circuit did not want to rely too heavily on cases issued before Wal-Mart. One influential court to discuss rule 23's application to oil-and-gas royalty cases in the post-Wal-Mart era is the United States Court of Appeals for the Fourth Circuit. In EQT Production Co. v. Adair, the Honorable Albert Diaz, United States Circuit Judge for the Fourth Circuit, joined by the Honorable J. Harvie Wilkinson III and Barbara M. Keenan, United States Circuit Judges for the Fourth Circuit, vacated a district court's certification of five closely related oil-and-gas royalty class actions and remanded them for further analysis. See 764 F.3d at 352. That case was primarily about mineral-rights ownership — namely, whether certain coal-rights owners also held title to the coalbed methane under the leased premises — but it also addressed royalty underpayments. See 764 F.3d at 347-365 (addressing the coalbed methane ownership issue). Judge Diaz pointed out three individual issues that the district court failed to consider and that weighed against predominance. First, the case addresses the issue of intra-class variations in lease language; the Fourth Circuit's rationale parallels the Tenth Circuit's, going into more detail in some areas:

The district court did identify common practices that may be pertinent to the predominance inquiry — e.g., the fact that "EQT calculated all royalties based on the same methodology." But the district court's analysis fell short because it never analyzed why those common practices were sufficient to ensure that the class members' common issues would predominate over individual ones.

The defendants have highlighted a number of uncommon practices that might cause individual issues to predominate. For example, EQT notes that it calculates royalties in different ways for different class members, depending on where the CBM is produced. Its method of calculating royalties — and the deductions it applies — have also changed over time. CNX submitted evidence that it takes different deductions depending on where it sells the CBM, and that its deduction calculations sometimes vary between and even within wells during different time periods.

764 F.3d at 366-67 (citations omitted). These statements support the Court's conclusion that the predominance inquiry is not a quantitative inquiry comparing the number of common questions to the number of individual questions, nor is it a cursory inquiry asking whether the defendants generally subjected the class members to the same factual treatment by the defendants or whether their claims are subject to the same legal standard, but, rather, it is a manageability inquiry that requires the Court to determine whether common legal issues, susceptible to common evidence, exist in the right places to try the case in a way that is fair to all parties. Second, the Fourth Circuit pointed out that the district court would "likely need to consider" course-of-performance evidence. 764 F.3d at 370-71. Third, it stated that "the district court should reevaluate the implications of the defendants' statute of limitations defense for Rule 23's predominance requirement." 764 F.3d at 371. The plaintiffs' claims were facially time-barred, but they pled fraudulent concealment to toll the statute, and the Fourth Circuit held that, "[a]lthough a defendant's conduct is not irrelevant, attention must also be paid to the plaintiff's knowledge and actions," and, "[i]n this context, a plaintiff's knowledge typically requires individual evidence." 764 F.3d at 370.

48. After determining that the facts that oil-and-gas companies engaged in numerous common practices may be sufficient for commonality purposes, the Fourth Circuit in EQT Production Co. v. Adair made it clear that such common practices are not enough to satisfy the predominance requirement:

764 F.3d at 366-68, 70 (footnote omitted)(citation omitted).

49. The Fourth Circuit, like the Tenth Circuit, never held that the five putative classes were intractably or irredeemably uncertifiable — just that the district court did not ask all the necessary questions.74

EQT Prod. Co. v. Adair, 764 F.3d at 367. The case is — moreso even than Roderick and Chieftain Royalty Co. v. XTO Energy, Inc. — littered with instructions to the district court for improving its rule 23 analysis on remand. See, e.g., EQT Prod. Co. v. Adair, 764 F.3d at 367 ("We also remand for the district court to . . . consider how variations in the defendants' royalty obligations to the class members implicate the commonality and predominance inquiries in [certain of the five classes]."); 764 F.3d at 371 ("Where the proper balance lies in the superiority analysis we leave to the district court on remand as part of its broader consideration of the other Rule 23(b)(3) factors."). In its conclusion, the Fourth Circuit summed up its holding:

764 F.3d at 371.

II. LAW REGARDING NEW MEXICO'S STATUTES OF LIMITATIONS AND THE DISCOVERY RULE.

50. "Although a statute of limitations bar is an affirmative defense, it may be resolved on a Rule 12(b)(6) motion to dismiss `when the dates given in the complaint make clear that the right sued upon has been extinguished.'" Torrez v. Eley, No. CIV 09-1464, 2010 WL 1948679 (10th Cir. May 17, 2010)(quoting Aldrich v. McCulloch Props., Inc., 627 F.2d 1036, 1041 n.4 (10th Cir. 1980)). Accord Lee v. Rocky Mountain UFCW Unions & Emp's Trust Pension Plan, No. 92-1308, 1993 WL 482951 (10th Cir. Nov. 23, 1993)("Because the critical dates appeared plainly on the face of [plaintiff's] complaint, we conclude that the statute of limitations defense was properly raised and resolved in the Rule 12(b) context."). When a party has asserted a statute of limitations issue in a rule 12(b)(6) motion, a court accepts all well-pled factual allegations in the complaint as true and views them in the light most favorable to the plaintiff to determine whether the statute of limitations has run. See Sunrise Valley, LLC v. Kempthorne, 528 F.3d 1251, 1254 (10th Cir. 2008). The statute of limitations for a breach-of-contract claim on a written contract, under New Mexico law, is six years. See N.M. Stat. Ann. § 37-1-3 ("Those founded upon any bond, promissory note, bill of exchange, or other contract in writing, or upon any judgment of any court not of record, within six years."). The statute of limitations for fraud, under New Mexico law, is four years. See N.M. Stat. Ann. § 37-1-4 ("Those founded upon accounts and unwritten contracts; those brought . . . for relief upon the ground of fraud, and all other actions not herein otherwise provided for and specified within four years.").

51. New Mexico applies the "discovery rule," which means that the statute of limitations period "begins to run when the claimant has knowledge of sufficient facts to constitute a cause of action." Gerke v. Romero, 2010-NMCA-060, ¶ 10, 237 P.3d 111, 115 (citing Martinez-Sandoval v. Kirsch, 1994-NMCA-115, ¶ 26, 884 P.2d 507, 513). "The discovery rule provides that `the cause of action accrues when the plaintiff discovers or with reasonable diligence should have discovered that a claim exists.'" Williams v. Stewart, 2005-NMCA-061, ¶ 12, 112 P.3d 281, 285 (quoting Roberts v. Sw. Comm. Health Servs., 1992-NMSC-042, ¶ 24, 837 P.2d 442, 449). Accord Eoff v. N.M. Corr. Dep't, Nos. CIV 10-0598, 10-0599, 10-0600, 2010 WL 5477679, at *18 (D.N.M. Dec. 20, 2010)(Browning, J.)("The Court believes that, in breach-of-contract actions involving an employee's termination, the statute of limitations should not begin to run until the employee is aware of the allegedly wrongful decision, because an employee would not be aware of the possible need to file suit until that time."); Gose v. Bd. of Cnty. Comm'rs of Cnty. of McKinley, 727 F.Supp.2d 1256, 1264 (D.N.M. 2010)(Browning, J.)("Specifically, [the] statute of limitations commences when an `injury manifests itself and is ascertainable, rather than when the wrongful or negligent act occurs."); Gerke v. Romero, 2010-NMCA-060, ¶ 12, 237 P.3d at 115 ("Under the discovery rule, the statute of limitations begins to run when the plaintiff knows or, with reasonable diligence should know, of his injury and its cause." (citing Roberts v. Sw. Cmty. Health Servs., 1992-NMSC-042, ¶ 24, 114 N.M. 248, 255-56, 837 P.2d 442, 449-50)).

III. LAW REGARDING NEW MEXICO'S IMPLIED COVENANT TO MARKET OIL AND GAS, AND THE ONGOING DISPUTE REGARDING THE EXISTENCE OF THE MARKETABLE-CONDITION RULE.

52. Oil and gas leases are construed "like any other contracts." Elliott, 407 F.3d at 1108. Additionally, New Mexico implies in law a duty — "`to make diligent efforts to market the production in order that the lessor may realize on his royalty interest'" — on oil-and-gas producers, "in equity, without looking to the language of the agreements or other evidence of the parties' intentions." Davis v. Devon Energy Corp., 2009-NMSC-048, ¶ 35, 147 N.M. 157, 218 P.3d 75 (quoting Darr v. Eldridge, 6 N.M. at 263, 346 P.2d at 1044). This obligation is called the "duty to market." Davis v. Devon Energy Corp., 2009-NMSC-048, ¶ 35, 147 N.M. 157, 218 P.3d 75. One possible corollary — "possible," because many New Mexico courts have recognized it, but the Tenth Circuit has not — of the duty to market is the "marketable condition rule." Compare Elliott, 407 F.3d at 1113-14, with Davis v. Devon Energy Corp., 2009-NMSC-048, ¶ 6, 218 P.3d at 78. The rule provides that the working interest owner must bear the full cost of any expenses incurred in drilling, removing the hydrocarbons from the ground, and rendering them into marketable condition, and may not assess those costs against the royalty it owes the lessee. See Davis v. Devon Energy Corp., 2009-NMSC-048, ¶ 6, 218 P.3d at 78.

53. In 2005, in Elliott, the Tenth Circuit addressed various obligations that oil-and-gas lessors owe the royalty interest owners on their leases under New Mexico law. The plaintiffs in Elliott were royalty owners who sued ConocoPhillips, the working interest owner, to collect additional royalties. The production subject to the plaintiffs' claim in Elliott was conventional gas. The gas contained NGLs that are removed through processing before the residue is generally acceptable for transportation on interstate pipeline transmission systems. See 407 F.3d at 1110-11. The plaintiffs alleged that ConocoPhillips was underpaying its royalty interests by reducing their royalties with illegitimate post-production costs, including "processing, marketing, transportation, and fractionation costs, from the value of the refined natural gas products." 407 F.3d at 1100. The plaintiffs alleged that ConocoPhillips violated the NMPPA, breached the implied duty of good faith and fair dealing, breached the implied duty to market, and committed conversion, constructive fraud, fraud, and unjust enrichment, among other alleged wrongs. See 407 F.3d at 1101. The plaintiffs expressly declined to assert any contract claims under the governing lease. See 407 F.3d at 1107. ConocoPhillips contended that it was performing its contractual obligations within the terms of the plaintiffs' leases. See 407 F.3d at 1101.

54. The Tenth Circuit, in an opinion authored by the Honorable Michael R. Murphy, United States Circuit Judge, determined that the district court properly granted ConocoPhillips summary judgment on the plaintiffs' allegation that ConocoPhillips' royalty payment practices violated the implied duty to market. The plaintiffs alleged that ConocoPhillips was obligated under the implied duty to market to pay royalties based upon the best price reasonably available for the gas-and-oil products, and not the actual price minus reasonable or actual cost deductions. 407 F.3d at 1113-14. The Tenth Circuit noted that New Mexico recognizes an "`implied covenant on the part of the lessee . . . that after production of oil and gas in paying quantities is obtained, he will thereafter continue the work of development . . . with reasonable diligence. . . . having in mind his own interest as well as that of the lessor, to market the product.'" 407 F.3d at 1113 (quoting Libby v. DeBaca, 51 N.M. at 95, 179 P.2d at 265). Perhaps because the Tenth Circuit construed Elliott before the Supreme Court of New Mexico's pronouncement in Davis v. Devon Energy Corp., 2009-NMSC-048, ¶ 35, 218 P.3d at 85-86, that the duty to market is implied "in equity, without looking to the language of the agreements or other evidence of the parties' intentions," the Tenth Circuit interpreted New Mexico law to imply the duty to market only in fact, based upon "whether any implied duty to market was intended by the parties or would contradict the express provisions of that agreement," Elliott, 407 F.3d at 1113. On that basis, the Tenth Circuit stated that it could not "speculate . . . how to construe the scope of any implied covenant to market that may exist," because the plaintiffs' divorced their implied duty to market claim from their contractual relationship with ConocoPhillips, and disclaimed any "reliance on the express provisions of the royalty agreements." 407 F.3d at 1113.

55. The Tenth Circuit also noted that there was no implied-in-fact marketable condition rule term in the royalty provisions in the plaintiffs' leases, because the royalty provisions expressly covered how ConocoPhillips was to calculate the plaintiffs' royalty payments. See 407 F.3d at 1113-14 ("[U]nder New Mexico law, covenants are not implied for subjects that are treated in express provisions. . . . [T]he express terms of the royalty obligations direct the royalty to be paid on the value of gas `at the well.'"). Moreover, the Tenth Circuit stated that the plaintiffs failed to show how ConocoPhillips' conduct violated any implied duty to market under New Mexico law. The Tenth Circuit stated that, because ConocoPhillips was and is "actively producing gas, processing the gas, and selling the refined natural gas and NGLs," ConocoPhillips' conduct "complied with the implied duty to market as articulated by the New Mexico courts." 407 F.3d at 1113 (citing Darr v. Eldridge, 346 P.2d at 1044). The Tenth Circuit expressly held that the plaintiffs' "conception of the implied duty to market" as requiring ConocoPhillips' to "bear the burden of all costs incurred to put the gas in a marketable condition including the cost of removing the NGLs from the gas . . . finds no support within New Mexico law." 407 F.3d at 1113-14.

56. From the time of the Tenth Circuit's decision in Elliott, the Supreme Court of New Mexico has, twice, expressly declined to decide whether a marketable condition rule is implied as a matter of law in oil and gas leases. In Davis v. Devon Energy Corp., 2009-NMSC-048, ¶ 1, 218 P.3d at 77 (Chavez, J.), the issue before the Supreme Court of New Mexico was whether a state district court properly denied certification of a class alleging that the defendant gas producers underpaid the plaintiffs' royalties by improperly deducting the cost of rendering the gas marketable. The state district court concluded that the plaintiffs failed to establish the commonality requirement to proceed as a class action, because determining whether the defendants' royalty payments violated the terms of the plaintiffs' leases would require interpreting each plaintiff's individual lease — totaling as many as thirty-four lease agreements — and, therefore, the plaintiffs failed to demonstrate that common questions of law or fact predominated the class' allegations. See 2009-NMSC-048, ¶ 26, 218 P.3d at 83. The Supreme Court of New Mexico concluded, however, in an opinion written by the Honorable Edward L. Chavez, Chief Justice of the Supreme Court of New Mexico,75 that the state district court's construction of the marketable condition rule would not require the court to determine whether that duty is implied in fact in each individual lease. The Supreme Court of New Mexico first explained that the implied duty to market is implied "in equity, without looking to the language of the agreements or other evidence of the parties' intentions." 2009-NMSC-048, ¶ 35, 218 P.3d at 85-85. The state district court had ruled that, "under the implied duty to market, the marketable condition rule applies in New Mexico." 2009-NMSC-048, ¶ 35, 218 P.3d at 85-86 (secondary quotation marks omitted). The Supreme Court of New Mexico concluded that, because the state district court concluded that the marketable condition rule is incorporated into the implied duty to market, the state district court would not be required to determine whether the marketable condition rule is implied, in fact, in each individual lease to adjudicate the class' allegations. See 2009-NMSC-048, ¶ 35, 218 P.3d at 85-86. The Supreme Court of New Mexico expressly disclaimed, however, that it was addressing the state district court's conclusion that the implied duty to market incorporates the marketable condition rule in New Mexico. See 2009-NMSC-048, ¶ 14, 218 P.3d at 80 ("For the purposes of our review . . . we do not address the existence of the marketable condition rule in New Mexico or its applicability in any of these cases."); 2009-NMSC-048, ¶ 35, 218 P.3d at 85-86 ("[T]he district court[] conclu[ded] that the duty to market, which applies in equity irrespective of the parties' intentions, incorporates the duty to put CBM gas in a marketable condition (a conclusion we do not review in this opinion).").

57. In ConocoPhillips v. Lyons, the issue before the Supreme Court of New Mexico was whether ConocoPhillips properly calculated the State of New Mexico's royalty payments as required under the statutes creating New Mexico's leases. See 2013-NMSC-009, ¶¶ 1-3, 299 P.3d 844. New Mexico contended that ConocoPhillips was not allowed, under the terms of New Mexico's statutory lease forms, to deduct the post-production costs necessary to render gas marketable from New Mexico's royalty payments. See 2013-NMSC-009, ¶¶ 2-6, 19-21, 299 P.3d 844. The Supreme Court of New Mexico, in an opinion written by the Honorable Petra J. Maes, then-Chief Justice of the Supreme Court of New Mexico,76 first explained that, when royalty provisions specify that a lessee is to calculate its net proceeds "at the well," the lessee is, generally,

2013-NMSC-009, ¶ 17, 299 P.3d 844 (citing Creson v. Amoco Prod. Co., 2000-NMCA-081, ¶¶ 11-12, 129 N.M. 529, 10 P.3d 835). New Mexico's statutorily created royalty interests, however, did not specify that net proceeds should be calculated at the well, but rather stated that net proceeds should be calculated "from the sale of such gas in the field." 2013-NMSC-009, ¶ 19, 299 P.3d 844 (secondary quotation marks omitted). The "key question" before the Supreme Court of New Mexico, therefore, was "whether a lease which provides for royalty payable upon `net proceeds . . . in the field' or `from the sale of gas from each gas well' compels a different royalty calculation than a lease which provides for `net proceeds . . . at the well.'" 2013-NMSC-009, ¶ 19, 299 P.3d 844. The Supreme Court of New Mexico stated that, although lessees must bear the costs incurred in producing oil and gas product, "absent an express contractual provision to the contrary. . . . costs incurred subsequent to production are considered post-production costs and are generally deducted from the sale of the product regardless of where the sale takes place." 2013-NMSC-009, ¶ 24, 299 P.3d 844 (citing Bice v. Petro-Hung LLC, 2009 ND 124, ¶ 19, 768 N.W.2d 496, 502 (N.D. 2009)). The Supreme Court of New Mexico therefore affirmed the state district court's ruling that the net proceeds term unambiguously allowed ConocoPhillips to deduct "from their gross sales price any post-production costs they reasonably and necessarily incur in selling the gas," regardless of where the sale gas occurred. 2013-NMSC-009, ¶¶ 21, 69, 299 P.3d 844.

58. New Mexico also alleged that ConocoPhillips' calculation of royalty payments breached the implied covenant to market. New Mexico asserted that the implied covenant to market required ConocoPhillips to "place the gas in a marketable condition and requires that the expenses incurred in obtaining a marketable product . . . be borne by Lessees." 2012 WL 3711550, at *16. The Supreme Court of New Mexico determined, however, that it need not reach the issue whether the marketable condition rule is incorporated into the implied covenant to market. The Supreme Court of New Mexico explained that whether the marketable condition rule applies in New Mexico was not ripe for review, because legislative policy decisions inform the extent of post-production costs that ConocoPhillips may deduct from New Mexico's royalty payments, but the lower court had not yet reached a decision of the merits on that issue. See 2012 WL 3711550, at *17.

59. Although the Court is bound by the Tenth Circuit's interpretation of New Mexico law, the Court is not convinced that the Elliott plaintiffs' "conception of the implied duty to market finds no support within New Mexico case law." 407 F.3d at 1114. From the time that the Tenth Circuit made this statement in Elliott, at least three New Mexico district courts have found that, "under the implied duty to market, the marketable condition rule applies in New Mexico." Davis v. Devon Energy Corp., 2009-NMSC-048, ¶ 14, 147 N.M. 157, 218 P.3d 75 (citing Davis v. Devon Energy Corp., 2008-NMCERT-003, 143 N.M. 682, 180 P.3d 1181; Ideal v. BP Am. Prod. Co., 2008-NMCERT-003, 143 N.M. 683, 180 P.3d 1182; Smith Family, L.L.C. v. ConocoPhillips Co., 2008-NMCERT-003, 143 N.M. 683, 180 P.3d 1182). In Davis v. Devon Energy Corp., the Supreme Court of New Mexico did not address the existence of the marketable condition rule, because it found that the matter was "not ripe for review at this time," as the New Mexico state district courts had left open questions regarding the scope of the rule. 2009-NMSC-048, ¶ 15, 147 N.M. 157, 218 P.3d 75. The Supreme Court of New Mexico made a similar statement in ConocoPhillips Co. v. Lyons. See 2013-NMSC-009, ¶ 64, 299 P.3d 844 ("As we indicated in Davis, whether the marketable condition rule applies in New Mexico is not yet ripe for review."). These pronouncements from the Supreme Court of New Mexico indicate, far from precluding the existence of the marketable condition rule as a matter of law within the state, that the Supreme Court of New Mexico considers the issue undetermined and, moreover, intends to address its existence when the record before the Supreme Court of New Mexico fully presents the issue.

60. The Court believes that, if and when the Supreme Court of New Mexico determines that the existence of the marketable condition rule is ripe for review, it will find that the rule is included in oil-and-gas contracts as part of the implied duty to market. Colorado, Wyoming, Kansas, and Oklahoma have all adopted a version of the marketable condition rule. The Supreme Court of Colorado announced its adoption of the marketable condition rule in Garman v. Conoco, Inc., P.2d 652 (Colo. 1994). There, the Supreme Court of Colorado held that, "absent an assignment provision to the contrary, overriding royalty interest owners are not obligated to bear any share of the post-production expenses . . . undertaken to transform raw gas produced at the surface into a marketable product." 886 P.2d at 661. The Supreme Court of Colorado noted that, although an oil-and-gas lease is "entered into for the mutual benefit of the parties, not all parties participate equally in lease development decisions." 886 P.2d at 657. Interest owners, whether of royalty or overriding royalty interests, must defer to the lessees regarding "where and when to drill, the formations to be tested and ultimately whether to complete a well and establish production." 886 P.2d at 675. The Supreme Court of Colorado was also persuaded by its neighboring states' — Wyoming, Kansas, and Oklahoma — and the federal government's requirement that lessees place gas in a marketable condition at no cost to the lessor. See 886 P.2d at 658 (citing 30 C.F.R. § 206.153(i); Wyo. Stat. § 30-5-304(a)(vi) (1994 Supp.); Wood v. TXO Prod. Corp., 854 P.2d 880, 882 (Okla. 1992); Gilmore v. Superior Oil Co., 388 P.2d 602, 606 (Kan. 1964)). The Supreme Court of Colorado explained that the marketable condition rule logically followed from a lessee's duty to effectuate the terms of a lease; the Supreme Court of Colorado reasoned that, just as the "purpose of an oil and gas lease could hardly be effected if the implied covenant to drill obligated the lessor to pay for his proportionate share of drilling costs," the purpose of a lease would be thwarted if lessors bore the cost of making a product marketable. 886 P.2d at 659. The Supreme Court of Colorado rejected an argument from oil-and-gas producers that industry practice dictates that lessees and lessors bear proportionately post-production costs necessary to render gas marketable. The Supreme Court of Colorado explained that, while other oil-and-gas producers may be aware of industry custom and factor that custom into oil-and-gas agreements, "[o]ften, however, executing an oil and gas lease, or assigning a federal lease won under the previously existing federal lottery system is the extent of a party's contact with the oil industry." 886 P.2d at 660. The Supreme Court of Colorado further emphasized that the marketable condition rule is consistent with the bargaining power of lessees and lessors: "The payment of royalties is controlled by lessees, and lessors have no ready means of ascertaining current market value other than to take lessees' word for it." 886 P.2d at 660.

61. The Supreme Court of Kansas based its formulation of the marketable condition rule on Colorado's. In Kansas, the rule currently requires a lessee of an oil-and-gas lease to "bear the entire expense of producing the gas at the wellhead pursuant to the terms of the oil and gas lease. Additionally, the lessee must bear `the entire cost of putting the gas in condition to be sold pursuant to the court-made `marketable condition rule.'" Coulter v. Anadarko Petroleum Corp., 296 P.3d 289, 306 (Kan. 2013)(citing Sternberger v. Marathon Oil Co., 894 P.2d 788 (Kan. 1995)). The Supreme Court of Kansas adopted a version of the marketable condition rule in Sternberger v. Marathon Oil Co. that allowed a lessee to share with a royalty owner the costs of transporting a marketable product to a point of sale and "to enhance the value of the gas stream, e.g., the processing costs to extract a saleable component such as helium." 292 P.3d at 306. The Supreme Court of Kansas explained that, in Kansas, ambiguities in oil-and-gas leases must be construed against the lessee, but found that the oil-and-gas leases at issue were not ambiguous. See 894 P.2d at 794. Rather, the Supreme Court of Kansas' adoption of the marketable condition rule was based upon the lessee's duty to "produce a marketable product," which requires "the lessee alone [to] bear[] the expense in making the product marketable." 894 P.2d at 799.

62. Kansas' interpretation of the marketable condition rule, which allows lessees to share the cost of transportation to the market with lessors may be vulnerable to attack. The Supreme Court of Kansas recognized, in Coulter v. Anadarko Petroleum Corp., that the Supreme Court of Colorado's decision in Rogers v. Waterman Farm Co., 29 P.3d 887, 896-902 (Colo. 2001), "clarified that. . . . `marketability' includes both the physical condition of the gas and the location of the gas, i.e., the commercial marketplace," and, therefore, whether oil-and-gas lessees in Kansas may share with lessors the cost of transporting marketable products to a market "may be questionable." Coulter v. Anadarko Petroleum Corp., 296 P.3d at 306 (quoting Rogers v. Westerman Farm Co., 29 P.3d at 902, 903). In Rogers v. Westerman Farm Co., the Supreme Court of Colorado held that, under the marketable condition rule, "the expense of getting the product to a marketable condition and location are born by the lessee." 29 P.3d at 906. The Supreme Court of Colorado explained that, whether gas is marketable is a question of fact, and requires, first, evidence that gas is "in the physical condition where it is acceptable to be bought and sold in a commercial marketplace," and, second, that the gas must be in a location "that is, the commercial marketplace, to determine whether the gas is commercially saleable in the oil-and-gas marketplace." 29 P.3d at 905. The Supreme Court of Colorado noted that "`a royalty clause should be construed in its entirety and against the party who offered it, and in light of the fact that the royalty clause is the means by which the lessor receives the primary consideration for a productive lease.'" 29 P.3d at 898 (quoting Owen L. Anderson, Royalty Valuation: Should Royalty Obligations be Determined Intrinsically, Theoretically, or Realistically, Part 2 (Should Courts Contemplates the Forest or Dissect Each Tree?), 37 Nat. Resources J. 611, 636 (1997)). The Supreme Court of Colorado reasoned that gas is not marketable until it is ready to be bought in a marketplace by a willing purchaser, and, accordingly, a lessee has not met its implied duty to market until a gas is transported to a marketplace, if transportation is necessary to reach purchasers. See 29 P.3d at 904-06.

63. Similarly, the Supreme Court of Oklahoma's adoption of the marketable condition rule is based upon the bargaining power of oil-and-gas lessees and lessors. In Wood v. TXO Prod. Corp., the Supreme Court of Oklahoma explained that "[p]art of the mineral owner's decision whether to lease or to become a working interest owner is based upon the costs involved," and, when an interest owner agrees to relinquish operating rights and lease a well in exchange for a royalty interest, as a lessor, the interest owner has no power to control post-production costs. 854 P.2d at 882-83. The Supreme Court of Oklahoma reasoned that, if lessees — oil-and-gas producers — were allowed to share production and marketing costs with royalty owners, "royalty owners would be sharing the burdens of working interest ownership without the attendant rights," including the greater share of proceeds which oil-and-gas producing lessees enjoy. 854 P.2d at 883. Accordingly, the Supreme Court of Oklahoma held that "in Oklahoma the lessee's duty to market involves obtaining a marketable product." 854 P.2d at 883.

64. Texas, on the other hand, has not adopted the marketable condition rule, but, rather, interprets oil-and-gas leases more strictly in accordance with their terms. The first case in Texas to discuss a marketable condition rule was Danciger Oil & Refineries v. Hamill Drilling Co., in which the Supreme Court of Texas interpreted a royalty clause which stated that payments were to be made out of "all the oil, gas, casinghead gas, and other minerals produced, saved and marketed at the prevailing market price paid by major companies in the Gulf Coastal area from the properties." 171 S.W. 2d at 322. The Supreme Court of Texas interpreted the lease as requiring the lessee to pay royalties for oil-and-gas "produced, saved and marketed," but not to "provide a market for all the products produced." 171 S.W. 2d at 323. The Supreme Court of Texas concluded that the language did not indicate that the gas produced from the subject wells would be "so mixed with other products as not to be `gas' of the kind contemplated" and also concluded that the lessee's operating expenses, which the lease required the lessees to bear, did not include expenses "of processing the named product into some other product after it has been produced." 171 S.W. 2d at 323. That there was no market for the gas in its unprocessed form in the vicinity of the wells did not sway the Supreme Court of Texas' ruling. "The mere fact that there was then no market in that vicinity for the product then being produced from the lease, is not alone sufficient to justify us in overturning the plain, certain, and unambiguous terms of the contract." 171 S.W. 2d at 323. The Supreme Court of Texas concluded that the lessor was "bound to accept payments out of the gas as it was then being produced from the wells, and is not entitled to have the gas refined into some other commodity." 171 S.W. 2d at 323. The Supreme Court's decision in Danciger Oil & Refineries v. Hamill Drilling Co. has evolved into a rule in Texas courts: "Since the early history of oil and gas litigation, the courts have held that covenants are implied when an oil and gas lease fails to express the lessee's obligation to develop and protect the lease." Amoco Prod. Co. v. Alexander, 622 S.W.2d 563, 567 (Tex. 1981). Accordingly, although Texas recognizes an implied duty to reasonably market oil and gas as part of an implied covenant of management and administration, which may be included in an oil-and-gas lease, the implied duty to market does not override language which specifies a particular payment method. For example, the Supreme Court of Texas has held that a gas lease which provides for payments to be made based upon the gas' "market price" is not breached when a lessee contracts to sell the gas at a price above the prevailing market cost, reaping profits beyond that which it could obtain in an open market, but calculates and pays royalties based upon the lower, prevailing, market price for the gas, because the language of the lease provides for royalty payments in accordance with "market price." Yzaguirre v. KCS Res., Inc., 53 S.W. 368, 370, 373-75 (Tex. 2001)("Depending on future market behavior, this may be financially beneficial to the lessor . . . or it may be less advantageous, as here. In either event, the parties have received the benefit of their bargain.").

65. The Court believes that, when the Supreme Court of New Mexico determines that the existence of the marketable condition rule is ripe for review, it will find the reasoning of Colorado, Kansas, Oklahoma, and Wyoming more persuasive than that of Texas. Like Kansas and Colorado, which construe oil-and-gas leases against the lessees, the Supreme Court of New Mexico has established a "rule that an oil and gas lease is to be construed most strongly against the lessee." Greer v. Salmon, 82 N.M. 245, 250, 479 P.2d 294, 299 (1970). This canon of construction is consistent with the duties a lease imposes on a lessee, such as the duty of "achiev[ing] the primary purpose of the lease, to explore, develop and produce." 82 N.M. at 250, 479 P.2d at 299. Colorado and Kansas have recognized that, once a lessor assigns its working and operating interests to a lessee, the lessee possesses the ability to evaluate and choose which post-production measures are necessary to render a gas marketable. Based upon the lessee's ability to assess post-production measures, Kansas and Colorado have determined that the lessee, and not the lessor, should bear the cost of those measures, as lessors generally will have "`no ready means of ascertaining'" the cost-benefit of a post-production measure "`other than to take lessees' word for it.'" Garman v. Conoco, 886 P.2d at 660 (quoting Piney Woods Cnty. Life Sch. v. Shell Oil Co., 726 F.2d 225, 240 (5th Cir. 1984)).

66. A critique of the marketable condition rule is that it necessarily turns on questions of fact, which the Supreme Court of Colorado recognized in Rogers v. Westerman Farm Co., because, whether a buyer is willing to purchase a product, and at what point, will vary from case to case. See Rogers v. Westerman Farm Co., 29 P.3d at 903-06; Scott Lansdown, The Marketable Condition Rule 44 S. Tex. L. Rev. 667, 702-04 (Summer 2003)("The strongest argument against the marketable condition rule is that . . . if the rule is adopted, oil and gas lessees will be faced with an endless wave of expensive, burdensome and wasteful litigation. . . . [because of] [t]he failure of . . . any real criteria for marketability."). The Court does not believe that the factual questions necessary to determining marketability are fatal to the marketable condition rule. The cases discussed herein indicate that, in certain locations and with certain products, no willing buyer may be found until an oil or gas product is either transformed into a different condition, or transported to a different location. At a minimum, the burden which the marketable condition rule imposes is that a market-ready product is able to reach the hands of a willing buyer, which is a burden New Mexico has already determined lessees should bear. Cf. Libby v. DeBaca, 51 N.M. at 99, 179 P.2d at 265 (holding that the implied covenant to market requires a lessee to construct a plant for converting gas into dry ice at his own cost, because the gas could be marketed only in dry ice form). The Court believes that the Supreme Court of New Mexico would find that, consistent with its holding that "pronouncement without disposition of the product is futile," the implied covenant to market includes a duty to render products marketable at the lessee's, and not lessor's, expense. Darr v. Eldridge, 66 N.M. at 263, 346 P.2d at 1044. While the situation which allows a buyer to purchase an oil or gas product will vary from case to case, the requirement that a royalty interest owner does not pay for the meeting of product and buyer is not onerous, and will, logically, be satisfied whenever a lessee realizes the goal of a lease: receiving a profit on oil-and-gas products.

67. This finding leads to the second critique of the marketable condition rule: requiring a lessee to bear the burden of post-production costs is pointless, because the marketable condition rule will incentivize lessees to find purchasers that will purchase unrefined products. Unrefined or unprocessed oil and gas will necessarily sell at a lower cost, because purchasers of the unprocessed products will factor into the price their costs to process the oil or gas. This critique of the marketable condition rule concludes, therefore, that payments will be calculated on oil-and-gas profits less production costs, regardless whether the lessee bears those costs. In theory, therefore, the marketable condition rule may not increase royalty owners' profits beyond their present state, as the cost of production will be taken from royalty payments in either transaction. The only change is in the entity deducting post-production costs. See Lansdown, supra, at 705-07. The Court does not believe that the Supreme Court of New Mexico will find this critique persuasive. The Court believes that the Supreme Court of New Mexico will conclude that, while it is true, in either situation, that post-production costs must be borne somewhere, the marketable condition rule, nonetheless, avoids an inefficient result. If oil-and-gas lessees may pass the cost onto lessors, the lessees lose the motivation for purchasing the most cost-efficient post-production measures. Oil-and-gas producers, as lessees, may attempt to pass those costs downstream to purchasers, but, in that instance, the purchaser will be assessing its own costs, and will, again, be incentivized to take on only cost-efficient post-production measures. See Libby v. DeBaca, 51 N.M. at 99, 179 P.2d at 265. In sum, the marketable condition rule incentivizes the entities with the most knowledge and ability to produce oil-and-gas in the most cost-effective manner. Without the marketable condition rule, oil-and-gas producers, as lessees, may pass post-production costs onto lessor-royalty-owners, who lack the knowledge and ability to evaluate and choose the best option. For these reasons, the Court believes that the Supreme Court of New Mexico will find that, included within the implied duty to market in New Mexico, is the marketable condition rule. As a district court, however, the Court is bound by the Tenth Circuit's decision in Elliott.77

IV. LAW REGARDING THE NMPPA.

68. The NMPPA sets forth a derivative remedy that the New Mexico Legislature provides to oil-and-gas royalty owners. It will not lie absent a demonstration of a lessee's breach of an underlying agreement with, or duty to, an interest owner. See Elliott, 407 F.3d at 1120 ("[I]n order to maintain a Payment Act claim, Elliott must allege a potentially successful claim for underpayment of royalties or theory of liability showing that it is `legally entitled to such payments.'" (quoting N.M. Stat. Ann. § 70-10-3)).

69. The NMPPA provides a specific time frame in which lessees on oil-and-gas lessees must pay royalty interest owners for proceeds they receive:

N.M. Stat. Ann. § 70-10-3. Working interest owners who fail to make payments within § 70-10-3's timeframe incur eighteen-percent interest on the "unpaid balance due," unless one of the four exceptions in § 70-10-5 applies:

N.M. Stat. Ann. § 70-10-5. Additionally, the lessee need not pay interest on unpaid balances if the lessee, has not received from the operator or lessee arranging for the sale of oil and gas "the name, the address, and the percentage of interest of each person to whom payment is to be made, as well as proof of marketable title" to the oil and gas to be sold. N.M. Stat. Ann. §§ 70-10-3.1 and -5 (providing that a lessor does not incur the eighteen-percent penalty on unpaid balances if payments are made in accordance with § 70-10-3's time period and the lessor "has been furnished with the information required by Section 70-10-3.1").

V. ANALYSIS.

70. The Court will deny the Motion. To be certified under rule 23(b)(3), a class must meet all four of rule 23(a)'s requirements — numerosity, commonality, typicality, and adequacy — and both of rule 23(b)(3)'s requirements — predominance and superiority. Because the NMPPA claim is separable from the other claims — while the other claims revolve around underpayment, the NMPPA claims revolve around late payments — the Court will analyze it separately. The Court thus divides its analysis into three parts. First, the Court will conclude that, although the underpayment claims satisfy rule 23(a)'s other requirements, they lack commonality under rule 23(a)(2). Second, the Court concludes that the underpayment claims fail to satisfy rule 23(b)(3)'s predominance requirement, although they would satisfy the superiority requirement. Last, the Court concludes that the NMPPA claims fail both rule 23(a)'s and 23(b)(3)'s requirements. Because the Defendants have contested virtually every component of this analysis — including both rule 23(b)(3) factors and three of the four rule 23(a) factors78 — the Court will go into some detail in discussing each portion.

A. THE UNDERPAYMENT CLAIMS DO NOT SATISFY RULE 23(a)(2)'S COMMONALITY REQUIREMENT, BUT THEY WOULD OTHERWISE SATISFY RULE 23(a).

71. Rule 23(a) sets forth the requirements that apply to all class actions in the federal courts: numerosity, commonality, typicality, and adequacy. The underpayment claims satisfy all but commonality.

1. At Over 1,367 Class Members, the Class Is Sufficiently Numerous to Warrant Class Treatment, Thus Satisfying Rule 23(a)(1)'s Numerosity Prerequisite.

72. Although it is said that there is "no set formula," Rex v. Owens, 585 F.2d at 436, nor "strict numerical test," Bittinger v. Tecumseh Prods. Co., 123 F.3d at 884 n.1, for determining when a class is sufficiently numerous for joinder to be impracticable, the reality is that a per se numerosity threshold seems to exist somewhere south of 150 proposed class members, see, e.g., Mullen v. Treasure Chest Casino, LLC, 186 F.3d at 624 (holding that "100 to 150 members . . . is within the range that generally satisfies the numerosity requirement"). This class contains over 1,367 members, which easily clears rule 23(a)(1)'s bar. The Court arrives at this number by starting with the 1,466 "persons or entities [who] are owners of royalty interests" and subtracting the up to 9979 proposed class members under the two excluded 372K wells, resulting in a final figure of 1,367.80 The actual total will likely be higher than this one, but it will not be lower. See supra notes 79, 80.

73. To elucidate the numerosity requirement's substantive content, the Court will look to its purposes, which the Court believes are two-fold. First, rule 23(a)(1) is concerned with manageability, i.e., the Court's ability to handle the case as a non-class action; this purpose is obvious from the rules text, which calls for "joinder . . . [being] impracticable." Fed. R. Civ. P. 23(a)(1). Here, the Court could not manage a non-class lawsuit where over 2,000 plaintiffs are expected to move and respond to motions on an individual basis; it certainly could not conduct hearings in such a manner.81

74. Second, the Court concludes that the numerosity requirement — like much if not most of rule 23 — is concerned with protecting absent plaintiffs from the dangers that inhere in class litigation's foregoing of meaningful, face-to-face attorney-client representation.82 In individual litigation, each party has, if not his or her own attorney, then at least an attorney who pledges, on pain of professional sanctions, to represent the party's interests to the fullest, and to make diligent efforts to communicate with the party fully about the case. This attorney is, in most cases, obligated to share all pertinent information and strategy relating to the case, and the client retains a great deal of control over the large-scale direction of the suit. In class litigation, however, the class counsel makes the big decisions that are, in individual litigation, reserved for the client, such as whether to settle for a given amount or to go to trial. Compare Model R. Prof'l Conduct 1.2(a) ("[A] lawyer shall abide by a client's decisions concerning the objectives of representation and . . . shall consult with the client. . . . A lawyer shall abide by a client's decision whether to settle a matter."), with Fed. R. Civ. P. 23(e)(5) (providing for settlement over the objection of some class members), and id. 23(c)(2)(B), (e)(1) (contemplating that "notice" be sent to class members in specific circumstances). Moreover, class counsel typically cannot share information or strategy with the class if he or she wants to keep that information secret from the defense. Given that keeping information and strategy secret from the opposition is often sound litigation strategy in itself, even a well-meaning class counsel advocating vigorously on behalf of the entire class might find himself or herself in the position of being unable to speak candidly with inquiring class members. Class litigation, in short, puts class counsel in a similar position in regard to his or her clients as a board of directors of a publicly traded corporation is to its shareholders: he or she must act on their behalf, but may do so without their knowledge and even over their objections. Class litigation attempts to bridge the gap between the absent plaintiffs and their attorneys by using class representatives — a somewhat weak response, as the Court will discuss later — as well as by having the judge appoint counsel, monitor class counsel's advocacy, set attorneys' fees, and scrutinize all settlements independently for fairness — a better response, but one that does not utilize the time-tested incentives of the adversarial process. See Fed. R. Civ. P. 23(e), (g), (h). For these reasons, individual litigation is preferable to class litigation — if it is a realistic option. See, e.g., Califano v. Yamasaki, 442 U.S. 682, 700-01 (1979)(describing class litigation as "an exception to the usual rule that litigation is conducted by and on behalf of the individual named parties only").

75. Here, however, individual litigation is not realistic, as joinder is impracticable. If, hypothetically, the Court were to force the Plaintiffs to join each class member as a full-fledged, jointly represented83 party under rule 20, counsel's communication with his clients would, of necessity, still resemble that of class counsel and class member, and not that of attorney and client. This observation is not to say that a class counsel cannot effectively communicate with his class outside of rule 23's notice requirements; he can. The internet has made it feasible to correspond regularly with class members — or at least those class members who care enough to keep informed — and keep them informed of the litigation's progress. What the Court means is that, in a case where plaintiffs' counsel represents 1,367 clients — whether as joined parties or a certified class — he cannot share secret information with its clients, he cannot obtain their unanimous permission to settle, and, to act in their best interests, he must represent the class' whole rather than its parts. Even if the Court could manage this number of plaintiffs under rule 20, which it cannot, all it would be doing is eschewing rule 23's built-in protections for absent plaintiffs. The class clears rule 23(a)(1)'s numerosity hurdle.

2. Incidental Common Questions of Law and Fact Exist, Most Notably Regarding the Defendants' Uniform Payment Methodology, but They Are Not Sufficient to Satisfy Rule 23(a)(2)'s Commonality Prerequisite.

76. Incidental common questions of law and fact exist in this case, but none satisfy Wal-Mart. For better or for worse, the commonality inquiry now focuses on quality rather than quantity. While, in the old days, a single common question might have cleared the rule 23(a)(2) bar, and in the right case might still do so, Wal-Mart has beefed up the requirements to be considered a common question in the first place. Post-Wal-Mart, a common question must be "capable of classwide resolution — which means that determination of its truth or falsity will resolve an issue that is central to the validity of each one of the claims in one stroke," or, to use the more popular phraseology, it must be prone "to generate [a] common answer[] apt to drive the resolution of the litigation."84 131 S. Ct. at 2551 (emphasis in original). In this case, common questions do not abound. The Court will analyze commonality for the underpayment claims and the NMPPA claim separately.

77. Regarding the underpayment claims, the Defendants paid all class royalties and overriding royalties under a uniform policy, with the exception of two of the wells committed to the 372K gathering contract, which the Court excludes from the class. See Stipulation ¶¶ 9, at 2 ("There are no differences in WPX's royalty accounting methodology based on the royalty provisions contained in the [class] leases and the [class] assignments."); id. at 4 n.6. This policy valued production from all wells committed to Williams Four Corners under a keep-whole method and production from all wells committed to independent gatherers under the sale price that the Defendants received from the independent gatherer. In terms of deducting post-production expenses from the royalty, the Defendants (i) do not deduct them at all for Colorado wells; (ii) deduct them at a proportionate rate to what the gatherer charges the Defendants for New Mexico wells committed to independent gatherers; and (iii) deduct them using a COS charge identical to the one that the federal government demands for non-arm's length transactions for New Mexico wells committed to the Williams Four Corners gathering systems. This uniform policy, which calculates and pays the class' royalties without regard to variations in lease language, is a common issue85 of fact, and it forms one half of the Plaintiffs' underpayment claims. The underpayment claims, at base, consist of two input inquiries and one output result: (i) "how were the class members entitled to be paid by the Defendants," which is a mixed legal and factual question that requires looking to the language in the leases and any implied-in-law terms; (ii) "how did the Defendants actually pay the class members," which is a factual question that requires looking to the evidence; and (iii) "what is the numerical difference, if any, between (ii) and (i)," which determines damages. Issue (ii) is common, but it is undisputed, and, thus, incidental. It is not merely "capable of" a producing a common answer, Wal-Mart, 131 S. Ct. at 2545, it has already been given one. The Court thus does not believe, after Wal-Mart, that the Defendants' uniform payment policy is the common question that satisfies rule 23(a)(2). See EQT Prod. Co. v. Adair, 764 F.3d at 366 ("That the defendants engaged in numerous common practices may be sufficient for commonality purposes." (emphasis added)). Issue (i) — how were the class members entitled to be paid by the Defendants — is the important one in this case, and it is an individualized inquiry.

78. Arguably, the aforementioned "uniform policy" is at least two policies — one that valued Williams Four Corners-gathered wells on a keep-whole basis, and another that valued independently gathered wells on sale-receipt basis — and thus is not common to the class.86 Of course, there are other common questions in this case, and, for the most part, they are "common to the class," but less clearly "central to the validity of each one of the claims." These questions include: (i) whether a marketable-condition rule exists, requiring the Defendants to absorb all costs of rendering the gas marketable; (ii) whether a WASP is a permissible basis for paying royalty; (iii) whether an index is a permissible basis for paying royalty; (iv) whether reasonable diligence by a hypothetical person in a class member's shoes would have uncovered the causes of action before the critical date for the statute of limitations;87 (v) whether the check stubs that the Defendants sent out to the class, which were uniform in nature, contained material misrepresentations; and (vi) whether the check stubs were misleading such that they violated the covenant of good faith and fair dealing. These questions do not resemble questions that have been held — pre-Wal-Mart and at the Court of Appeals-level — to be common questions in other cases, including: (i) whether an employer engaged in a pattern of racketeering activity that depressed the wages of all employees, see Williams v. Mohawk Indus., Inc., 568 F.3d 1350 (11th Cir. 2009); (ii) whether an employer engaged in racial discrimination in the setting of wages, see Parra v. Bashas', Inc., 536 F.3d 975, 980 (9th Cir. 2009); (iii) whether a health-care plan created a backlog of unprocessed claims, see Gunnells v. Healthplan Servs., Inc., 348 F.3d 417, 425 (4th Cir. 2003); and (iv) whether a product produced by the defendant was defective, see Butler v. Sears, Roebuck & Co., 727 F.3d 796, 801 (7th Cir. 2013). See also Newberg § 3:24.

79. The primary question in this case is not sufficiently similar to the common questions in those cases to give the Court comfort that the primary question in the case is a common question. In those cases, the common questions answered the main issues in the case. Here, the primary issue is how much the Plaintiffs should have been paid, and the Defendants' practices do not answer that question in a common way. Moreover, most of these common questions, in the pre-Wal-Mart era, could theoretically be broken down into more specific questions that no longer encompassed the entire class. None of them, on its own, definitively establishes a claim, even if answered in the affirmative. It is questions like these that Justice Scalia had in his crosshairs when he wrote Wal-Mart.

80. Even if the Court were to certify any part of this case, the Court would still exclude from the class the two 372K wells on which the Defendants pay royalty under a separate methodology. The Plaintiffs' premier common issue — that the Defendants calculate and pay all royalties under a uniform policy — does not apply to these wells. While other common questions may apply to the two 372K wells, the uniform-payment issue is ultimately the issue that has the best chance to render this case manageable, as the Court will describe in its predominance analysis. The bigger problem is that no evidence was presented to the Court regarding how royalty is paid on these wells. Other than the vague statements in the Stipulation that these two wells "are exceptions to th[e otherwise common] methodology" and that the interest owners on those wells "are paid . . . for NGLs," the Court has heard little about them. Stipulation at 4 n.6. They came up only briefly at the hearing, during Ward's direct examination, and Ward did nothing but repeat the assertions in the Stipulation footnote. See Tr. at 452:3-21 (Sutphin, Ward). The Plaintiffs seem to have essentially written those wells off, and, accordingly, they have failed to carry their burden under rule 23 to include them in the class.

3. The Class Representatives' Claims Are, in All Important Respects, Identical to the Absent Class Members', Thus Satisfying Rule 23(a)(3)'s Typicality Prerequisite.

81. Typicality is satisfied in this case, because the class representatives bring the same causes of action, and present comparable factual circumstances, as the absent class members. The Court notes that it is not clear whether typicality requires independent inquiry at all in the Tenth Circuit. At least one district court in the Tenth Circuit has concluded that the "Tenth Circuit has said that the typicality requirement is satisfied if there are common questions of law or fact." Gianzero v. Wal-Mart Stores Inc., 2010 WL 1258071, at *3 (citing Milonas v. Williams, 691 F.2d at 938). That is not quite what the Tenth Circuit said in the cited case, but nor is it an absurd characterization:

Milonas v. Williams, 691 F.2d at 938 (citations omitted)(footnote omitted). The first sentence of the quoted excerpt, read literally, seems to suggest that the commonality and typicality inquiries are coextensive. Although Milonas v. Williams is a pre-Wal-Mart case, Wal-Mart only heightened the commonality inquiry, so, if commonality and typicality were coextensive before Wal-Mart, then the Court can conceive of only two possible effects that Wal-Mart could have on typicality: (i) the typicality inquiry is heightened alongside the commonality inquiry, so that the two remain coextensive; or (ii) the typicality inquiry remains where it was, meaning that typicality now represents a lower threshold, fully inscribed within the commonality inquiry. Either way, the typicality inquiry would not bar any cases that passed the commonality inquiry.

82. Although typicality certainly seems to be the forgotten rule 23(a) prerequisite after Wal-Mart, the Court thinks that it still has some utility. In the post-Wal-Mart era, class representatives probably have to allege all of the same claims that the absent class members do to even satisfy commonality. Class representatives, however, can still have factual circumstances that differ from those of the bulk of the absent portion of the class, or their claims could be subject to defenses that do not apply to many absent class members, and, in extreme cases, this dissimilarity might make the proposed class representatives unsuitable under rule 23(a)(3). This inquiry is necessarily an imprecise, "eye-test" standard, in which the Court tries to discern whether the putative class counsel has made a reasonable effort to collect class representatives who fairly reflect the absent class members' posture in the litigation.88 Here, no absent class member asserts any cause of action that is not also asserted by at least one of the class representatives, and the class representatives appear to be spread fairly well across the various segments the Court would use to manage this case. There are Colorado representatives and New Mexico representatives; there are representatives with Williams Four Corners-gathered wells and representatives with independently gathered wells; and there are representatives with conventional wells and representatives with coalbed methane wells. See Typicality and Adequacy of Class Reps (Plaintiffs' Demonstrative Exs. 9-11). The Court thus concludes that the class representatives have claims that are typical of the class.

4. The Class Representatives Will Vigorously Prosecute the Action, Thus Satisfying Rule 23(a)(4)'s Adequacy Prerequisite.

83. The class representatives will vigorously prosecute this action on behalf of the absent class members. The representatives' claims are not only typical but essentially identical to those of the absent class, and the representatives appear competent, informed, and savvy regarding the law and the facts of this case. The Patton Trust has Bank of America as its trustee, represented by Munoz, who has over fifteen years of experience in the oil-and-gas industry. Anderson received royalties from seven different oil-and-gas companies, and has served as a class representative in other oil-and-gas class actions — meaning that at least one other judge has already deemed him an adequate representative in a case very similar to this one. This part of the commonality analysis overlaps heavily with the typicality analysis. To the extent that there is any noticeable difference in factual circumstances between the representatives and the bulk of the class, it is that the representatives appear to own unusually large or valuable interests relative to the rest of the class. This difference however, increases the representatives' adequacy rather than decreasing it.89 Last, the Defendants also contend that the representatives are inadequate, because they do not possess leases and assignments that contain every category of textual royalty/overriding royalty provision. The Defendants, however, offer no reason for why that level of detailed representativeness is necessary, and the Court cannot conceive of any strong ones.90

B. THE UNDERPAYMENT CLAIMS DO NOT SATISFY RULE 23(b)(3).

84. The Court concludes that the proposed class fails to satisfy the rule 23(b)(3) requirement of predominance of common issues over individual ones, although it satisfies the superiority requirement.

1. The Underpayment Claims Fail Predominance, Because the Court Would Spend More Time Adjudicating Individual Questions Than Common Questions.

85. "Predominance regularly presents the greatest obstacle to class certification." CGC Holding Co. v. Broad and Cassel, 773 F.3d at 1087. This axiom holds true in this case. As the Tenth Circuit has instructed, to determine predominance, the Court must "characterize the issues in the case as common or not, and then weigh which issues predominate." CGC Holding Co., LLC v. Broad & Cassel, 773 F.3d at 1087.

86. The proposed class fails the Tenth Circuit's predominance test. The common evidence in this case includes: (i) evidence about the Defendants' payment methodology, which is uncontroverted and thus likely to be minimal; (ii) industry-custom-and-usage evidence shedding light on the meaning of all of the class leases; (iii) course-of-performance evidence, which is essentially the same as (i); (iv) evidence regarding the level of diligence that a reasonable lessor would exercise to learn of his or her claims — relevant to the Defendants' limitations defense; and (v) the Plaintiffs' requested damages methodology — they request a netback payment, and, thus, their total damages evidence involves only the Defendants' total (common) final proceeds, and their total (common) transportation and processing expenses. The individualized evidence in this case includes: (i) industry-custom-and-usage evidence regarding what specific royalty provisions — e.g., "proceeds," "market value," "gross proceeds," "net proceeds" — which are not shared by all class members, mean; (ii) the differing language between the various leases; (iii) parol evidence concerning negotiations and oral agreements contemporaneous to the execution of certain class leases — the Court doubts that much of this evidence exists, however, and assigns a low weight to it in the predominance calculus; (iv) evidence of certain class members' calls to WPX Energy inquiring about their royalty payments — relevant to individual affirmative defenses against certain members; and (v) the individual damages evidence — which includes analyses of which wells' gas tends to travel to which plants, various plants' efficiency levels and bypass rates over time, and what costs, including used gas, are attributable to which individual wells. Weighing the individualized evidence against the common evidence, the Court concludes that it will spend the majority of its time hearing individualized evidence and adjudicating individual questions.

87. The Court has identified five common issues in this case, two of which are essentially identical. Evidence of the Defendants' payment methodology and of the parties' course-of-performance would take up a small part of the trial and the Court's management of the case. First, the parties do not dispute the methodology that the Defendants' used to pay the Plaintiffs — i.e. the parties' course of performance. Little, if any, evidence would be introduced at trial to show the Defendants' payment methodology. In all likelihood, there would be no evidence entered at trial, because the Defendants have stipulated to what methodology they used to pay the Plaintiffs. Second, even if the Defendants refused to stipulate to their payment methodology, this evidence could easily be proven at trial, and it would not consume a large portion of the case. Absent fraud in the form of altering or destroying accounting records, the Defendants likely have records of the methodology they used to determine each lessee's payments. During discovery, the Plaintiffs would likely uncover this information, and they could easily prove the methodology through a single witness and the introduction of several documents. In any case, because the Defendants stipulate to the methodology, these common issues would take up only a miniscule portion of the case.

88. In the same way that the Defendants' payment methodology and the parties' course of performance would not play a large role in the case, neither would calculating the Plaintiffs' requested payment methodology. The netback payment method requires knowledge of two figures: (i) the Defendants' total (common) final proceeds; and (ii) their total (common) transportation and processing expenses. The Defendants likely keep accounting documents from which these figures can easily be derived. There is no indication that either party would dispute the accuracy of the numbers; rather, the main objections lie in what methodology to use and how to determine individualized damages after total, class-wide damages have been calculated. Therefore, the jury's only job — if the Court adopted the Plaintiffs' requested payment methodology — would be to make one simple calculation: the Defendants' total final proceeds minus total transportation and processing expenses. This common issue would, thus, take up little time at trial.

89. As for industry-custom evidence, while this evidence may be common for leases with the same language, this issue's significance is undercut by the fact that all of the leases do not have identical language. Some of the leases — perhaps even a vast majority of them — have similar wording, which can be defined through common industry-custom evidence. Yet, because all of the leases do not have identical language, they will still require individualized determinations — thus cutting against a finding of predominance.

90. Finally, there may be common evidence concerning the amount of diligence a reasonable lessee would exercise in discovering whether he or she was being paid adequate royalties. This evidence is common across the class, because if a common lessee would have discovered his or her cause of action before a certain point in time, the statute of limitations may bar all of the Plaintiffs' claims. Similarly, if a reasonable plaintiff would not have discovered his or her cause of action, then the statute of limitations would not present a per se bar to the Plaintiffs' claims. This factor is undercut, however, by the fact that the Defendants are focusing less on when a reasonable lessee would have discovered his or her cause of action, and more on when specific individuals would have discovered their causes of action. The Defendants' statute of limitations defense, thus, focuses on individualized and not common issues.

91. While there are several common issues in this case, they will not predominate over the individualized ones. The majority of the trial, and the Court's time preparing for trial and managing this case, will be spent on the individual issues.

92. The parties would likely spend the bulk of the trial presenting testimony regarding the meaning of the various textual royalty provisions; these issues are not truly individual, because multiple class members share the same royalty provisions — perhaps a better term would be "categorical" or "quasi-common" — but they are not common, and, given that subclassification cannot substitute for the entire class' satisfaction of the rule 23(b)(3) requirements, they weigh against predominance. But see EQT Prod. Co. v. Adair, 764 F.3d at 363 ("[T]he plaintiffs may be able to identify a finite number of variations in deed language, such that the ownership question is answerable on a subclass basis.").91 The main fight in this case is what payment methodology the Defendants should have used. This issue is resolved by examining the language of the individual leases. Every lease does not, however, contain identical language; the Court must, therefore, apply a different legal standard to each lease variety. Variation in lease language was the main problem that the Fourth Circuit identified in EQT Production Co. v. Adair. See 764 F.3d at 367. There, the Fourth Circuit instructed the district court to "consider how variations in the defendants' royalty obligations to the class members implicate the commonality and predominance inquiries," and even noted that these lease variations would "make it difficult, if not impossible, for a court to assess the validity of the defendants' royalty payment practices on a classwide basis." 764 F.3d at 367-68. These same concerns are prevalent in this case because of the leases' varying language and the different industry-custom-and-usage evidence that will be needed to interpret the different lease variations.

93. The management plan that the Court crafted underscores that individual issues would predominate over common ones. Under its plan, the Court would divide the class into segments on the basis of either the potential of a different legal standard applying or different factual circumstances existing: (i) between Colorado wells and New Mexico wells; (ii) between Williams Four Corners-gathered wells and independently gathered wells; and (iii) among the eight textual formulations the Court has identified among the class leases' royalty provisions. If there is one thing that the case law has repeatedly made clear, it is that the Court cannot ignore variations in contractual language. See, e.g., EQT Prod. v. Adair, 764 F.3d at 363; Roderick, 725 F.3d at 1218-19; Chieftain Royalty Co. v. XTO Energy, Inc., 528 F. App'x at 942-44. Each segmentation creates an individual issue, because the Court has to determine in which segment each lease belongs.

94. The Court has produced a spreadsheet — attached hereto — based on the Spreadsheet of Lease Language (Plaintiffs' Ex. 428),92 that divides the leases into eight categories, A through H, where each lease within any given category contains a materially93 textually identical royalty provision. Cf. Roderick, 725 F.3d at 1219 ("On remand, the Trust could, for example, create a chart classifying lease types....").94 See EQT Prod. Co. v. Adair, 764 F.3d at 369 ("[A]fter reviewing the leases in this case, the plaintiffs may be able to show that there are a limited number of lease forms, such that the validity of the defendants' conduct can be assessed on a subclass basis."). Leases in which the royalty provision is illegible but the form-contract identifier is legible were assumed to have the same textual royalty provision as the other leases with the same form-contract identifier, and were placed into the appropriate category, accordingly. Leases that are illegible — i.e., they are not themselves readable, nor do they have a legible form-contract number — were placed in category X.95 The Court designates a lone lease with an entirely unique textual royalty provision with a Y. This spreadsheet has columns specifying whether each lease is from Colorado or New Mexico, and whether wells on the lease are gathered by Williams Four Corners or an independent gatherer — although the latter column is currently empty, as the Plaintiffs have not provided the Court with the necessary information. Once again, each of these designations required individual determinations.

95. As for the difference between one-pronged and two-pronged leases, the Court has fully separated them into their own categories — no two-pronged lease is in the same category as any one-pronged lease or any two-pronged lease that differs on either of the two prongs. The Defendants contend that the two prongs — and the Court uses "prongs" to refer to variations in royalty language triggered by whether the gas is sold at the wellhead or away from the wellhead, and not variations based on whether gas is casinghead gas — are important, and the Plaintiffs have not yet shown that they are not important. No gas is sold at arm's length at the wellhead, unless that clause is intended to refer to gas transmitted to independent gatherers. If transfer to a gatherer counts as a "sale" under these provisions — although, at the present time, the Court is inclined to think that it does not — then the Court would be required to keep all eight lease-language categories, unless the Plaintiffs can establish that the language used in some of the categories is identical in its meaning. If, however, independent gathering does not count as a wellhead sale, the Court could ignore the "sold at the well" prong of the two-prong leases, and collapse the eight categories into four or five categories. These determinations are individual ones that the Court would need to make if it were to certify this class.

96. Category A consists of leases that pay royalty on the basis of "proceeds, as such," and contains 222 of the 507 class leases. Category B consists of leases that pay royalty on the basis of "proceeds if sold at the well" and "market value at the well" "if marketed by Lessee off the leased premises," and contains 113 class leases. Category C consists of leases that pay royalty on the basis of "the amount realized from ... sale" on gas "sold at the well[]" and "market value at the well" on gas "sold or used off the premises or in the manufacture of gasoline or other product therefrom," and contains seventy-eight class leases. Category D consists of leases that pay royalty on the basis of "gross proceeds" and contains thirty-four class leases. Category E consists of leases that pay royalty on the basis of "net proceeds realized from ... sale" on gas "sold at the well," and "market value at the well," on gas "sold or used off the premises or in the manufacture of products therefrom," and contains twenty-four class leases. Category F is an unusual textual formulation. Its leases provide that royalty is to be paid on the basis of "gross proceeds" on gas "used off the premises," and "if used in the manufacture of gasoline a royalty [paid on the basis of] the prevailing market rate for gas." It contains ten class leases. Category G consists of leases that pay royalty on the basis of "market price at the well" and contains four class leases. Category H consists of leases that pay royalty on the basis of "gross proceeds" on gas "sold at the mouth of the well" and "market value ... at the mouth of the well" on gas "not sold at the mouth of the well," and contains three class leases. The oddball Y lease provides that royalty is to be paid on the basis of "gross proceeds" "and if such gas be used in the manufacture of gasoline ... the prevailing market rate."

97. Even if not all — or even no — textual variations take on a different meaning in New Mexico than they do in Colorado, the Court would still need to segment the class by the state in which the well is situated, because (i) Colorado recognizes the marketable-condition rule, while New Mexico does not, meaning that a different legal standard applies between the two segments; and, correspondingly, (ii) the Defendants assess a COS charge on Williams Four Corners-gathered wells in New Mexico, but not in Colorado, meaning that the two segments are in different factual circumstances. The Court would also have to segment the class based on whether the well is gathered by Williams Four Corners or an independent gatherer, because (i) the Defendants assess a COS charge, or no charge at all, on Williams Four Corners-gathered wells in New Mexico and Colorado, respectively, but merely pass on a proportionate chunk of the independent gatherer's fee on independently gathered wells, meaning that the two segments are in different factual circumstances; and (ii) if a transfer of gas to an independent gatherer is considered a "sale at the well," under the two-pronged leases, then the independently gathered wells with two-pronged leases will also each be subject to a different legal standard than wells in the same lease category, but that Williams Four Corners gathers. The Court, and the parties, would be required to make individual determinations of each and every lease to place them in the correct segment.

98. The illegible (X) leases and the unique (Y) lease are outside of this management framework, but the Court might be able to include them in the class, if it were to certify the class under this management plan. The unique (Y) lease would probably be folded into one of the existing lease categories once the Court established its meaning.96 As for the eighteen illegible leases, three things could happen with them. First, the parties might be able to produce legible copies of them. The Court has the same copies that Kaplin had, and it is possible that legible copies exist out there somewhere. Second, the parties might come forward with evidence of individual leases' likely text, e.g., if a lessor executed an illegible lease at the same time as the lessor executed two other class leases, both of which have the same textual royalty provision, then the Court could find that the illegible lease says the same thing as the two contemporaneously executed leases. At any rate, unless the illegible leases turned out to be unique, the leases could then be placed, on an individual basis, into the category in which they belong. Third, even if the parties presented the Court with no individualized evidence on the illegible leases' meanings, the Court would still have to interpret them to mean something — that the leases are illegible does not give the Defendants free reign to pay however they want, any more than it permits them to stop paying royalty altogether on gas they extract from the class members' land. Determining these leases' meaning, and how to make that determination, are individualized issues.

99. Working from front-to-back — i.e., starting with the lease-language obligations, the variations in state law, and the situational differences between affiliate-gathered and independently gathered wells — as the Court has thus far, this class action could involve up to forty different legal standards for the jury to apply. Peeking at the back end of this case, however, the Court doubts that forty different standards — i.e., forty different ways of paying royalty on natural gas — exist, let alone that the class leases contain all forty of them. The problem for the Court is that the Plaintiffs have not, by a preponderance of the evidence, established that the Court's doubts are well-founded. The same seven payment terms appear in every lease: (i) "proceeds, as such"; (ii) "proceeds"; (iii) "gross proceeds"; (iv) "net proceeds"; (v) "market value at the well"; (vi) "market price at the well"; and (vii) "amount realized." Many of these terms may mean the same thing as one other, and all of the terms may mean the same thing in New Mexico as they do in Colorado — with regard to the basic payment methodology, at least; permissible deductions will differ between the two states. The problem for the Court is that the Plaintiffs have not, by a preponderance of the evidence, established that the terms are the same. The Court, if it certified the class action, would have to keep these categories separate for the time being for four reasons: (i) class certification is not the time to decide the case's merits, and the royalty provisions' meanings are merits issues; (ii) even if the Court wanted to determine the provisions' meanings at the point of certification, the parties have presented the Court with little evidence on this topic;97 (iii) as a practical matter, it would be easier to start with greater number of segments and winnow them down later in the case than it is to separate out differences after certification that the Court had glossed over before certification; and, most importantly, (iv) for any given lease provision, if the Court cannot pin down the terms' meanings as a matter of law, then the jury must decide them as a matter of fact — this last point prevents the Court from just taking its best crack at interpreting the leases based on the little bits of evidence the parties have presented to date. Point (iv) does not necessarily mean that the jury would have to find and apply forty different standards. It means that, if the Court ends up being unable to collapse any of the current segments together before trial as a matter of law, the jury would have to, first, find all forty legal standards and, second, apply however many remained after, undoubtedly, some of them may turn out to be identical to one another98 — effectively collapsing the segments and then applying the smaller number of legal standards. The Court would likely, however, be able to discern some of the leases' meanings during the parties' pre-trial motion practice.

100. That the Court may be able to winnow the forty different standards down a bit does not, however, weigh in favor of predominance. As of now — the class certification stage — the Court must determine predominance. The Court should not certify the class on the basis that perhaps at some point down the road common issues will predominate, or at least will be closer to predominating, individual ones. The Court must determine predominance now, and, the potential forty different legal standards governing the various claims creates too many individualized standards for the Court to find that common issues predominate.

101. In In re Bridgestone/Firestone, Inc., Judge Easterbrook addressed the question whether a district court properly certified a nationwide class action involving fifty different legal standards — i.e., one from each state. See 288 F.3d at 1018. Judge Easterbrook explained that such a class would not be manageable and would not be efficient. See 288 F.3d at 1018-20. Judge Easterbrook commended the district judge's resolve to apply fifty different legal standards, rather than refusing the certify the class and requiring each class member to file individual suits:

288 F.3d at 1019-20. Judge Easterbrook concluded, however, that the case was not appropriate for certification. See 288 F.3d at 1018-20.

102. While the forty potential legal standards in this case is less than the fifty with which Judge Easterbrook was presented in In re Bridgestone/Firestone, Inc., forty is just a stone's throw away from fifty, and Judge Easterbrook's predominance concerns resonate here. That the Court and jury will have to spend a substantial amount of time interpreting the differing lease provisions that are not common to the entire class shows that common issues do not predominate over individualized ones.

103. That the Defendants may introduce parol evidence to interpret the meaning of individual leases further cuts against predominance. The Court doubts that such evidence exists, given the age of the leases, but the possibility of such evidence weighs against predominance. If the Defendants presented parol evidence, the Court would have to make individual determinations as to the meaning of each lease on a lease-by-lease basis. While the variations in the leases' language already defeats predominance, parol evidence that would cause even more lease variations and standards counsels further against certification. The Court may have to consider parol evidence to determine if the meaning of individual leases is ambiguous. If the Court found ambiguity, it would permit the parties to present evidence at trial to determine the meaning of these individual leases. The jury would be required not only to apply forty different legal standards to the different lease segments, but also determine the individual leases' meanings.

104. As the Court has discussed, state courts are more amiable to oil-and-gas royalty class actions, but, even in New Mexico state court, the possibility of parol evidence, which would require to Court to make individualized lease-by-lease determinations, may defeat certification. The district court in Davis v. Devon Energy Corp. concluded that the possibility of parol evidence, which may cause individual leases to be ambiguous, could overwhelm the case, such that common issues would no longer predominate over individualized ones. See 2009-NMSC-048, at ¶ 10. The Supreme Court of New Mexico reversed the district court, but on different grounds, holding that, under the marketable condition rule, the district court should have considered an implied covenant that did not require consideration of the individual leases' provisions. See 2009-NMSC-048, at ¶ 36. The Supreme Court of New Mexico did not, however, consider whether the district court erred in concluding that the possibility of parol evidence may defeat predominance when the plaintiffs' claims rely on interpretation of the leases' provisions. The Court agrees with the state district court. The possibility of parol evidence counsels against finding predominance and against certification.

105. The Defendants' statue-of-limitations defense also cuts against certification. While "[u]nique affirmative defenses that require some individualized inquiry do not present a per se bar to certification," Pace v. PetSmart Inc., No. CIV 13-0500 DOC/RBNx, 2014 WL 2511297, at *9 (C.D. Cal. June 3, 2014)(Carter, J.)(quoting Kelly v. City and County of San Francisco, No CIV 05-1287, 2005 WL 3113065, at *3 (N.D. Cal. Nov. 21, 2005)(Illston, J.)), affirmative defenses that will require individualized evidence and determinations cut against finding predominance, see Waste Mgmt. Holdings, Inc. v. Mowbray, 208 F.3d 288, 295 (1st Cir. 2000)("[W]e regard the law as settled that affirmative defenses should be considered in making class certification decisions."); Kaye v. Amicus Mediation & Arbitration Grp., Inc., 300 F.R.D. 67, 79 (D. Conn. 2014)(Hall, J.)("This court is bound by Dukes, and in the wake of Dukes, this Circuit has likewise treated affirmative defenses on which defendants' ultimate liability will depend as proper subjects of the inquiries into commonality and typicality, as well as predominance."); Donaca v. Dish Network, LLC., 303 F.R.D. 390, 399-400 (D. Colo. 2014)(Jackson, J.)("However, `an affirmative defense is not per se irrelevant to the predominance inquiry.'" (quoting Gene & Gene LLC v. Biopay LLC, 541 F.3d 318, 327 (5th Cir. 2008)); Robert Elliott Trucking, Inc. v. Caterpillar, Inc., No. CIV 11-0753 RMG, 2012 WL 2918700, at *8 (D.S.C. Mar. 21, 2012)(Gergel, J.)("Additionally, the Court finds that the commonality and predominance requirements are not satisfied because Defendant's affirmative defenses would require individual determinations."). The Defendants may prove their statute-of-limitations defense by showing that a reasonable lessee would have discovered his or her cause of action sooner; however, they may also prove their defense on an individualized basis — the time when individual lessees discovered their causes of action. Several lessees made inquiries with concerning their royalty payments. There is a question whether these inquiries should have alerted the lessees to whether they had a cause of action. The jury might hear evidence on what each lessee, or a significant number of lessees learned during those conversations and will have to determine whether these individual lessees should have discovered that they had a cause of action at that time. It is unclear how much of this evidence the Defendants will present, but the fact that they will present some individualized affirmative defense evidence counsels against finding predominance.

106. Finally, there are a number of individualized issues that must be resolved to determine individual class-member's damages. As the Court has already concluded, Comcast v. Behrend requires the Court to consider individual damages calculations at the certification stage. Here, the jury will have to consider a number of individualized issues, including which wells traveled to which plants, the various plants' efficiency levels, the bypass rates over time, and from which wells drip condensate was collected. While the overall damages may be calculated through a simple mathematic formula — the Defendants' total (common) final proceeds minus their total (common) transportation and processing expenses — the individual damages must be calculated through consideration of a significant amount of individualized evidence. It would take more time and resources to make these individualized damages calculations than to make the fairly straightforward class-wide damages calculation.

107. The leases' variations, by themselves, create too many individualized issues so that the common issues do not predominate the individualized ones. Because of the lease variations, the state-law issues, the affirmative defenses, and potential challenges with calculating damages, the Plaintiffs fail to satisfy the predominance requirement. The large number of individualized issues that are central to this case prevent the Court from finding that common issues predominate. For this reason, the Court concludes that the Plaintiffs cannot satisfy the predominance requirement, and certification is inappropriate.

2. The Class Action Device Is Superior to Other Available Procedural Forms, Largely Because the Class Members' Individual Suits Have Negative Value.

108. The class action device is superior to other available procedural forms. The only form available to adjudicate this dispute is individual litigation, and the class members' individual suits have negative value, and thus cannot be pragmatically pursued in the absence of certification. Addressing the four rule 23(b)(3) factors in turn, the Court concludes first that "the class members' interests in individually controlling the prosecution or defense of separate actions" would not be served by denying class certification, because the class members cannot economically maintain their own suits. Fed. R. Civ. P. 23(b)(3)(A). This factor thus cuts in favor of certification. Second, considering "the extent and nature of any litigation concerning the controversy already begun by or against class members" also cuts in favor of certification, because the Court is unaware that any class members have commenced individual litigation. Fed. R. Civ. P. 23(b)(3)(B). Third, it is "desirab[le] ... [to] concentrat[e] the litigation of the claims in th[is] particular forum," because (i) it is geographically convenient for the parties, witnesses, and lawyers, and near to the locus of the action, which is largely within the District of New Mexico; and (ii) the Court has worked on this case extensively and become familiar with the factual and legal issues involved. Fed. R. Civ. P. 23(b)(3)(C). Fourth, the proposed class does not present insurmountable manageability issues. See Fed. R. Civ. P. 23(b)(3)(D). Accordingly, the Court concludes that the proposed class satisfies the superiority requirement.

a. The Class Action Device Would Be Superior to Individual Suits, Because the Class Members' Individual Suits Have Negative Value.

109. The class-action device would be superior to the use of individual actions to adjudicate this case, because the individual actions that could arise from this case have negative value. Because the class-action device is, itself, unavailable — lacking commonality and predominance — the superiority requirement is not satisfied. Interestingly, while virtually everything that has ever been written on class actions states — and every legal and political perspective on class actions espouses — that negative-value class actions are favored over positive-value ones, no one has (i) outlined a workable test for determining if a class action has negative value; or (ii) crisply defined what negative value means. What is clear is that a case has negative value when it would be uneconomical for the class members to bring individual claims.

110. The Court concludes that negative value does not correspond to a particular claimed dollar amount that applies in every case, e.g., every case in which the plaintiff requests more than $10,000.00 has positive value or every case in which the plaintiff requests less than $3,000.00 has negative value. Two additional factors must be considered in addition to the dollar figure that the plaintiff may write in the complaint. First, the Court must multiply the case's potential damages by the plaintiff's likelihood of success, thus calculating the case's expected value. Second, the Court must subtract any disparity in litigation costs between the plaintiff and defendant, i.e., any expected litigation costs that the plaintiff will incur but the defendant will not.99 This calculation is how a rational plaintiff decides whether an individual case is worth pursuing, and that is what the Court is trying to discern. If a case is for a half-million dollars, but has only a one-in-three chance of success, then a plaintiff will not pursue the claim if it will cost over $166,666.67 to litigate.100 The plaintiff might not pursue the case even if it were cheaper to do so, if the plaintiff could get a better return on his or her investment elsewhere.

111. The Court can try to conduct this calculation directly, i.e., by looking at the claim amounts, and gauging the likelihood of success and the probable litigation costs. Here, all the check stubs that the Court have seen have been for monthly payments in the two-figure to low three-figure range, and the stubs at which the Court has looked are those of the class representatives — who have larger claims than the average class member. The Court conservatively assumes that a typical class member received a royalty of $100.00 per month, which would come to roughly $35,000.00 in royalty payments over the class period. Even if the Plaintiffs contend that they have been underpaid by twenty-five percent — and the underpayment is not that great — the class member's case would be for $17,500.00. Even if the Plaintiffs had a one-hundred percent chance of prevailing at trial, their litigation costs would be high enough to make individual litigation uneconomical. The discovery in this case has been voluminous and extensive. Although a class member's individual case could be brought cheaper than this class action was — for example, all leases other than the class member's own could be disregarded, and all discovery and argument related to class certification could be foregone — it would still be expensive to pursue such a case. All the discovery and argument that the Plaintiffs have presented that relates to the Defendants' gathering and processing operations, deductions, and payment policies would still be required in individual litigation — and such evidence constitutes the bulk of this class action. This controversy's merits are irreducibly expensive to litigate, whether in individual litigation or class litigation. It could not be done profitably in individual litigation.

112. Another method — other than attempting to conduct a direct value approximation — is looking to indirect evidence, namely: (i) how many individuals who would otherwise be class members or who resemble class members in material respects have filed individual cases; and (ii) what have those cases earned in settlements or verdicts.101 This method produces evidence that convinces the Court. No individual royalty owners in the San Juan Basin have filed individual suits against their working-interest owners. If these cases were viable to bring on an individual basis, one would expect to see it.

113. In some ways, this class action resembles a shareholder class action. In a shareholder action, a small number of shareholders may have sufficient interests in their cases to justify individual actions, i.e., while a single share of stock is almost never sufficiently harmed enough to make litigation worthwhile, a single investor — often a mutual fund or other institutional investor — may own enough shares for litigation to be profitable. Here, a single well will not have sustained losses large enough to warrant litigation. Some royalty owners own enough wells to where they have incentive to conduct their own lawsuits. The most obvious examples, however — the federal government and the Indian tribes — have been excluded from this class. There are no class members with inordinately large stakes relative to the rest of the class; if there were, the Court might be inclined to take another cue from the shareholder-litigation context and appoint them as class representatives. See Manual for Complex Litigation § 21.272, at 281. This class appears be composed of ordinary individuals, not institutional investors or oil companies. The class representatives are, appropriately, class members with a little more at stake than the average class member, and the Court has determined that even they cannot pursue their claims on an individual basis. The class members' claims have negative value, and, thus, the class-action procedural form — if it were available — would be superior to individual litigation.

b. Other Complex Procedural Forms Are Unavailable in This Case, Thus Taking Them Out of the Superiority Calculus.

114. No other complex-litigation form is available in this case. The Court has already determined that rule 20 "joinder of all members is impracticable." Fed. R. Civ. P. 23(a)(1). Multiparty, multiforum jurisdiction does not exist, because "at least 75 natural persons have [not] died in [an] accident at a discrete location." 28 U.S.C. § 1369(a). No multidistrict litigation presently exists for oil-and-gas royalty-underpayment cases, and the Court has no power to conjure one into existence. See supra note 56. The possibility for multidistrict litigation thus does not cut against finding superiority, even if the Court speculated that it might be a viable procedural form to manage the case.

115. Last, the Court has already stated that rule 23(b)(3)(B)'s dictate to consider the "nature of any litigation concerning the controversy already begun by ... class members" requires the Court consider any other class actions that have already been certified. See Conclusion of Law 22 & n.59. Two other class actions have been filed that relate to this case: Lindauer v. Williams Production RMT Co., in Colorado state court; and Abraham v. WPX Energy Production, LLC, No. CIV 12-0917 JB (D.N.M. 2012)(Browning, J.)("Abraham"), which was filed with the Court after this case, and for which the class certification hearing has been completed but the Court has not yet ruled whether to certify. The Court concludes that neither of these cases cut against finding superiority. The class members in Lindauer v. Williams Production RMT Co. have been excluded from the class definition in this case, there is no overlap in the class definition, and there is thus no question of which class action will be superior for those individuals in both classes. As for Abraham, that it is not yet certified takes it out of the superiority calculus. Given the judicial resources required to conduct a rule 23 analysis on a factually complex case like this one and Abraham, it is unrealistic for the Court to conduct both analyses at once before determining which class action is superior.

116. Moreover, the superiority inquiry asks whether "a class action is superior to other available methods" and not whether this particular class action is superior. Fed. R. Civ. P. 23(b)(3) (emphasis added). While the existence of an already certified class action may defeat the superiority of any subsequent putative class action, thus rendering the class-action device, generally, inappropriate, the Court does not read rule 23's text to require that the Court compare the putative class action in question with every other pre-certification class action out there. Taken to its logical endpoint, this reading would require the Court to compare the putative class action in front of it with every putative class action that could exist, even if it has not been filed — the same analysis the Court must perform when evaluating superiority vis-à-vis individual suits. This interpretation would then result in the Court certifying a class action only if it deemed the class action to be superior to all other theoretical class actions — in essence, perfect. The Court does not believe that the superiority inquiry is that demanding, and, although excluding other pre-certification class actions from the superiority consideration greatly incentivizes being the first attorney to file a class action and pursuing that case diligently, the Court concludes that these incentives are generally positive.

c. The Desirability of Concentrating the Litigation of the Plaintiffs' Claims in the District of New Mexico Weighs in Favor of Certification.

117. Rule 23(b)(3)'s third factor, "the desirability or undesirability of concentrating the litigation of the claims in the particular forum," cuts in favor of certification. Fed. R. Civ. P. 23(b)(3). Specifically, both prongs for this factor — (i) the desirability of aggregation; and (ii) the desirability of the Court adjudicating the dispute — cut in favor of certification. First, because this is a negative value case, the first prong is satisfied. Without aggregation, there would be no mechanism — or at least no economical mechanism — for the Plaintiffs to have their grievances heard. For essentially the same reasons that the Court finds that a class action is superior to any other form of litigation, the Court finds that aggregation of the Plaintiffs' claims is desirable.

118. Second, the Court is a desirable forum for the case. Several factors are considered in making this determination: (i) the geographic convenience of the parties, witnesses, or class counsel, see Zinser v. Accufix Research Inst., Inc., 253 F.3d at 1191-92; (ii) the locus of the harm, as well as any other events forming the basis of the action, see Winkler v. DTE, Inc., 205 F.R.D. at 245; (iii) the location of the bulk of the proposed class, see Macarz v. Transworld Sys., Inc., 193 F.R.D. at 57; and (iv) whether the defendant is located in the forum state, see In re Warfarin Sodium Antitrust Litig., 391 F.3d at 534. Each factor cuts in favor of concluding that the Court is a desirable forum. At least one of Plaintiffs' lead counsel is located in Albuquerque, New Mexico, while the Defendants' counsel is located in Santa Fe, New Mexico, which is about an hour drive North of Albuquerque. All of the events leading to this case occurred in New Mexico or its northern neighbor, Colorado. It is unclear where the bulk of the proposed class members reside, but, because the leases are all located in New Mexico or Colorado, at least some members likely reside in one of those two states. Finally, while the Defendants are incorporated in Delaware, with their principal places of business in Oklahoma, they each own oil-and-gas leases in New Mexico. See Complaint ¶¶ 5-6 (noting that WPX Production and WPX Rocky Mountain are incorporated in Delaware with their principal places of business in Oklahoma). Three of the factors cut in favor of the Court being a desirable forum while one — the location of the Defendants — cuts against. Even the fourth factor, however, does not weigh heavily against desirability, because the Defendants conduct business in New Mexico — i.e. the business leading to this case. Because all, or a substantial number, of the factors weigh in favor of finding that the Court is a desirable forum, the Court concludes that it is desirable to litigate this case in this forum.

d. This Class Action Does Not Present Insurmountable Manageability Issues.

119. The fourth and final factor a court must consider in assessing superiority is the extent to which it will be able to manage the class action, if certified, through pre-trial litigation and trial, accurately adjudicating the class' claims — in particular the individual issues — and fairly distributing relief among the class members. See Fed. R. Civ. P. 23(b)(3)(D). The manageability factor "encompasses the whole range of practical problems that may render the class action format inappropriate for a particular suit." Eisen v. Carlisle & Jacquelin, 417 U.S. at 164. This case does not present insurmountable manageability issues.

120. The Court would divide the class into segments on the basis of either the potential of a different legal standard applying or different factual circumstances existing: (i) between Colorado wells and New Mexico wells; (ii) between Williams Four Corners-gathered wells and independently gathered wells; and (iii) among the eight textual formulations the Court has identified among the class leases' royalty provisions. The Court would thus segment the class as follows:

In this chart, "OF" refers to the "same as fed" overriding royalties and "OS" refers to the "same as state" overriding royalties. For the Plaintiffs' primary claim/theory of liability — which is that the keep-whole methodology and index-based pricing constitute a contract-breaching method of paying royalty — potentially all forty segments would need to be analyzed separately. For the Plaintiffs' claim/theory that the magnitude of the COS charge was a breach of contract,102 only segments 1 through 10 would need be analyzed at all — the COS charge was not applied to Colorado wells or independently gathered wells. For the Plaintiffs' theory that gas was used off the lease, no segmentation is necessary,103 as no lease permits the lessee to use gas off the leased premises free of charge, but all leases permit the lessee to use gas on the lease free of charge.104 These three claims/theories constitute the whole of the Plaintiffs' case — except for the NMPPA claim, which the Court will analyze separately — because the Court has declined to certify any WASP-based claim/theory of liability, and the Court believes that the affiliate-transaction claim/theory is a rephrasing of the primary improper-value-calculation claim/theory.

121. As for the trial, if the Court were to certify the class, the Court would prefer a single trial to multiple trials, but the Court would take its cues from the parties and would consider splitting the case up into parts pursuant to rule 42(b). The most obvious point of bifurcation in this case — the one mirrored in the organization of this Analysis — is separation of the NMPPA claims. Separating the NMPPA claims involves both severance — as only the New Mexico wells can bring NMPPA claims — and horizontal bifurcation. The issue overlap between the NMPPA claims and the other claims is minimal, and the NMPPA claims could be tried separately without the trials presenting duplicative evidence. After the NMPPA claims, the next most attractive points of separation are (i) between the Colorado wells and the New Mexico wells; and (ii) between the affiliate-gathered wells and the independently gathered wells. Severance might also be desirable to cut out the class members against whom the Defendants have substantial individualized evidence, but those class members are not likely numerous, and thus severing them might make for judicial waste.

122. If the Court were to certify the class, the Court's preference would be to try all the underpayment claims together. Multiple trials on the underpayment claims would require that much of the same evidence be presented at each trial, thus reducing judicial economy. Having already sat through two largely duplicative class certification hearings in this case and in Abraham, the Court would rather not spend its time and society's resources sitting through similarly duplicative trials.105

123. The Court will next discuss two potential management issues that the Defendants raise with regard to this plan: (i) their right to introduce individualized evidence establishing a limitations defense; and (ii) the difficulty in determining individual damages. Neither of these issues presents intractable management difficulties.

i. The Defendants' Limitations Defense Does Not Render the Case Unmanageable.

124. The Defendants' limitations defense does not render the case unmanageable, because (i) the Defendants' have mostly common evidence, although they have also adduced some individualized evidence; and (ii) even if the Defendants had a large amount of individualized evidence to present, so long as the trial remained manageable, it would remain the Defendants' burden to either present this evidence or forfeit the argument. The Court discussed the Defendants' burden in proving a limitations defense under New Mexico's discovery rule — which governs all claims for all class members, including Colorado-well owners — in detail in the MOO. There are two ways for the Defendants to prevail: (i) prove that certain — or all — class members had actual knowledge of their causes of action before October 20, 2007; or (ii) prove that reasonable diligence by a royalty owner would have resulted in the class members discovering their causes of action before October 20, 2007. Both defenses could be either individualized or common — although in this case, the first is individualized while the second is common.

125. While the Defendants have some individual evidence to present against some class members, they would have to argue their limitations defense, for the most part, on ground (ii), and present evidence and argument that the check stubs put the class members on notice and that the class members' inherent responsibilities as lessors reasonably necessitated inquiry. This evidence is largely common and thus has a minimal impact on manageability. The Defendants also presented evidence at the hearing that certain class members called them with questions about their royalty payments. The Defendants can use this evidence either as individualized evidence — arguing that those class members who called were given actual knowledge of their claims or put on notice to do reasonable research into them — or as common evidence — arguing that, if some class members saw fit to call about their royalty checks, then all of them should reasonably have. Either way, the amount of evidence that the Defendants have is manageable. The Defendants wrote a short memorandum each time a royalty owner called them, and these documents might be admissible under the business-records exception to the hearsay rule. See Fed. R. Evid. 803(6). Similarly, the Defendants would be able to call witnesses to testify to this information. Regardless, the Court would not have a difficult time organizing and managing the requisite evidence and testimony for the limitations defense.

ii. Damages Determinations Do Not Render the Case Unmanageable.

126. The Defendants last argue that damages calculations pose intractable management problems in this case. The Court disagrees. As the Court mentioned earlier, the payment methodology to which the Plaintiffs argue that they are entitled is simple enough to compute: (i) for NGLs, start with the Defendants' arm's length sale proceeds, allocate the proceeds attributable to each well by dividing the total proceeds by each well's wellhead GPM, and then divide each well's attributable proceeds by the royalty fraction specified in its lease; and (ii) for residue gas, start with the Defendants' arm's length sale proceeds, allocate the proceeds attributable to each well by dividing the total proceeds by each well's wellhead MMBtu — reduced to compensate for the separate payment on NGLs106 — and then divide each well's attributable proceeds by the royalty fraction specified in its lease. This calculation is simple enough, despite the Defendants' attempts to obfuscate the process with their references to intermingling and their suggestions that virtually every damages component must be calculated on a well-by-well basis.

127. It appears that the wellhead meter's GPM readout reports only the total NGLs in the gas, rather than giving separate readouts for butane, propane, pentane, et cetera. It is true that some NGL constituents are more valuable than others, and, if the more detailed information is available, it should be used in allocating any damages among the class. If a wellhead NGL-constituent breakdown is not available, however, the case is still manageable. First, this issue goes only to damages distribution and not to the Defendants' overall damages,107 and thus looser proof should be required. Second, if certain information is not kept, or the calculations involved are too confusing to be submitted to a jury or examined in court, then: (i) the Defendants are probably not expected to pay royalties under that fine of a methodology; and (ii) even if they are, the resultant uncertainties in damages would persist even in individual litigation, and, thus, do not militate against the use of the class-action form. For example, the Defendants argue that: (i) gas from multiple wells is intermingled, and one cannot assume that all the gas from any given well goes to any given plant; (ii) a large portion of gas that goes to some processing plants get bypassed, and it is impossible to know which class members to pay for NGLs, because, if wellhead GPM is used, it cannot be known whether those exact NGLs were ultimately bypassed or processed and sold; and (iii) operating costs and fuel consumption varies among the plants, and even a single plant's costs vary over time. None of these issues makes this class unmanageable.

128. No royalty-payment methodology takes into account intermingling and pays well owners separately for gas that ends up at separate wells. No methodology tracks which molecules of gas are bypassed and from what well that molecule hails. Even if the Plaintiffs were asking for a royalty methodology that does those things — and by arguing for a netback methodology, they are expressly not arguing as much — the calculations would be just as impractical or impossible in individual litigation as they are in class litigation. They are red herrings, inserted into the case to sow confusion and conjure up individual issues. Hydrocarbons are measured for volume, MMBtu content, and NGL content, at the point when they pass through the wellhead meter; they are measured again at the point of sale. Those two measurements — and the lump sum of any legally deductible post-production costs that the Defendants incur in between — are all that is needed to construct a workable damages model. Thus, damages calculations do not render the case unmanageable.

C. THE NMPPA CLAIMS ARE ALSO NOT CERTIFIABLE UNDER RULE 23(b)(3).

129. Having addressed the underpayment claims, the Court now turns to the NMPPA claims and concludes that they, too, do not meet rule 23(b)(3)'s demands. Substantively, the NMPPA provides that royalty owners are entitled to be paid "not later than forty-five days after the end of the calendar month within which payment is received by payor for production." N.M. Stat. Ann. § 70-10-3. If the payor cannot determine to whom to pay royalty, it must create a suspense account and keep the funds in suspense until the identity of the proper payee is ascertained; in-suspense funds accrue at an interest rate that is one-and-one-half percent higher than that set by the federal reserve bank of Dallas. See N.M. Stat. Ann. § 70-10-4. If the payor fails to pay in a timely fashion and that failure cannot be attributed to an excusable failure to ascertain the identity of the proper payee, then the payor owes eighteen-percent annual interest on the late payments. See N.M. Stat. Ann. § 70-10-5. Whether a failure to pay is excusable — and thus triggers § 70-10-4B's lower interest rate rather than § 70-10-5's higher, punitive interest rate — is determined by whether "the payor has been furnished with the information required by Section 70-10-3.1." N.M. Stat. Ann. § 70-10-5. Section 70-10-3.1 is entitled "duty to locate" and provides:

N.M. Stat. Ann. 70-10-3. The NMPPA trumps contravening lease language, thus obviating any need for the Court to individually examine the leases to determine whether they provide for different payment periods. See First Baptist Church of Roswell v. Yates Petrol. Corp., 2014-NMSC-004, ¶¶ 9-20 (N.M. 2014)(Vigil, C.J.).

130. Little is established about the mechanics of an NMPPA claim beyond the fact that, in federal court, at least, no NMPPA claim may lie absent some underlying claim — typically an underpayment claim. See Elliott, 407 F.3d at 1120 ("[I]n order to maintain a Payment Act claim, Elliott must allege a potentially successful claim for underpayment of royalties or theory of liability showing that it is `legally entitled to such payments.'" (quoting N.M. Stat. Ann. § 70-10-3)). The Plaintiffs have not satisfied that requirement. Moreover, the allocation of the burden of proof for triggering the various statutory elements is unclear, and so the Court must interpret the statute as best it can. The Court concludes that the initial burden of showing that a payment was made outside the forty-five-day window rests with the Plaintiffs, as this showing seems to be a prima facie element of an NMPPA claim. After that, late payments are presumed to be inexcusable and thus subject to § 70-10-5's punitive eighteen-percent interest rate, unless the Defendants prove that they lacked the information outlined in § 70-10-3.1. Section § 70-10-3.1 divides the "duty to locate" — i.e., the obligation to ascertain the proper payee's identity — between the payor and "[t]he operator or lessee," who, in this case, are the same entities: the Defendants. N.M. Stat. Ann. § 70-10-3.1. In addition to being sound statutory interpretation, allocating the burden in this fashion also places the burden of proof on the party that has the information; if the Defendants lacked § 70-10-3.1 information and kept funds in suspense as a result, then they will have records proving as much.

131. The Court concludes that the NMPPA claims are substantively separate from the underpayment claims. The Court also thinks that it could manage them more easily. They do not satisfy predominance, however, and, thus, the Court also declines to certify them.

1. Neither Commonality Nor Predominance Is Satisfied.

132. The Plaintiffs state that they have records showing when payments were made outside the NMPPA's forty-five-day window, and the Defendants do not dispute this assertion. This case could be managed by having the Plaintiffs present each instance in which they believe a payment was made late; the Defendants could dispute that any given payment was made late, and the Plaintiffs would bear the burden of proving lateness. Next, the Defendants could argue that all or a certain number of the late payments were properly in suspense, and thus subject to § 70-10-4B's interest rate. The Plaintiffs could dispute that any given in-suspense payment was properly in suspense under § 70-10-3.1, and the burden would rest with the Defendants to prove that the payment was properly in suspense. Last, to calculate damages, whatever the Defendants actually paid could be subtracted from the amount to which the Plaintiffs were legally entitled. The Plaintiffs' expert, Ley, testified at the hearing that she has calculated NMPPA damages many times before and that it tends to be fairly easy. See Tr. at 178:18-179:8 (Brickell, Ley). Unfortunately for the Plaintiffs, manageability is not the same as predominance. While this management plan is easy enough, it presents effectively no common issues. Although there is a common legal standard under the NMPPA, these claims are really about the Defendants' late payments — which will vary from class member to class member, as will the reasons for the Defendants' tardiness. Thus, neither commonality nor predominance is satisfied.

2. The NMPPA Claims Satisfy Superiority.

133. It is even less likely that the NMPPA claims could be pursued as individual actions than the underpayment claims. They are not valuable enough to render individual litigation financially worthwhile.108 Furthermore, the NMPPA claims could not even be brought separately in their own class action; under Elliott, NMPPA claims may exist only as tagalong claims to one or more underpayment claims. See Elliott, 407 F.3d at 1120. Thus, the Court believes that trying the Plaintiffs' NMPPA claims as a class action would be superior to other alternatives and is likely the only way those claims would be heard.

134. Having reached the end of this analytical journey, the Court has a few parting concerns regarding its ruling in particular and the state of class-action law in general. The Court well understands that refusing to certify this class likely closes the courthouse doors to the Plaintiffs' claims forever. It may be true that each Plaintiff has suffered a cognizable wrong. Yet, the costs of proving such wrongs are so large and the reward for prevailing so small that the prospect of thousands of individual actions is unfeasible. In a negative-value case, such as this, denying certification leaves the Plaintiffs out in the cold, thus violating the deeply rooted principle in American jurisprudence that "every wrong shall have a remedy." Stoneridge Inv. Partners, LLC v. Scientific-Atlanta, 552 U.S. 148, 176-77 (2008)(Stevens, J., dissenting).

135. That this case is manageable, would be a superior method of trying the Plaintiffs' claims than individual actions, and is likely the only avenue of relief for the Plaintiffs, are all factors that weigh heavily in favor of certifying this class. Supreme Court and Tenth Circuit precedent, however, ties the Court's hands. Those courts have repeatedly instructed that, when faced with class certification, district courts must rigorously enforce rule 23's commonality and predominance requirements — separate and apart from the more plaintiff-friendly superiority test. The Court has done its best to faithfully apply that law. The Court is concerned, however, that appellate courts' increasing hostility towards class actions is a result of their largely unfounded belief that district courts cannot handle them. As the foregoing analysis demonstrates, trying class actions like this one takes some elbow grease and some creativity, but it is not impossible. District courts can, and often do, try cases that are at least as difficult as this one.

136. At the end of the day, district court judges know whether they can try a case. If they determine that a class action is manageable and more efficient than other alternatives, appellate courts should give some deference to their judgment. Under this approach, efficiency, manageability, and superiority would drive the class-certification analysis, rather than commonality and predominance.109 Such an approach would be a more equitable and pragmatic way to determine class certification than the existing framework. The Court must follow binding precedent, however, and therefore has no choice but to deny certification.

IT IS ORDERED that the Plaintiffs' Motion and Supporting Brief to Determine That This Matter Proceed as a Class Action, filed January 6, 2014 (Doc. 194), is denied.