Abraham v. WPX Production Productions, LLC

MEMORANDUM OPINION AND ORDER 1

JAMES O. BROWNING, UNITED STATES DISTRICT JUDGE

THIS MATTER comes before the Court on the Plaintiffs’ Renewed Motion for Class Certification, filed January 13, 2014 (Doe. 116). The Court held a multi-part class certification heating, which took place on: (i) May 8 and 9, 2014; (ii) March 13 and 14, 2014; (iii) June 30, 2014; and (iv) July 14, 2014. See Transcript of Hearing, taken March 13, filed June 26, 2014 (Doc. 200); Transcript of Hearing, taken March 14, 2014 (Doc. 201); Transcript of Hearing, taken May 8, 2014, filed June 26, 2014 (Doc. 198); Transcript of Hearing, taken May 9, 2014, filed June 26, 2014 (Doc. 199); Transcript of Hearing, taken June 30, 2014, filed July 23, 2014 (Doc. 211); Transcript of Hearing, taken July 14, 2014, filed July 23, 2014 (Doc. 212)(eollectively, “Tr.”). 2 The primary issues are: (i) whether a class is ascertainable; (ii) whether the determination of which class wells’ gas is processed at the processing plants named in the Plaintiffs’ class definition defeats the predominance requirement of rule 23 of the Federal Rules of *175 Civil Procedure; (iii) whether textual variations among the leases within the proposed class defeat commonality and predominance under rule 23; and (iv) 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. First, because the Plaintiffs’ class definition includes only those wells whose gas is or has been processed at three specific processing plants, and the Court cannot determine whether some of the wells’ gas was processed at those plants, the Court cannot adequately ascertain the class. Second, because the Plaintiffs’ class definition includes only that gas that was processed for natural gas liquid extraction and marketing, the Court must determine which gas was processed. This inquiry weighs against finding predominance. Third, the central issue in this case — how the Defendants should have paid the Plaintiffs — -varies between leases. Accordingly, when considered alongside the other individual issues, textual variations among the leases destroy commonality and predominance. Therefore, 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 it fails rule 23(a)(2)’s commonality prerequisite and rule 23(b)(3)’s 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 Regarding Class Certification, filed August 15, 2014 (Doc. 217)(“Plaintiffs’ Findings”); Defendants’ Requested Findings of Fact and Conclusions of Law, filed August 18, 2014 (Doc. 218)(“Defen-dants’ Findings”). 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. 3 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.

The Court organizes this portion of its Memorandum Opinion and Order into eight parts. First, it will define some of the specific industry terms applicable in this case. Second, it will introduce the important players in this action: the Defendants and their corporate affiliates, the named Plaintiffs, and the absent class members. 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. Seventh, it will describe the issues relevant to WPX Production’s gathering and processing negotiations and agreements. 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 *176 Opinion and Order. The Court takes many of the definitions from a similar case involving royalty disputes in the San Juan Basin, Anderson Living Trust v. WPX Energy Production, LLC, 306 F.R.D. 312 (D.N.M.2015)(Browning, J.)(“ Anderson”). 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,” and 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” 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 the product out of the ground. 8 Howard R. Williams, Charles J. Meyers, Patrick H. Martin & Brace 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). For example, 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 underlying mineral lease’s terms. See Anderson, 306 F.R.D. at 321 .

*177 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. Anderson, 306 F.R.D. at 321 .

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 4 gas. 4

17. “Natural gas” is a gaseous mixture of hydrocarbons, the primary one being methane (CH4), commonly used as fuel in homes and in 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 deposits. Tr. at 158:1-159:23. See Anderson, 306 F.R.D. at 322 .

21. Conventional gas typically undergoes processing to remove impurities, separate out valuable natural gas liquids, and render the gas into marketable condition. See Anderson, 306 F.R.D. at 322 .

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

23. Coalbed methane is typically only methane and carbon dioxide, and is generally treated only for carbon dioxide removal and possibly water-vapor removal — rather than being processed — before it is placed in a pipeline. See Anderson, 306 F.R.D. at 322 .

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 phrase “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, pen-tane, and hexane. EIA Glossary.

28. Among NGL compounds, heavier compounds are typically more valuable than lighter ones. See Anderson, 306 F.R.D. at 322 .

29. “Heavier,” in this context, refers to the compound’s molecular weight, which, for al-kane hydrocarbons, equates to the magnitude of the n term in the generic chemical formula C»H(2b+2). See Anderson, 306 F.R.D. at 322 .

30. For example, pentane (C5H12) is heavier than butane (C4H10), which is, in turn, heavier than propane (C3H8). See Anderson, 306 F.R.D. at 322 .

*178 31. All of the constituent compounds of NGLs are heavier than methane (CH4), which is the primary component of natural gas, See Anderson, 306 F.R.D. at 322 .

32. NGLs are commonly entrained in — or entrapped and carried along with — natural gas. See Anderson, 306 F.R.D. at 322 .

33. “Natural gasoline” refers to a mixture of natural gas liquid products manufactured from natural gas. Anderson, 306 F.R.D. at 322 .

34. Natural gasoline is not the same substance as automotive gasoline. 5 See Anderson, 306 F.R.D. at 322 .

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 Anderson, 306 F.R.D. at 323 .

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 NGLs recovered at the surface without resorting to processing. 30 C.F.R. § 1206.171 .

40. “Condensation,” generieally, 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. Anderson, 306 F.R.D. at 323 .

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, Anderson, 306 F.R.D. at 323 .

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,” in., perforated and isolated in the well bore, such that gas is capable of being produced from the well. Anderson, 306 F.R.D. at 323 .

47. “Lease use” gas is gas that the working interest owner uses — to power machinery, fuel heaters, et cetera — on the lease. Anderson, 306 F.R.D. at 323 .

48. A “gathering system” is the system of low-pressure lines that transport natural gas from the lease site, he., 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 is NGLs that condense into liquid form in the gathering sys *179 tem, Le., 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. Anderson, 306 F.R.D. at 323 .

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. Anderson, 306 F.R.D. at 323-24 .

55. A processing plant is typically connected to a gathering system on the input end and a pipeline system on the output end. See Anderson, 306 F.R.D. at 324 .

56. A “treatment plant” is a facility that is fundamentally similar to a processing plant— Le., it takes impure gas from a gathering system and renders it into marketable condition — but it does not remove NGLs from the gas. Anderson, 306 F.R.D. at 324 .

57. Treatment removes carbon dioxide and often dehydrates the gas — Le., it removes the water vapor — but, unlike processing, it does not extract NGLs. See Anderson, 306 F.R.D. at 324 .

58. Gas that is relatively clean — Le., free from impurities — and dry — Le., free from NGLs — may need only to be treated, rather than processed. See Anderson, 306 F.R.D. at 324 .

59. Coalbed methane typically requires only treatment to remove carbon dioxide. It tends to contain more carbon dioxide than conventional gas. See Anderson, 306 F.R.D. at 324 .

60. “Bypassing” is when a gathering system delivers raw gas to a processing plant, but does not process the raw gas. Instead, the raw gas is mixed with processed gas in such proportions that the resultant product is still of pipeline quality. Anderson, 306 F.R.D. at 324 .

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.” 8 Williams & Meyers at 787. See ConocoPhillips Co. v. Lyons, 2013-NMSC-009, ¶ 11 , 299 P.3d 844 , 850 (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. 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 , 134 N.M. 162 , 74 P.3d 96, 99 (“‘[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. 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, 129 N.M. 529 , 10 P.3d 853, *180 859 (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 1.005. See Tr. at 487:4-8 (Griffin); id. at 738:7-11 (Emory, Gallegos).

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 Tr. at 485:9-18 (Griffin).

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 about .9 to 1.25. See Tr. at 486:6^487:8 (Griffin).

74. As natural gas is valuable, ultimately, for its energetic potential — he., 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/2013/04/ 01-natural-gas-ebinger-avasarala/natural-gas-briefing-l-pdf.pdf. See Report of John W. Emory ¶ 28, at 15 (dated January 27, 2014)(Defendants’ Hearing Ex. 73)(“Emory Report”).

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. Anderson, 306 F.R.D. at 326 .

77. Producers measure the percentage of the gas stream composed of methane, ethane, butane, and propane in units known as gallons per thousand cubic feet (“gpm”). Tr. at 375:6-11 (Gallegos, McArthur); id. at 428:21-24 (Tysseling).

c. Royalty Distribution and Accounting Terminology.

78. The “netback” or “workbaek” method is a method of determining the wellhead price of gas by starting with the downstream *181 (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.

79. The netback method “is widely accept ed 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.).

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. 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 $260,000.00, regardless whether that lease actually produced $260,000.00 in natural gas.

81. 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. 8 Williams & Meyers at 496.

82. 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. 8 Williams & Meyers at 533.

83. 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 483:7-16 (Griffin). Under the keep-whole methodology, the Defendants: (i) measure the gas produced at the lease in Mcfs; (ii) apply a Btu factor to those Mcfs, which determines the millions of Btus that exited the meter; (in) multiply the Federal Energy Regulatory Commission (“FERC”) index price for residue gas by the Btus produced; and (iv) deduct certain costs to determine the net value of the gas produced. See Tr. at 483:7-25 (Griffin).

84. “'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 NGLs’ sale proceeds, rather than simply compensating the lessors on an MMBtu basis at the wellhead, when NGLs are still entrained. Tr. at 447:19-455:1 (Berge, Tyssel-ing). See Supplemental Expert Report of John C. Tysseling, Ph.D. at 20 (dated February 14, 2014)(Plaintiffs’ Hearing Ex. 222)(“Tysseling Report”); Anderson, 306 F.R.D. at 327 . In short, the whole-stream method requires the lessee to: (i) “perform separate valuations of what the residue gas is worth” and “what the natural gas liquids are worth;” and (ii) add those values together after deducting the costs required to recover the liquids. Tr. at 482:20-483:3 (Griffin).

85. An “arm’s length” transaction is a transaction between entities that are not corporate affiliates of one another. Anderson, 306 F.R.D. at 328 .

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

86. 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 ¶ 12, at 5; id ¶ 20, at 7.

87. The named Plaintiffs 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).

88. Before December 31, 2011, “WPX and Williams [Four Corners] were corporate affiliates as wholly or partially owned subsidiaries of Williams Companies Inc.” Complaint ¶ 42, at 12.

*182 89. Although there was a corporate spinoff in January, 2012, which 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 when the contractual parties were corporate affiliates. Accordingly, transactions under these contracts are still considered affiliate transactions even after the spinoff.

a. The Defendants.

90. There are three Defendants in this case: (i) WPX Energy Production, LLC (“WPX Production”), formerly known as Williams Production, LLC; (ii) Williams Four Comers, LLC (‘Williams Four Comers”); and (iii) Williams Energy Resources, LLC (“Williams Energy”). Complaint ¶¶ 3-5, at 2-3.

91. On December 31, 2011, Williams Production Company, LLC changed its name to WPX Energy San Juan, LLC. See WPX Energy Production, LLC’s Corporate Disclosure Statement at 1, filed November 27, 2012 (Doc. 24)(“WPX Corporate Disclosure”).

92. On January 13, 2012, WPX Energy San Juan, LLC changed its name to WPX Energy Production, LLC. See WPX Corporate Disclosure at 1.

93. WPX Energy Production, LLC is a wholly owned subsidiary of WPX Energy, Inc. (“WPX Energy”), which is a publicly-held corporation. WPX Corporate Disclosure at 1.

94. Until a 2012 spin-off, the exploration and production companies comprising WPX Production “were wholly owned by their parent corporation Williams Companies Inc.,” Complaint ¶3, at 2, which 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.eom/e/141027/wmb8-k. html.

95. Williams Four Corners and Williams Energy are wholly owned subsidiaries of Williams Partners. See Form 8-K for Williams Companies, Inc., Securities and Exchange Commission (Oct. 27, 2014), available at http://biz.yahoo.eom/e/141027/wmb8-k. html; Williams Four Corners LLC’s and Williams Energy Resources LLC’s Corporate Disclosure Statement, filed November 26, 2012 (Doc. 23).

96. Williams Four Comers 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. Anderson, 306 F.R.D. at 330 .

97. Williams Field Services was formerly named Northwest Pipeline Corp. (“Northwest Pipeline”), until it changed its name in 1992. See Tr. at 395:1-6 (McArthur, Sheridan).

98. The Court will refer to WPX Production, Williams Four Comers, and Williams Energy Resources collectively as “the Defendants.”

b. The Defendants’ Corporate Affiliates.

99. WPX Gas Resources Company (“WPX Gas”) 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/1518832/000119312513084857/d 448908dex211.htm.

100. WPX Gas was formerly named WFS Gas Resources Company (“WFS Gas Resources”), until it changed its name on December 1, 1998. See Anderson, 306 F.R.D. at 330 .

101. 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/ 000119312513084857/d448908dex211.htm.

102. WPX Energy Marketing was formerly named Williams Gas Marketing, Inc. (“Williams Gas Marketing”), until it changed its name on June 20, 2011. See Deposition of Frank Lee Field at 10:1-11:25 (taken December 5, 2013)(“Field Depo.”); Deposition of *183 Sheryl Ward at 13:1-17:20 (taken November 13,2013)(“Ward Nov. Depo.”).

103. Williams Gas Marketing was formerly named Williams Power Company, Inc. (“Williams Power”), until it changed its name on November 16, 2007. Field Depo, at 10-11; Ward Nov. Depo. at 13-17.

104. Williams Power was formerly named Williams Energy Marketing & Trading Company (‘Williams Marketing and Trading”), until it changed its name on August 6, 2003. See Anderson, 306 F.R.D. at 330 .

106.Any transactions between the two of the following list of entities is considered an affiliate transaction 8 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 Energy, Williams Partners, Williams Four Corners, Williams Field Services, Northwest Pipeline, WPX Gas, WFS Gas, WPX Energy Marketing, Williams Gas Marketing, Williams Power, Williams Marketing and Trading, Williams Energy Services, and Williams EDT. See Anderson, 306 F.R.D. at 330 ; Ward April Depo. at 89:6-13 (Ward).

106. The Court will refer to these entities, generically, as “WPX affiliates.”

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

107. Plaintiff Steven J. Abraham owns royalty interests in Colorado and overriding royalty interests New Mexico. See Tr. at 231:2-7 (Abraham, Gallegos). In 1996, Abraham acquired his royalty interests, which his family passed down to him, originating with his grandmother Hazel Abraham in 1966. See Tr. at 231:16-232:16 (Abraham, Gallegos).

108. Despite receiving the division orders and other payment information from the Defendants, Abraham knew very little about the information he received, did not actively manage his interests, and did not know how the Defendants were calculating his royalty payment — including that he was not compensated for the value of the NGLs produced. See Tr. at 232:19-236:9; id. at 239:9-22 (Abraham, Gallegos).

109. While serving as a class representative in a prior oil-and-gas dispute, Abraham v. BP America Production Co., 685 F.3d 1196 (10th Cir.2012), Abraham learned that the gas produced from wells on conventional formations in which he has an interest contain valuable natural gas liquids on which he was not paid. See Tr. at 240:9-241:4 (Abraham, Gallegos).

110. Abraham understands the burdens involved in being a named plaintiff and agrees to actively participate in this case, attending depositions, mediations, hearings, the trial, and any other negotiations involved. See Tr. at 241:18-242:11 (Abraham, Gallegos); id. at 244:22-25 (Abraham, Gallegos).

111. Plaintiff H Limited Partnership, a New Mexico limited partnership, owns mineral interests in New Mexico. See Tr. at 294:3-296:3 (Gallegos, Harvey).

112. Plaintiff H Limited Partnership, formed in 1996, owns the mineral interests that Francis Harvey assembled. See Tr. at 294:3-296:3 (Gallegos, Harvey). It primarily owns overriding royalty interests on wells in Tracts 30 and 42 of the San Juan Basin’s Rosa Unit, which is in the Mesa Verde participating area. See Tr. at 298:15-304:22 (Gallegos, Harvey); id. at 308:16-18 (Gallegos, Harvey). In 2008, Haila Harvey became the managing partner, and in 2009, she engaged J.E. Gallegos to assist her with any oil-and-gas related issues that could arise. See Tr. at 297:3-298:7 (Gallegos, Harvey).

113. Before H. Harvey became H Limited’s managing partner in 2008, she had no work experience in the oil-and-gas business. See Tr. at 294:22-24 (Gallegos, Harvey).

114. H. Harvey understands her role as class representative, has been deposed, has testified at class certification hearings, has attended court sessions, and is willing to serve as class representative. See Tr. at 308:19-310:20 (Gallegos, Harvey).

*184 d. The Proposed Class Members.

115. The parties “agree that the Court should determine the motion for class certification based on the definition contained in Plaintiffs’ Fourth Amended Complaint,” amended to exclude the Defendants and their affiliates, including: WPX Production, Williams Four Corners, Williams Energy, and them predecessors, successors, and affiliates. Agreed Order on Defendants’ Motion to Determine Class Certification Based on the Class Definition Contained in Plaintiffs’ Fourth Amended Complaint, filed September 24, 2015 (Doc. 243)(“Agreed Order on Class Definition”).

116. Per the class definition, the proposed class members are all present and former owners of royalties and overriding royalties that burden oil-and-gas leases and wells in the San Juan Basin of Colorado and New Mexico, where those leases and wells are now or were formerly held by the Defendants or their corporate affiliates, successors, or predecessors, and where the oil or natural gas produced from the leases was delivered to the Ignacio processing Plant in La Plata County, Colorado, the Kutz Plant in San Juan County, New Mexico, or the Lybrook Plant in Rio Arriba County, New Mexico, for processing. See Complaint ¶ 25, at 8; Tr. at 360:21-361:4 (McArthur).

117. The proposed class membership excludes the United States of America in its own right, and as trustee for Indian tribes or Indian lessors, and “any other lessors for which an agency of the Secretary of Interior administers royalties.” Class Definition at 2.

118. The proposed class definition also excludes “the State Land Board of Colorado and the Commissioner of Public Lands of New Mexico and oil and gas leases issued by either of those states.” Class Definition at 2.

119. The proposed class definition includes a total of 1,715 proposed class members. See Ward April Deposition at 9:16-24 (Ward)(taken April 29, 2014)(“Ward April Depo.”).

120. The class definition covers approximately 1,637 wells. See Tr. at 87:3-4 (Gallegos); Class Well List (Plaintiffs’ Hearing Ex. 225)(“Class Well List”).

121. Out of the 1,637 wells, 1,254 are located in federal units 9 in New Mexico. See Tr. at 1012:22-1013:4 (Gallegos); Griffin Supplemental Report (Defendants’ Hearing Ex. 143). 10

122. Although WPX Production calculates royalty volumes and value on an individual, well-by-well basis for all wells committed to a participating area 11 within a federal unit, a royalty owner’s actual “entitlement is based *185 on the volume of all the wells in the unit.” Ward April Depo. at 60:12-62:22 (Ward). See id. at 67:24-66:19 (Ward); id. at 63:7-15 (Ward)(explaining H Limited’s interest and stating that “he is participating in all the volumes of all the wells in that unit as opposed to getting only his entitled share of the well that he ... has an interest in before it was committed to the unit”). Wells in participating areas of federal units therefore “receive a percentage of the participating area’s revenue, as opposed to the individual well that they might have owned an overriding royalty in.” Tr. at 566:22-25 (Griffin); id. at 180-183. Accordingly, an owner’s royalty entitlement is based on the volume of gas that all of the wells in the participating unit produce rather than the gas that the one well produces. See Tr. at 557:1-20 (Gallegos, Griffin); Unit Agreement for the Development and Operation of the Rosa Unit Area, Counties of San Juan and Rio Arriba, State of New Mexico at 3 (dated May 10, 1948)(Plain-tiffs’ Hearing Ex. 310)(“Rosa Unit Agreement”).

123. The unit agreements define the unitized substances as “All oil, gas, natural gasoline and associated fluid hydrocarbons in any and all formations _” Tr. at 180:15-19 (Hajny); Rosa Unit Agreement at 3. Each geological formation in a unit has its own participating area, such as the Pictured Cliffs, Mesa Verde, or the Dakota formations. See Tr. at 181:13-182:3 (Gallegos, Hany).

124. In New Mexico, there are six “nonra-tified” royalty owners who own sixteen different royalty and/or overriding royalty interests within the exterior boundaries of a federal unit, but have not committed their interests to the unit. See Ward April Depo. at 13:3-12 (Sutphin, Ward). Nonratified owners are paid based on the production of the well in which they own an interest rather than on a unit basis. See Ward April Depo. at 11:20-12:14 (Sutphin, Ward).

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

125. 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 Tr. at 157:17-158:10 (Gallegos, Hajny); id. at 488:1-11 (Griffin).

126. 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 157:17-158:10 (Gallegos, Hajny); id. at 671:11-15 (Emory).

127. As natural gas emerges from a well, a meter measures the volume of natural gas produced daily, which is stated in Mcf. See Tr. at 483:7-16 (Griffin). Because the meter does not measure the gas’ Btu content on a daily basis, WPX Production instead applies an individual Btu factor for each well to determine the MMBtus in the raw gas stream. See Tr. at 488:14-25 (Berge, Griffin); id. at 646:9-549:20 (Gallegos, Griffin); id. at 710:10-16 (Emory, Gallegos).

128. The NGL content, or Btu factor, of gas from a particular well is ascertained by annually testing a sample of the well’s gas for its chemical content, then entering the data in the gathering system’s electronic accounting system. See Tr. at 547:1-25 (Gallegos, Griffin); id. at 710:17-21 (Emory, Gallegos).

129. A well’s NGL content will change from year to year. See Tr. at 549:5-12 (Gallegos, Griffin).

130. Different wells produce different volumes of gas. See Tr. at 747:3-22 (Emory, Gallegos).

131. The New Mexico Oil and Gas Proceeds Payment Act, N.M. Stat. Ann. § 70-10-1 through § 70-10-6, defines “oil and gas” to include “crude oil, natural gas, cas-inghead gas, condensate or any other related hydrocarbons.” N.M. Stat. Ann. § 70-10-2 . See Tr. at 377:1-11 (Gallegos, McArthur).

132. The class definition excludes wells or coal gas from the Fruitland coal formation. See Tr. at 86:7-8 (Gallegos); id. at 414:1-4 (Gallegos, Tysseling).

133. Despite this exclusion, some of the class wells are “commingled wells,” which *186 means that two formations — a conventional formation and a coal-bed formation — produce gas into a single well, where the gas is commingled. See Tr. at 673:6-15 (Emory). There is one meter at the wellhead, which meters and samples this commingled stream. See Tr. at 673:20-21 (Emory). The Class Well List contains 282 commingled wells. See Tr. at 675:4-6 (Emory).

134. In contrast, some class wells are “dual completion” wells, which mean that two formations produce gas into a single well, but the gas from each formation is maintained separately and metered separately. See Tr. at 674:9-16 (Emory), The class well list contains fifteen dual-completion wells. See Tr. at 675:4-6 (Emory).

135. Of the 282 commingled wells, thirteen wells have a Fruitiand Coal completion in addition to at least one conventional completion. See Well Detail for Table 3 of John Emory’s Expert Report dated January 27, 2013 at 1-7 (Defendants’ Hearing Ex. 139)(“Commingled Well List”). “An engineering analysis would need to be made as to the estimated composition of the conventional production versus the CBM production based on the composition of the commingled stream.” Emory Report ¶ 28, at 16. 12 See Tr. at 678:3-5 (Emory).

136. For some of the remaining eomingled wells, WPX Production does not own an interest in the other formation(s) in which the well is completed. See Commingled Well List at 1-7.

137. Some wells produce gas with a higher Btu content — and thus more liquids — than other wells. See Tr. at 485:9-18 (Griffin); id. at 747:13-16 (Emory, Gallegos). Moreover, each well has a different composition of NGLs, meaning that some wells produce more ethane than propane, while other wells produce no propane but have a considerable amount of ethane and butane. See Tr. at 492:3-17 (Griffin).

138. When the gas exits the wellhead, it is run through a separator, which removes the liquid water and NGLs. See Tr. at 753:17-23 (Emory),

139. No gaseous-phase natural gas from the class wells was sold to a third party from the wellhead; all of it goes into a gathering-system. See Tr. at 383:13-16 (McArthur); id. at 755:16-18 (Emory, Sutphin).

140. The reduction in pressure and temperature that occurs when producing natural gas causes heavier hydrocarbon molecules to “condense” and separate from the gas stream at the lease. These are known as well condensate or oil. Tysseling Report at 16.

141. After liquids are separated from the gas, the gas is transmitted from the wellhead to an affiliate gathering system and is metered before it leaves the lease. See Tr. at 483:7-16 (Griffin).

142. Metering measures the volume of gas that the lease produces measured in Mcfs. See Tr, at 488:1-25 (Griffin); id. at 754:1-6 (Emory).

143. To obtain the thermo-energetic potential in a particular well’s production, the Defendants must take an annual gas sample and run it through a gas chromatograph. See Tr. at 754:11-14 (Emory); id, at 520:22-521:15 (Gallegos, Griffin). This process reveals the well’s Btu factor, which is multiplied by the well’s volume to determine the NGL content. See Tr. at 483:7-25 (Griffin).

144. 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 travel from one end of the column to the other at different speeds, which correspond to their level of interaction with the stationary phase. 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. *187 wfu.edu/chemistry/courses/organic/GC/index. html. See generally Gas Chromatography, Wikipedia.org, available at en.wikipe-dia.org/wiki/Gas_ehromatography.

145. 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.

146. The meter and chromatographic anal-yses produce data, which make it possible to determine the potential production value attributable to each individual well for all relevant production months. See Tr. at 748:21-749:23 (Emory, Gallegos); Tysseling Report at 9-10. This information is also used to calculate federal and state royalty interests. See Tr. at 749:14-750:10 (Emory, Gallegos).

147. In the gathering system, the natural gas is transmitted through the gathering system’s network of low-pressure pipes to one of several processing or treatment plants. See Tr. at 495:3-24 (Berge, Griffin).

148. Conventional gas wells often 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 157:12-20 (Hajny); Comparison of NGL and Residue Natural Gas Prices (Left Scale) and Relative Prices (Right Scale)(Plaintiffs’ Hearing Ex. 306).

149. For gas that goes to a treatment plant, the plant removes the impurities from the raw gas, removes the CO2, and removes the water vapor, leaving residue gas that can go into an interstate pipeline. See Tr. at 496:1-6 (Griffin).

150. At a processing plant, the gas is cleaned of impurities, and any NGLs that are still entrained in the gas are removed. See Tr. at 496:13-25 (Griffin).

151. Processing does not create new NGLs, nor does it change their constituency — be., 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 Tr. at 493:15-23 (Griffin).

152. NGLs removed during processing are either: (i) sent to a fractionator and separated — or “fractionated” — into their constituent compounds, Tr. at 493:15-23 (Griffin); or (ii) fractionated at the processing plant, see Tr. at 498:12-20 (Griffin). Only the Ignacio plant has the ability to perform “limited fractionation,” meaning that it can “split out the pro-pones and it also can split out some natural gasoline,” enabling the processor to sell the NGLs locally. Tr. at 498:10-16 (Griffin).

153. For NGLs sold locally from the Ignacio plant, the plant takes a volume of the NGLs fractionated — primarily propane and a small amount of natural gasoline — and a fractionation fee, but there is no processor’s tax or transportation cost. See Tr, at 503:7-22 (Griffin).

154. The other liquids that the Ignacio plant cannot fractionate must be shipped in the pipeline to a downstream fractionator in Mont Belvieu, Texas. See Tr. at 498:16-20 (Griffin).

155. For NGLs transported to the Mont Belvieu fractionation facility, fractionation fees and transportation fees apply for gas processed in New Mexico. See Tr. at 498:24-499:3 (Griffin); id at 502:23-25 (Griffin).

156. 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 383:13-16 (McArthur).

157. Williams Four Corners owns three plants to which class wells flow: the Lybrook processing plant, the Kutz processing plant, and the Ignacio processing plant. See Tr. at 87:3-89:3 (Gallegos); id at 360:21-360:4 (Gallegos, McArthur).

158. Williams Four Corners also owns the gathering lines connecting the class wells to three four plants. See Tr. at 360:21-361:4 (Gallegos, McArthur).

159. An independent, third-party gathering system in the San Juan Basin, Enterprise San Juan Gathering, carries gas from non-class wells on which WPX Production has a working interest to Enterprise Gathering’s *188 Chaco processing plant. See Tr. at 88:16-20 (Gallegos); id. at 169:16-22 (Gallegos, Hajny); id. at 361:9-14 (Gallegos, McArthur); Ward Nov. Depo. at 70:4-22 (Ward).

160. WPX Production pays royalty on the NGLs processed at the Chaco plant, see Ward Nov. Depo. at 74:4-75:12, so the Plaintiffs’ claims do not involve leases burdening WPX Production’s wells whose gas flows on the Enterprise Gathering system to the Cha-co plant, see Tr. at 88:16-20 (Gallegos); id. at 361:9-21 (Gallegos, McArthur).

161. A processing fee is typically a “flat fee,” entitling the processor to a certain percentage of the NGLs processed from the plant, regardless of: (i) which wells produced the gas with the entrained liquefiable hydrocarbons; (ii) the distance between the wells and the processing plant; or (iii) the amount of gas that the wells produce. Tr. at 166:13— 167:13 (Gallegos, Hajny).

162. 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. Tr. at 665:12-24 (Emory).

163. The Williams Four Corners gathering systems are interconnected, which allows various gathering line segments to flow to different gathering systems and more than one plant. See Tr. at 649:1-9 (Emory, Sut-phin). Gas from a well may not actually flow to the plant associated with the gathering system to which the well is connected. See Emory Report ¶ 44, at 24; Ward April Depo. at 119:1-5 (Ward)(explaining that gas may not be processed at a certain plant, even if the contract states that it will be delivered to that plant).

164. The actual gas flow depends on “system interconnections and natural flow hydraulics resulting in volumes of commingled gas being delivered to different WFC’s plants _” Emory Report ¶44, at 24. A well’s contractual dedication to a particular plant does not determine whether the well actually flows to that plant. See Emory Report ¶ 45, at 25; Tr. at 649:10-650:1 (Emory, Sutphin).

165. Some of the class wells do not deliver gas to the Ignacio, Kutz, or Lybrook plants to be processed. 13 See Tr. at 649:10-650:9 (Emory, Sutphin). Moreover, some of the gas from the class wells that is delivered to one of these plants gets bypassed around the processing plant, and therefore is not processed. See Tr. at 662:3-12 (Emory, Sutphin); id. at 666:11-16 (Emory).

166. It is impossible to determine whether a certain small percentage of the gas flows to the Ignacio plant, where it could be processed, or to the Milagro plant, where it is not processed. See Tr. at 662:13-20 (Emory, Sutphin); Emory Report ¶48, at 26 n.20; Emory Report ¶47, at 25 (“[I]t would be virtually impossible to determine with certainty where all of the molecules from any given gas well would flow.”).

167. The volumes of processed gas change over time, because: (i) wells produce at different rates and decline in production over time; (ii) wells are added to or removed from the gathering systems; and (iii) the piping changes or expands. See Tr. at 665:18-25 (Emory). Because gas flow changes over time, a month-by-month study is the only way to ascertain where gas actually flowed on a month-by-month basis. See Tr. at 716:24-717:8 (Emory).

168. Three gathering trunks — Trank N, TRKNEAST, and TRKNWEST — are interconnected between the conventional and coalbed gathering systems, enabling gas to flow to either the Milagro plant or a processing plant. See Tr. at 658:18-661:18 (Emory, Sutphin); Emory Report ¶ 48, at 26 n.20. Williams Four Corners does not maintain data to identify the plants to which the wells on these tranks flow. See Tr. at 658:18-661:18 (Emory, Sutphin). Approximately sixteen percent of the production from the class wells flowed on these gathering lines. See Tr. at 660:24-661:18 (Emory).

169. Production from two tranks — Trank B and Trank C — flows to the Ignacio plant, but bypasses the processing unit and is therefore *189 not processed. See Tr. at 666:2-668:2 (Emory, Sutphin).

170. Williams Four Corners does not receive NGLs from WPX Production that is not processed for NGL removal. See Tr. at 670:5-671:15 (Emory, Sutphin). Instead, the NGLs remain entrained in the gas stream delivered to the transmission pipeline and sold on a Btu basis in downstream markets. See Tr. at 670:5-671:15 (Emory, Sutphin).

171. For WPX Production-operated and Williams Four Corners-gathered production at issue in this case: 14

a. In 2007:

i. 34% flowed to the Ignacio, Kutz and Lybrook plants, and was processed for NGL removal;

ii. 42% flowed to the Milagro plant and was not processed;

iii. 10% flowed to the Ignacio plant, but was not processed for NGL removal, because it was bypassed;

iv. 16% flowed either to the Milagro plant and was not processed, or to the Ignacio plant and was processed;

b. In 2011:

i. 23% flowed to the Ignacio, Kutz and Lybrook plants, and was processed for NGL removal;

ii. 53% flowed to the Milagro plant and was not processed;

iii. 8% flowed to the Ignacio plant, but was not processed for NGL removal, because it was bypassed;

iv. 16% flowed either to the Milagro plant and was not processed or to the Ignacio plant and was processed;

c. In 2013:

i. 26% flowed to the Ignacio, Kutz and Lybrook plants, and was processed for NGL removal;

ii. 49% flowed to the Milagro plant and was not processed;

iii. 9% flowed to the Ignacio plant, but was not processed for NGL removal, because it was bypassed;

iv. 16% flowed either to the Milagro plant and was not processed, or to the Ignacio plant and was processed.

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

a. Who Held Title on the Natural Gas from 2006 to December, 2010.

173. The production from the 1,637 class wells has been gathered and processed under a keep-whole arrangement between Williams affiliates since the time that the Defendants’ predecessors entered into a gathering and processing agreement designated “J99” in March, 1991. Tr. at 419:8-420:3 (Gallegos, Tysseling). See Letter Agreement Northwest Pipeline Corporation and Williams Production Company Keepwhole J99 (Plaintiffs’ Hearing Ex. 9).

174. During the class period, a significant number of the class wells were covered by J99. Tr. at 433:17-23 (Tysseling); Class Well List (Plaintiffs’ Hearing Ex. 225).

175. WPX Production and Williams Four Comers entered into a gathering and processing agreement designated as 372K that provides gathering of WPX Production gas to Williams Four Comer’s Kutz processing plant in New Mexico. See Tr. at 422:9-23:15 (Gallegos, Tysseling).

*190 176. From 1996 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 Ward Nov. Depo. at 13:1-14:17 (Ward).

177. The lessee would transfer title to the natural gas to a marketing affiliate — WFS Gas Resources, or its successor WPX Gas Resources — as it transferred physical possession of the gas to an affiliate gathering company, Williams Field Services. See Ward Nov. Depo. at 13:1-14:17 (Ward).

178. After processing the gas, WFS Gas Resources, or successor WPX Gas, transferred title to the residue gas to Williams Gas Marketing and title to the processed NGLs to Williams Power. See Ward Nov. Depo. at 13:1-17 (Ward).

179. Williams Gas Marketing and Williams Power would then sell their respective products to arm’s-length buyers with the goal of selling the gas at a higher price than the price at which they obtained the gas. See Field Depo. at 10:6-14:2; id. at 69:1-14 (Field); id. at 16:7-10 (Field); Ward Nov. Depo. at 14:23-25 (Ward).

180. The prices for which Williams Gas Marketing sold the gas at arm’s length were never used in royalty accounting. See Ward Nov. Depo. at 14:1-15:25 (Ward); Field Depo. at 59:1-15 (Field).

b. The 2011 Reorganization.

181. In 2011, in preparation for the upcoming spinoff of various WPX affiliates, the Defendants and their affiliates executed a new set of gathering contracts. See Deposition of Paul Dolan at 57:24-61:18 (Dolan)(taken February 10, 2014)(“Dolan Depo.”); Gas Gathering, Processing, Dehydrating and Treating Agreement between Williams Four Comers and WPX Gas Resources (dated July 1, 2011)(Plaintiffs’ Hearing Ex. 11)(“J99M”).

182. J99M combined the J99 and 372K services, replaced the prior contracts, and maintained the keep-whole arrangement whereby WFC “shall retain the gross Plant Products Processed from [WPX Production’s] Gas_” J99M § 1.7. See Dolan Depo. at 59:6-21 (Dolan); id. at 69:3-10 (Do-lan).

183. The agreement term extends for ten years through December 31, 2022, and binds the spun-off companies, despite being executed before the spinoff. See J99M § 4; Dolan Depo. at 63:3-7 (Dolan).

184. 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 Deposition of Jefferson Paul Dolan at 52:1-5 (Dolan), taken February 10, 2014 in Anderson (“Dolan Anderson Depo.”)(stating that “both companies were owned by the same parent”).

185. After WPX Production became independent and no longer affiliated with Williams Four Corners, however, WPX Production’s independent marketing unit would not accept a keep-whole contract with Williams Four Corners for future gathering and processing services. See Dolan Depo. at 20:8-27:14 (Dolan); id at 74:15-22 (Dolan).

186. WPX Production’s December 9, 2013 contract with Williams Four Corners for gathering and processing services resulted in WPX Production retaining eighty percent of the NGLs. See Dolan Depo. at 29:16-31:4 (Dolan); Gas Gathering, Processing, Dehydration and Treating Agreement between Williams Four Comers and WPX Production, dated December 9, 2013 (Plaintiffs’ Hearing Ex. 205)(“Dec. 2013 Gathering Contract”).

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

187. The class leases were largely executed in the 1940s and early 1950s, and, in all known instances, the original lessors and the original lessee representatives are unavailable. See Tr. at 370:4-10 (Gallegos, McAr-thur); Beach Depo. at 24:10-15 (Beach).

188. Every lease has a granting clause, which describes what is being conveyed to the lessee, and a royalty clause, which explains how royalty is to be paid. See Tr. at 362:8-15 (McArthur); id at 938:1-939:15 (Mc-Arthur); id at 366:4-361:13 (McArthur).

*191 189.No lease expressly excludes payment of royalty for NGLs or condensate. See Tr. at 370:17-371:7 (Gallegos, McArthur).

190. All leases require payment on “gas.” Tr. at 937:13-25 (McArthur).

191. 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 at 1 (Defendants’ Hearing Ex. 125).

192. 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 at 1; Tr. at 828:11-14 (Terry).

193. 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 828:16-20 (Terry).

194. Although 210 leases use textual formulation (iii), fifty-five leases contain specific, separate royalty provisions relating to cas-inghead gas, which the class wells, being gas wells, do not produce. See Lease Language Chart at 1.

195. Thirty-one of these 210 leases are Colorado leases and twenty-four of them are New Mexico leases. See Lease Language Chart at 1.

196. The majority of the leases are form contracts 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 generally Spreadsheet of Lease Language (Plaintiffs’ Hearing Ex. 304)(categorizing each lease by its form number).

197. Numbers stamped on the leases’ top comers identify the form contract used to produce the lease, as well as the corporate author and model number. See Tr. at 830:5-12 (Terry).

198. Some leases have royalty clauses that differ from the language that a certain form contract uses. See Tr. at 830:5-8 (Terry).

*192 199. The form designation as to the type of lease form does not necessarily mean that the royalty clause will be identical for all leases using one type of form. Terry testified that “you can have a form that says — it’s the very same form on the front in that upper left-hand corner — and you can have a royalty clause that’s completely different.” Tr. at 830:4-8 (Terry).

200. None of the leases expressly provide for payment on the basis of an index price, but none of them prohibits payment on that basis. See Tr. at 857:17-22 (Terry).

201. Similarly, the leases do not expressly prohibit the use of an affiliate transaction to compute the applicable royalty. See Tr. at 857:23-858:2 (Sheridan, Terry); id. at 930:10-21 (McArthur).

202. Of the 480 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 at 1 (Defendants’ Hearing Ex. 125).

203. Of the 480 leases with legible royalty provisions, 381 are in Colorado, and ninety-nine are in New Mexico. See Lease Language Chart at 1 (Defendants’ Hearing Ex. 125).

a. The New Mexico Leases’ Royalty-Provision Breakdown.

204. Sixty-eight of the ninety-nine total New Mexico leases are single-pronged, and thirty-one are double-pronged. See Lease Language Chart at 1 (Defendants’ Hearing Ex. 125).

205. Sixty-seven of the sixty-eight single-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 at 1 (Defendants’ Hearing Ex. 125).

206. 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 at 1 (Defendants’ Hearing Ex. 125).

207. 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 at 1 (Defendants’ Hearing Ex. 125).

208. 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 at 1 (Defendants’ Hearing Ex. 125).

b. The Colorado Leases’ Royalty-Provision Breakdown.

209. One-hundred fifty-six of the 381 total Colorado leases are single-pronged, and 225 are double-pronged. See Lease Language Chart at 1 (Defendants’ Hearing Ex. 125).

210. 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 at 1 (Defendants’ Hearing Ex. 125).

211. Eight of the 156 total single-pronged Colorado leases pay on the basis of “proceeds at the mouth of the well.” Lease Language Chart at 1 (Defendants’ Hearing Ex. 125).

212. Four of the 156 total single-pronged Colorado leases pay on the basis of “price [or market price] at the well.” Lease Language Chart at 1 (Defendants’ Hearing Ex. 125).

213. 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 at 1 (Defendants’ Hearing Ex. 126).

214. 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 at 1 (Defendants’ Hearing Ex. 125).

215. 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 at 1 (Defendants’ Hearing Ex. 125).

*193 216. 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 at 1 (Defendants’ Hearing Ex. 125).

217. 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.” Lease Language Chart at 1 (Defendants’ Hearing Ex. 125).

218. These 23 leases are the only leases to disclaim or negate Colorado’s marketable-condition rule. See Lease Language Chart at 1 (Defendants’ Hearing Ex. 125).

219. 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 at 1 (Defendants’ Hearing Ex. 125).

220. 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 at 1 (Defendants’ Hearing Ex. 125).

c. The Named Plaintiffs’ Royalty Provisions.

221. Abraham owns a royalty interest in three leases in Colorado, each of which contains the same two-prong royalty clause that provides:

on gas, including casinghead gas or other gaseous substance, produced from said land and sold or used off the premises or in the manufacture of gasoline or other product therefrom, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at the wells the royalty shall be one-eighth of the amount realized from such sale

Expert Report of Kris L. Terry ¶¶ 10-11, at 4-5 (dated January 27, 2014)(Defendants’ Hearing Ex. 71).

222. Abraham does not own any royalty or overriding royalty interests that burden WPX Production wells that produce drip condensate in the San Juan Basin. See Ward April Depo. at 19:6-9 (Ward).

223. H Limited owns an overriding royalty interest in 2.5%

of the value, based on the field market price at the well, of all oil and/or gas that may be produced, saved, and marketed, except that used for operating or development purposes on said lease or unavoidably lost from any wells that may be hereafter drilled by assignee or its assigns on the assigned land pursuant to said lease.

Tr. at 299:12-300:14 (Gallegos, Harvey). See Contract of Reservation and Agreement to Reassign (dated October 20, 1984)(Plaintiffs’ Hearing Ex. 95); Overriding Royalty Language Used in Various Assignments at 1 (Defendants’ Hearing Ex. 130)(“Overriding Language Chart”).

224. H Limited’s override applies to Tract 30 in the Mesa Verde participating area of the Rosa Unit — a federal unit that WPX Production operates. See Tr. at 183:4-185:6 (Gallegos, Hajny).

225. H Limited owns another overriding royalty interest in “5 per cent of the sales price at the wells as produced of all of the oil, gas, natural gasoline and other products obtained from gas which may be produced, saved and marketed from the above described land.” Overriding Royalty Agreement (dated September 18, 1952)(Defendants’ Hearing Ex. 11).

226. The overriding royalty requires royalty to be paid “at the same time and in the same manner as royalties payable to the State of New Mexico .... ” Overriding Language Chart at 1.

227. Because the Rosa Unit in which H Limited owns interests does not produce condensate, H Limited does not own a royalty or overriding royalty interest in any WPX Production wells that produce condensate. See Ward April Depo. at 18:9-19 (Ward).

*194 d. The Meanings of the Leases’ Varying Language.

228. In the oil-and-gas industry, “net proceeds” and “amount realized” mean the same thing. Ti\ at 843:19-844:4 (Sheridan, Terry).

229. In the oil-and-gas industry, the term “gas used in the manufacture of gasoline or other product therefrom” refers to the decrease in the volume of natural gas that occurs when the entrained liquefiable hydrocarbons are extracted through processing. Tr. at 841:2-13 (Sheridan, Terry).

230. In some states, the terms “proceeds” and “market value” do not necessarily mean the same thing in the oil-and-gas industry. Tr. at 920:3-13 (McArthur).

231. In the oil-and-gas industry, “proceeds” refers to the amount of money that the lessee realizes from the sale of gas. Tr. at 882:6-22 (Gallegos, Terry); id. at 843:19-844:4 (Sheridan, Terry).

232. 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 846:10-22 (Sheridan, Terry).

233. Gas’ market value 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 882:6-22 (Gallegos, Terry).

234. In some quarters of the oil-and-gas industry, specifically in Texas, royalty has been paid differently depending on whether it is payable on market value or proceeds. See Tr. at 918:17-25 (Gallegos, McArthur); id. at 918:1-6 (McArthur)(stating that the two variations do not necessarily produce a different price, but that “[t]hey have slight differences in deductions”).

235. 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 royalty valuation purposes, that is, the condition at the well, and not at a downstream sales point. See Tr. at 845:7-25 (Sheridan, Terry).

236. 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 its condition as it emerges from the well. See Tr. at 833:9-18 (Sheridan, Terry),

237. In contrast, other industry players use the phrase “gas as such” to distinguish gas that emerges from a gas well as opposed to casinghead gas, which emerges from an oil well. See Tr. at 940:15-941:16 (McArthur).

238. In some quarters of the oil-and-gas industry, when a lease requires the lessee to pay royalty on all “products,” it expressly requires payment on both the residue gas and NGLs. Tr, at 893:14-19 (Terry).

239. The New Mexico Energy, Minerals and Natural Resources Department, Oil Conservation Division, defines “gas” or “natural gas” as “a combustible vapor composed chiefly of hydrocarbons occurring naturally in a pool the division has classified as a gas pool.” N.M.A.C. § 19,15.2.

240. Some courts have held that “market-value” leases require royalty to be paid “based on the market value of unprocessed gas as it emerged from the ground (‘at the well’).” Abraham v. BP Am. Prod. Co., 685 F.3d 1196, 1199 (10th Cir.2012).

241. As the liquids market developed over time, lease language became more detailed to include the full array of products being developed. See Tr. at 908:8-16 (McArthur).

242. The double-pronged leases provide varying means of determining how royalties should be paid, depending on where the gas is sold and how the gas is used. See 842:3-17 (Sheridan, Terry).

243. For a period of time, WPX Production sold gas to an affiliate in sales at the well. See Tr. at 844:5-8 (Sheridan, Terry).

244. 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.

*195 245. 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.”).

246. As the leases are predominantly form contracts, few leases were the product of meaningful negotiation. See Tr. at 865:17— 866:9 (Sheridan, Terry); id. at 904:7-905:1 (MeArthur)(“[T]here were eight lease forms that appeared 25 or more times in the 502 leases in the class”); id. at 907:25-908:1 (Mc-Arthur)(“And the wording in the forms doesn’t vary, other than the percent sometimes.”).

247. The only terms that frequently involved meaningful negotiation were the magnitude of the fractional royalty share and the length of the primary term, “which is the period in which the lessee has to drill.” Tr. at 923:13-24 (McArthur). See Tr. at 864:5-9 (Terry); id. at 868:3-21 (Sheridan, Terry); id. at 870:1-4 (Terry).

248. Approximately forty of the class leases have alterations to the royalty clauses, demonstrating that, at least with respect to the royalty clause, some leases involved individual negotiation. See Tr. at 870:19-23 (Terry).

249. The federal government provides detailed instructions about how working interest owners must pay royalty interests— 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”).

250. 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 their practices. See Anderson, 306 F.R.D. at 342 .

5. The Overriding Royalty Interests.

251. An overriding royalty is typically carved out from the working interest owner’s share. See Beach Depo. at 13:12-14 (Beach).

252. One common way an override can be created is when a royalty owner assigns its lease to a new lessee and reserves an overriding royalty in the lease. See Tr. at 792:12— 16 (Terry).

253. Further overriding royalty interests can arise in the same lease when the original overriding royalty owner “subsequently assigns a portion of his override, which is characterized as an assignment of a[n] overriding royalty interest.” Tr. at 792:16-22 (Terry).

254. Another common way to create an overriding royalty interest is when a lessee assigns an interest and retains an overriding royalty interest, and then the second lessee creates another override when it assigns the instrument. See Tr. at 793:2-8 (Terry). This situation produces an “override stacked upon override, which creates a greater percentage of total override.” Tr. at 793:6-8 (Terry).

255. Overriding royalty interests generally are not created through the use of form contracts, See Tr. at 790:14-18 (Sheridan, Terry).

256. Overriding royalty interests often are created in individualized circumstances and business transactions, and the agreements contain unique royalty valuation terms. See Tr. at 800:14-18 (Terry); id. at 809:15-18 (Terry)(“[T]he various parties to these agreements really were fairly creative in the types of obligations that they decided would pertain to their interest.”).

257. There is no standardization in the overriding royalty interest terms, because overriding royalty instruments are not generic like leases. See Tr. at 807:9-10 (Terry); id. at 808:6-14 (Terry).

258. The Court has a list of some of the textual provisions found in the class overriding royalties. See Overriding Language Chart at 1-12. The list is illustrative, not *196 exhaustive, of all the overriding royalty provisions among the class. See Tr. at 802:3-7 (Terry)(explaining that the summary of overriding royalty instruments “certainly does not include all instruments at issue”).

259. Many of the overriding interests are “carved out, not of the private leases, but out of state and federal leases.” Tr. at 802:12-15 (Terry).

260. 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 924:22-925:5 (McArthur).

261. 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 and pay unique royalty interests on 229 federal oil-and-gas leases and eighty-six state leases in the San Juan Basin. See Tr. at 802:1-S04:13 (Sheridan, Terry).

262. 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. Tr. at 815:13-816:9 (Sheridan, Terry). New Mexico changed its form lease over time. See Tr. at 816:14-17 (Terry).

263. The Plaintiffs’ override categorization includes some instruments that create overriding royalty interests owned by persons who are not members of the proposed class, including four instruments that create overriding royalty interests in the Fruitland coal formation. See Tr. at 791:21-792:2 (Terry).

264. There are overriding royalty instruments subject to the class claims that disclaim the duty of the lessee to market oil or gas from the subject lands. See Overriding Language Chart at 11-12.

6. The Defendants’ Royalty-Distribution System.

265. The Defendants use a different royalty-payment system for wells on their own gathering system, he., the Williams Four Comers gathering system, than the one they used for wells on an independent, third-party gathering system, the non-affiliated Products System. See Tr. at 96; id. at 189; id. at 606-609; id. at 897-899; Tysseling Report at 16 & n.9.

266. The Defendants did not vary their payouts to the class on the basis of the individual leases’ language. See Tr. at 151— 153; id. at 359-360; id. at 412-413.

267. The generally applicable master equation that the Defendants use to determine royalty payouts is: (Price • Wellhead Volume) - Applicable Post-Production Deductions = Royalty Value. See Tr. at 446:8— 447:18 (Berge, Tysseling).

268. To determine the amount that each royalty owner is owed, the Defendants multiply the Royalty Value by the royalty owner’s fractional interest. See Tr. at 446:19-447:18 (Berge, Tysseling).

269. The Colorado wells are not subject to deductions for gathering and processing costs. See Ward Nov. Depo. at 52-55. (Ward).

270. For New Mexico wells, the applicable post-production deductions are described below.

a. Payments on NGLs, Including Drip Condensate.

271. The Defendants pay the class members’ royalties on the basis of MMBtus at the wellhead, known as a keep-whole basis. See Tr. at 151:12-13 (Hajny); id. at 483:7-15 (Griffin).

272. This practice of paying a per-MMBtu-at-the-wellhead royalty compensates the class members partially, but not fully, for the value of entrained liquefiable hydrocarbons. See Tr. at 151:16-22 (Hajny).

273. Gas with a higher content of liquefia-ble hydrocarbons 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 Tr. at 484:20-485:1 (“If a gas is rich in natural gas liquids, it will have a higher Btu factor. And because it has a higher Btu factor, then it will receive a higher payment.... [T]he real *197 question is whether they’re being compensated enough for those liquids.” (emphasis added)); id. at 544:24-545:21 (Gallegos, Griffin).

274. 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 Tr. at 152:15-153:11 (Gallegos, Hajny).

275. 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 — he., 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. 17

276. The Defendants do not pay royalties on drip condensate or processed NGLs— except to the extent that, when what will become drip condensate or NGLs are entrained in the gas at the wellhead, it causes the gas to have a higher MMBtu factor. See Ward April Depo. at 15:2-21 (Ward); id. at 97:12-15 (Gallegos, Ward).

277. The processor — a Williams entity— “keep[s] all the liquids,” Ward April Depo. at 92:4-8 (Gallegos, Ward), because WPX Production entered into the keep-whole contract, see Ward April Depo. at 140:23-24 (“[WPX Production] do[es]n’t get the liquids because we have a contract, a keep-whole contract”).

278. The Defendants disburse division orders to the Plaintiffs and proposed class members that ask them to review and confirm the information on the division order and alert the Defendants if there is a problem. See Beach Depo. at 16:8-17 (Beach).

279. The royalty owners’ signature on the division order serves as an acknowledgement that the royalty owners have reviewed the information. See Beach Depo. at 16:8-17 (Beach).

280. WPX Production’s revenue department uses the information in the division order to compile a revenue deck on which WPX Production distributes royalty payments. See Beach Depo. at 17:1-7 (Beach).

281. Neither the revenue decks nor the division orders reveal how the oil-and-gas lease directs royalty to be paid, e.g., on proceeds or market value. See Beach Depo. at 22:1-15 (Beach); Ward Nov. Depo. at 55:15— 56:16 (Ward).

282. To obtain the named Plaintiffs’ lease and other documents relating to them, Beach spent two weeks to retrieve the documents from the lease records department. See Beach Depo. at 28:7-25 (Beach); id. at 32:4-35:4 (Beach). Those documents, including the lease, were not already filed or preserved in one place. See Beach Depo. at 34:14-17 (Beach).

*198 283. There are two exceptions to this keep-whole payment scheme: for two wells committed to the 372K gathering contract, the Defendants pay royalty on the basis of NGLs: the Sanchez and San Juan 32-8 Unit No. 33A, both of which are completed in the Mesa Verde formation. 18 See Ward April Depo. at 44:10-45:14 (Wal’d); Ward Nov. Depo. at 113:10-114:4 (Ward); Ward Nov. Depo. at 120:7-24 (Ward). There are approximately ninety-nine royalty and overriding royalty owners in the proposed class that receive NGL payment for production from the 32-8 Unit No. 33A well. See Ward April Depo. at 45:1-14 (Ward); Email from Sheryl Ward, WPX Production, to Robert Sutphin, counsel for WPX Production (dated Nov. 27, 2013)(Defendants’ Hearing Ex. 70).

284. Moreover, there are approximately ten wells committed to the December 2013 Contract (Plaintiffs’ Hearing Ex. 205) for which WPX Production pays royalty owners on refined NGLs. Ward April Depo. at 160:22-162:21 (Ward).

285. To calculate federal royalties, WPX Production uses “accounting for comparison.” Mathis Depo. at 6:5-9:23 (Mathis, Sutphin). WPX Production compares the value of processed gas — residue gas’ value after processing plus NGL value after processing — with the value of unprocessed gas — the wellhead-adjusted Btu — and uses the higher of the two figures. See Mathis Depo. at 6:5-9:23 (Mathis, Sutphin).

286. For unprocessed gas, however, WPX Production pays federal royalties on the wellhead-adjusted Btu basis under the same keep-whole scheme that it uses to pay the proposed class members’ royalties. See Mathis Depo. at 6:5-9:23 (Mathis, Sutphin).

287. Currently (and going back to 2008), 19 WPX Production takes into account a well’s actual gas flow — i.e., whether it flows to a processing plant and is processed — in paying federal royalties on production committed to a WFC gathering agreement. See Mathis Depo. at 6:5-9:23 (Mathis, Sutphin).

b. Cost Deductions.

288. 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 Comers gathering system, regardless of the actual costs attributable to each well of rendering the gas into marketable condition. See Ward Nov. Depo. at 27:16-29:13 (Ward).

289. Williams Four Comers computes the COS charge and relays it to WPX Production, who assesses it against the royalty in lieu of the actual charges that WPX Production incurs for gathering. See Ward April Depo. at 27:13-29:2 (Ward).

*199 290. The COS charge does not contain any costs associated with processing. 20 See Ward April Depo. at 43:19-25 (Ward). Accordingly, WPX Production does not assess any actual processing charges under its keep-whole methodology. See Ward April Depo. at 28:6— 9 (Ward); id. at 30:1-8 (Ward); id. at 25:10-26:5 (Ward); id. at 43:19-21 (Ward)(explaining that royalty owners “do not bear any processing costs because they are charged the cost of service, which is a gathering charge”); id. at 122:19-123:10 (explaining that WPX Production does not pay a natural gas processors’ tax for Williams Four Corners gathered wells).

291. The Defendants do not deduct certain post-production costs for the Colorado royalty owners. See Ward Nov. Depo. at 54:22-55:14 (Ward).

292. 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 Ward April Depo. at 29:2-20 (Ward).

293. 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 Field Depo. at 16:11-15 (Field).

294. WPX Production deducts federal and state taxes from royalty payouts, in keeping with the law. See Ward Nov. Depo. at 53:20-54:2 (Ward).

295. 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 invoices to it. See Ward April Depo. at 46:2-22 (Ward).

296. For gas processed on the Enterprise system, Enterprise charges WPX Production fees for plant fuel, taxes, transportation, and fractionation. 21 See Ward April Depo. at 45:15 — 46:22 (Ward).

297. In determining the royalty payments for WPX Production’s gas committed to third parties like Enterprise, WPX Production deducts a proportional share of all actual charges that third parties assess. See Response to Interrogatory. 1, at 10-11 (Doc. 146-5); Ward Nov. Depo. at 73:25-75:18 (Ward). Consequently, these deductions should apply to the whole-stream method, which compensates royalty owners on the basis of the NGL and residue value.

c. Payments of the Basis of Index Price.

298. WPX Production receives revenue for its NGLs based on the OPIS Mont Belvieu index price — an oil index — for well condensate. See Dolan Depo. at 32:9-22 (Dolan).

299. For natural gas, the Defendants use the index price in the firsbof-the-month Platt’s Inside FERC San Juan Gas Market Report for El Paso Natural Gas Company. See Ward Nov. Depo. at 50:12-14 (Ward).

300. An independent company, Platt’s, calculates the index and publishes it in Inside FERC Natural Gas Report. See Tr. at 860:12-861:24 (Sheridan, Terry).

301. This index price is based upon actual reported sales and purchases of dry gas to be *200 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 861:4-18 (Sheridan, Terry).

302. This price reflects the average arm’s length sale price of pipeline-quality gas, not wellhead gas that includes entrained liquefia-ble hydrocarbons. See Tr. at 862:16-24 (Sheridan, Terry); id. at 931:3-22 (McAr-thur)(“Williams used the indexed price for methane, dry gas, not what’s paid for liquids when they’re sold in the marketplace.”).

303. As the index price reflects an average, some producers obviously obtain higher prices than the index price. After WPX Production’s marketing department became independent, one of its goals was to obtain higher-than-index prices. Field Depo. at 15:24-16:25 (Field, Gallegos); id. at 43:18-24 (Field, Gallegos). Large producers can potentially obtain better prices by committing large gas volumes for longer terms. See Tr. at 931:8-932:20 (Gallegos, McArthur).

304. Natural gas is regularly sold and purchased by unrelated sellers and buyers at the index price. See Field Depo. at 39:1-13 (Field).

305. Within the oil-and-gas industry, it is generally believed that the index price reflects the market value of residue gas delivered at the designated location in the month of publication. See Field Depo. at 61:2-4 (Field).

306. In comparison, no such publicly available pricing mechanism exists for gas at the wellhead. See Tr. at 745:22-746:1 (Emory, Gallegos). There are no sales of gas at the wellhead to third parties during the class period. See Tr. at 746:25-747:2 (Emory); id. at 755:15-18 (Emory, Sutphin).

7. WPX Production’s Contracts for Production and Processing.

307. Three types of processing contracts are used in the San Juan Basin: (i) keep-whole contracts; (ii) percentage of liquids contracts; and (iii) fee-based contracts. See Dolan Depo. at 26:7-27:1 (Dolan).

308. There are several production conditions that parties consider in determining the type of contract to use. See Tr. at 685:6-19 (Emory). Gas composition and flow rate, which vary among wells, are primary production conditions that parties consider. See Tr. at 689:2-693:22 (Emory). A well’s proximity to a gathering system is another production condition that impacts the costs necessary to connect to a gathering system. See Tr. at 695:2-697:25 (Emory).

309. Gas containing .5 or less Gpm contains primarily ethane, which is the least valuable NGL and is often not extracted. See Tr, at 691:11-692:19 (Emory).

310. ConocoPhillips also has working interests in the San Juan Basin, and pays its burdening royalty owners for gas proceeds and NGL proceeds. See Tr. at 237:13-25 (Abraham, Gallegos). ConocoPhillips provides royalty owners with monthly statements that state the amount of royalty attributable to gas, NGLs, and condensate. See Tr. at 237:13-25 (Abraham, Gallegos); id. at 307:15-17 (Harvey). BP similarly indicates how much of a royalty owner’s payment is attributable to gas, NGLs, and condensate. See Tr. at 238:18-24 (Abraham, Gallegos); id. at 307:15-17 (Harvey).

311. Nevertheless, Williams Four Corners has “keep whole” contracts with producers in addition to WPX Production, including large unaffiliated producers like ConocoPhillips, BP, XTO, and Devon, as well as, with smaller independent producers. See Tr. at 681:9-15 (Emory, Sutphin).

312. Under one of WPX Production’s other gathering and processing contracts, Enterprise Gathering charges WPX Production a fourteen percent processing fee for gas processed at the Chaco plant, in addition to processing-related shrinkage. See Tr. at 165:5-10 (Hajny); id. at 201:1-203:3 (Berge, Hajny); Gas Dedication, Gas Gathering, and Production Area Services Agreement between El Paso Field Services Co. and WFS Gas Resources Co. at 2-4, D-2 (dated February 1, 1996)(Defendants’ Hearing Ex. 30)(“1996 Gathering Agreement”).

313. Under another WPX Production contract, the processing fee is twenty percent of the liquids, which leaves WPX Production with eighty percent of the liquids. See Ward *201 April Depo. at 143:7-13 (Gallegos, Ward); Gas Gathering, Processing, Dehydrating and Treating Agreement between Williams Four Corners, LLC and WPX Energy Production, LLC § 1.9, at 3 (dated December 9, 2013)(Plaintiffs’ Hearing Ex. 204)(“2013 Gathering Agreement”).

314. WPX Production was not an original party to one of the processing contracts that the Plaintiffs challenge: the February 2008 keep-whole contract between Williams Four Corners and Thompson Engineering. See Tr. at 681:16-683:11 (Emory); Gas Gathering, Processing, Dehydrating and Treating Agreement between Williams Four Corners LLC and Thompson Engineering (dated February 1, 2007)(Defendants’ Hearing Ex. 49)(“Thompson Contract”). "WPX Production acquired Thompson Engineering’s interests in the wells committed to the contract, and assumed Thompson’s position under the contract. See Tr. at 681:16-683:11 (Emory).

8. Potential Damage-Calculation Models.

315. The Defendants have maintained data, information systems, and invoices from Williams Four Corners to WPX Production for Williams Four Corners’ gathering and processing services. See Tr. at 419:10-420:17 (Gallegos, Tysseling); Tysseling Report at 4. Data within the Defendants’ information systems track and report natural gas content, NGL content, and condensate content. See Tysseling Report at 4-6.

316. The invoices list the wells that were gathered and processed under the J99, the 372K, and the J99M agreements. See Tr. at 419:10-423:15 (Gallegos, Tysseling). These invoices provide the volumes delivered to the Ignacio, Kutz, and Lybrook plants. See Tr. at 419:10-423:15 (Gallegos, Tysseling); id. at 430:10-21 (Tysseling); Williams Four Corners LLC Invoice for August 2009 to "WPX Gas Resources regarding J99 (Plaintiffs’ Hearing Ex. 22); Williams Four Corners LLC Invoice for January 2012 to WPX Gas Resources regarding 372K (Plaintiffs’ Hearing Ex. 23).

317. Williams Four Comers also issued "WPX Production a monthly liquids report for every well under the two gathering contracts. See Tr. at 427:5-430:6 (Gallegos, Tysseling). This information uses meter information to provide the total Gpm per well, the liquids products contained in a well’s production, and the plant recovery factors. See Tr. at 427:5-430:6 (Gallegos, Tysseling)(stating that the “data provides both the gross Mcf produced from the well and the gross MMBtus produced from the well in that production month”); id. at 428:21-429:21 (Gallegos, Tys-seling); id. at 433:9-23 (Gallegos, Tysseling).

318. The data reveal where and at what price Williams Four Corners sold the NGLs. Specifically, the data shows: (i) whether the NGLs were sold in the local market from the Ignacio plant or instead fractionated at the Mont Belvieu, Texas fractionation facility; (ii) the value of the NGLs; and (in) whether the liquids were subject to certain transportation and fractionation charges. See Tr. at 431:4— 433:23 (Gallegos, Tysseling).

319. Even if wells produce different amounts of liquids, the data that the Defendants maintain accounts for those differences. See Tr. at 430:20-21 (Tysseling); id. at 429:22-430:2 (Gallegos, Tysseling). WPX Production’s automated accounting system processes royalty payments to private owners and federal and state royalty owners, despite variations in production volumes and liquid content. See Ward Nov. Depo. at 45:3-49:9 (Ward).

320. The Plaintiffs can input the Defendants’ own information into automated algorithms to determine the precise amount of damages to which the proposed class is entitled. See Tysseling Report at 25.

321. Even though the Plaintiffs can determine the amount of entrained liquefiable hydrocarbons possible of being extracted from each well, not all NGLs entrained in the gas are ultimately extracted from the gas. See Tr. at 666:2-668:2 (Emory, Sutphin); Ward April Depo. at 96:5-9 (Ward)(“[N]ot all of it is processed. Some of that gas, it cannot physically go to the Ignacio plant and be processed.”). Because some of the gas is bypassed from processing, determining the amount of extracted NGLs produced from each well requires a well-by-well flow analysis. See Tr. at 716:24-717:8 (Emory).

*202 322. The Plaintiffs’ damages formula, however, purports to calculate the damages for failure to pay royalty on all NGLs capable of being extracted, regardless of whether all of the gas was actually processed. See Emory Report ¶66, at 33 (Tysseling’s calculations presume that all Class Wells are physically processed at one of the WFC gas processing plants.”); Tr. at 429:8-14 (Gallegos, Tyssel-ing)(explaining that Tysseling calculated damages using the invoices, which state only “the theoretical volumes that would be recovered from the wellhead” and do not note whether the gas was actually processed). Accordingly, if the Plaintiffs demonstrate that they should be compensated for NGL value regardless of whether the gas was processed, the processing issue is not relevant to the damages calculation.

323. The Plaintiffs’ damages formula relies on a fourteen percent of NGLs processing fee, but WPX Production has paid processing fees of thirty-three percent, twenty-seven percent, and fourteen percent. See Ward April Depo. at 46:23-57:23 (Ward). For the entire class period, the weighted average processing fee for WPX gas committed to an Enterprise processing contract was approximately twenty-nine percent. See Ward April Depo. at 46:23-57:23 (Ward).

324. The Plaintiffs’ damages formula takes into account some, but not all, of the costs associated with extracting the NGLs. Specifically, it calculates the cost associated with isolating the NGLs at each plant and takes into account a processing fee. See Tr. at 435:5-20 (Gallegos, Tysseling); id. at 417:1— 418:8 (Gallegos, Tysseling); Hajny Report at 4-5; at 451:3-452:10 (Berge, Tysseling)(stat-ing that the formula does not account for the fractionation costs related to separating the NGLs into their constituent parts, taxes, or plant fuel).

325. In calculating royalty payments for WPX Production’s gas committed to third parties, WPX Production deducts a proportional share of all actual charges that third parties assess, which can include plant fuel, taxes, transportation, and fractionation. See Response to Interrogatory. 1, at 10-11 (Doc, 146-5); Ward Nov. Depo, at 73:25-76:18 (Ward); Ward April Depo. at 45:16-46:22 (Ward). Consequently, at least some of the deductions should apply to the whole-stream method, which compensates royalty owners on the basis of the NGL value and residue value separately. 22 Although these deductions should apply, the Court cannot determine with certainty whether the processing fee includes any of these costs, or instead, whether those costs are deducted on top of the processing fee. 23

326. These costs are specific to each processing plant, as some plants are more efficient than others, and to each applicable gathering agreement. See Emory Report ¶ 66, at 33-34.

*203 327. When Griffin compared the whole-stream method with the keep-whole method, his calculations revealed that some proposed class members would receive higher royalty payments if WPX Production paid on the basis of the keep-whole method. 24 See Tr. at *204 611:16-513:23 (Griffin); Individual Well Summary Assuming Constant 14% NGL Processing Fee (Defendants’ Hearing Ex. 144)(“Indi-vidual Well Summary”); See Tr. at 513:24— 615:6 (Griffin); Unit Summary Assuming Constant 14% NGL Processing Fee at 1 (Defendants’ Hearing Ex. 145)(“Unit Summary”). If WPX Production paid royalty as the Plaintiffs argue that it should — on the basis of actual sales prices rather than index prices, and the costs that Griffin deducts were improper or overstate the deduction, the whole-stream method would yield higher results than the keep-whole method for all class members. Overall, the Court cannot conclude that the keep-whole method produces higher royalty payments for certain class members.

328. Under the Plaintiffs’ proposed damages calculation, which pays royalties for NGLs regardless whether those NGLs were extracted through processing, each class member will benefit from the whole-stream calculation that the Plaintiffs propose. See Tr. at 415:20-24 (Tysseling)(asserting that “all class members will benefit ... when natural gas liquids values are included in their royalty payments”).

PROCEDURAL BACKGROUND

The Court will outline the basic factual allegations and legal arguments underlying the Plaintiffs’ case, as well as the Defendants’ responses to those arguments. The Court will also briefly describe the witnesses each side presented at the hearing, in addition to the witness’ 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 federal court on August 28, 2012. See Class Action Complaint, filed August 28, 2012 (Doc. l)(“First Complaint”). After several rounds of amended pleadings, the Plaintiffs filed the current iteration of their Complaint — the FAC — on October 31, 2013. See FAC at 1. The Plaintiffs allege that they are present and former landowners who own royalties and overriding royalties that burden oil-and-gas leases and wells in the San Juan Basin. See FAC ¶ 25, at 8. They assert that the Defendants underpaid their royalties by: (i) substituting NGLs with “less valuable residue gas in calculating royalty payments”; and (ii) basing the royalty payments on the price of the gas sold in affiliate transactions. FAC ¶20, at 7. They seek to obtain class status under rule 23 to represent themselves and other royalty owners. See FAC ¶ 25, at 8.

3. The Plaintiffs allege numerous claims, but they do not seek to certify all of them as class claims. First, they allege that WPX Production breached their royalty contracts by failing to pay royalty on NGLs. 25 See *205 FAC ¶¶ 72-75, at 20. Second, the Plaintiffs contend that WPX Production breached the covenant of good faith and fair dealing by “intentionally reduc[ing] financial value to which the plaintiffs and the class members are entitled” by failing to pay royalty on all production. FAC ¶¶ 76-79, at 20-21. Third, they assert that WPX Production breached the implied duty to market by failing to market NGLs, “and in doing so obtain the best terms and prices for the benefit of the plaintiffs and members of the class.” FAC ¶ 87, at 22. Fourth, they allege that the Defendants “combined and conspired to cause WPX to unlawfully breach its Royalty agreements with plaintiffs and members of the putative class by failing to pay and/or underpaying Royalty on residue gas, [and] NGLs.” FAC ¶ 91, at 23. Fifth, the Plaintiffs argue that the Defendants violated the New Mexico Oil and Gas Proceeds Payment Act, N.M. Stat. Ann. § 70-10-1 (“NMPPA”). FAC ¶¶ 102-104, at 25-26. The Plaintiffs also assert claims, which they do not seek to certify, for declaratory judgment, accounting, and injunction. See FAC ¶¶ 96-101, at 24-25.

b. The Answer.

4.WPX Production answered the Third Amended Complaint on October 16,2013. See Answer of WPX Energy Production, LLC to Plaintiffs’ Third Amended Class Action Complaint, filed October 16, 2013 (Doc. 89)(“WPX Answer”). WPX Production denies almost all of the Plaintiffs’ allegations, except the jurisdictional and background facts about the parties. See WPX Answer ¶¶ 1-88, at 1-7. WPX Production asserts sixteen affirmative defenses for: (i) failure to state a claim upon which relief may be granted; (ii) WPX Production has fully performed pursuant to its contract with the Plaintiffs and any proposed class members; (in) the Plaintiffs’ claims are not sustainable as class action claims, and the Plaintiffs lack standing to bring these claims; (iv) the Plaintiffs’ claims are barred by the statute of limitations, or alternatively, by the doctrine of laches; (v) the Plaintiffs’ ratification and acquiescence of a continuing course of performance bar their claims; (vi) the doctrines of waiver and estoppel bar the Plaintiffs’ claims; (vii) the doctrine of accord and satisfaction bars the Plaintiffs’ claims; (viii) the express lease terms and “other written instruments governing the relationships among the parties” bar the Plaintiffs’ claims; (ix) the existence of an adequate legal remedy bars the Plaintiffs’ equitable claim for an accounting; (x) WPX Production has the right to offset any underpayments with over-payments as a recoupment or offset; (xi) some of the “plaintiffs’ claims premised upon implied contractual obligations do not extend to holders of overriding royalty interests as a matter of law”; (xii) the Court may not grant relief absent a showing of express breach of contract on the Plaintiffs’ claim for breach of the implied duty of good faith and fair dealing; (xiii) the Plaintiffs may not recover under the NMPPA without showing that they are “entitled to an alleged underpayment of royalty”; (xiv) the Plaintiffs fail to state with particularity the circumstances constituting fraudulent concealment; (xv) the Plaintiffs claim for equitable tolling based on fraudulent concealment is not suitable or sustainable as a class action claim; and (xvi) the Plaintiffs’ claim for punitive damages is unconstitutional. See WPX Answer ¶¶ 1-16, at 7-9.

5. Williams Four Comers and Williams Energy Resources responded on October 16, 2013. See Answer of Williams Four Corners, LLC and Williams Energy Resources, LLC to Plaintiffs’ Third Amended Class Action Complaint, filed October 16, 2013 (Doe. 90)(“Williams Answer”). Like WPX Production, they also denied nearly all of the Plaintiffs’ allegations against them. See Williams Answer ¶¶ 1-89, at 1-9. They also asserted many of the same affirmative defenses. See Williams Answer ¶¶ 1-12, at 9-10.

6. No party has filed an answer to the FAC after the Court granted the Plaintiffs leave to file it.

2. The Motion.

7. In the Motion, the Plaintiffs challenge WPX Production’s royalty payment on the “production gathered to and processed by *206 WFC.” Plaintiffs’ Memorandum Brief in Support of Renewed Motion for Class Certification at 9, filed January 13, 2014 (Doc. 117)(“Brief’). They assert that commonality under rule 23 exists here. See Brief at 13. First, they argue, the Defendants paid royalties in the same manner regardless of a royalty owner’s lease language. See Brief at 13. Second, they note that the leases’ royalty terms “fall into a small number of repeated categories.” Brief at 13. The Plaintiffs contend that commonality exists, because “[n]one of the leases have language that authorizes WPX to fail to report and pay royalties on NGLs.” Brief at 14. See Brief at 17 (“[N]o lease type negates the payment claims here.”). They assert that, because each lease requires payment on all production, all proposed class members “possess the same interest and suffer the same injury.” Brief at 17. They adopt McArthur’s list of common questions, which include:

a. Whether Williams Four Corners, LLC (WFC) and/or Williams Energy Resources, LLC (WER) obtains and sells the NGLs and condensate produced by WPX from leases subject to class royalty and overriding royalty agreements, and, if so, an accounting for the value of the royalty share of the NGLs and condensate sold;

b. Whether WPX breached the leases and overriding royalty agreements by failing to pay royalty on NGLs and condensate production from the leases subject to the royalties;

e.Whether the royalty instruments authorize WPX to deduct postproduction expenses when paying royalty;

d. Whether allowable post-production expenses, assuming there are any, charged by WPX are actual and reasonable;

e. Whether the monthly payment statements to royalty owners are misleading and show bad faith in representing that royalty is paid on “Total Production” when in fact no royalty is paid on production of NGLs and condensate;

f. Whether the monthly payment statements provided by WPX to the royalty owners are materially misleading because they (a) do not report value for NGLs; (b) do not report value for condensate; (c) deduct expenses of gathering and processing allocable to NGLs in the gas stream while providing no royalties on that production; and (d) reflect netback deductions that are improper;

g. Whether the monthly payment statements provided by WPX to the royalty owners are intentionally misleading or issued with gross negligence;

h. Whether WPX has breached the royalty agreements and its duty to get the best price reasonably possible for production under the duty to market by acquiescing in or participating in “keep whole” gathering and processing arrangements with affiliates;

i. Whether WPX has paid overriding royalty interest owners with same-as-federal interests the same as it pays the federal government lessor;

j. Whether WPX uses and has used a single royalty computation and payment methodology for all private Colorado royalty owners;

k. Whether WPX uses and has used a single royalty computation and payment methodology for all Private New Mexico royalty owners;

l. Whether WPX has used differing royalty computations and payment methodologies based on the particular wording of the payment clauses in any of the royalty and overriding royalty agreements;

m. Whether any of the royalty agreements authorize WPX to avoid paying royalty on all gas and all liquid hydrocarbons produced from leases burdened by class royalties and overriding royalties;

n. Whether any of the royalty agreements authorize WPX to substitute less valuable volumes of residue gas for more valuable NGLs in paying royalty and overriding royalty;

o. Whether any of the royalty agreements authorize WPX to contract with WFC to allow WFC to take possession of and dispose of NGLs and condensate that are subject to the rights of royalty own *207 ers without paying royalty and overriding royalty on that production;

p. Whether WPX acted in bad faith and breached its duty of good faith and fair dealing in paying royalty and overriding royalty;

q. Whether damages for royalty underpayment can be calculated on a class wide basis;

r. 'Whether equitable and declaratory relief should be granted to establish 'WPX’s ongoing royalty obligation to the class and for an accounting by 'WFC of the proceeds of sales on all hydrocarbons produced from leases burdened by class royalties and overriding royalties.

Report of John Burritt McArthur at 13-14, filed January 13, 2014 (Doc. 118-13)(“McAr-thur Expert Report”).

8. Regarding typicality, the Plaintiffs assert that their contractual claims are the same as the class members’ claims, and that the implied covenants “are implied in law and relate to all owners’ agreements.” Brief at 18. As for adequacy, the Plaintiffs explain that Abraham and H Limited “have significant stakes in the San Juan Basin oil and gas industry,” and “are committed to vigorously prosecuting this lawsuit.” Brief at 19.

9. They next explain that the common issues predominate. See Brief at 19. Although they admit that “variations in the wording” exist, they maintain that all leases nonetheless “uniformly require payment on all hydrocarbons produced; that means Royalty must be paid on NGLs and oil. ” Brief at 19 (emphasis in original). The Plaintiffs note that they can calculate damages using a class-wide formula, “which supports certification of the class.” Brief at 20.

10. Regarding rule 23(b)’s superiority requirement, they explain that a class action is the best method to try the case, because “Individual Royalty owners typically are unable to pursue them claims on an individual basis,” as it would be too expensive. Brief at 20. They note: “The class here will number about nineteen hundred, the great majority of whom own small individual claims,” which they could not individually prosecute and finance. Brief at 20. Moreover, the Plaintiffs note that the class action would be manageable. See Brief at 21. They contend that WPX Production’s royalty payment computer system “allows for identification of class members and their addresses permitting notification to the class.” Brief at 21.

3. The Response.

11. The Defendants argue that the Plaintiffs do not satisfy rule 23’s requirements. See Defendants’ Response in Opposition to Plaintiffs’ Motion for Class Certification, filed February 17, 2014 (Doc. 139)(“Re-sponse”). Regarding adequacy and typicality, the Defendants assert that the “Plaintiffs’ royalty provisions account for only two of the 15 different types of royalty clauses found in 'WPX’s leases.” Response at 5. The Defendants further argue that these lease variations alter 'WPX Production’s payment obligations, which therefore destroys commonality. See Response at 6-7, 11. They observe that the Court must also consider extrinsic evidence to determine whether each lease includes a duty to pay royalties on extracted NGLs. See Response at 15-16. Furthermore, the Defendants contend that the different lease language and extrinsic evidence defeats rule 23’s predominance requirement. See Response at 23.

12. In addition to the lease variations, the Defendants argue that the varying gas composition defeats commonality. See Response at 7; id. at 14 . They explain that some gas is processed, while other gas is not, and the Plaintiffs’ class action includes only gas which is processed with NGLs extracted. See Response at 7-8. They argue that the Court must identify “which gas must be processed and which does not ... on a well-by-well basis.” Response at 7. They explain that determining which wells’ gas is processed is “even more difficult for wells connected to gathering systems that can deliver the gas either to the Milagro Plant, where NGLs are not extracted, or to another WFC plant, where NGLs are extracted,” which must be done on a month-by-month basis. Response at 8 (emphasis in original).

13. Regarding the Plaintiffs’ implied covenant claims, the Defendants argue that the Plaintiffs seek to create a new implied duty *208 as an “offshoot” of the implied duty to market. Response at 19-20. They argue that the Court can create an implied duty “only ‘in the absence of any expressed [covenant] on the subject.’ ” Response at 18 (quoting Libby v. De Baca, 1947-NMSC-007 , ¶ 6, 51 N.M. 95 , 179 P.2d 263 )(citation and quotation marks omitted). Here, the Defendants argue, the contract language addresses the issues that the implied duties address. See Response at 18-19.

14. The Defendants further note that questions of “individual damage calculations will inevitably overwhelm questions common to the class,” thereby defeating predominance. Response at 25. Specifically, they argue that WPX Production’s keep-whole contracts do not damage some class members. See Response at 25. They argue that “[determining which class members benefitted in which months for which wells requires an analysis incapable of a class-wide approach.” Response at 26. According to the Defendants, some proposed class members benefit from the challenged payment method also demonstrates that the Plaintiffs’ claims are not typical of the class’ claims. See Response at 28-29.

15. Next, the Defendants explain why the Court cannot certify the Plaintiffs’ remaining claims. See Response at 33-38. First, the Defendants maintain that the Court cannot certify the Plaintiffs’ claim for breach of the duty of good faith and fair dealing. See Response at 32-33. They assert that the Court must consider extrinsic evidence and conduct an individualized inquiry “into what each royalty and overriding royalty interest owner expected when entering into the particular royalty instrument.” Response at 33. Second, the Defendants contend that the Court cannot certify the Plaintiffs’ claim for violation of the NMPPA, because “there can be no class PPA claim for penalty interest on underpayments” unless they can allege “a potentially successful claim for underpayment of royalties,” which the Plaintiffs cannot do here. Response at 36. Finally, the Defendants assert that the Court cannot certify the Plaintiffs’ civil conspiracy claim, because the choice-of-law analysis defeats commonality and predominance. See Response at 37-38.

4. The Reply.

16. The Plaintiffs replied on March 3, 2014. See Plaintiffs’ Reply in Support of Renewed Motion for Class Certification, filed March 3, 2014 (Doc. 155)(“Reply”). In response to the Defendants’ argument that varying contractual language prevents class certification, the Plaintiffs contend that the lease language does not affect class certification where the Defendants pay royalties without reference to the lease language, all leases require payment on all production, and there is little to no extrinsic evidence that would entangle the Court in individual issues. See Reply at 2-3; ⅛ at 7 (arguing that “[t]hese facts together support certification”).

17. Regarding their implied-duty-to-market claim, the Plaintiffs clarify that they assert no new or expanded duty. See Reply at 8-9. Instead, the Plaintiffs contend, they “simply allege that defendant WPX has a duty to market, which it has violated,” and which “is well established in New Mexico law.” Reply at 9. They argue that the Court need not consider extrinsic evidence. See Reply at 8-9.

18. The Plaintiffs next argue that variations between the wells do not preclude class damages calculation, because routine computer systems can account for those differences. See Reply at 4. The Plaintiffs contend that the whole-stream valuation method is better for all proposed class members, because the Defendants’ calculation ignores a large quantity of gas and adds “nonexistent expenses.” Reply at 5.

19. The Plaintiffs assert that their claims are typical of the class’ claims, because all proposed class members advance claims “for failure of WPX to make royalty payments on NGLs and condensate, and failure of WPX to pay royalty on the actual revenue received for sales of processed gas.” Reply at 11.

20. As to the other claims, the Plaintiffs contend first that the Court can certify the Plaintiffs’ good-faith-and-fair-dealing claim. See Reply at 12-13. They argue that the Defendants misread New Mexico precedent, and that New Mexico law does not require *209 the Court to “factually gleanf] the parties’ intentions in each case.” Reply at IS.

21. Second, the Plaintiffs explain that the Court may certify their claim under the NMPPA, because “outdated and superseded division orders” do not supersede their lease agreements and relieve the Defendants’ of them responsibilities under the NMPPA. Reply at 14-15.

22. Finally, the Plaintiffs explain that only New Mexico and Colorado law will apply to their conspiracy claims, which shows that no extensive choice-of-law analysis will preclude class certification. See Reply at 16-17.

5. The Class Certification Hearing.

23. The parties began the hearing by giving brief opening statements. See Tr. at 83:9-146:1 (Court, Gallegos, Sheridan).

24. In their opening, the Plaintiffs predominantly argued that their experts can calculate class-wide damages, see Tr. at 106:16-22 (Gallegos), and that common issues predominate, because the Defendants pay all royalties using a common payment method and because all royalty agreements require the Defendants to pay royalty on all production, see Tr. at 106:23-107:3 (Gallegos).

25. In the Defendants’ opening, the Defendants mainly argued that the Court must examine the extrinsic evidence relating to each contract to determine how the contracting parties intended royalty payments to be made, which would overwhelm the Court with individual issues and prevent common issues from predominating. See Tr, at 111:14-127:15 (Court, Sheridan).

a. The Plaintiffs’ First Witness: David Hajny.

26. David Hajny obtained his Bachelor’s Degree in accountancy from New Mexico State University and a Master’s Degree in taxation from Baylor University. See Tr. at 147:8-12 (Gallegos, Hajny). After finishing his education in 1982, Hajny worked as a Certified Public Accountant at: (i) Peat Mar-wick in El Paso, Texas; (ii) then at Coopers and Lybrand in Philadelphia, Pennsylvania; and (iii) at KPMG in Albuquerque, New Mexico. See Tr. at 147:13-17 (Hajny). After leaving KPMG in 1997, Hajny worked for Cinco General Partnership, which produces oil and gas in wells in the San Juan Basin. See Tr. at 147:21-25 (Hajny). Almost ten years ago, Hajny began working at the Albuquerque accounting firm Reynolds Hicks and Company, where he has performed “a significant amount of oil and gas work.” Tr. at 148:10-16 (Hajny). Hajny has served as an expert witness in federal court, where he testified regarding these plaintiffs’ damages calculation. See Tr. at 148:24-149:13 (Gallegos, Hajny).

27. Hajny calculated a measure of damages for the Plaintiffs’ claim, which: (i) deducted a fourteen-percent processing fee for processing the NGLs; and (ii) used an estimated 5.5% payment as the “class royalty burden” — the class members’ ownership percentage of WPX Production’s share of the plant liquids. Tr. at 160:22-170:6 (Gallegos, Hajny). See id. at 417:4-24 (Gallegos, Tyssel-ing). Hajny testified that, because of a lack of sufficient discovery at this point, he did not have enough information to calculate how much the Defendants’ royalty payment system, which paid royalty using an index price rather than the actual sales price, had underpaid the Plaintiffs. See Tr. at 174:14-176:8 (Gallegos, Hajny). Despite his current lack of information, Hajny testified that the Court could easily manage the distribution of a class award to each individual plaintiff by allocating the class members a pro rata share of the class award based on each class member’s ownership interest. See Tr. at 192:9-194:16 (Gallegos, Hajny).

b. The Plaintiffs’ Second Witness: Steve Abraham.

28. S. Abraham, a named Plaintiff and proposed class representative, testified that he has lived in the Albuquerque area his entire life. See Tr. at 226:16-25 (Abraham, Gallegos). S. Abraham testified that his royalty interests came from his grandmother, Hazel Abraham, who acquired three mineral deeds in 1955. See Tr. at 231:19-25 (Abraham). S. Abraham explained how H. Abraham left these mineral interests to her four children, who deeded those interests to S. Abraham’s aunt in 1967. See Tr. at 231:19-25 (Abraham). When S. Abraham’s aunt died in *210 1995, those interests were distributed to S. Abraham, his brother, and his sister’s trust, See Tr. at 232:1-5 (Abraham).

29. On cross-examination, the Defendants questioned S. Abraham whether the subsequent documents that S. Abraham’s predecessors in interest executed, including the: (i) Department of Interior Decision (dated July, 1952)(Defendants’ Hearing Ex. 10); and (ii) the Division Order (dated June 17,1960)(De-fendants’ Healing Ex. 17), provided insight into how royalty should be paid, see Tr. at 254:14-259:23 (Abraham, Sheridan). S. Abraham answered that the Department of Interi- or Decision and Division Order stated that royalty should be paid on “natural gas and components thereof ... [on] the price at the wellhead.” Tr. at 256:16-25 (Abraham, Sheridan)(quoting Defendants’ Hearing Ex. 17). The Defendants also asked whether those subsequent documents demonstrated that S. Abraham’s predecessors in interest possibly understood that: (i) the working interest owner might base the royalty payment on gas sales to affiliates, see Tr. at 258:22-259:8 (Abraham, Sheridan); and (ii) the parties understood that royalty would be based on the price of gas at the wellhead, id. at 262:15-23 (Sheridan). S. Abraham stated that the documents suggest that the working interest owner’s affiliate might also be a natural gas purchaser, but not necessarily that the royalty would be based on a sale to an affiliate. See Tr. at 258:7-259:17 (Abraham, Sheridan).

c. The Plaintiffs’ Third Witness: Haila Harvey.

30. H. Harvey, a named Plaintiff and proposed class representative, testified that she has lived in Santa Fe, New Mexico for the past eight years. See Tr. at 292:10-13 (Gallegos, Harvey). She stated that H Limited formed in 1996 and owns the mineral interests that Francis Harvey, her father, assembled. See Tr. at 294:3-295:3 (Gallegos, Harvey), H. Harvey explained that H Limited primarily owns overriding royalty interests on wells in Tracts 30 and 42 of the San Juan Basin’s Rosa Unit, which is in the Mesa Verde participating area. See Tr. at 298:15-304:22 (Gallegos, Harvey); id. at 308:16-18 (Gallegos, Harvey).

31. On cross-examination, the Defendants suggested that documents that H Limited’s predecessors in interest executed indicate that the predecessors understood that royalty would be paid on the gas price at the wellhead. See Tr. at 319:4-320 (Harvey, Sheridan)(discussing Defendants’ Hearing Ex. 14 and Ex. 21). H. Harvey agreed that the documents, which were executed with the benefit of legal representation, affirmed that the settlement price “for natural gas and components thereof shall be the price at the wellhead.” Tr. at 328:17-329:4 (Harvey, Sheridan). H. Harvey further testified that H Limited had previously negotiated changes to division orders in the past. See Tr. at 333:7-12 (Harvey, Sheridan).

d. The Plaintiffs’ Fourth Witness: John Burritt McArthur.

32. McArthur obtained his Bachelor’s Degree from Brown University in 1975, his Master’s Degree in Economics from the University of Connecticut in 1978, his law degree from the University of Texas in 1984, his Master’s in Public Administration from Harvard in 1993, and his Ph.D. in public policy from the University of California, Berkeley. See Tr, at 341:19-342:5 (Gallegos, McArthur). The bulk of his legal work has involved the oil-and-gas industry. See Tr. at 342:9-13 (Mc-Arthur). His major published articles on royalty payments include: (i) The Mutual Benefit Implied Covenant for Oil and Gas Royalty Owners. 41 N.M. Nat. Res. J. 795 (2001); (ii) The Precedent Trap and the Irrational Persistence of the Vela Rule, 39 Houston L. Rev. 979 (2002); (iii) A Minority of One? The Reasons to Reject the Texas Supreme Court’s Recent Abandonment of the Duty to Market in Market-Value Leases, 37 Tex. Tech L. Rev. 271 (2005); (iv) The Class Action Tool in Oil Field Litigation, 45 Kan. L. Rev. 1 (1996); (v) Anti-trust in the New [Deregulated Natural Gas Industry, Energy L.J. 1 (1997); and (vi) a forthcoming book entitled Oil and Gas Implied Covenants in the 21st Century that Jurist Publications will publish. Tr. at 342:21-344:2 (McArthur). McArthur described his experience in both litigating and testifying in royalty disputes in New Mexico and around the country. See Tr. at 344:21-350:25 (Gallegos, McArthur).

*211 33. McArthur testified to his two main conclusions: (i) that the leases’ linguistic differences are largely irrelevant to payment; and (ii) that all leases require payment on all production. First, he stated that, after reviewing all 503 leases, he determined that “the great majority of the leases had variations of the two basic pricing terms”: (i) one category that requires payment on the “proceeds” the lessee receives for selling the lessor’s gas — or “amount realized” or “amount received”; and (ii) one category that requires payment on the “market value” or “market price.” Tr. at 351:12-353:8 (Gallegos, McArthur). McArthur noted that the leases at issue are form leases that the oil-and-gas industry commonly uses. See Tr. at 357:8-19 (McArthur)(stating that most of the leases used a form known as Producers’ 88 and that the leases were “not crafted separately for each lessee”). McArthur explained that, on the other hand, the overriding royalty instruments did not use a common form, even though the overriding royalties used the same repetitive language. See Tr. at 357:24-358:8 (McArthur). McArthur stated that there were approximately six categories of overriding royalty language. See Tr. at 358:15-359:3 (Gallegos, McArthur). McAr-thur further stated that WPX Production did not recognize any of the language variation, instead opting to pay all of the proposed class members using the same keep-whole method. See Tr. at 360:1-8 (Gallegos, McAr-thur). Nevertheless, McArthur added, the linguistic differences do not implicate pricing issues, and under the industry’s practice, those differences are not significant. See Tr. at 364:20-366:10 (Gallegos, McArthur).

34. Second, McArthur stated that, outside of this case, some leases he has seen expressly state that no implied covenants apply to the lease, and some royalty provisions expressly exclude payment on NGLs or condensate. See Tr. at 362:22-363:6 (McArthur). McArthur further explained that there is an industry practice of using the word “gas” in a royalty agreement to mean “gas and its components or constituents,” Tr. at 369:21-23 (McArthur). Accordingly, McArthur testified that, when a royalty agreement requires royalty payment on “all oil and gas,” it requires the lessee “to pay on all the products you get from the production stream.” Tr. at 373:15— 20 (McArthur). McArthur noted that none of the royalty instruments address the use of an index price in a transaction between affiliated companies as a basis for royalty payment. See Tr. at 383:17-22 (Gallegos, McArthur).

e. The Plaintiffs’ Fifth Witness: John Tysseling.

35. Tysseling obtained his Bachelor’s Degree in economics and philosophy from the University of New Mexico in 1978, his Master’s Degree in economics from the University of New Mexico in 1979, and his Ph.D. in economics in 1986, with an emphasis on applied natural resource economics and natural resources law. See Tr. at 406:2-8 (Tysseling). In 1985, he joined the New Mexico State Land Office, where he established a royalty management division which worked on royalty policy issues, integrated all aspects of royalty management within the State Land Office, and developed an oil-and-gas information system that managed the State of New Mexico’s production, royalty, and tax interests. See Tr. at 406:25-407:8 (Tysseling). During his tenure at the State Land Office, Tysseling testified before the Federal Energy Regulatory Commission and other state commissions regarding interstate market reforms in the oil-and-gas industry. See Tr. at 407:15-24 (Gallegos, Tysseling). In 1992, Tys-seling began his own economic consulting business focusing on energy and natural resource issues, particularly those involving oil and gas. See Tr. at 408:8-11 (Tysseling). Since that time, Tysseling has testified in class certification proceedings regarding the management ability of class actions. See Tr. at 408:18-25 (Tysseling). Tysseling also investigated damages associated with failure to properly pay natural gas royalties and royalties on natural gas liquids for the Department of Justice, which was representing the Minerals Management Service of the Department of Interior. See Tr. at 409:18-25 (Tys-seling). Currently, Tysseling works in Albuquerque for Moss Adams LLP, a private consulting firm based in Seattle, Washington. See Tr. at 410:15-19 (Tysseling).

36. Tysseling first testified that all class members will benefit from having NGL val *212 ues included in their royalty payments. See Tr. at 415:20-24 (Gallegos, Tysseling). Tys-seling explained that “damages can be calculated on a class-wide basis related to the failure to pay on natural gas liquids.” Tr. at 414:14-16 (Tysseling). Tysseling stated that he applied a 5.5% royalty burden, which is the amount that the proposed class members were entitled to be paid, see Tr. at 417:4-24 (Gallegos, Tysseling), and reduced the damages to account for a fourteen percent processing fee for the New Mexico royalty owners, see Tr. at 417:1-418:8 (Gallegos, Tysseling).

37. Tysseling then described his process. He reviewed eighty-four months’ worth of invoices from Williams Four Comers to WPX Production for Williams Four Corners’ gathering and processing services. See Tr. at 419:10^420:17 (Gallegos, Tysseling). He stated that the invoices provided a means for him to determine: (i) which WPX Production wells produced the gas that Williams Four Comers processed under the J99 contract; (ii) the portion of the gas processed that is attributable to WPX Production’s working interest on the particular well; and (iii) the gallons per thousand cubic feet (“gpm”) for each of the NGL products attributable to WPX Production’s interest in each well. Tr. at 420:13-422:8 (Gallegos, Tysseling); id. at 427:15-21 (Tysseling)(stating that the “data provides both the gross Mef produced from the well and the gross MMBtus produced from the well in that production month”); id. at 428:21-429:21 (Gallegos, Tysseling); id. at 433:9-23 (Gallegos, Tysseling). Tysseling noted that, even if wells produce different amounts of liquids, the data that the Defendants provided to him accounts for those differences. See Tr. at 430:20-21 (Tysseling).

38. Finally, Tysseling described his summary of the NGL production from each of the three processing plants at issue in Plaintiffs’ Hearing Ex. 227. See Tr. at 430:24-431:8 (Gallegos, Tysseling). Plaintiffs’ Hearing Ex. 227 also reveals the sales proceeds that Williams Four Corners obtained for the NGL sales. See Tr. at 432:6-18 (Gallegos, Tysseling). He described how the Defendants’ expert omits the full value of WPX Production gas volume in the Defendants’ damages calculation. See Tr. at 434:2-10 (Gallegos, Tysseling). 26 In sum, Tysseling concluded that the class would be entitled to a preliminary damages amount of approximately $9 million of NGLs, which includes a deduction for a 5.5% royalty burden and a fourteen-percent processing fee. See Tr. at 437:6-17 (Gallegos, Tysseling). On cross-examination, Tysseling conceded that his calculations did not take into account certain deductions like taxes and certain fractionation costs. See Tr. at 438:9-13 (Tysseling).

f. The Plaintiffs’ and Defendants’ Witnesses by Deposition.

39. Both the Plaintiffs and the Defendants designated portions of Mark Beach’s video deposition to be played at the hearing. Beach works for WPX Production in Broken Arrow, Oklahoma. See Deposition of Mark Beach at 4:13-25 (Beach)(taken November 15, 2013)(“Beach Depo.”). He explained that WPX Production maintains oil-and-gas leases and overriding royalty agreements in various files. See Beach Depo. at 10:2-11 (Beach). Beach then described his two-week process of finding the named Plaintiffs’ original lease documents and other related documents. See Beach Depo. at 28:7-34:16 (Beach). He stated that, although he believed that he found most of the lease documents creating the named Plaintiffs’ interests, he did not know whether he found every one. See Beach Depo. at 53:13-14 (Beach).

40. Jefferson Paul Dolan also testified by video deposition. Dolan currently works as director of infrastructure services for WPX Production in Tulsa, Oklahoma, where he manages a group of commercial representatives that negotiate gathering and processing contracts. See Deposition of Jefferson Paul Dolan at 4:7-14 (taken February 10, 2014) (Dolan)(“Dolan Depo.”); id. at 15:19-16:8 (Do-lan). He has formerly worked as an engineer and as a project developer for Williams Field Services and Williams Production Company, where he also engaged in gas marketing. See *213 Dolan Depo. at 5:13-7:11 (Dolan); id. at 9:2-25 (Dolan). Dolan explained that the December 9, 2013 gathering and processing between WPX Production and Williams Four Corners, which he negotiated, was not a keep-whole contract. See Dolan Depo. at 20:8-24:25 (Dolan). He described how one of his goals in negotiating the contract was to retain the NGL value of the gas. See Dolan Depo. at 25:8-25 (Dolan). He also described the Williams companies’ 2011 spin-off and restructuring. See Dolan Depo. at 46:18-48:12 (Dolan).

41. Frank Field testified by video deposition next. He works as a natural gas trader for WPX Production, but he also provides services for WPX Energy Marketing and has formerly worked for various Williams affiliates. See Field Depo. at 4:7-5:22 (Field); id. at 11:2-23 (Field). Field explained WPX Productions’ marketing process. See Field Depo. at 17:19-19:19 (Field); id. at 43:1-47:3 (Field). He stated that, as a gas trading manager, his goals were to “sell and market the products,” to “maximize the value of the price that we receive,” and “to try to make a profit” by selling the gas at a higher price than the index price. Tr. at 17:19-19:19 (Field).

42. The parties designated portions of Sheryl Ward’s November, 2013 and April, 2014 depositions. Ward works for WPX Production in Tulsa, where she is responsible for distributing royalties and working interests to private royalty owners. See Deposition of Sheryl Ward at 4:19-8:2 (taken November 13, 2013)(iCWard Nov. Depo.”). Ward first described the proposed class’ composition: the number of royalty and overriding royalty owners in each state. See Ward April Depo. at 1:1-14:16 (Sutphin, Ward). She then explained WPX Production’s royalty payment system. See Ward April Depo. at 14:17-48:25 (Sutphin, Ward).

43. Finally, the Defendants designated portions of Julie Mathis’ deposition. See Julie Mathis Deposition (taken June 5, 2014)(“Mathis Depo.”). Mathis serves as WPX Productions’ accounting director. See Mathis Depo. at 3:17-25 (Mathis, Sutphin). Mathis explained how WPX Production calculated its federal royalty obligations. See Mathis Depo, at 6:5-9:25 (Mathis, Sutphin). She stated that WPX Production used the “accounting for comparison methodology,” under which WPX Production compares the value of processed gas — La, the value of residue gas after processing, plus the value of NGLs after processing — with the value of unprocessed gas — Le., the wellhead-adjusted Btu — and uses the higher of the two figures. Mathis Depo at 6:22-8:15 (Mathis, Sutphin).

g. The Defendants’ First Witness: James Griffin.

44. Griffin received his Bachelor’s Degree in Mathematics and Economics from Southern Methodist University, and his Ph.D. from the University of Pennsylvania. See Tr. at 477:4-6 (Griffin). For the past thirty years, Griffin has served as an economies and public policy professor at the George Bush School at Texas A&M University, specializing in energy economics. See Tr. at 477:8-13 (Berge, Griffin). Griffin has published more than fifty articles in peer-reviewed academic journals and eight books, including a leading textbook on energy economics — Energy Economics and Policy, and sits on the editorial board of three journals specializing in energy economies. See James M. Griffin Curriculum Vitae (dated January 2014)(Defendants’ Hearing Ex. 79)(“Griffm CV”); Tr. at 478:18-22 (Griffin).

45. Griffin first asserted that no common injury exists among all the class members, because “some wells are better off under the existing keep-whole method,” while other wells “would be better off under the whole-stream method.” Tr. at 481:14-20 (Griffin). Griffin explained that “about 38 percent of the wells ... were actually worse off with the whole-stream approach,” because the whole-stream approach benefits the royalty owner only when the well is relatively rich in NGLs. Tr. at 505:23-8 (Griffin)(“If you don’t have a well that’s relative rich in NGLs, it’s costly to go through this procedure of processing it, splitting out the NGLs, and then incurring the expenses of transporting them and fractionating them.”). Griffin performed a well-by-well analysis on each class well to determine which wells were “better off under the existing keep-whole method.” Tr. at 513:9-17 (Griffin). See Griffin Supplement: Individual Well Summary Assuming Constant 14% *214 NGL Processing Fee (Defendants’ Hearing Ex. 144). He observed that, after deducting a processor’s tax and plant fuel costs, the proposed class members would benefit from using the whole-stream method only during certain time periods where the NGL price was unusually high. See Tr. at 508:1-25 (Griffin).

46. On cross-examination, however, Griffin agreed that the whole-stream method would benefit all class members if Griffin did not include certain deductions. See Tr. at 528:1-9 (Gallegos, Griffin). Although Griffin maintained that certain fees must be deducted under the whole-stream method, he could not identify the source of the gathering fee and fuel cost used in his calculations. See Tr. at 587:7-25 (Gallegos, Griffin)(“Fm still trying to figure it out, and I didn’t get a definitive answer, but we really think that — I really think that it was based on the cost of service.”). Griffin also admitted that his initial calculations slightly — but not materially— “overstated the expenses” involved in transporting some of the NGLs to a fractionation facility. Tr. at 578:4-14 (Gallegos, Griffin).

h. The Defendants’ Second Witness: John Emory.

47. Emory received his bachelor’s degree in mechanical engineering from Michigan State University and a Master’s in Business Administration from Cleveland State University. See Tr. at 630:2-5 (Emory). He has worked in the oil-and-gas industry for approximately thirty-four years, holding positions in engineering, business, and consulting. See Tr. at 630:8-631:22 (Emory). As a midstream participant, Emory negotiated gathering and processing agreements. See Tr. at 632:5-7 (Emory). Currently, he works for the Dallas-based consulting firm Pearson, Watson, Millican, where he advises clients on negotiating gathering and processing contracts, and on royalty and gas valuations issues in San Juan Basin related litigation. See Tr. at 631:23-25 (Emoiy); id. at 634:12-636:24 (Sutphin, Emory).

48. To support his opinion that this case is not amenable to a common damages model, Emory testified that not all gas is processed for NGL removal and that some gas is merely treated for carbon dioxide removal. See Tr. at 672:18-21 (Emory). Emory testified that his research revealed which wells’ gas flowed to which specific plant. See Tr. at 653:16-656:1 (Emory, Sutphin). This determination enabled him to identify how much of the class wells’ gas was processed, and how much of the gas was instead treated at the Milagro plant or bypassed around a processing plant. See Tr. at 662:3-8 (Emory); id. at 664:20-665:4 (Emory, Sutphin); id. at 667:6-9 (Emory, Sutphin). He testified that eight to ten percent of the class well volumes were bypassed around the Ignacio plant, and a total of around sixty to sixty-five percent of the gas was not processed, whereas eighty to ninety percent of the named Plaintiffs’ gas was not processed. See Tr. at 667:23-669:2 (Emory, Sutphin). In sum, he stated that “not all of the wells that are on Plaintiffs’ proposed class list are actually being processed at one of the Williams Four Corners gas processing plants.” Tr. at 672:18-21 (Em-oiy).

49. On cross examination, Emory testified that each well’s meter enables a person to determine whether a class well was being allocated liquids in a particular month. See Tr. at 718:7-20 (Emory, Gallegos). He further agreed that he could ascertain the actual amount of liquids extracted and the amount of liquids allocated to a particular well, even if those liquids were not actually processed. See Tr, at 719:6-19 (Emory, Gallegos).

50. Second, Emory testified that “a significant number of the wells that are on Plaintiffs’ proposed class well list are commingled wells, where there is actually a conventional formation and a Fruitland coal-bed formation commingled.” Tr. at 672:13-18 (Emory). Em-oiy explained that this commingling requires the Court to identify which liquids are alloca-ble to the conventional formation as opposed to the coal-bed formation. See Tr. at 672:21-24 (Emoiy). Emory stated that, to determine which gas is conventional gas, the Plaintiffs would have to rely on decades-old gas sampling, or instead, perform a new time-intensive analysis. See Tr. at 678:3-5 (Emory). The Defendants later identified thirteen class wells that produced from one or more conventional formations that combined production from the Fruitland coal. See Commin *215 gled Well List at 1-7 (Defendants’ Hearing Ex. 139).

51. Based on Emory’s experience in the midstream industry, he explained that reasonably prudent operators must consider “a number of different factors,” which are “really unique to any given well and the circumstances associated with that well.” Tr. at 9-19 (Emory). He described these factors as including: (i) a well’s N6L composition; (ii) the volume of gas a well produces; (iii) a well’s proximity to a gathering system connection; 27 (iv) the commercial terms involved in a gathering agreement for a particular well; and (v) the overall economics associated with extracting the liquids. See Tr. at 689:7-19 (Emory); id. at 695:5-15 (Emory); id. at 698:4-699:7 (Emory, Sutphin). Emory concluded that determining whether an operator acted reasonably requires a well-by-well analysis, because these factors vary drastically between wells. See Tr. at 752:6-9 (Emory, Sutphin). On cross-examination, Emory admitted that, even though wells have numerous differences between them, producers typically do not make gathering and processing agreements for one well; they make the contracts based on a whole package of wells. See Tr. at 704:17-705:20 (conceding that contracts are typically entered into “with a number of wells, or a given area”).

i. The Defendants’ Third Witness: Kris Terry.

52. Terry obtained her bachelor’s degree in history from the University of Oklahoma in 1976, and her law degree from the University of Oklahoma in 1979. See Tr. at 782:12-21 (Sheridan, Terry). She then worked for Fina Oil and Chemical Company, where she served as the exploration-and-production manager for natural gas contracting, and negotiated natural gas contracts when the natural gas industry was undergoing a fundamental restructuring because of federal deregulation. See Tr. at 783:1-785:11 (Sheridan, Terry). Since 1989, Terry has served as President of Kris Terry & Associates, Inc., where she performs consulting services in the oil-and-gas industry. See Tr. at 781:3-25 (Sheridan, Terry). She advises producers in negotiating gathering and purchasing agreements with midstream companies. On natural gas sales contract, she helps companies evaluate merger prospects based on the target company’s existing oil-and-gas prospects, and she advises companies in litigation. See Tr. at 781:20-782:7 (Sheridan, Terry). She has testified as an expert witness in numerous oil-and-gas disputes in state court and federal court, often on issues relating to royalty language. See Tr. at 785:12-25 (Terry).

53.Terry testified that some overriding royalty instruments relate to parties that are not in the class. See Tr. at 791:4-7 (Sheridan, Terry). Specifically, she stated that: (i) “six instruments that were retained by Williams Production Company, Northwest Pipeline, or El Paso, [ ] are now in the hands of WPX,” Tr. at 791:10-15 (Terry); (ii) four overriding royalty instruments “relate to Fruitland coal gas,” Tr. at 791:21-792:2 (Sheridan, Terry); (iii) one instrument is an assignment of a networking interest, see Tr. at 792:5-6 (Terry); (iv) five instruments are assignments of “existing overriding royalty interests and therefore, not the original assignment that created the override,” Tr. at 793:13-17 (Terry); and (v) eighty-six instruments are “corrections of a previous assignment,” which “supersede that original assignment,” Tr. at 794:4-7 (Terry). She argued that, to determine what has been reserved, one must “go back to the original instrument that creates this interest.” Tr. at 793:18-21 (Terry). She disagreed with the Plaintiffs’ classifications, stating that some overriding instruments modified the override to pay royalty in the same manner as the federal government’s payments and arguing that the Plaintiffs “lumped together” different types of leases into the same category, Tr. at 795:16-21 *216 (Terry). See id. at 796:8-9 (Terry); id. at 826:11-17 (Terry).

j. The Closing Arguments.

54. The parties gave their dosing ai’gu-ments on July 14, 2014. See Tr. at 999:1. The Court will summarize each of the parties’ arguments.

i. The Plaintiffs’ Closing.

55. The Plaintiffs emphasized that the Defendants failed “to pay royalty to the class members across the board” on NGLs, and failed “to pay royalty on the actual sales proceeds for processed gas.” Tr. at 1003:7-13 (Gallegos). The Plaintiffs clarified that they dropped their claim for nonpayment of royalty on condensate, as the facts in this case did not support that claim. See Tr. at 1003:25-1004:3 (Gallegos).

56. The Court asked the Plaintiffs how certification in Anderson would impact the Plaintiffs’ case. See Tr. at 1005:3-12 (Court). The Plaintiffs observed that Anderson contains many claims that their case does not include. See Tr. at 1005:17-25 (Gallegos). They argued that their case was sufficiently different from Anderson to allow the Court to certify a class here, even if it could not do so in Anderson. See Tr. at 1007:6-16 (Gallegos). The Plaintiffs then summarized the applicable law and notable testimony from the class certification hearing. See Tr. at 1007:18-1019:3 (Gallegos).

57. The Plaintiffs further explained how they could calculate a class-wide damages measure for the failure to pay NGLs claim, as well as the underpayment of processed gas claim. See Tr. at 1017:5-1018:19 (explaining that, while the Plaintiffs did not have all of the data necessary to calculate damages for the underpayment of processed gas, they proposed to find the difference between “what the gas actually sold for” and “one month’s revenue as attributed on index to WPX”).

58. Regarding typicality, the Plaintiffs argued that H Limited’s interests are typical of the class’ interests, because it owns interests in a federal unit well, and “everybody in federal units is paid in this same kind of an acreage allocation method.” Tr. at 1013:5-13 (Gallegos). Similarly, they asserted that S. Abraham’s interests are typical of the Colorado royalty owners’ interests, because he owns royalties in Colorado. See Tr. at 1013:14-19 (Gallegos).

59. The Plaintiffs conceded that “there are times when the gas is bypassed and not processed,” but maintained that the bypass was “[i]rrelevant,” because WPX Production “allocated” NGLs to the well that produced those NGLs each month. Tr. at 1022:25-1023:5 (Gallegos). The Plaintiffs explained that, in other words, WPX Production determined the amount of NGLs that each well produced in any given month, regardless whether the gas from that well was processed. See Tr. at 1030:15-1031:8 (Gallegos).

60. Finally, the Plaintiffs stated that their “class definition [ ] calls for a couple modifications .... [W]e also propose that the class definition speak to the gas and liquids processed at the various plants, or if not processed, the gas is or has been allocated natural gas liquids _” Tr. at 1033:2-16 (Gallegos)(emphasis added). After the hearing, they acknowledged that they “were not aware of the issue raised by defendants, i.e., that conventional gas from some WPX wells is not processed, until defendants served their expert reports.” Plaintiffs’ Response in Opposition to Defendants’ Motion to Determine Class Certification Based on the Class Definition Contained in Plaintiffs’ Fourth Amended Complaint at 6, filed September 29, 2014 (Doc. 232)(“Response Supporting Class Definition Modification”). They therefore asked the Court to modify the class definition, because modification is necessary and will conform to the evidence presented. See Response Supporting Class Definition Modification at 5-7. The Defendants objected that they “spent thousands of hours building them respective cases around the definition” in the FAC. Motion to Determine Class Certification Based on the Class Definition Contained in Plaintiffs’ Fourth Amended Complaint, filed September 10, 2014 (Doc. 222)(“Class Definition Motion”). They argued that the Plaintiffs’ “new definition is an eleventh hour attempt to expand their putative class to avoid the consequences of WPX’s unrebutted evidence that *217 first, a significant amount of WPX gas is not subject to the class claims, and second, the definition contained in Plaintiffs’ Fourth Amended Complaint renders the class unas-certainable.” Class Definition Motion at 1. The parties later agreed, however, that the Court should use the FAC’s class definition without any further modifications. Agreed Order on Class Definition at 1-2.

ii. The Defendants’ Closing.

61. The Defendants opened by explaining that the Plaintiffs’ main argument for certification on their breach-of-contract claim for failure to pay on NGLs rested on the following: (i) WPX Production pays royalties in a uniform fashion; and (ii) all of the leases require payment on all production. See Tr. at 1035:20-25 (Sheridan). The Defendants argued that “all production” includes only the gas as it emerges from the well and not the later-extracted NGLs. Tr. at 1037:3-1038:13 (Sheridan). They cite numerous cases standing for the proposition that, although “gas” may include all constituent elements, the word does not require payment on the processed plant products. Tr. at 1038:15-1042:15 (Sheridan).

62. Next, the Defendants spent the majority of their time explaining how the implied duty to market did not include an expanded duty to process and market NGLs. See Tr. at 1057:7-1062:17 (Court, Sheridan). They argued that the duty is more limited. They asserted that, were the Court to conclude that the duty to market includes a duty to market NGLs, the Court would have to consider extrinsic evidence for each royalty agreement. See Tr. at 1058:2-1071:7 (Court, Sheridan).

63. The Defendants concluded that “Emory’s testimony demonstrates beyond any question that the plaintiffs cannot meet the requirements of ascertainability of the class.” Tr. at 1071:18-21 (Sheridan).

iii. The Plaintiffs’ Rebuttal.

64. On rebuttal, the Plaintiffs clarified that their case “is not a marketable condition case.” Tr. at 1073:2-3 (Gallegos). They emphasized that the implied-duty-to-market claim at issue involves the same implied duty described in “good old Parr versus Eldridge and Libby versus De Baca.” Tr. at 1073:4-7 (Gallegos)(underline added). The Plaintiffs also emphasized that “[y]ou can’t inject a product into the pipelines without processing,” which means that all of the gas is processed and yields NGLs. Tr. at 1076:5-10 (Gallegos).

65. They argued that no lease negated the duty to pay royalty on the NGLs. See Tr. at 1078:17-25 (Gallegos). They further asserted that “all production” “means the components of the gas as it’s processed.” Tr. at 1080:4-7 (Gallegos).

6. The Supplemental Filings.

66. The Defendants filed several notices regarding supplemental authority, all of which the Court considered in reaching its opinion. The Court also considered these cases’ subsequent histories on appeal or remand. On February 20, 2014, the Defendants advised the Court of “Fitzgerald v. Chesapeake Operating, Inc., Case No. 111, 566, [ 2014 WL 813861 ] as issued on February 14, 2014,” in which the “Oklahoma Court of Civil Appeals reversed the trial court’s decision to certify a class of royalty owners who claimed that Chesapeake had underpaid royalties on oil and gas production. Defendants’ Notice of Supplemental Authority, filed February 20, 2014 (Doc. 142). Second, on May 12, 2014, the Defendants advised the Court of Lauren v. PNC Bank, N.A., 296 F.R.D. 389 (W.D.Pa.2014), which stands “for the proposition that a putative class representative lacks standing to bring class-wide claims, including common law claims, under state laws that bear no causal relationship to that plaintiffs injury.” Notice of Supplemental Authority on Motion to Dismiss for Lack of Standing, filed May 12, 2014 (Doc. 193). On September 25, 2014, the Defendants advised the Court of EQT Production Co. v. Adair, 764 F.3d 347 (4th Cir.2014), in which the Fourth Circuit “vacated class certification in five natural gas royalty class actions.” Defendants’ Notice of Supplemental Authority in Support of Defendants’ Response in Opposition to Plaintiffs’ Motion for Class Certification, filed September 25, 2014 (Doc. 231).

*218 67. On June 27, 2016, the Defendants advised the Court of additional authorities supporting their position. See Defendants’ Notice of Supplemental Authorities in Opposition to Plaintiffs’ Renewed Motion for Class Certification, filed June 27, 2016 (Doc. 246)(“Supplemental Notice”). They informed the Court that it “must be ‘reticent to expand state law without clear guidance from its highest court.’” Supplemental Notice at 2 (quoting A

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